US20080156480A1 - Apparatus for expanding a tubular member - Google Patents
Apparatus for expanding a tubular memberDownload PDFInfo
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- US20080156480A1 US20080156480A1US11/831,466US83146607AUS2008156480A1US 20080156480 A1US20080156480 A1US 20080156480A1US 83146607 AUS83146607 AUS 83146607AUS 2008156480 A1US2008156480 A1US 2008156480A1
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Classifications
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/10—Setting of casings, screens, liners or the like in wells
- E21B43/103—Setting of casings, screens, liners or the like in wells of expandable casings, screens, liners, or the like
- E21B43/106—Couplings or joints therefor
- B—PERFORMING OPERATIONS; TRANSPORTING
- B21—MECHANICAL METAL-WORKING WITHOUT ESSENTIALLY REMOVING MATERIAL; PUNCHING METAL
- B21D—WORKING OR PROCESSING OF SHEET METAL OR METAL TUBES, RODS OR PROFILES WITHOUT ESSENTIALLY REMOVING MATERIAL; PUNCHING METAL
- B21D39/00—Application of procedures in order to connect objects or parts, e.g. coating with sheet metal otherwise than by plating; Tube expanders
- B21D39/08—Tube expanders
- B21D39/20—Tube expanders with mandrels, e.g. expandable
- B21D39/203—Tube expanders with mandrels, e.g. expandable expandable by fluid or elastic material
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B29/00—Cutting or destroying pipes, packers, plugs or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground
- E21B29/10—Reconditioning of well casings, e.g. straightening
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/04—Casing heads; Suspending casings or tubings in well heads
- E21B33/047—Casing heads; Suspending casings or tubings in well heads for plural tubing strings
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/08—Screens or liners
- E21B43/084—Screens comprising woven materials, e.g. mesh or cloth
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/10—Setting of casings, screens, liners or the like in wells
- E21B43/103—Setting of casings, screens, liners or the like in wells of expandable casings, screens, liners, or the like
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/10—Setting of casings, screens, liners or the like in wells
- E21B43/103—Setting of casings, screens, liners or the like in wells of expandable casings, screens, liners, or the like
- E21B43/105—Expanding tools specially adapted therefor
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/14—Obtaining from a multiple-zone well
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/30—Specific pattern of wells, e.g. optimising the spacing of wells
- E21B43/305—Specific pattern of wells, e.g. optimising the spacing of wells comprising at least one inclined or horizontal well
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B7/00—Special methods or apparatus for drilling
- E21B7/20—Driving or forcing casings or pipes into boreholes, e.g. sinking; Simultaneously drilling and casing boreholes
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
- Y10T—TECHNICAL SUBJECTS COVERED BY FORMER US CLASSIFICATION
- Y10T29/00—Metal working
- Y10T29/49—Method of mechanical manufacture
- Y10T29/49826—Assembling or joining
- Y10T29/49908—Joining by deforming
- Y10T29/49938—Radially expanding part in cavity, aperture, or hollow body
Definitions
- This inventionrelates generally to wellbore casings, and in particular to wellbore casings that are formed using expandable tubing.
- a relatively large borehole diameteris required at the upper part of the wellbore.
- Such a large borehole diameterinvolves increased costs due to heavy casing handling equipment, large drill bits and increased volumes of drilling fluid and drill cuttings.
- increased drilling rig timeis involved due to required cement pumping, cement hardening, required equipment changes due to large variations in hole diameters drilled in the course of the well, and the large volume of cuttings drilled and removed.
- a wellheadis formed that typically includes a surface casing, a number of production and/or drilling spools, valving, and a Christmas tree.
- the wellheadfurther includes a concentric arrangement of casings including a production casing and one or more intermediate casings.
- the casingsare typically supported using load bearing slips positioned above the ground.
- the conventional design and construction of wellheadsis expensive and complex.
- the present inventionis directed to overcoming one or more of the limitations of the existing procedures for forming wellbores and wellheads.
- FIG. 1is a fragmentary cross-sectional view illustrating the drilling of a new section of a well borehole.
- FIG. 2is a fragmentary cross-sectional view illustrating the placement of an embodiment of an apparatus for creating a casing within the new section of the well borehole.
- FIG. 3is a fragmentary cross-sectional view illustrating the injection of a first quantity of a fluidic material into the new section of the well borehole.
- FIG. 3 ais another fragmentary cross-sectional view illustrating the injection of a first quantity of a hardenable fluidic sealing material into the new section of the well borehole.
- FIG. 4is a fragmentary cross-sectional view illustrating the injection of a second quantity of a fluidic material into the new section of the well borehole.
- FIG. 5is a fragmentary cross-sectional view illustrating the drilling out of a portion of the cured hardenable fluidic sealing material from the new section of the well borehole.
- FIG. 6is a cross-sectional view of an embodiment of the overlapping joint between adjacent tubular members.
- FIG. 7is a fragmentary cross-sectional view of an exemplary embodiment of the apparatus for creating a casing within a well borehole.
- FIG. 8is a fragmentary cross-sectional illustration of the placement of an expanded tubular member within another tubular member.
- FIG. 9is a cross-sectional illustration of an exemplary embodiment of an apparatus for forming a casing including a drillable mandrel and shoe.
- FIG. 9 ais another cross-sectional illustration of the apparatus of FIG. 9 .
- FIG. 9 bis another cross-sectional illustration of the apparatus of FIG. 9 .
- FIG. 9 cis another cross-sectional illustration of the apparatus of FIG. 9 .
- FIG. 10 ais a cross-sectional illustration of a wellbore including a pair of adjacent overlapping casings.
- FIG. 10 bis a cross-sectional illustration of an apparatus and method for creating a tie-back liner using an expandable tubular member.
- FIG. 10 cis a cross-sectional illustration of the pumping of a fluidic sealing material into the annular region between the tubular member and the existing casing.
- FIG. 10 dis a cross-sectional illustration of the pressurizing of the interior of the tubular member below the mandrel.
- FIG. 10 eis a cross-sectional illustration of the extrusion of the tubular member off of the mandrel.
- FIG. 10 fis a cross-sectional illustration of the tie-back liner before drilling out the shoe and packer.
- FIG. 10 gis a cross-sectional illustration of the completed tie-back liner created using an expandable tubular member.
- FIG. 11 ais a fragmentary cross-sectional view illustrating the drilling of a new section of a well borehole.
- FIG. 11 bis a fragmentary cross-sectional view illustrating the placement of an embodiment of an apparatus for hanging a tubular liner within the new section of the well borehole.
- FIG. 11 cis a fragmentary cross-sectional view illustrating the injection of a first quantify of a hardenable fluidic sealing material into the new section of the well borehole.
- FIG. 11 dis a fragmentary cross-sectional view illustrating the introduction of a wiper dart into the new section of the well borehole.
- FIG. 11 eis a fragmentary cross-sectional view illustrating the injection of a second quantity of a hardenable fluidic sealing material into the new section of the well borehole.
- FIG. 11 fis a fragmentary cross-sectional view illustrating the completion of the tubular liner.
- FIG. 12is a cross-sectional illustration of an exemplary embodiment of a wellhead system utilizing expandable tubular members.
- FIG. 13is a partial cross-sectional illustration of an exemplary embodiment of the wellhead system of FIG. 12 .
- FIG. 14 ais an illustration of the formation of an embodiment of a mono-diameter wellbore casing.
- FIG. 14 bis another illustration of the formation of the mono-diameter wellbore casing.
- FIG. 14 cis another illustration of the formation of the mono-diameter wellbore casing.
- FIG. 14 dis another illustration of the formation of the mono-diameter wellbore casing.
- FIG. 14 eis another illustration of the formation of the mono-diameter wellbore casing.
- FIG. 14 fis another illustration of the formation of the mono-diameter wellbore casing.
- FIG. 15is an illustration of an embodiment of an apparatus for expanding a tubular member.
- FIG. 15 ais another illustration of the apparatus of FIG. 15 .
- FIG. 15 bis another illustration of the apparatus of FIG. 15 .
- FIG. 16is an illustration of an embodiment of an apparatus for forming a mono-diameter wellbore casing.
- FIG. 17is an illustration of an embodiment of an apparatus for expanding a tubular member.
- FIG. 17 ais another illustration of the apparatus of FIG. 16 .
- FIG. 17 bis another illustration of the apparatus of FIG. 16 .
- FIG. 18is an illustration of an embodiment of an apparatus for forming a mono-diameter wellbore casing.
- FIG. 19is an illustration of another embodiment of an apparatus for expanding a tubular member.
- FIG. 19 ais another illustration of the apparatus of FIG. 17 .
- FIG. 19 bis another illustration of the apparatus of FIG. 17 .
- FIG. 20is an illustration of an embodiment of an apparatus for forming a mono-diameter wellbore casing.
- FIG. 21is an illustration of the isolation of subterranean zones using expandable tubulars.
- An apparatus and method for forming a wellbore casing within a subterranean formationpermits a wellbore casing to be formed in a subterranean formation by placing a tubular member and a mandrel in a new section of a wellbore, and then extruding the tubular member off of the mandrel by pressurizing an interior portion of the tubular member.
- the apparatus and methodfurther permits adjacent tubular members in the wellbore to be joined using an overlapping joint that prevents fluid and or gas passage.
- the apparatus and methodfurther permits a new tubular member to be supported by an existing tubular member by expanding the new tubular member into engagement with the existing tubular member.
- the apparatus and methodfurther minimizes the reduction in the hole size of the wellbore casing necessitated by the addition of new sections of wellbore casing.
- An apparatus and method for forming a tie-back liner using an expandable tubular memberis also provided.
- the apparatus and methodpermits a tie-back liner to be created by extruding a tubular member off of a mandrel by pressurizing and interior portion of the tubular member. In this manner, a tie-back liner is produced.
- the apparatus and methodfurther permits adjacent tubular members in the wellbore to be joined using an overlapping joint that prevents fluid and/or gas passage.
- the apparatus and methodfurther permits a new tubular member to be supported by an existing tubular member by expanding the new tubular member into engagement with the existing tubular member.
- An apparatus and method for expanding a tubular memberis also provided that includes an expandable tubular member, mandrel and a shoe.
- the interior portions of the apparatusis composed of materials that permit the interior portions to be removed using a conventional drilling apparatus. In this manner, in the event of a malfunction in a downhole region, the apparatus may be easily removed.
- An apparatus and method for hanging an expandable tubular liner in a wellboreis also provided.
- the apparatus and methodpermit a tubular liner to be attached to an existing section of casing.
- the apparatus and methodfurther have application to the joining of tubular members in general.
- An apparatus and method for forming a wellhead systemis also provided.
- the apparatus and methodpermit a wellhead to be formed including a number of expandable tubular members positioned in a concentric arrangement.
- the wellheadpreferably includes an outer casing that supports a plurality of concentric casings using contact pressure between the inner casings and the outer casing.
- the resulting wellhead systemeliminates many of the spools conventionally required, reduces the height of the Christmas tree facilitating servicing, lowers the load bearing areas of the wellhead resulting in a more stable system, and eliminates costly and expensive hanger systems.
- An apparatus and method for forming a mono-diameter well casingis also provided.
- the apparatus and methodpermit the creation of a well casing in a wellbore having a substantially constant internal diameter. In this manner, the operation of an oil or gas well is greatly simplified.
- An apparatus and method for expanding tubular membersis also provided.
- the apparatus and methodutilize a piston-cylinder configuration in which a pressurized chamber is used to drive a mandrel to radially expand tubular members.
- a pressurized chamberis used to drive a mandrel to radially expand tubular members.
- higher operating pressurescan be utilized.
- the tubular memberis never placed in direct contact with the operating pressures. In this manner, damage to the tubular member is prevented while also permitting controlled radial expansion of the tubular member in a wellbore.
- An apparatus and method for forming a mono-diameter wellbore casingis also provided.
- the apparatus and methodutilize a piston-cylinder configuration in which a pressurized chamber is used to drive a mandrel to radially expand tubular members.
- higher operating pressurescan be utilized.
- Throughput the radial expansion processthe tubular member is never placed in direct contact with the operating pressures. In this manner, damage to the tubular member is prevented while also permitting controlled radial expansion of the tubular member in a wellbore.
- An apparatus and method for isolating one or more subterranean zones from one or more other subterranean zonesis also provided.
- the apparatus and methodpermits a producing zone to be isolated from a nonproducing zone using a combination of solid and slotted tubulars.
- the teachings of the present disclosuremay be used in combination with conventional, well known, production completion equipment and methods using a series of packers, solid tubing, perforated tubing, and sliding sleeves, which will be inserted into the disclosed apparatus to permit the commingling and/or isolation of the subterranean zones from each other.
- a wellbore 100is positioned in a subterranean formation 105 .
- the wellbore 100includes an existing cased section 110 having a tubular casing 115 and an annular outer layer of cement 120 .
- a drill string 125is used in a well known manner to drill out material from the subterranean formation 105 to form a new section 130 .
- an apparatus 200 for forming a wellbore casing in a subterranean formationis then positioned in the new section 130 of the wellbore 100 .
- the apparatus 200preferably includes an expandable mandrel or pig 205 , a tubular member 210 , a shoe 215 , a lower cup seal 220 , an upper cup seal 225 , a fluid passage 230 , a fluid passage 235 , a fluid passage 240 , seals 245 , and a support member 250 .
- the expandable mandrel 205is coupled to and supported by the support member 250 .
- the expandable mandrel 205is preferably adapted to controllably expand in a radial direction.
- the expandable mandrel 205may comprise any number of conventional commercially available expandable mandrels modified in accordance with the teachings of the present disclosure.
- the expandable mandrel 205comprises a hydraulic expansion tool as disclosed in U.S. Pat. No. 5,348,095, the contents of which are incorporated herein by reference, modified in accordance with the teachings of the present disclosure.
- the tubular member 210is supported by the expandable mandrel 205 .
- the tubular member 210is expanded in the radial direction and extruded off of the expandable mandrel 205 .
- the tubular member 210may be fabricated from any number of conventional commercially available materials such as, for example, Oilfield Country Tubular Goods (OCTG), 13 chromium steel tubing/casing, or plastic tubing/casing.
- OCTGOilfield Country Tubular Goods
- 13 chromium steel tubing/casingor plastic tubing/casing.
- the tubular member 210is fabricated from OCTG in order to maximize strength after expansion.
- the inner and outer diameters of the tubular member 210may range, for example, from approximately 0.75 to 47 inches and 1.05 to 48 inches, respectively.
- the inner and outer diameters of the tubular member 210range from about 3 to 15.5 inches and 3.5 to 16 inches, respectively in order to optimally provide minimal telescoping effect in the most commonly drilled wellbore sizes.
- the tubular member 210preferably comprises a solid member.
- the end portion 260 of the tubular member 210is slotted, perforated, or otherwise modified to catch or slow down the mandrel 205 when it completes the extrusion of tubular member 210 .
- the length of the tubular member 210is limited to minimize the possibility of buckling.
- the length of the tubular member 210is preferably limited to between about 40 to 20,000 feet in length.
- the shoe 215is coupled to the expandable mandrel 205 and the tubular member 210 .
- the shoe 215includes fluid passage 240 .
- the shoe 215may comprise any number of conventional commercially available shoes such as, for example, Super Seal II float shoe, Super Seal II Down-Jet float shoe or a guide shoe with a sealing sleeve for a latch down plug modified in accordance with the teachings of the present disclosure.
- the shoe 215comprises an aluminum down-jet guide shoe with a sealing sleeve for a latch-down plug available from Halliburton Energy Services in Dallas, Tex., modified in accordance with the teachings of the present disclosure, in order to optimally guide the tubular member 210 in the wellbore, optimally provide an adequate seal between the interior and exterior diameters of the overlapping joint between the tubular members, and to optimally allow the complete drill out of the shoe and plug after the completion of the cementing and expansion operations.
- the shoe 215includes one or more through and side outlet ports in fluidic communication with the fluid passage 240 . In this manner, the shoe 215 optimally injects hardenable fluidic sealing material into the region outside the shoe 215 and tubular member 210 .
- the shoe 215includes the fluid passage 240 having an inlet geometry that can receive a dart and/or a ball sealing member. In this manner, the fluid passage 240 can be optimally sealed off by introducing a plug, dart and/or ball sealing elements into the fluid passage 230 .
- the lower cup seal 220is coupled to and supported by the support member 250 .
- the lower cup seal 220prevents foreign materials from entering the interior region of the tubular member 210 adjacent to the expandable mandrel 205 .
- the lower cup seal 220may comprise any number of conventional commercially available cup seals such as, for example, TP cups, or Selective Injection Packer (SIP) cups modified in accordance with the teachings of the present disclosure.
- the lower cup seal 220comprises a SIP cup seal, available from Halliburton Energy Services in Dallas, Tex. in order to optimally block foreign material and contain a body of lubricant.
- the upper cup seal 225is coupled to and supported by the support member 250 .
- the upper cup seal 225prevents foreign materials from entering the interior region of the tubular member 210 .
- the upper cup seal 225may comprise any number of conventional commercially available cup seals such as, for example, TP cups or SIP cups modified in accordance with the teachings of the present disclosure.
- the upper cup seal 225comprises a SIP cup, available from Halliburton Energy Services in Dallas, Tex. in order to optimally block the entry of foreign materials and contain a body of lubricant.
- the fluid passage 230permits fluidic materials to be transported to and from the interior region of the tubular member 210 below the expandable mandrel 205 .
- the fluid passage 230is coupled to and positioned within the support member 250 and the expandable mandrel 205 .
- the fluid passage 230preferably extends from a position adjacent to the surface to the bottom of the expandable mandrel 205 .
- the fluid passage 230is preferably positioned along a centerline of the apparatus 200 .
- the fluid passage 230is preferably selected, in the casing running mode of operation, to transport materials such as drilling mud or formation fluids at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to minimize drag on the tubular member being run and to minimize surge pressures exerted on the wellbore which could cause a loss of wellbore fluids and lead to hole collapse.
- the fluid passage 235permits fluidic materials to be released from the fluid passage 230 . In this manner, during placement of the apparatus 200 within the new section 130 of the wellbore 100 , fluidic materials 255 forced up the fluid passage 230 can be released into the wellbore 100 above the tubular member 210 thereby minimizing surge pressures on the wellbore section 130 .
- the fluid passage 235is coupled to and positioned within the support member 250 .
- the fluid passageis further fluidicly coupled to the fluid passage 230 .
- the fluid passage 235preferably includes a control valve for controllably opening and closing the fluid passage 235 .
- the control valveis pressure activated in order to controllably minimize surge pressures.
- the fluid passage 235is preferably positioned substantially orthogonal to the centerline of the apparatus 200 .
- the fluid passage 235is preferably selected to convey fluidic materials at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to reduce the drag on the apparatus 200 during insertion into the new section 130 of the wellbore 100 and to minimize surge pressures on the new wellbore section 130 .
- the fluid passage 240permits fluidic materials to be transported to and from the region exterior to the tubular member 210 and shoe 215 .
- the fluid passage 240is coupled to and positioned within the shoe 215 in fluidic communication with the interior region of the tubular member 210 below the expandable mandrel 205 .
- the fluid passage 240preferably has a cross-sectional shape that permits a plug, or other similar device, to be placed in fluid passage 240 to thereby block further passage of fluidic materials. In this manner, the interior region of the tubular member 210 below the expandable mandrel 205 can be fluidicly isolated from the region exterior to the tubular member 210 . This permits the interior region of the tubular member 210 below the expandable mandrel 205 to be pressurized.
- the fluid passage 240is preferably positioned substantially along the centerline of the apparatus 200 .
- the fluid passage 240is preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the annular region between the tubular member 210 and the new section 130 of the wellbore 100 with fluidic materials.
- the fluid passage 240includes an inlet geometry that can receive a dart and/or a ball sealing member. In this manner, the fluid passage 240 can be sealed of by introducing a plug, dart and/or ball sealing elements into the fluid passage 230 .
- the seals 245are coupled to and supported by an end portion 260 of the tubular member 210 .
- the seals 245are further positioned on an outer surface 265 of the end portion 260 of the tubular member 210 .
- the seals 245permit the overlapping joint between the end portion 270 of the casing 115 and the portion 260 of the tubular member 210 to be fluidicly sealed.
- the seals 245may comprise any number of conventional commercially available seals such as, for example, lead, rubber, Teflon, or epoxy seals modified in accordance with the teachings of the present disclosure.
- the seals 245are molded from Stratalock epoxy available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide a load bearing interference fit between the end 260 of the tubular member 210 and the end 270 of the existing casing 115 .
- the seals 245are selected to optimally provide a sufficient frictional force to support the expanded tubular member 210 from the existing casing 115 .
- the frictional force optimally provided by the seals 245ranges from about 1,000 to 1,000,000 lbf in order to optimally support the expanded tubular member 210 .
- the support member 250is coupled to the expandable mandrel 205 , tubular member 210 , shoe 215 , and seals 220 and 225 .
- the support member 250preferably comprises an annular member having sufficient strength to carry the apparatus 200 into the new section 130 of the wellbore 100 .
- the support member 250further includes one or more conventional centralizers (not illustrated) to help stabilize the apparatus 200 .
- a quantity of lubricant 275is provided in the annular region above the expandable mandrel 205 within the interior of the tubular member 210 . In this manner, the extrusion of the tubular member 210 off of the expandable mandrel 205 is facilitated.
- the lubricant 275may comprise any number of conventional commercially available lubricants such as, for example, Lubriplate, chlorine based lubricants, oil based lubricants or Climax 1500 Antisieze (3100).
- the lubricant 275comprises Climax 1500 Antisieze (3100) available from Climax Lubricants and Equipment Co. in Houston, Tex. in order to optimally provide optimum lubrication to facilitate the expansion process.
- the support member 250is thoroughly cleaned prior to assembly to the remaining portions of the apparatus 200 . In this manner, the introduction of foreign material into the apparatus 200 is minimized. This minimizes the possibility of foreign material clogging the various flow passages and valves of the apparatus 200 .
- a couple of wellbore volumesare circulated in order to ensure that no foreign materials are located within the wellbore 100 that might clog up the various flow passages and valves of the apparatus 200 and to ensure that no foreign material interferes with the expansion process.
- the fluid passage 235is then closed and a hardenable fluidic sealing material 305 is then pumped from a surface location into the fluid passage 230 .
- the material 305then passes from the fluid passage 230 into the interior region 310 of the tubular member 210 below the expandable mandrel 205 .
- the material 305then passes from the interior region 310 into the fluid passage 240 .
- the material 305then exits the apparatus 200 and fills the annular region 315 between the exterior of the tubular member 210 and the interior wall of the new section 130 of the wellbore 100 . Continued pumping of the material 305 causes the material 305 to fill up at least a portion of the annular region 315 .
- the material 305is preferably pumped into the annular region 315 at pressures and flow rates ranging, for example, from about 0 to 5000 psi and 0 to 1,500 gallons/min, respectively.
- the optimum flow rate and operating pressuresvary as a function of the casing and wellbore sizes, wellbore section length, available pumping equipment, and fluid properties of the fluidic material being pumped.
- the optimum flow rate and operating pressureare preferably determined using conventional empirical methods.
- the hardenable fluidic sealing material 305may comprise any number of conventional commercially available hardenable fluidic sealing materials such as, for example, slag mix, cement or epoxy.
- the hardenable fluidic sealing material 305comprises a blended cement prepared specifically for the particular well section being drilled from Halliburton Energy Services in Dallas, Tex. in order to provide optimal support for tubular member 210 while also maintaining optimum flow characteristics so as to minimize difficulties during the displacement of cement in the annular region 315 .
- the optimum blend of the blended cementis preferably determined using conventional empirical methods.
- the annular region 315preferably is filled with the material 305 in sufficient quantities to ensure that, upon radial expansion of the tubular member 210 , the annular region 315 of the new section 130 of the wellbore 100 will be filled with material 305 .
- the wall thickness and/or the outer diameter of the tubular member 210is reduced in the region adjacent to the mandrel 205 in order optimally permit placement of the apparatus 200 in positions in the wellbore with tight clearances. Furthermore, in this manner, the initiation of the radial expansion of the tubular member 210 during the extrusion process is optimally facilitated.
- a plug 405is introduced into the fluid passage 240 thereby fluidicly isolating the interior region 310 from the annular region 315 .
- a non-hardenable fluidic material 306is then pumped into the interior region 310 causing the interior region to pressurize. In this manner, the interior of the expanded tubular member 210 will not contain significant amounts of cured material 305 . This reduces and simplifies the cost of the entire process.
- the material 305may be used during this phase of the process.
- the tubular member 210is extruded off of the expandable mandrel 205 .
- the expandable mandrel 205may be raised out of the expanded portion of the tubular member 210 .
- the mandrel 205is raised at approximately the same rate as the tubular member 210 is expanded in order to keep the tubular member 210 stationary relative to the new wellbore section 130 .
- the extrusion processis commenced with the tubular member 210 positioned above the bottom of the new wellbore section 130 , keeping the mandrel 205 stationary, and allowing the tubular member 210 to extrude off of the mandrel 205 and fall down the new wellbore section 130 under the force of gravity.
- the plug 405is preferably placed into the fluid passage 240 by introducing the plug 405 into the fluid passage 230 at a surface location in a conventional manner.
- the plug 405preferably acts to fluidicly isolate the hardenable fluidic sealing material 305 from the non hardenable fluidic material 306 .
- the plug 405may comprise any number of conventional commercially available devices from plugging a fluid passage such as, for example, Multiple Stage Cementer (MSC) latch-down plug, Omega latch-down plug or three-wiper latch-down plug modified in accordance with the teachings of the present disclosure.
- the plug 405comprises a MSC latch-down plug available from Halliburton Energy Services in Dallas, Tex.
- a non hardenable fluidic material 306is preferably pumped into the interior region 310 at pressures and flow rates ranging, for example, from approximately 400 to 10,000 psi and 30 to 4,000 gallons/min. In this manner, the amount of hardenable fluidic sealing material within the interior 310 of the tubular member 210 is minimized.
- the non hardenable material 306is preferably pumped into the interior region 310 at pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to 3,000 gallons/min in order to maximize the extrusion speed.
- the apparatus 200is adapted to minimize tensile, burst, and friction effects upon the tubular member 210 during the expansion process. These effects will depend upon the geometry of the expansion mandrel 205 , the material composition of the tubular member 210 and expansion mandrel 205 , the inner diameter of the tubular member 210 , the wall thickness of the tubular member 210 , the type of lubricant, and the yield strength of the tubular member 210 . In general, the thicker the wall thickness, the smaller the inner diameter, and the greater the yield strength of the tubular member 210 , then the greater the operating pressures required to extrude the tubular member 210 off of the mandrel 205 .
- the extrusion of the tubular member 210 off of the expandable mandrelwill begin when the pressure of the interior region 310 reaches, for example, approximately 500 to 9,000 psi.
- the expandable mandrel 205may be raised out of the expanded portion of the tubular member 210 at rates ranging, for example, from about 0 to 5 ft/sec. In an exemplary embodiment, during the extrusion process, the expandable mandrel 205 is raised out of the expanded portion of the tubular member 210 at rates ranging from about 0 to 2 ft/sec in order to minimize the time required for the expansion process while also permitting easy control of the expansion process.
- the outer surface 265 of the end portion 260 of the tubular member 210will preferably contact the interior surface 410 of the end portion 270 of the casing 115 to form an fluid tight overlapping joint.
- the contact pressure of the overlapping jointmay range, for example, from approximately 50 to 20,000 psi. In an exemplary embodiment, the contact pressure of the overlapping joint ranges from approximately 400 to 10,000 psi in order to provide optimum pressure to activate the annular sealing members 245 and optimally provide resistance to axial motion to accommodate typical tensile and compressive loads.
- the overlapping joint between the section 410 of the existing casing 115 and the section 265 of the expanded tubular member 210preferably provides a gaseous and fluidic seal.
- the sealing members 245optimally provide a fluidic and gaseous seal in the overlapping joint.
- the operating pressure and flow rate of the non hardenable fluidic material 306is controllably ramped down when the expandable mandrel 205 reaches the end portion 260 of the tubular member 210 . In this manner, the sudden release of pressure caused by the complete extrusion of the tubular member 210 off of the expandable mandrel 205 can be minimized.
- the operating pressureis reduced in a substantially linear fashion from 100% to about 10% during the end of the extrusion process beginning when the mandrel 205 is within about 5 feet from completion of the extrusion process.
- a shock absorberis provided in the support member 250 in order to absorb the shock caused by the sudden release of pressure.
- the shock absorbermay comprise, for example, any conventional commercially available shock absorber adapted for use in wellbore operations.
- a mandrel catching structureis provided in the end portion 260 of the tubular member 210 in order to catch or at least decelerate the mandrel 205 .
- the expandable mandrel 205is removed from the wellbore 100 .
- the integrity of the fluidic seal of the overlapping joint between the upper portion 260 of the tubular member 210 and the lower portion 270 of the casing 115is tested using conventional methods.
- any uncured portion of the material 305 within the expanded tubular member 210is then removed in a conventional manner such as, for example, circulating the uncured material out of the interior of the expanded tubular member 210 .
- the mandrel 205is then pulled out of the wellbore section 130 and a drill bit or mill is used in combination with a conventional drilling assembly 505 to drill out any hardened material 305 within the tubular member 210 .
- the material 305 within the annular region 315is then allowed to cure.
- any remaining cured material 305 within the interior of the expanded tubular member 210is then removed in a conventional manner using a conventional drill string 505 .
- the resulting new section of casing 510includes the expanded tubular member 210 and an outer annular layer 515 of cured material 305 .
- the bottom portion of the apparatus 200 comprising the shoe 215 and dart 405may then be removed by drilling out the shoe 215 and dart 405 using conventional drilling methods.
- the upper portion 260 of the tubular member 210includes one or more sealing members 605 and one or more pressure relief holes 610 .
- the overlapping joint between the lower portion 270 of the casing 115 and the upper portion 260 of the tubular member 210is pressure-tight and the pressure on the interior and exterior surfaces of the tubular member 210 is equalized during the extrusion process.
- the sealing members 605are seated within recesses 615 formed in the outer surface 265 of the upper portion 260 of the tubular member 210 .
- the sealing members 605are bonded or molded onto the outer surface 265 of the upper portion 260 of the tubular member 210 .
- the pressure relief holes 610are preferably positioned in the last few feet of the tubular member 210 . The pressure relief holes reduce the operating pressures required to expand the upper portion 260 of the tubular member 210 . This reduction in required operating pressure in turn reduces the velocity of the mandrel 205 upon the completion of the extrusion process. This reduction in velocity in turn minimizes the mechanical shock to the entire apparatus 200 upon the completion of the extrusion process.
- an exemplary embodiment of an apparatus 700 for forming a casing within a wellborepreferably includes an expandable mandrel or pig 705 , an expandable mandrel or pig container 710 , a tubular member 715 , a float shoe 720 , a lower cup seal 725 , an upper cup seal 730 , a fluid passage 735 , a fluid passage 740 , a support member 745 , a body of lubricant 750 , an overshot connection 755 , another support member 760 , and a stabilizer 765 .
- the expandable mandrel 705is coupled to and supported by the support member 745 .
- the expandable mandrel 705is further coupled to the expandable mandrel container 710 .
- the expandable mandrel 705is preferably adapted to controllably expand in a radial direction.
- the expandable mandrel 705may comprise any number of conventional commercially available expandable mandrels modified in accordance with the teachings of the present disclosure.
- the expandable mandrel 705comprises a hydraulic expansion tool substantially as disclosed in U.S. Pat. No. 5,348,095, the contents of which are incorporated herein by reference, modified in accordance with the teachings of the present disclosure.
- the expandable mandrel container 710is coupled to and supported by the support member 745 .
- the expandable mandrel container 710is further coupled to the expandable mandrel 705 .
- the expandable mandrel container 710may be constructed from any number of conventional commercially available materials such as, for example, Oilfield Country Tubular Goods, stainless steel, titanium or high strength steels.
- the expandable mandrel container 710is fabricated from material having a greater strength than the material from which the tubular member 715 is fabricated. In this manner, the container 710 can be fabricated from a tubular material having a thinner wall thickness than the tubular member 210 . This permits the container 710 to pass through tight clearances thereby facilitating its placement within the wellbore.
- the outside diameter of the tubular member 715is greater than the outside diameter of the container 710 .
- the tubular member 715is coupled to and supported by the expandable mandrel 705 .
- the tubular member 715is preferably expanded in the radial direction and extruded off of the expandable mandrel 705 substantially as described above with reference to FIGS. 1-6 .
- the tubular member 715may be fabricated from any number of materials such as, for example, Oilfield Country Tubular Goods (OCTG), automotive grade steel or plastics. In an exemplary embodiment, the tubular member 715 is fabricated from OCTG.
- the tubular member 715has a substantially annular cross-section. In an exemplary embodiment, the tubular member 715 has a substantially circular annular cross-section.
- the tubular member 715preferably includes an upper section 805 , an intermediate section 810 , and a lower section 815 .
- the upper section 805 of the tubular member 715preferably is defined by the region beginning in the vicinity of the mandrel container 710 and ending with the top section 820 of the tubular member 715 .
- the intermediate section 810 of the tubular member 715is preferably defined by the region beginning in the vicinity of the top of the mandrel container 710 and ending with the region in the vicinity of the mandrel 705 .
- the lower section of the tubular member 715is preferably defined by the region beginning in the vicinity of the mandrel 705 and ending at the bottom 825 of the tubular member 715 .
- the wall thickness of the upper section 805 of the tubular member 715is greater than the wall thicknesses of the intermediate and lower sections 810 and 815 of the tubular member 715 in order to optimally facilitate the initiation of the extrusion process and optimally permit the apparatus 700 to be positioned in locations in the wellbore having tight clearances.
- the outer diameter and wall thickness of the upper section 805 of the tubular member 715may range, for example, from about 1.05 to 48 inches and 1 ⁇ 8 to 2 inches, respectively. In an exemplary embodiment, the outer diameter and wall thickness of the upper section 805 of the tubular member 715 range from about 3.5 to 16 inches and 3 ⁇ 8 to 1.5 inches, respectively.
- the outer diameter and wall thickness of the intermediate section 810 of the tubular member 715may range, for example, from about 2.5 to 50 inches and 1/16 to 1.5 inches, respectively. In an exemplary embodiment, the outer diameter and wall thickness of the intermediate section 810 of the tubular member 715 range from about 3.5 to 19 inches and 1 ⁇ 8 to 1.25 inches, respectively.
- the outer diameter and wall thickness of the lower section 815 of the tubular member 715may range, for example, from about 2.5 to 50 inches and 1/16 to 1.25 inches, respectively. In an exemplary embodiment, the outer diameter and wall thickness of the lower section 810 of the tubular member 715 range from about 3.5 to 19 inches and 1 ⁇ 8 to 1.25 inches, respectively. In an exemplary embodiment, the wall thickness of the lower section 815 of the tubular member 715 is further increased to increase the strength of the shoe 720 when drillable materials such as, for example, aluminum are used.
- the tubular member 715preferably comprises a solid tubular member.
- the end portion 820 of the tubular member 715is slotted, perforated, or otherwise modified to catch or slow down the mandrel 705 when it completes the extrusion of tubular member 715 .
- the length of the tubular member 715is limited to minimize the possibility of buckling.
- the length of the tubular member 715is preferably limited to between about 40 to 20,000 feet in length.
- the shoe 720is coupled to the expandable mandrel 705 and the tubular member 715 .
- the shoe 720includes the fluid passage 740 .
- the shoe 720further includes an inlet passage 830 , and one or more jet ports 835 .
- the cross-sectional shape of the inlet passage 830is adapted to receive a latch-down dart, or other similar elements, for blocking the inlet passage 830 .
- the interior of the shoe 720preferably includes a body of solid material 840 for increasing the strength of the shoe 720 .
- the body of solid material 840comprises aluminum.
- the shoe 720may comprise any number of conventional commercially available shoes such as, for example, Super Seal II Down-Jet float shoe, or guide shoe with a sealing sleeve for a latch down plug modified in accordance with the teachings of the present disclosure.
- the shoe 720comprises an aluminum down-jet guide shoe with a sealing sleeve for a latch-down plug available from Halliburton Energy Services in Dallas, Tex., modified in accordance with the teachings of the present disclosure, in order to optimize guiding the tubular member 715 in the wellbore, optimize the seal between the tubular member 715 and an existing wellbore casing, and to optimally facilitate the removal of the shoe 720 by drilling it out after completion of the extrusion process.
- the lower cup seal 725is coupled to and supported by the support member 745 .
- the lower cup seal 725prevents foreign materials from entering the interior region of the tubular member 715 above the expandable mandrel 705 .
- the lower cup seal 725may comprise any number of conventional commercially available cup seals such as, for example, TP cups or Selective Injection Packer (SIP) cups modified in accordance with the teachings of the present disclosure.
- the lower cup seal 725comprises a SIP cup, available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide a debris barrier and hold a body of lubricant.
- the upper cup seal 730is coupled to and supported by the support member 760 .
- the upper cup seal 730prevents foreign materials from entering the interior region of the tubular member 715 .
- the upper cup seal 730may comprise any number of conventional commercially available cup seals such as, for example, TP cups or Selective Injection Packer (SIP) cup modified in accordance with the teachings of the present disclosure.
- the upper cup seal 730comprises a SIP cup available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide a debris barrier and contain a body of lubricant.
- the fluid passage 735permits fluidic materials to be transported to and from the interior region of the tubular member 715 below the expandable mandrel 705 .
- the fluid passage 735is fluidicly coupled to the fluid passage 740 .
- the fluid passage 735is preferably coupled to and positioned within the support member 760 , the support member 745 , the mandrel container 710 , and the expandable mandrel 705 .
- the fluid passage 735preferably extends from a position adjacent to the surface to the bottom of the expandable mandrel 705 .
- the fluid passage 735is preferably positioned along a centerline of the apparatus 700 .
- the fluid passage 735is preferably selected to transport materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 40 to 3,000 gallons/minute and 500 to 9,000 psi in order to optimally provide sufficient operating pressures to extrude the tubular member 715 off of the expandable mandrel 705 .
- the apparatus 700further includes a pressure release passage that is coupled to and positioned within the support member 260 .
- the pressure release passageis further fluidicly coupled to the fluid passage 735 .
- the pressure release passagepreferably includes a control valve for controllably opening and closing the fluid passage.
- the control valveis pressure activated in order to controllably minimize surge pressures.
- the pressure release passageis preferably positioned substantially orthogonal to the centerline of the apparatus 700 .
- the pressure release passageis preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 500 gallons/minute and 0 to 1,000 psi in order to reduce the drag on the apparatus 700 during insertion into a new section of a wellbore and to minimize surge pressures on the new wellbore section.
- the fluid passage 740permits fluidic materials to be transported to and from the region exterior to the tubular member 715 .
- the fluid passage 740is preferably coupled to and positioned within the shoe 720 in fluidic communication with the interior region of the tubular member 715 below the expandable mandrel 705 .
- the fluid passage 740preferably has a cross-sectional shape that permits a plug, or other similar device, to be placed in the inlet 830 of the fluid passage 740 to thereby block further passage of fluidic materials. In this manner, the interior region of the tubular member 715 below the expandable mandrel 705 can be optimally fluidicly isolated from the region exterior to the tubular member 715 . This permits the interior region of the tubular member 715 below the expandable mandrel 205 to be pressurized.
- the fluid passage 740is preferably positioned substantially along the centerline of the apparatus 700 .
- the fluid passage 740is preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill an annular region between the tubular member 715 and a new section of a wellbore with fluidic materials.
- the fluid passage 740includes an inlet passage 830 having a geometry that can receive a dart and/or a ball sealing member. In this manner, the fluid passage 240 can be sealed off by introducing a plug, dart and/or ball sealing elements into the fluid passage 230 .
- the apparatus 700further includes one or more seals 845 coupled to and supported by the end portion 820 of the tubular member 715 .
- the seals 845are further positioned on an outer surface of the end portion 820 of the tubular member 715 .
- the seals 845permit the overlapping joint between an end portion of preexisting casing and the end portion 820 of the tubular member 715 to be fluidicly sealed.
- the seals 845may comprise any number of conventional commercially available seals such as, for example, lead, rubber, Teflon, or epoxy seals modified in accordance with the teachings of the present disclosure.
- the seals 845comprise seals molded from StrataLock epoxy available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide a hydraulic seal and a load bearing interference fit in the overlapping joint between the tubular member 715 and an existing casing with optimal load bearing capacity to support the tubular member 715 .
- the seals 845are selected to provide a sufficient frictional force to support the expanded tubular member 715 from the existing casing. In an exemplary embodiment, the frictional force provided by the seals 845 ranges from about 1,000 to 1,000,000 lbf in order to optimally support the expanded tubular member 715 .
- the support member 745is preferably coupled to the expandable mandrel 705 and the overshot connection 755 .
- the support member 745preferably comprises an annular member having sufficient strength to carry the apparatus 700 into a new section of a wellbore.
- the support member 745may comprise any number of conventional commercially available support members such as, for example, steel drill pipe, coiled tubing or other high strength tubular modified in accordance with the teachings of the present disclosure.
- the support member 745comprises conventional drill pipe available from various steel mills in the United States.
- a body of lubricant 750is provided in the annular region above the expandable mandrel container 710 within the interior of the tubular member 715 . In this manner, the extrusion of the tubular member 715 off of the expandable mandrel 705 is facilitated.
- the lubricant 705may comprise any number of conventional commercially available lubricants such as, for example, Lubriplate, chlorine based lubricants, oil based lubricants, or Climax 1500 Antisieze (3100).
- the lubricant 750comprises Climax 1500 Antisieze (3100) available from Halliburton Energy Services in Houston, Tex. in order to optimally provide lubrication to facilitate the extrusion process.
- the overshot connection 755is coupled to the support member 745 and the support member 760 .
- the overshot connection 755preferably permits the support member 745 to be removably coupled to the support member 760 .
- the overshot connection 755may comprise any number of conventional commercially available overshot connections such as, for example, Innerstring Sealing Adapter, Innerstring Flat-Face Sealing Adapter or EZ Drill Setting Tool Stinger.
- the overshot connection 755comprises a Innerstring Adapter with an Upper Guide available from Halliburton Energy Services in Dallas, Tex.
- the support member 760is preferably coupled to the overshot connection 755 and a surface support structure (not illustrated).
- the support member 760preferably comprises an annular member having sufficient strength to carry the apparatus 700 into a new section of a wellbore.
- the support member 760may comprise any number of conventional commercially available support members such as, for example, steel drill pipe, coiled tubing or other high strength tubulars modified in accordance with the teachings of the present disclosure.
- the support member 760comprises a conventional drill pipe available from steel mills in the United States.
- the stabilizer 765is preferably coupled to the support member 760 .
- the stabilizer 765also preferably stabilizes the components of the apparatus 700 within the tubular member 715 .
- the stabilizer 765preferably comprises a spherical member having an outside diameter that is about 80 to 99% of the interior diameter of the tubular member 715 in order to optimally minimize buckling of the tubular member 715 .
- the stabilizer 765may comprise any number of conventional commercially available stabilizers such as, for example, EZ Drill Star Guides, packer shoes or drag blocks modified in accordance with the teachings of the present disclosure.
- the stabilizer 765comprises a sealing adapter upper guide available from Halliburton Energy Services in Dallas, Tex.
- the support members 745 and 760are thoroughly cleaned prior to assembly to the remaining portions of the apparatus 700 . In this manner, the introduction of foreign material into the apparatus 700 is minimized. This minimizes the possibility of foreign material clogging the various flow passages and valves of the apparatus 700 .
- a couple of wellbore volumesare circulated through the various flow passages of the apparatus 700 in order to ensure that no foreign materials are located within the wellbore that might clog up the various flow passages and valves of the apparatus 700 and to ensure that no foreign material interferes with the expansion mandrel 705 during the expansion process.
- the apparatus 700is operated substantially as described above with reference to FIGS. 1-7 to form a new section of casing within a wellbore.
- the method and apparatus described hereinis used to repair an existing wellbore casing 805 by forming a tubular liner 810 inside of the existing wellbore casing 805 .
- an outer annular lining of cementis not provided in the repaired section.
- any number of fluidic materialscan be used to expand the tubular liner 810 into intimate contact with the damaged section of the wellbore casing such as, for example, cement, epoxy, slag mix, or drilling mud.
- sealing members 815are preferably provided at both ends of the tubular member in order to optimally provide a fluidic seal.
- the tubular liner 810is formed within a horizontally positioned pipeline section, such as those used to transport hydrocarbons or water, with the tubular liner 810 placed in an overlapping relationship with the adjacent pipeline section. In this manner, underground pipelines can be repaired without having to dig out and replace the damaged sections.
- the method and apparatus described hereinis used to directly line a wellbore with a tubular liner 810 .
- an outer annular lining of cementis not provided between the tubular liner 810 and the wellbore.
- any number of fluidic materialscan be used to expand the tubular liner 810 into intimate contact with the wellbore such as, for example, cement, epoxy, slag mix, or drilling mud.
- an exemplary embodiment of an apparatus 900 for forming a wellbore casingincludes an expandable tubular member 902 , a support member 904 , an expandable mandrel or pig 906 , and a shoe 908 .
- the design and construction of the mandrel 908 and shoe 908permits easy removal of those elements by drilling them out. In this manner, the assembly 900 can be easily removed from a wellbore using a conventional drilling apparatus and corresponding drilling methods.
- the expandable tubular member 902preferably includes an upper portion 910 , an intermediate portion 912 and a lower portion 914 .
- the tubular member 902is preferably extruded off of the mandrel 906 by pressurizing an interior region 966 of the tubular member 902 .
- the tubular member 902preferably has a substantially annular cross-section.
- an expandable tubular member 915is coupled to the upper portion 910 of the expandable tubular member 902 .
- the tubular member 915is preferably extruded off of the mandrel 906 by pressurizing the interior region 966 of the tubular member 902 .
- the tubular member 915preferably has a substantially annular cross-section.
- the wall thickness of the tubular member 915is greater than the wall thickness of the tubular member 902 .
- the tubular member 915may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steels, titanium or stainless steels.
- the tubular member 915is fabricated from oilfield tubulars in order to optimally provide approximately the same mechanical properties as the tubular member 902 .
- the tubular member 915has a plastic yield point ranging from about 40,000 to 135,000 psi in order to optimally provide approximately the same yield properties as the tubular member 902 .
- the tubular member 915may comprise a plurality of tubular members coupled end to end.
- the upper end portion of the tubular member 915includes one or more sealing members for optimally providing a fluidic and/or gaseous seal with an existing section of wellbore casing.
- the combined length of the tubular members 902 and 915are limited to minimize the possibility of buckling.
- the combined length of the tubular members 902 and 915are limited to between about 40 to 20,000 feet in length.
- the lower portion 914 of the tubular member 902is preferably coupled to the shoe 908 by a threaded connection 968 .
- the intermediate portion 912 of the tubular member 902preferably is placed in intimate sliding contact with the mandrel 906 .
- the tubular member 902may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steels, titanium or stainless steels.
- the tubular member 902is fabricated from oilfield tubulars in order to optimally provide approximately the same mechanical properties as the tubular member 915 .
- the tubular member 902has a plastic yield point ranging from about 40,000 to 135,000 psi in order to optimally provide approximately the same yield properties as the tubular member 915 .
- the wall thickness of the upper, intermediate, and lower portions, 910 , 912 and 914 of the tubular member 902may range, for example, from about 1/16 to 1.5 inches. In an exemplary embodiment, the wall thickness of the upper, intermediate, and lower portions, 910 , 912 and 914 of the tubular member 902 range from about 1 ⁇ 8 to 1.25 in order to optimally provide wall thickness that are about the same as the tubular member 915 . In an exemplary embodiment, the wall thickness of the lower portion 914 is less than or equal to the wall thickness of the upper portion 910 in order to optimally provide a geometry that will fit into tight clearances downhole.
- the outer diameter of the upper, intermediate, and lower portions, 910 , 912 and 914 of the tubular member 902may range, for example, from about 1.05 to 48 inches. In an exemplary embodiment, the outer diameter of the upper, intermediate, and lower portions, 910 , 912 and 914 of the tubular member 902 range from about 31 ⁇ 2 to 19 inches in order to optimally provide the ability to expand the most commonly used oilfield tubulars.
- the length of the tubular member 902is preferably limited to between about 2 to 5 feet in order to optimally provide enough length to contain the mandrel 90 t and a body of lubricant.
- the tubular member 902may comprise any number of conventional commercially available tubular members modified in accordance with the teachings of the present disclosure.
- the tubular member 902comprises Oilfield Country Tubular Goods available from various U.S. steel mills.
- the tubular member 915may comprise any number of conventional commercially available tubular members modified in accordance with the teachings of the present disclosure.
- the tubular member 915comprises Oilfield Country Tubular Goods available from various U.S. steel mills.
- the various elements of the tubular member 902may be coupled using any number of conventional process such as, for example, threaded connections, welding or machined from one piece. In an exemplary embodiment, the various elements of the tubular member 902 are coupled using welding.
- the tubular member 902may comprise a plurality of tubular elements that are coupled end to end.
- the various elements of the tubular member 915may be coupled using any number of conventional process such as, for example, threaded connections, welding or machined from one piece. In an exemplary embodiment, the various elements of the tubular member 915 are coupled using welding.
- the tubular member 915may comprise a plurality of tubular elements that are coupled end to end.
- the tubular members 902 and 915may be coupled using any number of conventional process such as, for example, threaded connections, welding or machined from one piece.
- the support member 904preferably includes an innerstring adapter 916 , a fluid passage 918 , an upper guide 920 , and a coupling 922 .
- the support member 904preferably supports the apparatus 900 during movement of the apparatus 900 within a wellbore.
- the support member 904preferably has a substantially annular cross-section.
- the support member 904may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steel, coiled tubing or stainless steel. In an exemplary embodiment, the support member 904 is fabricated from low alloy steel in order to optimally provide high yield strength.
- the innerstring adaptor 916preferably is coupled to and supported by a conventional drill string support from a surface location.
- the innerstring adaptor 916may be coupled to a conventional drill string support 971 by a threaded connection 970 .
- the fluid passage 918is preferably used to convey fluids and other materials to and from the apparatus 900 .
- the fluid passage 918is fluidicly coupled to the fluid passage 952 .
- the fluid passage 918is used to convey hardenable fluidic sealing materials to and from the apparatus 900 .
- the fluid passage 918may include one or more pressure relief passages (not illustrated) to release fluid pressure during positioning of the apparatus 900 within a wellbore.
- the fluid passage 918is positioned along a longitudinal centerline of the apparatus 900 .
- the fluid passage 918is selected to permit the conveyance of hardenable fluidic materials at operating pressures ranging from about 0 to 9,000 psi.
- the upper guide 920is coupled to an upper portion of the support member 904 .
- the upper guide 920preferably is adapted to center the support member 904 within the tubular member 915 .
- the upper guide 920may comprise any number of conventional guide members modified in accordance with the teachings of the present disclosure.
- the upper guide 920comprises an innerstring adapter available from Halliburton Energy Services in Dallas, Tex. order to optimally guide the apparatus 900 within the tubular member 915 .
- the coupling 922couples the support member 904 to the mandrel 906 .
- the coupling 922preferably comprises a conventional threaded connection.
- the various elements of the support member 904may be coupled using any number of conventional processes such as, for example, welding, threaded connections or machined from one piece. In an exemplary embodiment, the various elements of the support member 904 are coupled using threaded connections.
- the mandrel 906preferably includes a retainer 924 , a rubber cup 926 , an expansion cone 928 , a lower cone retainer 930 , a body of cement 932 , a lower guide 934 , an extension sleeve 936 , a spacer 938 , a housing 940 , a sealing sleeve 942 , an upper cone retainer 944 , a lubricator mandrel 946 , a lubricator sleeve 948 , a guide 950 , and a fluid passage 952 .
- the retainer 924is coupled to the lubricator mandrel 946 , lubricator sleeve 948 , and the rubber cup 926 .
- the retainer 924couples the rubber cup 926 to the lubricator sleeve 948 .
- the retainer 924preferably has a substantially annular cross-section.
- the retainer 924may comprise any number of conventional commercially available retainers such as, for example, slotted spring pins or roil pin.
- the rubber cup 926is coupled to the retainer 924 , the lubricator mandrel 946 , and the lubricator sleeve 948 .
- the rubber cup 926prevents the entry of foreign materials into the interior region 972 of the tubular member 902 below the rubber cup 926 .
- the rubber cup 926may comprise any number of conventional commercially available rubber cups such as, for example, TP cups or Selective Injection Packer (SIP) cup.
- SIPSelective Injection Packer
- the rubber cup 926comprises a SIP cup available from Halliburton Energy Services in Dallas, Tex. in order to optimally block foreign materials.
- a body of lubricantis further provided in the interior region 972 of the tubular member 902 in order to lubricate the interface between the exterior surface of the mandrel 902 and the interior surface of the tubular members 902 and 915 .
- the lubricantmay comprise any number of conventional commercially available lubricants such as, for example, Lubriplate, chlorine based lubricants, oil based lubricants or Climax 1500 Antisieze (3100).
- the lubricantcomprises Climax 1500 Antisieze (3100) available from Climax Lubricants and Equipment Co. in Houston, Tex. in order to optimally provide lubrication to facilitate the extrusion process.
- the expansion cone 928is coupled to the lower cone retainer 930 , the body of cement 932 , the lower guide 934 , the extension sleeve 936 , the housing 940 , and the upper cone retainer 944 .
- the tubular members 902 and 915are extruded off of the outer surface of the expansion cone 928 .
- axial movement of the expansion cone 928is prevented by the lower cone retainer 930 , housing 940 and the upper cone retainer 944 .
- Inner radial movement of the expansion cone 928is prevented by the body of cement 932 , the housing 940 , and the upper cone retainer 944 .
- the expansion cone 928preferably has a substantially annular cross section.
- the outside diameter of the expansion cone 928is preferably tapered to provide a cone shape.
- the wall thickness of the expansion cone 928may range, for example, from about 0.125 to 3 inches. In an exemplary embodiment, the wall thickness of the expansion cone 928 ranges from about 0.25 to 0.75 inches in order to optimally provide adequate compressive strength with minimal material.
- the maximum and minimum outside diameters of the expansion cone 928may range, for example, from about 1 to 47 inches. In an exemplary embodiment, the maximum and minimum outside diameters of the expansion cone 928 range from about 3.5 to 19 in order to optimally provide expansion of generally available oilfield tubulars
- the expansion cone 928may be fabricated from any number of conventional commercially available materials such as, for example, ceramic, tool steel, titanium or low alloy steel. In an exemplary embodiment, the expansion cone 928 is fabricated from tool steel in order to optimally provide high strength and abrasion resistance.
- the surface hardness of the outer surface of the expansion cone 928may range, for example, from about 50 Rockwell C to 70 Rockwell C. In an exemplary embodiment, the surface hardness of the outer surface of the expansion cone 928 ranges from about 58 Rockwell C to 62 Rockwell C in order to optimally provide high yield strength.
- the expansion cone 928is heat treated to optimally provide a hard outer surface and a resilient interior body in order to optimally provide abrasion resistance and fracture toughness.
- the lower cone retainer 930is coupled to the expansion cone 928 and the housing 940 .
- axial movement of the expansion cone 928is prevented by the lower cone retainer 930 .
- the lower cone retainer 930has a substantially annular cross-section.
- the lower cone retainer 930may be fabricated from any number of conventional commercially available materials such as, for example, ceramic, tool steel, titanium or low alloy steel. In an exemplary embodiment, the lower cone retainer 930 is fabricated from tool steel in order to optimally provide high strength and abrasion resistance.
- the surface hardness of the outer surface of the lower cone retainer 930may range, for example, from about 50 Rockwell C to 70 Rockwell C. In an exemplary embodiment, the surface hardness of the outer surface of the lower cone retainer 930 ranges from about 58 Rockwell C to 62 Rockwell C in order to optimally provide high yield strength.
- the lower cone retainer 930is heat treated to optimally provide a hard outer surface and a resilient interior body in order to optimally provide abrasion resistance and fracture toughness.
- the lower cone retainer 930 and the expansion cone 928are formed as an integral one-piece element in order reduce the number of components and increase the overall strength of the apparatus.
- the outer surface of the lower cone retainer 930preferably mates with the inner surfaces of the tubular members 902 and 915 .
- the body of cement 932is positioned within the interior of the mandrel 906 .
- the body of cement 932provides an inner bearing structure for the mandrel 906 .
- the body of cement 932further may be easily drilled out using a conventional drill device. In this manner, the mandrel 906 may be easily removed using a conventional drilling device.
- the body of cement 932may comprise any number of conventional commercially available cement compounds. Alternatively, aluminum, cast iron or some other drillable metallic, composite, or aggregate material may be substituted for cement.
- the body of cement 932preferably has a substantially annular cross-section.
- the lower guide 934is coupled to the extension sleeve 936 and housing 940 .
- the lower guide 934preferably helps guide the movement of the mandrel 906 within the tubular member 902 .
- the lower guide 934preferably has a substantially annular cross-section.
- the lower guide 934may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steel or stainless steel. In an exemplary embodiment, the lower guide 934 is fabricated from low alloy steel in order to optimally provide high yield strength. The outer surface of the lower guide 934 preferably mates with the inner surface of the tubular member 902 to provide a sliding fit.
- the extension sleeve 936is coupled to the lower guide 934 and the housing 940 .
- the extension sleeve 936preferably helps guide the movement of the mandrel 906 within the tubular member 902 .
- the extension sleeve 936preferably has a substantially annular cross-section.
- the extension sleeve 936may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steel or stainless steel. In an exemplary embodiment, the extension sleeve 936 is fabricated from low alloy steel in order to optimally provide high yield strength. The outer surface of the extension sleeve 936 preferably mates with the inner surface of the tubular member 902 to provide a sliding fit. In an exemplary embodiment, the extension sleeve 936 and the lower guide 934 are formed as an integral one-piece element in order to minimize the number of components and increase the strength of the apparatus.
- the spacer 938is coupled to the sealing sleeve 942 .
- the spacer 938preferably includes the fluid passage 952 and is adapted to mate with the extension tube 960 of the shoe 908 . In this manner, a plug or dart can be conveyed from the surface through the fluid passages 918 and 952 into the fluid passage 962 .
- the spacer 938has a substantially annular cross-section.
- the spacer 938may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, the spacer 938 is fabricated from aluminum in order to optimally provide disability. The end of the spacer 938 preferably mates with the end of the extension tube 960 . In an exemplary embodiment, the spacer 938 and the sealing sleeve 942 are formed as an integral one-piece element in order to reduce the number of components and increase the strength of the apparatus.
- the housing 940is coupled to the lower guide 934 , extension sleeve 936 , expansion cone 928 , body of cement 932 , and lower cone retainer 930 .
- the housing 940preferably prevents inner radial motion of the expansion cone 928 .
- the housing 940has a substantially annular cross-section.
- the housing 940may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steel or stainless steel. In an exemplary embodiment, the housing 940 is fabricated from low alloy steel in order to optimally provide high yield strength. In an exemplary embodiment, the lower guide 934 , extension sleeve 936 and housing 940 are formed as an integral one-piece element in order to minimize the number of components and increase the strength of the apparatus.
- the interior surface of the housing 940includes one or more protrusions to facilitate the connection between the housing 940 and the body of cement 932 .
- the sealing sleeve 942is coupled to the support member 904 , the body of cement 932 , the spacer 938 , and the upper cone retainer 944 .
- the sealing sleeve 942preferably provides support for the mandrel 906 .
- the sealing sleeve 942is preferably coupled to the support member 904 using the coupling 922 .
- the sealing sleeve 942has a substantially annular cross-section.
- the sealing sleeve 942may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron.
- the sealing sleeve 942is fabricated from aluminum in order to optimally provide drillability of the sealing sleeve 942 .
- the outer surface of the sealing sleeve 942includes one or more protrusions to facilitate the connection between the sealing sleeve 942 and the body of cement 932 .
- the spacer 938 and the sealing sleeve 942are integrally formed as a one-piece element in order to minimize the number of components.
- the upper cone retainer 944is coupled to the expansion cone 928 , the sealing sleeve 942 , and the body of cement 932 .
- the upper cone retainer 944preferably prevents axial motion of the expansion cone 928 .
- the upper cone retainer 944has a substantially annular cross-section.
- the upper cone retainer 944may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, the upper cone retainer 944 is fabricated from aluminum in order to optimally provide drillability of the upper cone retainer 944 .
- the upper cone retainer 944has a cross-sectional shape designed to provide increased rigidity. In an exemplary embodiment, the upper cone retainer 944 has a cross-sectional shape that is substantially I-shaped to provide increased rigidity and minimize the amount of material that would have to be drilled out.
- the lubricator mandrel 946is coupled to the retainer 924 , the rubber cup 926 , the upper cone retainer 944 , the lubricator sleeve 948 , and the guide 950 .
- the lubricator mandrel 946preferably contains the body of lubricant in the annular region 972 for lubricating the interface between the mandrel 906 and the tubular member 902 .
- the lubricator mandrel 946has a substantially annular cross-section.
- the lubricator mandrel 946may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, the lubricator mandrel 946 is fabricated from aluminum in order to optimally provide drillability of the lubricator mandrel 946 .
- the lubricator sleeve 948is coupled to the lubricator mandrel 946 , the retainer 924 , the rubber cup 926 , the upper cone retainer 944 , the lubricator sleeve 948 , and the guide 950 .
- the lubricator sleeve 948preferably supports the rubber cup 926 .
- the lubricator sleeve 948has a substantially annular cross-section.
- the lubricator sleeve 948may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron.
- the lubricator sleeve 948is fabricated from aluminum in order to optimally provide drillability of the lubricator sleeve 948 .
- the lubricator sleeve 948is supported by the lubricator mandrel 946 .
- the lubricator sleeve 948in turn supports the rubber cup 926 .
- the retainer 924couples the rubber cup 926 to the lubricator sleeve 948 .
- seals 949 a and 949 bare provided between the lubricator mandrel 948 , lubricator sleeve 948 , and rubber cup 926 in order to optimally seal off the interior region 972 of the tubular member 902 .
- the guide 950is coupled to the lubricator mandrel 946 , the retainer 924 , and the lubricator sleeve 948 .
- the guide 950preferably guides the apparatus on the support member 904 .
- the guide 950has a substantially annular cross-section.
- the guide 950may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, the guide 950 is fabricated from aluminum order to optimally provide drillability of the guide 950 .
- the fluid passage 952is coupled to the mandrel 906 .
- the fluid passage 952preferably conveys hardenable fluidic materials.
- the fluid passage 952is positioned about the centerline of the apparatus 900 .
- the fluid passage 952is adapted to convey hardenable fluidic materials at pressures and flow rate ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/min in order to optimally provide pressures and flow rates to displace and circulate fluids during the installation of the apparatus 900 .
- the various elements of the mandrel 906may be coupled using any number of conventional process such as, for example, threaded connections, welded connections or cementing. In an exemplary embodiment, the various elements of the mandrel 906 are coupled using threaded connections and cementing.
- the shoe 908preferably includes a housing 954 , a body of cement 956 , a sealing sleeve 958 , an extension tube 960 , a fluid passage 962 , and one or more outlet jets 964 .
- the housing 954is coupled to the body of cement 956 and the lower portion 914 of the tubular member 902 .
- the housing 954preferably couples the lower portion of the tubular member 902 to the shoe 908 to facilitate the extrusion and positioning of the tubular member 902 .
- the housing 954has a substantially annular cross-section.
- the housing 954may be fabricated from any number of conventional commercially available materials such as, for example, steel or aluminum. In an exemplary embodiment, the housing 954 is fabricated from aluminum in order to optimally provide drillability of the housing 954 .
- the interior surface of the housing 954includes one or more protrusions to facilitate the connection between the body of cement 956 and the housing 954 .
- the body of cement 956is coupled to the housing 954 , and the sealing sleeve 958 .
- the composition of the body of cement 956is selected to permit the body of cement to be easily drilled out using conventional drilling machines and processes.
- the composition of the body of cement 956may include any number of conventional cement compositions.
- a drillable materialsuch as, for example, aluminum or iron may be substituted for the body of cement 956 .
- the sealing sleeve 958is coupled to the body of cement 956 , the extension tube 960 , the fluid passage 962 , and one or more outlet jets 964 .
- the sealing sleeve 958preferably is adapted to convey a hardenable fluidic material from the fluid passage 952 into the fluid passage 962 and then into the outlet jets 964 in order to inject the hardenable fluidic material into an annular region external to the tubular member 902 .
- the sealing sleeve 958further includes an inlet geometry that permits a conventional plug or dart 974 to become lodged in the inlet of the sealing sleeve 958 . In this manner, the fluid passage 962 may be blocked thereby fluidicly isolating the interior region 966 of the tubular member 902 .
- the sealing sleeve 958has a substantially annular cross-section.
- the sealing sleeve 958may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron.
- the sealing sleeve 958is fabricated from aluminum in order to optimally provide drillability of the sealing sleeve 958 .
- the extension tube 960is coupled to the sealing sleeve 958 , the fluid passage 962 , and one or more outlet jets 964 .
- the extension tube 960preferably is adapted to convey a hardenable fluidic material from the fluid passage 952 into the fluid passage 962 and then into the outlet jets 964 in order to inject the hardenable fluidic material into an annular region external to the tubular member 902 .
- the sealing sleeve 960further includes an inlet geometry that permits a conventional plug or dart 974 to become lodged in the inlet of the sealing sleeve 958 .
- one end of the extension tube 960mates with one end of the spacer 938 in order to optimally facilitate the transfer of material between the two.
- the extension tube 960has a substantially annular cross-section.
- the extension tube 960may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron.
- the extension tube 960is fabricated from aluminum in order to optimally provide drillability of the extension tube 960 .
- the fluid passage 962is coupled to the sealing sleeve 958 , the extension tube 960 , and one or more outlet jets 964 .
- the fluid passage 962is preferably conveys hardenable fluidic materials.
- the fluid passage 962is positioned about the centerline of the apparatus 900 .
- the fluid passage 962is adapted to convey hardenable fluidic materials at pressures and flow rate ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/min in order to optimally provide fluids at operationally efficient rates.
- the outlet jets 964are coupled to the sealing sleeve 958 , the extension tube 960 , and the fluid passage 962 .
- the outlet jets 964preferably convey hardenable fluidic material from the fluid passage 962 to the region exterior of the apparatus 900 .
- the shoe 908includes a plurality of outlet jets 964 .
- the outlet jets 964comprise passages drilled in the housing 954 and the body of cement 956 in order to simplify the construction of the apparatus 900 .
- the various elements of the shoe 908may be coupled using any number of conventional process such as, for example, threaded connections, cement or machined from one piece of material. In an exemplary embodiment, the various elements of the shoe 908 are coupled using cement.
- the assembly 900is operated substantially as described above with reference to FIGS. 1-8 to create a new section of casing in a wellbore or to repair a wellbore casing or pipeline.
- a drill stringis used in a well known manner to drill out material from the subterranean formation to form a new section.
- the apparatus 900 for forming a wellbore casing in a subterranean formationis then positioned in the new section of the wellbore.
- the apparatus 900includes the tubular member 915 .
- a hardenable fluidic sealing hardenable fluidic sealing materialis then pumped from a surface location into the fluid passage 918 .
- the hardenable fluidic sealing materialthen passes from the fluid passage 918 into the interior region 966 of the tubular member 902 below the mandrel 906 .
- the hardenable fluidic sealing materialthen passes from the interior region 966 into the fluid passage 962 .
- the hardenable fluidic sealing materialthen exits the apparatus 900 via the outlet jets 964 and fills an annular region between the exterior of the tubular member 902 and the interior wall of the new section of the wellbore. Continued pumping of the hardenable fluidic sealing material causes the material to fill up at least a portion of the annular region.
- the hardenable fluidic sealing materialis preferably pumped into the annular region at pressures and flow rates ranging, for example, from about 0 to 5,000 psi and 0 to 1,500 gallons/min, respectively.
- the hardenable fluidic sealing materialis pumped into the annular region at pressures and flow rates that are designed for the specific wellbore section in order to optimize the displacement of the hardenable fluidic sealing material while not creating high enough circulating pressures such that circulation might be lost and that could cause the wellbore to collapse.
- the optimum pressures and flow ratesare preferably determined using conventional empirical methods.
- the hardenable fluidic sealing materialmay comprise any number of conventional commercially available hardenable fluidic sealing materials such as, for example, slag mix, cement or epoxy.
- the hardenable fluidic sealing materialcomprises blended cements designed specifically for the well section being lined available from Halliburton Energy Services in Dallas, Tex. In order to optimally provide support for the new tubular member while also maintaining optimal flow characteristics so as to minimize operational difficulties during the displacement of the cement in the annular region.
- the optimum composition of the blended cementsis preferably determined using conventional empirical methods.
- the annular regionpreferably is filled with the hardenable fluidic sealing material in sufficient quantities to ensure that, upon radial expansion of the tubular member 902 , the annular region of the new section of the wellbore will be filled with hardenable material.
- a plug or dart 974preferably is introduced into the fluid passage 962 thereby fluidicly isolating the interior region 966 of the tubular member 902 from the external annular region.
- a non hardenable fluidic materialis then pumped into the interior region 966 causing the interior region 966 to pressurize.
- the plug or dart 974preferably is introduced into the fluid passage 962 by introducing the plug or dart 974 , or other similar device into the non hardenable fluidic material. In this manner, the amount of cured material within the interior of the tubular members 902 and 915 is minimized.
- the tubular members 902 and 915are extruded off of the mandrel 906 .
- the mandrel 906may be fixed or it may be expandable.
- the mandrel 906is raised out of the expanded portions of the tubular members 902 and 915 using the support member 904 .
- the shoe 908is preferably substantially stationary.
- the plug or dart 974is preferably placed into the fluid passage 962 by introducing the plug or dart 974 into the fluid passage 918 at a surface location in a conventional manner.
- the plug or dart 974may comprise any number of conventional commercially available devices for plugging a fluid passage such as, for example, Multiple Stage Cementer (MSC) latch-down plug, Omega latch-down plug or three-wiper latch down plug modified in accordance with the teachings of the present disclosure.
- the plug or dart 974comprises a MSC latch-down plug available from Halliburton Energy Services in Dallas, Tex.
- the non hardenable fluidic materialis preferably pumped into the interior region 966 at pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to 3,000 gallons/min in order to optimally extrude the tubular members 902 and 915 off of the mandrel 906 .
- the extrusion of the tubular members 902 and 915 off of the expandable mandrelwill begin when the pressure of the interior region 966 reaches approximately 500 to 9,000 psi.
- the extrusion of the tubular members 902 and 915 off of the mandrel 906begins when the pressure of the interior region 966 reaches approximately 1,200 to 8,500 psi with a flow rate of about 40 to 1250 gallons/minute.
- the mandrel 906may be raised out of the expanded portions of the tubular members 902 and 915 at rates ranging, for example, from about 0 to 5 ft/sec.
- the mandrel 906is raised out of the expanded portions of the tubular members 902 and 915 at rates ranging from about 0 to 2 ft/sec in order to optimally provide pulling speed fast enough to permit efficient operation and permit full expansion of the tubular members 902 and 915 prior to curing of the hardenable fluidic sealing material; but not so fast that timely adjustment of operating parameters during operation is prevented.
- the outer surface of the upper end portion of the tubular member 915will preferably contact the interior surface of the lower end portion of the existing casing to form an fluid tight overlapping joint.
- the contact pressure of the overlapping jointmay range, for example, from approximately 50 to 20,000 psi.
- the contact pressure of the overlapping joint between the upper end of the tubular member 915 and the existing section of wellbore casingranges from approximately 400 to 10,000 psi in order to optimally provide contact pressure to activate the sealing members and provide optimal resistance such that the tubular member 915 and existing wellbore casing will carry typical tensile and compressive loads.
- the operating pressure and flow rate of the non hardenable fluidic materialwill be controllably ramped down when the mandrel 906 reaches the upper end portion of the tubular member 915 . In this manner, the sudden release of pressure caused by the complete extrusion of the tubular member 915 off of the expandable mandrel 906 can be minimized.
- the operating pressureis reduced in a substantially linear fashion from 100% to about 10% during the end of the extrusion process beginning when the mandrel 906 has completed approximately all but about the last 5 feet of the extrusion process.
- the operating pressure and/or flow rate of the hardenable fluidic seating material and/or the non hardenable fluidic materialare controlled during all phases of the operation of the apparatus 900 to minimize shock.
- a shock absorberis provided in the support member 904 in order to absorb the shock caused by the sudden release of pressure.
- a mandrel catching structureis provided above the support member 904 in order to catch or at least decelerate the mandrel 906 .
- the mandrel 906is removed from the wellbore.
- the integrity of the fluidic seal of the overlapping joint between the upper portion of the tubular member 915 and the lower portion of the existing casingis tested using conventional methods. If the fluidic seal of the overlapping joint between the upper portion of the tubular member 915 and the lower portion of the existing casing is satisfactory, then the uncured portion of any of the hardenable fluidic sealing material within the expanded tubular member 915 is then removed in a conventional manner. The hardenable fluidic sealing material within the annular region between the expanded tubular member 915 and the existing casing and new section of wellbore is then allowed to cure.
- any remaining cured hardenable fluidic sealing material within the interior of the expanded tubular members 902 and 915is then removed in a conventional manner using a conventional drill string.
- the resulting new section of casingpreferably includes the expanded tubular members 902 and 915 and an outer annular layer of cured hardenable fluidic sealing material.
- the bottom portion of the apparatus 900 comprising the shoe 908may then be removed by drilling out the shoe 908 using conventional drilling methods.
- the interior elements of the apparatus 900are fabricated from materials such as, for example, cement and aluminum, that permit a conventional drill string to be employed to drill out the interior components.
- the composition of the interior sections of the mandrel 906 and shoe 908including one or more of the body of cement 932 , the spacer 938 , the sealing sleeve 942 , the upper cone retainer 944 , the lubricator mandrel 946 , the lubricator sleeve 948 , the guide 950 , the housing 954 , the body of cement 956 , the sealing sleeve 958 , and the extension tube 960 , are selected to permit at least some of these components to be drilled out using conventional drilling methods and apparatus. In this manner, in the event of a malfunction downhole, the apparatus 900 may be easily removed from the wellbore.
- a wellbore 1000 positioned in a subterranean formation 1002includes a first casing 1004 and a second casing 1006 .
- the first casing 1004preferably includes a tubular liner 1008 and a cement annulus 1010 .
- the second casing 1006preferably includes a tubular liner 1012 and a cement annulus 1014 .
- the second casing 1006is formed by expanding a tubular member substantially as described above with reference to FIGS. 1-9 c or below with reference to FIGS. 11 a - 11 f.
- an upper portion of the tubular liner 1012overlaps with a lower portion of the tubular liner 1008 .
- an outer surface of the upper portion of the tubular liner 1012includes one or more sealing members 1016 for providing a fluidic seal between the tubular liners 1008 and 1012 .
- an apparatus 1100in order to create a tie-back liner that extends from the overlap between the first and second casings, 1004 and 1006 , an apparatus 1100 is preferably provided that includes an expandable mandrel or pig 1105 , a tubular member 1110 , a shoe 1115 , one or more cup seals 1120 , a fluid passage 1130 , a fluid passage 1135 , one or more fluid passages 1140 , seals 1145 , and a support member 1150 .
- the expandable mandrel or pig 1105is coupled to and supported by the support member 1150 .
- the expandable mandrel 1105is preferably adapted to controllably expand in a radial direction.
- the expandable mandrel 1105may comprise any number of conventional commercially available expandable mandrels modified in accordance with the teachings of the present disclosure.
- the expandable mandrel 1105comprises a hydraulic expansion tool substantially as disclosed in U.S. Pat. No. 5,348,095, the disclosure of which is incorporated herein by reference, modified in accordance with the teachings of the present disclosure.
- the tubular member 1110is coupled to and supported by the expandable mandrel 1105 .
- the tubular member 1105is expanded in the radial direction and extruded off of the expandable mandrel 1105 .
- the tubular member 1110may be fabricated from any number of materials such as, for example, Oilfield Country Tubular Goods, 13 chromium tubing or plastic piping.
- the tubular member 1110is fabricated from Oilfield Country Tubular Goods.
- the inner and outer diameters of the tubular member 1110may range, for example, from approximately 0.75 to 47 inches and 1.05 to 48 inches, respectively. In an exemplary embodiment, the inner and outer diameters of the tubular member 1110 range from about 3 to 15.5 inches and 3.5 to 16 inches, respectively in order to optimally provide coverage for typical oilfield casing sizes.
- the tubular member 1110preferably comprises a solid member.
- the upper end portion of the tubular member 1110is slotted, perforated, or otherwise modified to catch or slow down the mandrel 1105 when it completes the extrusion of tubular member 1110 .
- the length of the tubular member 1110is limited to minimize the possibility of buckling.
- the length of the tubular member 1110is preferably limited to between about 40 to 20,000 feet in length.
- the shoe 1115is coupled to the expandable mandrel 1105 and the tubular member 1110 .
- the shoe 1115includes the fluid passage 1135 .
- the shoe 1115may comprise any number of conventional commercially available shoes such as, for example, Super Seal II float shoe, Super Seal II Down-Jet float shoe or a guide shoe with a sealing sleeve for a latch down plug modified in accordance with the teachings of the present disclosure.
- the shoe 1115comprises an aluminum down-jet guide shoe with a sealing sleeve for a latch-down plug with side ports radiating off of the exit flow port available from Halliburton Energy Services in Dallas, Tex., modified in accordance with the teachings of the present disclosure, in order to optimally guide the tubular member 1100 to the overlap between the tubular member 1100 and the casing 1012 , optimally fluidicly isolate the interior of the tubular member 1100 after the latch down plug has seated, and optimally permit drilling out of the shoe 1115 after completion of the expansion and cementing operations.
- the shoe 1115includes one or more side outlet ports 1140 in fluidic communication with the fluid passage 1135 . In this manner, the shoe 1115 injects hardenable fluidic sealing material into the region outside the shoe 1115 and tubular member 1110 .
- the shoe 1115includes one or more of the fluid passages 1140 each having an inlet geometry that can receive a dart and/or a ball sealing member. In this manner, the fluid passages 1140 can be sealed off by introducing a plug, dart and/or ball sealing elements into the fluid passage 1130 .
- the cup seal 1120is coupled to and supported by the support member 1150 .
- the cup seal 1120prevents foreign materials from entering the interior region of the tubular member 1110 adjacent to the expandable mandrel 1105 .
- the cup seal 1120may comprise any number of conventional commercially available cup seals such as, for example, TP cups or Selective injection Packer (SIP) cups modified in accordance with the teachings of the present disclosure.
- the cup seal 1120comprises a SIP cup, available from Halliburton Energy Services in Dallas, Tex. In order to optimally provide a barrier to debris and contain a body of lubricant.
- the fluid passage 1130permits fluidic materials to be transported to and from the interior region of the tubular member 1110 below the expandable mandrel 1105 .
- the fluid passage 1130is coupled to and positioned within the support member 1150 and the expandable mandrel 1105 .
- the fluid passage 1130preferably extends from a position adjacent to the surface to the bottom of the expandable mandrel 1105 .
- the fluid passage 1130is preferably positioned along a centerline of the apparatus 1100 .
- the fluid passage 1130is preferably selected to transport materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally provide sufficient operating pressures to circulate fluids at operationally efficient rates.
- the fluid passage 1135permits fluidic materials to be transmitted from fluid passage 1130 to the interior of the tubular member 1110 below the mandrel 1105 .
- the fluid passages 1140permits fluidic materials to be transported to and from the region exterior to the tubular member 1110 and shoe 1115 .
- the fluid passages 1140are coupled to and positioned within the shoe 1115 in fluidic communication with the interior region of the tubular member 1110 below the expandable mandrel 1105 .
- the fluid passages 1140preferably have a cross-sectional shape that permits a plug, or other similar device, to be placed in the fluid passages 1140 to thereby block further passage of fluidic materials. In this manner, the interior region of the tubular member 1110 below the expandable mandrel 1105 can be fluidicly isolated from the region exterior to the tubular member 1105 . This permits the interior region of the tubular member 1110 below the expandable mandrel 1105 to be pressurized.
- the fluid passages 1140are preferably positioned along the periphery of the shoe 1115 .
- the fluid passages 1140are preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the annular region between the tubular member 1110 and the tubular liner 1008 with fluidic materials.
- the fluid passages 1140include an inlet geometry that can receive a dart and/or a ball sealing member. In this manner, the fluid passages 1140 can be sealed off by introducing a plug, dart and/or ball sealing elements into the fluid passage 1130 .
- the apparatus 1100includes a plurality of fluid passage 1140 .
- the base of the shoe 1115includes a single inlet passage coupled to the fluid passages 1140 that is adapted to receive a plug, or other similar device, to permit the interior region of the tubular member 1110 to be fluidicly isolated from the exterior of the tubular member 1110 .
- the seals 1145are coupled to and supported by a lower end portion of the tubular member 1110 .
- the seals 1145are further positioned on an outer surface of the lower end portion of the tubular member 1110 .
- the seals 1145permit the overlapping joint between the upper end portion of the casing 1012 and the lower end portion of the tubular member 1110 to be fluidicly sealed.
- the seals 1145may comprise any number of conventional commercially available seals such as, for example, lead, rubber, Teflon or epoxy seals modified in accordance with the teachings of the present disclosure.
- the seals 1145comprise seals molded from Stratalock epoxy available from Halliburton Energy Services in Dallas, Tex. In order to optimally provide a hydraulic seal in the overlapping joint and optimally provide load carrying capacity to withstand the range of typical tensile and compressive loads.
- the seals 1145are selected to optimally provide a sufficient frictional force to support the expanded tubular member 1110 from the tubular liner 1008 .
- the frictional force provided by the seals 1145ranges from about 1,000 to 1,000,000 lbf in tension and compression in order to optimally support the expanded tubular member 1110 .
- the support member 1150is coupled to the expandable mandrel 1105 , tubular member 1110 , shoe 1115 , and seal 1120 .
- the support member 1150preferably comprises an annular member having sufficient strength to carry the apparatus 1100 into the wellbore 1000 .
- the support member 1150further includes one or more conventional centralizers (not illustrated) to help stabilize the tubular member 1110 .
- a quantity of lubricant 1150is provided in the annular region above the expandable mandrel 1105 within the interior of the tubular member 1110 . In this manner, the extrusion of the tubular member 1110 off of the expandable mandrel 1105 is facilitated.
- the lubricant 1150may comprise any number of conventional commercially available lubricants such as, for example, Lubriplate, chlorine based lubricants or Climax 1500 Antisieze (3100).
- the lubricant 1150comprises Climax 1500 Antiseize (3100) available from Climax Lubricants and Equipment Co. in Houston, Tex. in order to optimally provide lubrication for the extrusion process.
- the support member 1150is thoroughly cleaned prior to assembly to the remaining portions of the apparatus 1100 . In this manner, the introduction of foreign material into the apparatus 1100 is minimized. This minimizes the possibility of foreign material clogging the various flow passages and valves of the apparatus 1100 and to ensure that no foreign material interferes with the expansion mandrel 1105 during the extrusion process.
- the apparatus 1100includes a packer 1155 coupled to the bottom section of the shoe 1115 for fluidicly isolating the region of the wellbore 1000 below the apparatus 1100 . In this manner, fluidic materials are prevented from entering the region of the wellbore 1000 below the apparatus 1100 .
- the packer 1155may comprise any number of conventional commercially available packers such as, for example, EZ Drill Packer, EZ SV Packer or a drillable cement retainer.
- the packer 1155comprises an EZ Drill Packer available from Halliburton Energy Services in Dallas, Tex.
- a high gel strength pillmay be set below the tie-back in place of the packer 1155 .
- the packer 1155may be omitted.
- a couple of wellbore volumesare circulated in order to ensure that no foreign materials are located within the wellbore 1000 that might clog up the various flow passages and valves of the apparatus 1100 and to ensure that no foreign material interferes with the operation of the expansion mandrel 1105 .
- a hardenable fluidic sealing material 1160is then pumped from a surface location into the fluid passage 1130 .
- the material 1160then passes from the fluid passage 1130 into the interior region of the tubular member 1110 below the expandable mandrel 1105 .
- the material 1160then passes from the interior region of the tubular member 1110 into the fluid passages 1140 .
- the material 1160then exits the apparatus 1100 and fills the annular region between the exterior of the tubular member 1110 and the interior wall of the tubular liner 1008 . Continued pumping of the material 1160 causes the material 1160 to fill up at least a portion of the annular region.
- the material 1160may be pumped into the annular region at pressures and flow rates ranging, for example, from about 0 to 5,000 psi and 0 to 1,500 gallons/min, respectively.
- the material 1160is pumped into the annular region at pressures and flow rates specifically designed for the casing sizes being run, the annular spaces being filled, the pumping equipment available, and the properties of the fluid being pumped.
- the optimum flow rates and pressuresare preferably calculated using conventional empirical methods.
- the hardenable fluidic sealing material 1160may comprise any number of conventional commercially available hardenable fluidic sealing materials such as, for example, slag mix, cement or epoxy.
- the hardenable fluidic sealing material 1160comprises blended cements specifically designed for well section being tied-back, available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide proper support for the tubular member 1110 while maintaining optimum flow characteristics so as to minimize operational difficulties during the displacement of cement in the annular region.
- the optimum blend of the blended cementsare preferably determined using conventional empirical methods.
- the annular regionmay be filled with the material 1160 in sufficient quantities to ensure that, upon radial expansion of the tubular member 1110 , the annular region will be filled with material 1160 .
- one or more plugs 1165preferably are introduced into the fluid passages 1140 thereby fluidicly isolating the interior region of the tubular member 1110 from the annular region external to the tubular member 1110 .
- a non hardenable fluidic material 1161is then pumped into the interior region of the tubular member 1110 below the mandrel 1105 causing the interior region to pressurize.
- the one or more plugs 1165are introduced into the fluid passage 1140 with the introduction of the non hardenable fluidic material. In this manner, the amount of hardenable fluidic material within the interior of the tubular member 1110 is minimized.
- the tubular member 1110is extruded off of the expandable mandrel 1105 .
- the expandable mandrel 1105is raised out of the expanded portion of the tubular member 1110 .
- the plugs 1165are preferably placed into the fluid passages 1140 by introducing the plugs 1165 into the fluid passage 1130 at a surface location in a conventional manner.
- the plugs 1165may comprise any number of conventional commercially available devices from plugging a fluid passage such as, for example, brass balls, plugs, rubber balls, or darts modified in accordance with the teachings of the present disclosure.
- the plugs 1165comprise low density rubber balls.
- the plugs 1165comprise a single latch down dart.
- the non hardenable fluidic material 1161is preferably pumped into the interior region of the tubular member 1110 below the mandrel 1105 at pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to 3,000 gallons/min.
- the non hardenable fluidic material 1161is preferably pumped into the interior region of the tubular member 1110 below the mandrel 1105 at pressures and flow rates ranging from approximately 1200 to 8500 psi and 40 to 1250 gallons/min in order to optimally provide extrusion of typical tubulars.
- the extrusion of the tubular member 1110 off of the expandable mandrel 1105will begin when the pressure of the interior region of the tubular member 1110 below the mandrel 1105 reaches, for example, approximately 1200 to 8500 psi. In an exemplary embodiment, the extrusion of the tubular member 1110 off of the expandable mandrel 1105 begins when the pressure of the interior region of the tubular member 1110 below the mandrel 1105 reaches approximately 1200 to 8500 psi.
- the expandable mandrel 1105may be raised out of the expanded portion of the tubular member 1110 at rates ranging, for example, from about 0 to 5 ft/sec. In an exemplary embodiment, during the extrusion process, the expandable mandrel 1105 is raised out of the expanded portion of the tubular member 1110 at rates ranging from about 0 to 2 ft/sec in order to optimally provide permit adjustment of operational parameters, and optimally ensure that the extrusion process will be completed before the material 1160 cures.
- At least a portion 1180 of the tubular member 1110has an internal diameter less than the outside diameter of the mandrel 1105 .
- the sealis effected by compressing the seals 1016 between the expanded section 1180 and the wellbore casing 1012 .
- the contact pressure of the joint between the expanded section 1180 of the tubular member 1110 and the casing 1012ranges from about 500 to 10,000 psi in order to optimally provide pressure to activate the sealing members 1145 and provide optimal resistance to ensure that the joint will withstand typical extremes of tensile and compressive loads.
- substantially all of the entire length of the tubular member 1110has an infernal diameter less than the outside diameter of the mandrel 1105 . In this manner, extrusion of the tubular member 1110 by the mandrel 1105 results in contact between substantially all of the expanded tubular member 1110 and the existing casing 1008 .
- the contact pressure of the joint between the expanded tubular member 1110 and the casings 1008 and 1012ranges from about 500 to 10,000 psi in order to optimally provide pressure to activate the sealing members 1145 and provide optimal resistance to ensure that the joint will withstand typical extremes of tensile and compressive loads.
- the operating pressure and flow rate of the material 1161is controllably ramped down when the expandable mandrel 1105 reaches the upper end portion of the tubular member 1110 . In this manner, the sudden release of pressure caused by the complete extrusion of the tubular member 1110 off of the expandable mandrel 1105 can be minimized.
- the operating pressure of the fluidic material 1161is reduced in a substantially linear fashion from 100% to about 10% during the end of the extrusion process beginning when the mandrel 1105 has completed approximately all but about 5 feet of the extrusion process.
- a shock absorberis provided in the support member 1150 in order to absorb the shock caused by the sudden release of pressure.
- a mandrel catching structureis provided in the upper end portion of the tubular member 1110 in order to catch or at least decelerate the mandrel 1105 .
- the expandable mandrel 1105is removed from the wellbore 1000 .
- the integrity of the fluidic seal of the joint between the upper portion of the tubular member 1110 and the upper portion of the tubular liner 1108is tested using conventional methods. If the fluidic seal of the joint between the upper portion of the tubular member 1110 and the upper portion of the tubular liner 1008 is satisfactory, then the uncured portion of the material 1160 within the expanded tubular member 1110 is then removed in a conventional manner. The material 1160 within the annular region between the tubular member 1110 and the tubular liner 1008 is then allowed to cure.
- any remaining cured material 1160 within the interior of the expanded tubular member 1110is then removed in a conventional manner using a conventional drill string.
- the resulting tie-back liner of casing 1170includes the expanded tubular member 1110 and an outer annular layer 1175 of cured material 1160 .
- the remaining bottom portion of the apparatus 1100 comprising the shoe 1115 and packer 1155is then preferably removed by drilling out the shoe 1115 and packer 1155 using conventional drilling methods.
- the apparatus 1100incorporates the apparatus 900 .
- a wellbore 1200is positioned in a subterranean formation 1205 .
- the wellbore 1200includes an existing cased section 1210 having a tubular casing 1215 and an annular outer layer of cement 1220 .
- a drill string 1225is used in a well known manner to drill out material from the subterranean formation 1205 to form a new section 1230 .
- an apparatus 1300 for forming a wellbore casing in a subterranean formationis then positioned in the new section 1230 of the wellbore 100 .
- the apparatus 1300preferably includes an expandable mandrel or pig 1305 , a tubular member 1310 , a shoe 1315 , a fluid passage 1320 , a fluid passage 1330 , a fluid passage 1335 , seals 1340 , a support member 1345 , and a wiper plug 1350 .
- the expandable mandrel 1305is coupled to and supported by the support member 1345 .
- the expandable mandrel 1305is preferably adapted to controllably expand in a radial direction.
- the expandable mandrel 1305may comprise any number of conventional commercially available expandable mandrels modified in accordance with the teachings of the present disclosure.
- the expandable mandrel 1305comprises a hydraulic expansion tool substantially as disclosed in U.S. Pat. No. 5,348,095, the disclosure of which is incorporated herein by reference, modified in accordance with the teachings of the present disclosure.
- the tubular member 1310is coupled to and supported by the expandable mandrel 1305 .
- the tubular member 1310is preferably expanded in the radial direction and extruded off of the expandable mandrel 1305 .
- the tubular member 1310may be fabricated from any number of materials such as, for example, Oilfield Country Tubular Goods (OCTG), 13 chromium steel tubing/casing or plastic casing.
- OCTGOilfield Country Tubular Goods
- 13 chromium steel tubing/casing or plastic casingIn an exemplary embodiment, the tubular member 1310 is fabricated from OCTG.
- the inner and outer diameters of the tubular member 1310may range, for example, from approximately 0.75 to 47 inches and 1.05 to 48 inches, respectively. In an exemplary embodiment, the inner and outer diameters of the tubular member 1310 range from about 3 to 15.5 inches and 3.5 to 16 inches, respectively in order to optimally provide minimal telescoping effect in the most commonly encountered wellbore sizes.
- the tubular member 1310includes an upper portion 1355 , an intermediate portion 1360 , and a lower portion 1365 .
- the wall thickness and outer diameter of the upper portion 1355 of the tubular member 1310range from about 3 ⁇ 8 to 11 ⁇ 2 inches and 31 ⁇ 2 to 16 inches, respectively.
- the wall thickness and outer diameter of the intermediate portion 1360 of the tubular member 1310range from about 0.625 to 0.75 inches and 3 to 19 inches, respectively.
- the wall thickness and outer diameter of the lower portion 1365 of the tubular member 1310range from about 3 ⁇ 8 to 1.5 inches and 3.5 to 16 inches, respectively.
- the outer diameter of the lower portion 1365 of the tubular member 1310is significantly less than the outer diameters of the upper and intermediate portions, 1355 and 1360 , of the tubular member 1310 in order to optimize the formation of a concentric and overlapping arrangement of wellbore casings. In this manner, as will be described below with reference to FIGS. 12 and 13 , a wellhead system is optimally provided. In an exemplary embodiment, the formation of a wellhead system does not include the use of a hardenable fluidic material.
- the wall thickness of the intermediate section 1360 of the tubular member 1310is less than or equal to the wall thickness of the upper and lower sections, 1355 and 1365 , of the tubular member 1310 in order to optimally facilitate the initiation of the extrusion process and optimally permit the placement of the apparatus in areas of the wellbore having tight clearances.
- the tubular member 1310preferably comprises a solid member.
- the upper end portion 1355 of the tubular member 1310is slotted, perforated, or otherwise modified to catch or slow down the mandrel 1305 when it completes the extrusion of tubular member 1310 .
- the length of the tubular member 1310is limited to minimize the possibility of buckling.
- the length of the tubular member 1310is preferably limited to between about 40 to 20,000 feet in length.
- the shoe 1315is coupled to the tubular member 1310 .
- the shoe 1315preferably includes fluid passages 1330 and 1335 .
- the shoe 1315may comprise any number of conventional commercially available shoes such as, for example, Super Seal II float shoe, Super Seal II Down-Jet float shoe or guide shoe with a sealing sleeve for a latch-down plug modified in accordance with the teachings of the present disclosure.
- the shoe 1315comprises an aluminum down-jet guide shoe with a sealing sleeve for a latch-down plug available from Halliburton Energy Services in Dallas, Tex., modified in accordance with the teachings of the present disclosure, in order to optimally guide the tubular member 1310 into the wellbore 1200 , optimally fluidicly isolate the interior of the tubular member 1310 , and optimally permit the complete drill out of the shoe 1315 upon the completion of the extrusion and cementing operations.
- the shoe 1315further includes one or more side outlet ports in fluidic communication with the fluid passage 1330 .
- the shoe 1315preferably injects hardenable fluidic sealing material into the region outside the shoe 1315 and tubular member 1310 .
- the shoe 1315includes the fluid passage 1330 having an inlet geometry that can receive a fluidic sealing member. In this manner, the fluid passage 1330 can be sealed off by introducing a plug, dart and/or ball sealing elements into the fluid passage 1330 .
- the fluid passage 1320permits fluidic materials to be transported to and from the interior region of the tubular member 1310 below the expandable mandrel 1305 .
- the fluid passage 1320is coupled to and positioned within the support member 1345 and the expandable mandrel 1305 .
- the fluid passage 1320preferably extends from a position adjacent to the surface to the bottom of the expandable mandrel 1305 .
- the fluid passage 1320is preferably positioned along a centerline of the apparatus 1300 .
- the fluid passage 1320is preferably selected to transport materials such as cement, drilling mud, or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally provide sufficient operating pressures to circulate fluids at operationally efficient rates.
- the fluid passage 1330permits fluidic materials to be transported to and from the region exterior to the tubular member 1310 and shoe 1315 .
- the fluid passage 1330is coupled to and positioned within the shoe 1315 in fluidic communication with the interior region 1370 of the tubular member 1310 below the expandable mandrel 1305 .
- the fluid passage 1330preferably has a cross-sectional shape that permits a plug, or other similar device, to be placed in fluid passage 1330 to thereby block further passage of fluidic materials.
- the interior region 1370 of the tubular member 1310 below the expandable mandrel 1305can be fluidicly isolated from the region exterior to the tubular member 1310 . This permits the interior region 1370 of the tubular member 1310 below the expandable mandrel 1305 to be pressurized.
- the fluid passage 1330is preferably positioned substantially along the centerline of the apparatus 1300 .
- the fluid passage 1330is preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the annular region between the tubular member 1310 and the new section 1230 of the wellbore 1200 with fluidic materials.
- the fluid passage 1330includes an inlet geometry that can receive a dart and/or a ball sealing member. In this manner, the fluid passage 1330 can be sealed off by introducing a plug, dart and/or ball sealing elements into the fluid passage 1320 .
- the fluid passage 1335permits fluidic materials to be transported to and from the region exterior to the tubular member 1310 and shoe 1315 .
- the fluid passage 1335is coupled to and positioned within the shoe 1315 in fluidic communication with the fluid passage 1330 .
- the fluid passage 1335is preferably positioned substantially along the centerline of the apparatus 1300 .
- the fluid passage 1335is preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the annular region between the tubular member 1310 and the new section 1230 of the wellbore 1200 with fluidic materials.
- the seals 1340are coupled to and supported by the upper end portion 1355 of the tubular member 1310 .
- the seals 1340are further positioned on an outer surface of the upper end portion 1355 of the tubular member 1310 .
- the seals 1340permit the overlapping joint between the lower end portion of the casing 1215 and the upper portion 1355 of the tubular member 1310 to be fluidicly sealed.
- the seals 1340may comprise any number of conventional commercially available seals such as, for example, lead, rubber, Teflon, or epoxy seals modified in accordance with the teachings of the present disclosure.
- the seals 1340comprise seals molded from Stratalock epoxy available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide a hydraulic seal in the annulus of the overlapping joint while also creating optimal load bearing capability to withstand typical tensile and compressive loads.
- the seals 1340are selected to optimally provide a sufficient frictional force to support the expanded tubular member 1310 from the existing casing 1215 .
- the frictional force provided by the seals 1340ranges from about 1,000 to 1,000,000 lbf in order to optimally support the expanded tubular member 1310 .
- the support member 1345is coupled to the expandable mandrel 1305 , tubular member 1310 , shoe 1315 , and seals 1340 .
- the support member 1345preferably comprises an annular member having sufficient strength to carry the apparatus 1300 into the new section 1230 of the wellbore 1200 .
- the support member 1345further includes one or more conventional centralizers (not illustrated) to help stabilize the tubular member 1310 .
- the support member 1345is thoroughly cleaned prior to assembly to the remaining portions of the apparatus 1300 . In this manner, the introduction of foreign material into the apparatus 1300 is minimized. This minimizes the possibility of foreign material clogging the various flow passages and valves of the apparatus 1300 and to ensure that no foreign material interferes with the expansion process.
- the wiper plug 1350is coupled to the mandrel 1305 within the interior region 1370 of the tubular member 1310 .
- the wiper plug 1350includes a fluid passage 1375 that is coupled to the fluid passage 1320 .
- the wiper plug 1350may comprise one or more conventional commercially available wiper plugs such as, for example, Multiple Stage Cementer latch-down plugs, Omega latch-down plugs or three-wiper latch-down plug modified in accordance with the teachings of the present disclosure.
- the wiper plug 1350comprises a Multiple Stage Cementer latch-down plug available from Halliburton Energy Services in Dallas, Tex. modified in a conventional manner for releasable attachment to the expansion mandrel 1305 .
- a couple of wellbore volumesare circulated in order to ensure that no foreign materials are located within the wellbore 1200 that might clog up the various flow passages and valves of the apparatus 1300 and to ensure that no foreign material interferes with the extrusion process.
- a hardenable fluidic sealing material 1380is then pumped from a surface location into the fluid passage 1320 .
- the material 1380then passes from the fluid passage 1320 , through the fluid passage 1375 , and into the interior region 1370 of the tubular member 1310 below the expandable mandrel 1305 .
- the material 1380then passes from the interior region 1370 into the fluid passage 1330 .
- the material 1380then exits the apparatus 1300 via the fluid passage 1335 and fills the annular region 1390 between the exterior of the tubular member 1310 and the interior wall of the new section 1230 of the wellbore 1200 .
- Continued pumping of the material 1380causes the material 1380 to fill up at least a portion of the annular region 1390 .
- the material 1380may be pumped into the annular region 1390 at pressures and flow rates ranging, for example, from about 0 to 5000 psi and 0 to 1,500 gallons/min, respectively.
- the material 1380is pumped into the annular region 1390 at pressures and flow rates ranging from about 0 to 5000 psi and 0 to 1,500 gallons/min, respectively, in order to optimally fill the annular region between the tubular member 1310 and the new section 1230 of the wellbore 1200 with the hardenable fluidic sealing material 1380 .
- the hardenable fluidic sealing material 1380may comprise any number of conventional commercially available hardenable fluidic sealing materials such as, for example, slag mix, cement or epoxy.
- the hardenable fluidic sealing material 1380comprises blended cements designed specifically for the well section being drilled and available from Halliburton Energy Services in order to optimally provide support for the tubular member 1310 during displacement of the material 1380 in the annular region 1390 .
- the optimum blend of the cementis preferably determined using conventional empirical methods.
- the annular region 1390preferably is filled with the material 1380 in sufficient quantities to ensure that, upon radial expansion of the tubular member 1310 , the annular region 1390 of the new section 1230 of the wellbore 1200 will be filled with material 1380 .
- a wiper dart 1395is introduced into the fluid passage 1320 .
- the wiper dart 1395is preferably pumped through the fluid passage 1320 by a non hardenable fluidic material 1381 .
- the wiper dart 1395then preferably engages the wiper plug 1350 .
- engagement of the wiper dart 1395 with the wiper plug 1350causes the wiper plug 1350 to decouple from the mandrel 1305 .
- the wiper dart 1395 and wiper plug 1350then preferably will lodge in the fluid passage 1330 , thereby blocking fluid flow through the fluid passage 1330 , and fluidicly isolating the interior region 1370 of the tubular member 1310 from the annular region 1390 .
- the non hardenable fluidic material 1381is then pumped into the interior region 1370 causing the interior region 1370 to pressurize.
- the tubular member 1310is extruded off of the expandable mandrel 1305 .
- the expandable mandrel 1305is raised out of the expanded portion of the tubular member 1310 by the support member 1345 .
- the wiper dart 1395is preferably placed into the fluid passage 1320 by introducing the wiper dart 1395 into the fluid passage 1320 at a surface location in a conventional manner.
- the wiper dart 1395may comprise any number of conventional commercially available devices from plugging a fluid passage such as, for example, Multiple Stage Cementer latch-down plugs, Omega latch-down plugs or three wiper latch-down plug/dart modified in accordance with the teachings of the present disclosure.
- the wiper dart 1395comprises a three wiper latch-down plug modified to latch and seal in the Multiple Stage Cementer latch down plug 1350 .
- the three wiper latch-down plugis available from Halliburton Energy Services in Dallas, Tex.
- the non hardenable fluidic material 1381may be pumped into the interior region 1370 at pressures and flow rates ranging, for example, from approximately 0 to 5000 psi and 0 to 1,500 gallons/min in order to optimally extrude the tubular member 1310 off of the mandrel 1305 . In this manner, the amount of hardenable fluidic material within the interior of the tubular member 1310 is minimized.
- the non hardenable fluidic material 1381is preferably pumped into the interior region 1370 at pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to 3,000 gallons/min in order to optimally provide operating pressures to maintain the expansion process at rates sufficient to permit adjustments to be made in operating parameters during the extrusion process.
- the extrusion of the tubular member 1310 off of the expandable mandrel 1305will begin when the pressure of the interior region 1370 reaches, for example, approximately 500 to 9,000 psi.
- the extrusion of the tubular member 1310 off of the expandable mandrel 1305is a function of the tubular member diameter, wall thickness of the tubular member, geometry of the mandrel, the type of lubricant, the composition of the shoe and tubular member, and the yield strength of the tubular member.
- the optimum flow rate and operating pressuresare preferably determined using conventional empirical methods.
- the expandable mandrel 1305may be raised out of the expanded portion of the tubular member 1310 at rates ranging, for example, from about 0 to 5 ft/sec. In an exemplary embodiment, during the extrusion process, the expandable mandrel 1305 is raised out of the expanded portion of the tubular member 1310 at rates ranging from about 0 to 2 ft/sec in order to optimally provide an efficient process, optimally permit operator adjustment of operation parameters, and ensure optimal completion of the extrusion process before curing of the material 1380 .
- the outer surface of the upper end portion 1355 of the tubular member 1310will preferably contact the interior surface of the lower end portion of the casing 1215 to form an fluid tight overlapping joint.
- the contact pressure of the overlapping jointmay range, for example, from approximately 50 to 20,000 psi. In an exemplary embodiment, the contact pressure of the overlapping joint ranges from approximately 400 to 10,000 psi in order to optimally provide contact pressure sufficient to ensure annular sealing and provide enough resistance to withstand typical tensile and compressive loads. In an exemplary embodiment, the sealing members 1340 will ensure an adequate fluidic and gaseous seal in the overlapping joint.
- the operating pressure and flow rate of the non hardenable fluidic material 1381is controllably ramped down when the expandable mandrel 1305 reaches the upper end portion 1355 of the tubular member 1310 . In this manner, the sudden release of pressure caused by the complete extrusion of the tubular member 1310 off of the expandable mandrel 1305 can be minimized.
- the operating pressureis reduced in a substantially linear fashion from 100% to about 10% during the end of the extrusion process beginning when the mandrel 1305 has completed approximately all but about 5 feet of the extrusion process.
- a shock absorberis provided in the support member 1345 in order to absorb the shock caused by the sudden release of pressure.
- a mandrel catching structureis provided in the upper end portion 1355 of the tubular member 1310 in order to catch or at least decelerate the mandrel 1305 .
- the expandable mandrel 1305is removed from the wellbore 1200 .
- the integrity of the fluidic seal of the overlapping joint between the upper portion 1355 of the tubular member 1310 and the lower portion of the casing 1215is tested using conventional methods. If the fluidic seal of the overlapping joint between the upper portion 1355 of the tubular member 1310 and the lower portion of the casing 1215 is satisfactory, then the uncured portion of the material 1380 within the expanded tubular member 1310 is then removed in a conventional manner. The material 1380 within the annular region 1390 is then allowed to cure.
- any remaining cured material 1380 within the interior of the expanded tubular member 1310is then removed in a conventional manner using a conventional drill string.
- the resulting new section of casing 1400includes the expanded tubular member 1310 and an outer annular layer 1405 of cured material 305 .
- the bottom portion of the apparatus 1300 comprising the shoe 1315may then be removed by drilling out the shoe 1315 using conventional drilling methods.
- the wellhead system 1500preferably includes a conventional Christmas tree/drilling spool assembly 1505 , a thick wall casing 1510 , an annular body of cement 1515 , an outer casing 1520 , an annular body of cement 1525 , an intermediate casing 1530 , and an inner casing 1535 .
- the Christmas tree/drilling spool assembly 1505may comprise any number of conventional Christmas tree/drilling spool assemblies such as, for example, the SS-15 Subsea Wellhead System, Spool Tree Subsea Production System or the Compact Wellhead System available from suppliers such as Dril-Quip, Cameron or Breda, modified in accordance with the teachings of the present disclosure.
- the drilling spool assembly 1505is preferably operably coupled to the thick wall casing 1510 and/or the outer casing 1520 .
- the assembly 1505may be coupled to the thick wall casing 1510 and/or outer casing 1520 , for example, by welding, a threaded connection or made from single stock.
- the assembly 1505is coupled to the thick wall casing 1510 and/or outer casing 1520 by welding.
- the thick wall casing 1510is positioned in the upper end of a wellbore 1540 . In an exemplary embodiment, at least a portion of the thick wall casing 1510 extends above the surface 1545 in order to optimally provide easy access and attachment to the Christmas tree/drilling spool assembly 1505 .
- the thick wall casing 1510is preferably coupled to the Christmas tree/drilling spool assembly 1505 , the annular body of cement 1515 , and the outer casing 1520 .
- the thick wall casing 1510may comprise any number of conventional commercially available high strength wellbore casings such as, for example, Oilfield Country Tubular Goods, titanium tubing or stainless steel tubing.
- the thick wall casing 1510comprises Oilfield Country Tubular Goods available from various foreign and domestic steel mills.
- the thick wall casing 1510has a yield strength of about 40,000 to 135,000 psi in order to optimally provide maximum burst, collapse, and tensile strengths.
- the thick wall casing 1510has a failure strength in excess of about 5,000 to 20,000 psi in order to optimally provide maximum operating capacity and resistance to degradation of capacity after being drilled through for an extended time period.
- the annular body of cement 1515provides support for the thick wall casing 1510 .
- the annular body of cement 1515may be provided using any number of conventional processes for forming an annular body of cement in a wellbore.
- the annular body of cement 1515may comprise any number of conventional cement mixtures.
- the outer casing 1520is coupled to the thick wall casing 1510 .
- the outer casing 1520may be fabricated from any number of conventional commercially available tubular members modified in accordance with the teachings of the present disclosure.
- the outer casing 1520comprises any one of the expandable tubular members described above with reference to FIGS. 1-11 f.
- the outer casing 1520is coupled to the thick wall casing 1510 by expanding the outer casing 1520 into contact with at least a portion of the interior surface of the thick wall casing 1510 using any one of the embodiments of the processes and apparatus described above with reference to FIGS. 1-11 f.
- the contact pressure of the interface between the outer casing 1520 and the thick wall casing 1510may range, for example, from about 500 to 10,000 psi. In an exemplary embodiment, the contact pressure between the outer casing 1520 and the thick wall casing 1510 ranges from about 500 to 10,000 psi in order to optimally activate the pressure activated sealing members and to ensure that the overlapping joint will optimally withstand typical extremes of tensile and compressive loads that are experienced during drilling and production operations.
- the upper end of the outer casing 1520includes one or more sealing members 1550 that provide a gaseous and fluidic seal between the expanded outer casing 1520 and the interior wall of the thick wall casing 1510 .
- the sealing members 1550may comprise any number of conventional commercially available seals such as, for example, lead, plastic, rubber, Teflon or epoxy, modified in accordance with the teachings of the present disclosure.
- the sealing members 1550comprise seals molded from StrataLock epoxy available from Halliburton Energy Services in order to optimally provide an hydraulic seal and a load bearing interference fit between the tubular members.
- the contact pressure of the interface between the thick wall casing 1510 and the outer casing 1520ranges from about 500 to 10,000 psi in order to optimally activate the sealing members 1550 and also optimally ensure that the joint will withstand the typical operating extremes of tensile and compressive loads during drilling and production operations.
- the outer casing 1520 and the thick walled casing 1510are combined in one unitary member.
- the annular body of cement 1525provides support for the outer casing 1520 .
- the annular body of cement 1525is provided using any one of the embodiments of the apparatus and processes described above with reference to FIGS. 1-11 f.
- the intermediate casing 1530may be coupled to the outer casing 1520 or the thick wall casing 1510 . In an exemplary embodiment, the intermediate casing 1530 is coupled to the thick wall casing 1510 .
- the intermediate casing 1530may be fabricated from any number of conventional commercially available tubular members modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, the intermediate casing 1530 comprises any one of the expandable tubular members described above with reference to FIGS. 1-11 f.
- the intermediate casing 1530is coupled to the thick wall casing 1510 by expanding at least a portion of the intermediate casing 1530 into contact with the interior surface of the thick wall casing 1510 using any one of the processes and apparatus described above with reference to FIGS. 1-11 f.
- the entire length of the overlap of the intermediate casing 1530 with the thick wall casing 1510contacts the inner surface of the thick wall casing 1510 .
- the contact pressure of the interface between the intermediate casing 1530 and the thick wall casing 1510may range, for example from about 500 to 10,000 psi.
- the contact pressure between the intermediate casing 1530 and the thick wall casing 1510ranges from about 500 to 10,000 psi in order to optimally activate the pressure activated sealing members and to optimally ensure that the joint will withstand typical operating extremes of tensile and compressive loads experienced during drilling and production operations.
- the upper end of the intermediate casing 1530includes one or more sealing members 1560 that provide a gaseous and fluidic seal between the expanded end of the intermediate casing 1530 and the interior wall of the thick wall casing 1510 .
- the sealing members 1560may comprise any number of conventional commercially available seals such as, for example, plastic, lead, rubber, Teflon or epoxy, modified in accordance with the teachings of the present disclosure.
- the sealing members 1560comprise seals molded from StrataLock epoxy available from Halliburton Energy Services in order to optimally provide a hydraulic seal and a load bearing interference fit between the tubular members.
- the contact pressure of the interface between the expanded end of the intermediate casing 1530 and the thick wall casing 1510ranges from about 500 to 10,000 psi in order to optimally activate the sealing members 1560 and also optimally ensure that the joint will withstand typical operating extremes of tensile and compressive loads that are experienced during drilling and production operations.
- the inner casing 1535may be coupled to the outer casing 1520 or the thick wall casing 1510 . In an exemplary embodiment, the inner casing 1535 is coupled to the thick wall casing 1510 .
- the inner casing 1535may be fabricated from any number of conventional commercially available tubular members modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, the inner casing 1535 comprises any one of the expandable tubular members described above with reference to FIGS. 1-11 f.
- the inner casing 1535is coupled to the outer casing 1520 by expanding at least a portion of the inner casing 1535 into contact with the interior surface of the thick wall casing 1510 using any one of the processes and apparatus described above with reference to FIGS. 1-11 f.
- the entire length of the overlap of the inner casing 1535 with the thick wall casing 1510 and intermediate casing 1530contacts the inner surfaces of the thick wall casing 1510 and intermediate casing 1530 .
- the contact pressure of the interface between the inner casing 1535 and the thick wall casing 1510may range, for example from about 500 to 10,000 psi.
- the contact pressure between the inner casing 1535 and the thick wall casing 1510ranges from about 500 to 10,000 psi in order to optimally activate the pressure activated sealing members and to ensure that the joint will withstand typical extremes of tensile and compressive loads that are commonly experienced during drilling and production operations.
- the upper end of the inner easing 1535includes one or more sealing members 1570 that provide a gaseous and fluidic seal between the expanded end of the inner casing 1535 and the interior wall of the thick wall casing 1510 .
- the sealing members 1570may comprise any number of conventional commercially available seals such as, for example, lead, plastic, rubber, Teflon or epoxy, modified in accordance with the teachings of the present disclosure.
- the sealing members 1570comprise seals molded from StrataLock epoxy available from Halliburton Energy Services in order to optimally provide an hydraulic seal and a load bearing interference fit.
- the contact pressure of the interface between the expanded end of the inner casing 1535 and the thick wall casing 1510ranges from about 500 to 10,000 psi in order to optimally activate the sealing members 1570 and also to optimally ensure that the joint will withstand typical operating extremes of tensile and compressive loads that are experienced during drilling and production operations.
- the inner casings, 1520 , 1530 and 1535may be coupled to a previously positioned tubular member that is in turn coupled to the outer casing 1510 . More generally, the exemplary embodiments may be used to form a concentric arrangement of tubular members.
- FIGS. 14 a, 14 b, 14 c, 14 d, 14 e and 14 fan exemplary embodiment of a method and apparatus for forming a mono-diameter well casing within a subterranean formation will now be described.
- a wellbore 1600is positioned in a subterranean formation 1605 .
- a first section of casing 1610is formed in the wellbore 1600 .
- the first section of casing 1610includes an annular outer body of cement 1615 and a tubular section of casing 1620 .
- the first section of casing 1610may be formed in the wellbore 1600 using conventional methods and apparatus.
- the first section of casing 1610is formed using one or more of the methods and apparatus described above with reference to FIGS. 1-13 or below with reference to FIGS. 14 b - 17 b.
- the annular body of cement 1615may comprise any number of conventional commercially available cement, or other load bearing, compositions. Alternatively, the body of cement 1615 may be omitted or replaced with an epoxy mixture.
- the tubular section of casing 1620preferably includes an upper end 1625 and a lower end 1630 .
- the lower end 1625 of the tubular section of casing 1620includes an outer annular recess 1635 extending from the lower end 1630 of the tubular section of casing 1620 .
- the lower end 1625 of the tubular section of casing 1620includes a thin walled section 1640 .
- an annular body 1645 of a compressible materialis coupled to and at least partially positioned within the outer annular recess 1635 . In this manner, the body of compressible material 1645 surrounds at least a portion of the thin walled section 1640 .
- the tubular section of casing 1620may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, automotive grade steel, carbon steel, low alloy steel, fiberglass or plastics. In an exemplary embodiment, the tubular section of casing 1620 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills.
- the wall thickness of the thin walled section 1640may range from about 0.125 to 1.5 inches. In an exemplary embodiment, the wall thickness of the thin walled section 1640 ranges from 0.25 to 1.0 inches in order to optimally provide burst strength for typical operational conditions while also minimizing resistance to radial expansion.
- the axial length of the thin walled section 1640may range from about 120 to 2400 inches. In an exemplary embodiment, the axial length of the thin walled section 1640 ranges from about 240 to 480 inches.
- the annular body of compressible material 1645helps to minimize the radial force required to expand the tubular casing 1620 in the overlap with the tubular member 1715 , helps to create a fluidic seal in the overlap with the tubular member 1715 , and helps to create an interference fit sufficient to permit the tubular member 1715 to be supported by the tubular casing 1620 .
- the annular body of compressible material 1645may comprise any number of commercially available compressible materials such as, for example, epoxy, rubber, Teflon, plastics or lead tubes.
- the annular body of compressible material 1645comprises StrataLock epoxy available from Halliburton Energy Services in order to optimally provide an hydraulic seal in the overlapped joint while also having compliance to thereby minimize the radial force required to expand the tubular casing.
- the wall thickness of the annular body of compressible material 1645may range from about 0.05 to 0.75 inches. In an exemplary embodiment, the wall thickness of the annular body of compressible material 1645 ranges from about 0.1 to 0.5 inches in order to optimally provide a large compressible zone, minimize the radial forces required to expand the tubular casing, provide thickness for casing strings to provide contact with the inner surface of the wellbore upon radial expansion, and provide an hydraulic seal.
- a drill stringis used in a well known manner to drill out material from the subterranean formation 1605 to form a new wellbore section 1650 .
- the diameter of the new section 1650is preferably equal to or greater than the inner diameter of the tubular section of casing 1620 .
- an exemplary embodiment of an apparatus 1700 for forming a mono-diameter wellbore casing in a subterranean formationis then positioned in the new section 1650 of the wellbore 1600 .
- the apparatus 1700preferably includes a support member 1705 , an expandable mandrel or pig 1710 , a tubular member 1715 , a shoe 1720 , slips 1725 , a fluid passage 1730 , one or more fluid passages 1735 , a fluid passage 1740 , a first compressible annular body 1745 , a second compressible annular body 1750 , and a pressure chamber 1755 .
- the support member 1705supports the apparatus 1700 within the wellbore 1600 .
- the support member 1705is coupled to the mandrel 1710 , the tubular member 1715 , the shoe 1720 , and the slips 1725 .
- the support member 1075preferably comprises a substantially hollow tubular member.
- the fluid passage 1730is positioned within the support member 1705 .
- the fluid passages 1735fluidicly couple the fluid passage 1730 with the pressure chamber 1755 .
- the fluid passage 1740fluidicly couples the fluid passage 1730 with the region outside of the apparatus 1700 .
- the support member 1705may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, low alloy steel, carbon steel, 13 chromium steel, fiberglass, or other high strength materials.
- the support member 1705is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide operational strength and facilitate the use of other standard oil exploration handling equipment.
- at least a portion of the support member 1705comprises coiled tubing or a drill pipe.
- the support member 1705includes a load shoulder 1820 for supporting the mandrel 1710 when the pressure chamber 1755 is unpressurized.
- the mandrel 1710is supported by and slidingly coupled to the support member 1705 and the shoe 1720 .
- the mandrel 1710preferably includes an upper portion 1760 and a lower portion 1765 .
- the upper portion 1760 of the mandrel 1710 and the support member 1705together define the pressure chamber 1755 .
- the lower portion 1765 of the mandrel 1710includes an expansion member 1770 for radially expanding the tubular member 1715 .
- the upper portion 1760 of the mandrel 1710includes a tubular member 1775 having an inner diameter greater than an outer diameter of the support member 1705 .
- an annular pressure chamber 1755is defined by and positioned between the tubular member 1775 and the support member 1705 .
- the top 1780 of the tubular member 1775preferably includes a bearing and a seal for sealing and supporting the top 1780 of the tubular member 1775 against the outer surface of the support member 1705 .
- the bottom 1785 of the tubular member 1775preferably includes a bearing and seal for sealing and supporting the bottom 1785 of the tubular member 1775 against the outer surface of the support member 1705 or shoe 1720 . In this manner, the mandrel 1710 moves in an axial direction upon the pressurization of the pressure chamber 1755 .
- the lower portion 1765 of the mandrel 1710preferably includes an expansion member 1770 for radially expanding the tubular member 1715 during the pressurization of the pressure chamber 1755 .
- the expansion memberis expandable in the radial direction.
- the inner surface of the lower portion 1765 of the mandrel 1710mates with and slides with respect to the outer surface of the shoe 1720 .
- the outer diameter of the expansion member 1770may range from about 90 to 100% of the inner diameter of the tubular casing 1620 .
- the outer diameter of the expansion member 1770ranges from about 95 to 99% of the inner diameter of the tubular casing 1620 .
- the expansion member 1770may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, ceramics, tungsten carbide, titanium or other high strength alloys.
- the expansion member 1770is fabricated from D2 machine tool steel in order to optimally provide high strength and abrasion resistance.
- the tubular member 1715is coupled to and supported by the support member 1705 and slips 1725 .
- the tubular member 1715includes an upper portion 1790 and a lower portion 1795 .
- the upper portion 1790 of the tubular member 1715preferably includes an inner annular recess 1800 that extends from the upper portion 1790 of the tubular member 1715 .
- at least a portion of the upper portion 1790 of the tubular member 1715includes a thin walled section 1805 .
- the first compressible annular member 1745is preferably coupled to and supported by the outer surface of the upper portion 1790 of the tubular member 1715 in opposing relation to the thin wall section 1805 .
- the lower portion 1795 of the tubular member 1715preferably includes an outer annular recess 1810 that extends from the lower portion 1790 of the tubular member 1715 .
- at least a portion of the lower portion 1795 of the tubular member 1715includes a thin walled section 1815 .
- the second compressible annular member 1750is coupled to and at least partially supported within the outer annular recess 1810 of the upper portion 1790 of the tubular member 1715 in opposing relation to the thin wall section 1815 .
- the tubular member 1715may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, low alloy steel, carbon steel, automotive grade steel, fiberglass, 13 chrome steel, other high strength material, or high strength plastics.
- the tubular member 1715is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide operational strength.
- the shoe 1720is supported by and coupled to the support member 1705 .
- the shoe 1720preferably comprises a substantially hollow tubular member.
- the wall thickness of the shoe 1720is greater than the wall thickness of the support member 1705 in order to optimally provide increased radial support to the mandrel 1710 .
- the shoe 1720may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, automotive grade steel, low alloy steel, carbon steel, or high strength plastics.
- the shoe 1720is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide matching operational strength throughout the apparatus.
- the slips 1725are coupled to and supported by the support member 1705 .
- the slips 1725removably support the tubular member 1715 . In this manner, during the radial expansion of the tubular member 1715 , the slips 1725 help to maintain the tubular member 1715 in a substantially stationary position by preventing upward movement of the tubular member 1715 .
- the slips 1725may comprise any number of conventional commercially available slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips, or Model 3L retrievable bridge plug tungsten carbide upper mechanical slips.
- the slips 1725comprise RTTS packer tungsten carbide mechanical slips available from Halliburton Energy Services.
- the slips 1725are adapted to support axial forces ranging from about 0 to 750,000 lbf.
- the fluid passage 1730conveys fluidic materials from a surface location into the interior of the support member 1705 , the pressure chamber 1755 , and the region exterior of the apparatus 1700 .
- the fluid passage 1730is fluidicly coupled to the pressure chamber 1755 by the fluid passages 1735 .
- the fluid passage 1730is fluidicly coupled to the region exterior to the apparatus 1700 by the fluid passage 1740 .
- the fluid passage 1730is adapted to convey fluidic materials such as, for example, cement, epoxy, drilling muds, slag mix, water or drilling gasses.
- the fluid passage 1730is adapted to convey fluidic materials at flow rate and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi. In order to optimally provide flow rates and operational pressures for the radial expansion processes.
- the fluid passages 1735convey fluidic material from the fluid passage 1730 to the pressure chamber 1755 .
- the fluid passage 1735is adapted to convey fluidic materials such as, for example, cement, epoxy, drilling muds, water or drilling gasses.
- the fluid passage 1735is adapted to convey fluidic materials at flow rate and pressures ranging from about 0 to 500 gallons/minute and 0 to 9,000 psi. in order to optimally provide operating pressures and flow rates for the various expansion processes.
- the fluid passage 1740conveys fluidic materials from the fluid passage 1730 to the region exterior to the apparatus 1700 .
- the fluid passage 1740is adapted to convey fluidic materials such as, for example, cement, epoxy, drilling muds, water or drilling gasses.
- the fluid passage 1740is adapted to convey fluidic materials at flow rate and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi. in order to optimally provide operating pressures and flow rates for the various radial expansion processes.
- the fluid passage 1740is adapted to receive a plug or other similar device for sealing the fluid passage 1740 .
- the pressure chamber 1755may be pressurized.
- the first compressible annular body 1745is coupled to and supported by an exterior surface of the upper portion 1790 of the tubular member 1715 .
- the first compressible annular body 1745is positioned in opposing relation to the thin walled section 1805 of the tubular member 1715 .
- the first compressible annular body 1745helps to minimize the radial force required to expand the tubular member 1715 in the overlap with the tubular casing 1620 , helps to create a fluidic seal in the overlap with the tubular casing 1620 , and helps to create an interference fit sufficient to permit the tubular member 1715 to be supported by the tubular casing 1620 .
- the first compressible annular body 1745may comprise any number of commercially available compressible materials such as, for example, epoxy, rubber, Teflon, plastics, or hollow lead tubes.
- the first compressible annular body 1745comprises StrataLock epoxy available from Halliburton Energy Services in order to optimally provide an hydraulic seal, and compressibility to minimize the radial expansion force.
- the wall thickness of the first compressible annular body 1745may range from about 0.05 to 0.75 inches. In an exemplary embodiment, the wall thickness of the first compressible annular body 1745 ranges from about 0.1 to 0.5 inches in order to optimally (1) provide a large compressible zone, (2) minimize the required radial expansion force, (3) transfer the radial force to the tubular casings. As a result, in an exemplary embodiment, overall the outer diameter of the tabular member 1715 is approximately equal to the overall inner diameter of the tubular member 1620 .
- the second compressible annular body 1750is coupled to and at least partially supported within the outer annular recess 1810 of the tubular member 1715 .
- the second compressible annular body 1750is positioned in opposing relation to the thin walled section 1815 of the tubular member 1715 .
- the second compressible annular body 1750helps to minimize the radial force required to expand the tubular member 1715 in the overlap with another tubular member, helps to create a fluidic seal in the overlap of the tubular member 1715 with another tubular member, and helps to create an interference fit sufficient to permit another tubular member to be supported by the tubular member 1715 .
- the second compressible annular body 1750may comprise any number of commercially available compressible materials such as, for example, epoxy, rubber, Teflon, plastics or hollow lead tubing.
- the first compressible annular body 1750comprises StrataLock epoxy available from Halliburton Energy Services in order to optimally provide an hydraulic seal in the overlapped joint, and compressibility that minimizes the radial expansion force.
- the wall thickness of the second compressible annular body 1750may range from about 0.05 to 0.75 inches. In an exemplary embodiment, the wall thickness of the second compressible annular body 1750 ranges from about 0.1 to 0.5 inches in order to optimally provide a large compressible zone, and minimize the radial force required to expand the tubular member 1715 during subsequent radial expansion operations.
- the outside diameter of the second compressible annular body 1750is adapted to provide a seal against the surrounding formation thereby eliminating the need for an outer annular body of cement.
- the pressure chamber 1755is fluidicly coupled to the fluid passage 1730 by the fluid passages 1735 .
- the pressure chamber 1755is preferably adapted to receive fluidic materials such as, for example, drilling muds, water or drilling gases.
- the pressure chamber 1755is adapted to receive fluidic materials at flow rate and pressures ranging from about 0 to 500 gallons/minute and 0 to 9,000 psi. in order to optimally provide expansion pressure.
- the operating pressure of the pressure chamberranges from about 0 to 5,000 psi in order to optimally provide expansion pressure while minimizing the possibility of a catastrophic failure due to over pressurization.
- the apparatus 1700is preferably positioned in the wellbore 1600 with the tubular member 1715 positioned in an overlapping relationship with the tubular casing 1620 .
- the thin wall sections, 1640 and 1805 , of the tubular casing 1620 and tubular member 1725are positioned in opposing overlapping relation. In this manner, the radial expansion of the tubular member 1725 will compress the thin wall sections, 1640 and 1605 , and annular compressible members, 1645 and 1745 , into intimate contact.
- a fluidic material 1825is then pumped into the fluid passage 1730 .
- the fluidic material 1825may comprise any number of conventional commercially available materials such as, for example, water, drilling mud, drilling gases, cement or epoxy.
- the fluidic material 1825comprises a hardenable fluidic sealing material such as, for example, cement in order to provide an outer annular body around the expanded tubular member 1715 .
- the fluidic material 1825may be pumped into the fluid passage 1730 at operating pressures and flow rates, for example, ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the fluidic material 1825 pumped into the fluid passage 1730passes through the fluid passage 1740 and outside of the apparatus 1700 .
- the fluidic material 1825fills the annular region 1830 between the outside of the apparatus 1700 and the interior walls of the wellbore 1600 .
- a plug 1835is then introduced into the fluid passage 1730 .
- the plug 1835lodges in the inlet to the fluid passage 1740 fluidicly isolating and blocking off the fluid passage 1730 .
- a fluidic material 1840is then pumped into the fluid passage 1730 .
- the fluidic material 1840may comprise any number of conventional commercially available materials such as, for example, water, drilling mud or drilling gases.
- the fluidic material 1825comprises a non-hardenable fluidic material such as, for example, drilling mud or drilling gases in order to optimally provide pressurization of the pressure chamber 1755 .
- the fluidic material 1840may be pumped into the fluid passage 1730 at operating pressures and flow rates ranging, for example, from about 0 to 9,000 psi and 0 to 500 gallons/minute. In an exemplary embodiment, the fluidic material 1840 is pumped into the fluid passage 1730 at operating pressures and flow rates ranging from about 500 to 5,000 psi and 0 to 500 gallons/minute in order to optimally provide operating pressures and flow rates for radial expansion.
- the fluidic material 1840 pumped into the fluid passage 1730passes through the fluid passages 1735 and into the pressure chamber 1755 .
- Continued pumping of the fluidic material 1840pressurizes the pressure chamber 1755 .
- the pressurization of the pressure chamber 1755causes the mandrel 1710 to move relative to the support member 1705 in the direction indicated by the arrows 1845 . In this manner, the mandrel 1710 will cause the tubular member 1715 to expand in the radial direction.
- the tubular member 1715is prevented from moving in an upward direction by the slips 1725 .
- a length of the tubular member 1715is then expanded in the radial direction through the pressurization of the pressure chamber 1755 .
- the length of the tubular member 1715 that is expanded during the expansion processwill be proportional to the stroke length of the mandrel 1710 .
- the operating pressure of the pressure chamber 1755is then reduced and the mandrel 1710 drops to it rest position with the tubular member 1715 supported by the mandrel 1715 .
- the position of the support member 1705may be adjusted throughout the radial expansion process in order to maintain the overlapping relationship between the thin walled sections, 1640 and 1805 , of the tubular casing 1620 and tubular member 1715 .
- the stroking of the mandrel 1710is then repeated, as necessary, until the thin walled section 1805 of the tubular member 1715 is expanded into the thin walled section 1640 of the tubular casing 1620 .
- the slips 1725are positioned as close as possible to the thin walled section 1805 of the tubular member 1715 in order minimize slippage between the tubular member 1715 and tubular casing 1620 at the end of the radial expansion process.
- the outside diameter of the first compressive annular member 1745is selected to ensure sufficient interference fit with the tubular casing 1620 to prevent axial displacement of the tubular member 1715 during the final stroke.
- the outside diameter of the second compressive annular body 1750is large enough to provide an interference fit with the inside walls of the wellbore 1600 at an earlier point in the radial expansion process so as to prevent further axial displacement of the tubular member 1715 .
- the interference fitis preferably selected to permit expansion of the tubular member 1715 by pulling the mandrel 1710 out of the wellbore 1600 , without having to pressurize the pressure chamber 1755 .
- the pressurized areas of the apparatus 1700are limited to the fluid passages 1730 within the support member 1705 and the pressure chamber 1755 within the mandrel 1710 .
- No fluid pressureacts directly on the tubular member 1715 . This permits the use of operating pressures higher than the tubular member 1715 could normally withstand.
- the support member 1705 and mandrel 1710are removed from the wellbore 1600 .
- the contact pressure between the deformed thin wall sections, 1640 and 1805 , and compressible annular members, 1645 and 1745ranges from about 400 to 10,000 psi in order to optimally support the tubular member 1715 using the tubular casing 1620 .
- tubular member 1715is radially expanded into contact with the tubular casing 1620 by pressurizing the interior of the fluid passage 1730 and the pressure chamber 1755 .
- the support member 1705 and mandrel 1710are removed from the wellbore 1600 .
- the annular body of hardenable fluidic materialis then allowed to cure to form a rigid outer annular body 1850 .
- the hardenable fluidic materialwill preferably permeate and envelop the expanded tubular member 1715 .
- the resulting new section of wellbore casing 1855includes the expanded tubular member 1715 and the rigid outer annular body 1850 .
- the overlapping joint 1860 between the tubular casing 1620 and the expanded tubular member 1715includes the deformed thin wall sections, 1640 and 1805 , and the compressible annular bodies, 1645 and 1745 .
- the inner diameter of the resulting combined wellbore casingsis substantially constant. In this manner, a mono-diameter wellbore casing is formed. This process of expanding overlapping tubular members having thin wall end portions with compressible annular bodies into contact can be repeated for the entire length of a wellbore. In this manner, a mono-diameter wellbore casing can be provided for thousands of feet in a subterranean formation.
- the apparatus 1900preferably includes a drillpipe 1905 , an innerstring adapter 1910 , a sealing sleeve 1915 , an inner sealing mandrel 1920 , an upper sealing head 1925 , a lower sealing head 1930 , an outer sealing mandrel 1935 , a load mandrel 1940 , an expansion cone 1945 , a mandrel launcher 1950 , a mechanical slip body 1955 , mechanical slips 1960 , drag blocks 1965 , casing 1970 , and fluid passages 1975 , 1980 , 1985 , and 1990 .
- the drillpipe 1905is coupled to the innerstring adapter 1910 .
- the drillpipe 1905supports the apparatus 1900 .
- the drillpipe 1905preferably comprises a substantially hollow tubular member or members.
- the drillpipe 1905may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular drillpipe, fiberglass or coiled tubing.
- the drillpipe 1905is fabricated from coiled tubing in order to facilitate the placement of the apparatus 1900 in non-vertical wellbores.
- the drillpipe 1905may be coupled to the innerstring adapter 1910 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connectors, OCTG specialty type box and pin connectors, a ratchet-latch type connector or a standard box by pin connector.
- the drillpipe 1905is removably coupled to the innerstring adapter 1910 by a drillpipe connection.
- the drillpipe 1905preferably includes a fluid passage 1975 that is adapted to convey fluidic materials from a surface location into the fluid passage 1980 .
- the fluid passage 1975is adapted to convey fluidic materials such as, for example, cement, drilling mud, epoxy or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the innerstring adapter 1910is coupled to the drill string 1905 and the sealing sleeve 1915 .
- the innerstring adapter 1910preferably comprises a substantially hollow tubular member or members.
- the innerstring adapter 1910may be fabricated from any number of conventional commercially available materials such as, for example, oil country tubular goods, low alloy steel, carbon steel, stainless steel or other high strength materials.
- the innerstring adapter 1910is fabricated from oilfield country tubular goods in order to optimally provide mechanical properties that closely match those of the drill string 1905 .
- the innerstring adapter 1910may be coupled to the drill string 1905 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connectors, oilfield country tubular goods specialty type threaded connectors, ratchet-latch type stab in connector, or a standard threaded connection.
- the innerstring adapter 1910is removably coupled to the drill pipe 1905 by a drillpipe connection.
- the innerstring adapter 1910may be coupled to the sealing sleeve 1915 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connector, ratchet-latch type stab in connectors, or a standard threaded connection.
- the innerstring adapter 1910is removably coupled to the sealing sleeve 1915 by a standard threaded connection.
- the innerstring adapter 1910preferably includes a fluid passage 1980 that is adapted to convey fluidic materials from the fluid passage 1975 into the fluid passage 1985 .
- the fluid passage 1980is adapted to convey fluidic materials such as, for example, cement, drilling mud, epoxy, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the sealing sleeve 1915is coupled to the innerstring adapter 1910 and the inner sealing mandrel 1920 .
- the sealing sleeve 1915preferably comprises a substantially hollow tubular member or members.
- the sealing sleeve 1915may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, carbon steel, low alloy steel, stainless steel or other high strength materials.
- the sealing sleeve 1915is fabricated from oilfield country tubular goods in order to optimally provide mechanical properties that substantially match the remaining components of the apparatus 1900 .
- the sealing sleeve 1915may be coupled to the innerstring adapter 1910 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type stab in connection, or a standard threaded connection.
- the sealing sleeve 1915is removably coupled to the innerstring adapter 1910 by a standard threaded connection.
- the sealing sleeve 1915may be coupled to the inner sealing mandrel 1920 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the sealing sleeve 1915is removably coupled to the inner sealing mandrel 1920 by a standard threaded connection.
- the sealing sleeve 1915preferably includes a fluid passage 1985 that is adapted to convey fluidic materials from the fluid passage 1980 into the fluid passage 1990 .
- the fluid passage 1985is adapted to convey fluidic materials such as, for example, cement, drilling mud, epoxy or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the inner sealing mandrel 1920is coupled to the sealing sleeve 1915 and the lower sealing head 1930 .
- the inner sealing mandrel 1920preferably comprises a substantially hollow tubular member or members.
- the inner sealing mandrel 1920may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, low alloy steel, carbon steel or other similar high strength materials.
- the inner sealing mandrel 1920is fabricated from stainless steel in order to optimally provide mechanical properties similar to the other components of the apparatus 1900 while also providing a smooth outer surface to support seals and other moving parts that can operate with minimal wear, corrosion and pitting.
- the inner sealing mandrel 1920may be coupled to the sealing sleeve 1915 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the inner sealing mandrel 1920is removably coupled to the sealing sleeve 1915 by a standard threaded connections.
- the inner sealing mandrel 1920may be coupled to the lower sealing head 1930 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type stab in connectors or standard threaded connections.
- the inner sealing mandrel 1920is removably coupled to the lower sealing head 1930 by a standard threaded connections connection.
- the inner sealing mandrel 1920preferably includes a fluid passage 1990 that is adapted to convey fluidic materials from the fluid passage 1985 into the fluid passage 1995 .
- the fluid passage 1990is adapted to convey fluidic materials such as, for example, cement, drilling mud, epoxy or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the upper sealing head 1925is coupled to the outer sealing mandrel 1935 and the expansion cone 1945 .
- the upper sealing head 1925is also movably coupled to the outer surface of the inner sealing mandrel 1920 and the inner surface of the casing 1970 . In this manner, the upper sealing head 1925 , outer sealing mandrel 1935 , and the expansion cone 1945 reciprocate in the axial direction.
- the radial clearance between the inner cylindrical surface of the upper sealing head 1925 and the outer surface of the inner sealing mandrel 1920may range, for example, from about 0.025 to 0.05 inches.
- the radial clearance between the inner cylindrical surface of the upper sealing head 1925 and the outer surface of the inner sealing mandrel 1920ranges from about 0.005 to 0.01 inches in order to optimally provide clearance for pressure seal placement.
- the radial clearance between the outer cylindrical surface of the upper sealing head 1925 and the inner surface of the casing 1970may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer cylindrical surface of the upper sealing head 1925 and the inner surface of the casing 1970ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 1945 as the expansion cone 1945 is upwardly moved inside the casing 1970 .
- the upper sealing head 1925preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the upper sealing head 1925may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, machine tool steel, or similar high strength materials.
- the upper sealing head 1925is fabricated from stainless steel in order to optimally provide high strength and smooth outer surfaces that are resistant to wear, galling, corrosion and pitting.
- the inner surface of the upper sealing head 1925preferably includes one or more annular sealing members 2000 for sealing the interface between the upper sealing head 1925 and the inner sealing mandrel 1920 .
- the sealing members 2000may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2000comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial motion.
- the upper sealing head 1925includes a shoulder 2005 for supporting the upper sealing head 1925 on the lower sealing head 1930 .
- the upper sealing head 1925may be coupled to the outer sealing mandrel 1935 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connections.
- the upper sealing head 1925is removably coupled to the outer sealing mandrel 1935 by a standard threaded connections.
- the mechanical coupling between the upper sealing head 1925 and the outer sealing mandrel 1935includes one or more sealing members 2010 for fluidicly sealing the interface between the upper sealing head 1925 and the outer sealing mandrel 1935 .
- the sealing members 2010may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2010comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroking motion.
- the lower sealing head 1930is coupled to the inner sealing mandrel 1920 and the load mandrel 1940 .
- the lower sealing head 1930is also movably coupled to the inner surface of the outer sealing mandrel 1935 .
- the radial clearance between the outer surface of the lower sealing head 1930 and the inner surface of the outer sealing mandrel 1935may range, for example, from about 0.025 to 0.05 inches.
- the radial clearance between the outer surface of the lower sealing head 1930 and the inner surface of the outer sealing mandrel 1935ranges from about 0.005 to 0.010 inches in order to optimally provide a close tolerance having room for the installation of pressure seal rings.
- the lower sealing head 1930preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the lower sealing head 1930may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, machine tool steel or other similar high strength materials.
- the lower sealing head 1930is fabricated from stainless steel in order to optimally provide high strength and resistance to wear, galling, corrosion, and pitting.
- the outer surface of the lower sealing head 1930preferably includes one or more annular sealing members 2015 for sealing the interface between the lower sealing head 1930 and the outer sealing mandrel 1935 .
- the sealing members 2015may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 2015comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 1930may be coupled to the inner sealing mandrel 1920 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection.
- the lower sealing head 1930is removably coupled to the inner sealing mandrel 1920 by a standard threaded connection.
- the mechanical coupling between the lower sealing head 1930 and the inner sealing mandrel 1920includes one or more sealing members 2020 for fluidicly sealing the interface between the lower sealing head 1930 and the inner sealing mandrel 1920 .
- the sealing members 2020may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 2020comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial motion.
- the lower sealing head 1930may be coupled to the load mandrel 1940 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connections, welding, amorphous bonding or a standard threaded connection.
- the lower sealing head 1930is removably coupled to the load mandrel 1940 by a standard threaded connection.
- the mechanical coupling between the lower sealing head 1930 and the load mandrel 1940includes one or more sealing members 2025 for fluidicly sealing the interface between the lower sealing head 1930 and the load mandrel 1940 .
- the sealing members 2025may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 2025comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 1930includes a throat passage 2040 fluidicly coupled between the fluid passages 1990 and 1995 .
- the throat passage 2040is preferably of reduced size and is adapted to receive and engage with a plug 2045 , or other similar device.
- the fluid passage 1990is fluidicly isolated from the fluid passage 1995 .
- the pressure chamber 2030is pressurized.
- the outer sealing mandrel 1935is coupled to the upper sealing head 1925 and the expansion cone 1945 .
- the outer sealing mandrel 1935is also movably coupled to the inner surface of the casing 1970 and the outer surface of the lower sealing head 1930 . In this manner, the upper sealing head 1925 , outer sealing mandrel 1935 , and the expansion cone 1945 reciprocate in the axial direction.
- the radial clearance between the outer surface of the outer sealing mandrel 1935 and the inner surface of the casing 1970may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer surface of the outer sealing mandrel 1935 and the inner surface of the casing 1970ranges from about 0.025 to 0.125 inches in order to optimally provide maximum piston surface area to maximize the radial expansion force.
- the radial clearance between the inner surface of the outer sealing mandrel 1935 and the outer surface of the lower sealing head 1930may range, for example, from about 0.025 to 0.05 inches.
- the radial clearance between the inner surface of the outer sealing mandrel 1935 and the outer surface of the lower sealing head 1930ranges from about 0.005 to 0.010 inches in order to optimally provide a minimum gap for the sealing elements to bridge and seal.
- the outer sealing mandrel 1935preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the outer sealing mandrel 1935may be fabricated from any number of conventional commercially available materials such as, for example, low alloy steel, carbon steel, 13 chromium steel or stainless steel.
- the outer sealing mandrel 1935is fabricated from stainless steel in order to optimally provide maximum strength and minimum wall thickness while also providing resistance to corrosion, galling and pitting.
- the outer sealing mandrel 1935may be coupled to the upper sealing head 1925 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, standard threaded connections, or welding. In an exemplary embodiment, the outer sealing mandrel 1935 is removably coupled to the upper sealing head 1925 by a standard threaded connections connection.
- the outer sealing mandrel 1935may be coupled to the expansion cone 1945 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connections connection, or welding. In an exemplary embodiment, the outer sealing mandrel 1935 is removably coupled to the expansion cone 1945 by a standard threaded connections connection.
- the upper sealing head 1925 , the lower sealing head 1930 , the inner sealing mandrel 1920 , and the outer sealing mandrel 1935together define a pressure chamber 2030 .
- the pressure chamber 2030is fluidicly coupled to the passage 1990 via one or more passages 2035 .
- the plug 2045engages with the throat passage 2040 to fluidicly isolate the fluid passage 1990 from the fluid passage 1995 .
- the pressure chamber 2030is then pressurized which in turn causes the upper sealing head 1925 , outer sealing mandrel 1935 , and expansion cone 1945 to reciprocate in the axial direction.
- the axial motion of the expansion cone 1945in turn expands the casing 1970 in the radial direction.
- the load mandrel 1940is coupled to the lower sealing head 1930 and the mechanical slip body 1955 .
- the load mandrel 1940preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the load mandrel 1940may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the load mandrel 1940is fabricated from oilfield country tubular goods in order to optimally provide high strength.
- the load mandrel 1940may be coupled to the lower sealing head 1930 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection.
- the load mandrel 1940is removably coupled to the lower sealing head 1930 by a standard threaded connection.
- the load mandrel 1940may be coupled to the mechanical slip body 1955 using any number of conventional commercially available mechanical couplings such as, for example, a drillpipe connection, oilfield country tubular goods specialty type threaded connections, welding, amorphous bonding, or a standard threaded connections connection.
- the load mandrel 1940is removably coupled to the mechanical slip body 1955 by a standard threaded connections connection.
- the load mandrel 1940preferably includes a fluid passage 1995 that is adapted to convey fluidic materials from the fluid passage 1990 to the region outside of the apparatus 1900 .
- the fluid passage 1995is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the expansion cone 1945is coupled to the outer sealing mandrel 1935 .
- the expansion cone 1945is also movably coupled to the inner surface of the casing 1970 . In this manner, the upper sealing head 1925 , outer sealing mandrel 1935 , and the expansion cone 1945 reciprocate in the axial direction. The reciprocation of the expansion cone 1945 causes the casing 1970 to expand in the radial direction.
- the expansion cone 1945preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces.
- the outside radius of the outside conical surfacemay range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 inches in order to optimally provide cone dimensions for the typical range of tubular members.
- the axial length of the expansion cone 1945may range, for example, from about 2 to 8 times the largest outer diameter of the expansion cone 1945 .
- the axial length of the expansion cone 1945ranges from about 3 to 5 times the largest outer diameter of the expansion cone 1945 in order to optimally provide stability and centralization of the expansion cone 1945 during the expansion process.
- the angle of attack of the expansion cone 1945ranges from about 5 to 30 degrees in order to optimally balance friction forces with the desired amount of radial expansion.
- the expansion cone 1945 angle of attackwill vary as a function of the operating parameters of the particular expansion operation.
- the expansion cone 1945may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, ceramics, tungsten carbide, nitride steel, or other similar high strength materials.
- the expansion cone 1945is fabricated from D2 machine tool steel in order to optimally provide high strength and resistance to corrosion, wear, galling, and pitting.
- the outside surface of the expansion cone 1945has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide high strength and resist wear and galling.
- the expansion cone 1945may be coupled to the outside sealing mandrel 1935 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield tubular country goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connections connection.
- the expansion cone 1945is coupled to the outside sealing mandrel 1935 using a standard threaded connections connection in order to optimally provide connector strength for the typical operating loading conditions while also permitting easy replacement of the expansion cone 1945 .
- the mandrel launcher 1950is coupled to the casing 1970 .
- the mandrel launcher 1950comprises a tubular section of casing having a reduced wall thickness compared to the casing 1970 .
- the wall thickness of the mandrel launcheris about 50 to 100% of the wall thickness of the casing 1970 . In this manner, the initiation of the radial expansion of the casing 1970 is facilitated, and the insertion of the larger outside diameter mandrel launcher 1950 into the wellbore and/or casing is facilitated.
- the mandrel launcher 1950may be coupled to the casing 1970 using any number of conventional mechanical couplings.
- the mandrel launcher 1950may have a wall thickness ranging, for example, from about 0.15 to 1.5 inches. In an exemplary embodiment, the wall thickness of the mandrel launcher 1950 ranges from about 0.25 to 0.75 inches in order to optimally provide high strength with a small overall profile.
- the mandrel launcher 1950may be fabricated from any number of conventional commercially available materials such as, for example, oil field tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the mandrel launcher 1950 is fabricated from oil field tubular goods of higher strength but lower wall thickness than the casing 1970 in order to optimally provide a thin walled container with approximately the same burst strength as the casing 1970 .
- the mechanical slip body 1955is coupled to the load mandrel 1970 , the mechanical slips 1960 , and the drag blocks 1965 .
- the mechanical slip body 1955preferably comprises a tubular member having an inner passage 2050 fluidicly coupled to the passage 1995 . In this manner, fluidic materials may be conveyed from the passage 2050 to a region outside of the apparatus 1900 .
- the mechanical slip body 1955may be coupled to the load mandrel 1940 using any number of conventional mechanical couplings.
- the mechanical slip body 1955is removably coupled to the load mandrel 1940 using a standard threaded connection in order to optimally provide high strength and permit the mechanical slip body 1955 to be easily replaced.
- the mechanical slip body 1955may be coupled to the mechanical slips 1955 using any number of conventional mechanical couplings.
- the mechanical slip body 1955is removably coupled to the mechanical slips 1955 using threads and sliding steel retainer rings in order to optimally provide high strength coupling and also permit easy replacement of the mechanical slips 1955 .
- the mechanical slip body 1955may be coupled to the drag blocks 1965 using any number of conventional mechanical couplings.
- the mechanical slip body 1955is removably coupled to the drag blocks 1965 using threaded connections and sliding steel retainer rings in order to optimally provide high strength and also permit easy replacement of the drag blocks 1965 .
- the mechanical slips 1960are coupled to the outside surface of the mechanical slip body 1955 .
- the mechanical slips 1960prevent upward movement of the casing 1970 and mandrel launcher 1950 .
- the casing 1970 and mandrel launcher 1950are maintained in a substantially stationary position.
- the mandrel launcher 1950 and casing 1970are expanded in the radial direction by the axial movement of the expansion cone 1945 .
- the mechanical slips 1960may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L retrievable bridge plug tungsten carbide upper mechanical slips.
- the mechanical slips 1960comprise RTTS packer tungsten carbide mechanical slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the casing 1970 during the expansion process.
- the drag blocks 1965are coupled to the outside surface of the mechanical slip body 1955 .
- the drag blocks 1965prevent upward movement of the casing 1970 and mandrel launcher 1950 .
- the casing 1970 and mandrel launcher 1950are maintained in a substantially stationary position.
- the mandrel launcher 1950 and casing 1970are expanded in the radial direction by the axial movement of the expansion cone 1945 .
- the drag blocks 1965may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L retrievable bridge plug tungsten carbide upper mechanical slips.
- the drag blocks 1965comprise RTTS packer tungsten carbide mechanical slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the casing 1970 during the expansion process.
- the casing 1970is coupled to the mandrel launcher 1950 .
- the casing 1970is further removably coupled to the mechanical slips 1960 and drag blocks 1965 .
- the casing 1970preferably comprises a tubular member.
- the casing 1970may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oil field country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the casing 1970is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength.
- the upper end of the casing 1970includes one or more sealing members positioned about the exterior of the casing 1970 .
- the apparatus 1900is positioned in a wellbore with the upper end of the casing 1970 positioned in an overlapping relationship within an existing wellbore casing.
- the fluid passage 1976is preferably provided with one or more pressure relief passages.
- the casing 1970is supported by the expansion cone 1945 .
- a first fluidic materialis pumped into the fluid passage 1975 from a surface location.
- the first fluidic materialis conveyed from the fluid passage 1975 to the fluid passages 1980 , 1985 , 1990 , 1995 , and 2050 .
- the first fluidic materialwill then exit the apparatus and fill the annular region between the outside of the apparatus 1900 and the interior walls of the bore hole.
- the first fluidic materialmay comprise any number of conventional commercially available materials such as, for example, drilling mud, wafer, epoxy or cement.
- the first fluidic materialcomprises a hardenable fluidic sealing material such as, for example, cement or epoxy. In this manner, a wellbore casing having an outer annular layer of a hardenable material may be formed.
- the first fluidic materialmay be pumped into the apparatus 1900 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi, and 0 to 3,000 gallons/minute.
- the first fluidic materialis pumped into the apparatus 1900 at operating pressures and flow rates ranging from about 0 to 4,500 psi and 0 to 3,000 gallons/minute in order to optimally provide operating pressures and flow rates for typical operating conditions.
- a plug 2045 , dart, or other similar deviceis introduced into the first fluidic material.
- the plug 2045lodges in the throat passage 2040 thereby fluidicly isolating the fluid passage 1990 from the fluid passage 1995 .
- a second fluidic materialis pumped into the fluid passage 1975 in order to pressurize the pressure chamber 2030 .
- the second fluidic materialmay comprise any number of conventional commercially available materials such as, for example, water, drilling gases, drilling mud or lubricant.
- the second fluidic materialcomprises a non-hardenable fluidic material such as, for example, water, drilling mud or lubricant in order minimize frictional forces.
- the second fluidic materialmay be pumped into the apparatus 1900 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute.
- the second fluidic materialis pumped into the apparatus 1900 at operating pressures and flow rates ranging from about 0 to 3,500 psi, and 0 to 1,200 gallons/minute in order to optimally provide expansion of the casing 1970 .
- the pressurization of the pressure chamber 2030causes the upper sealing head 1925 , outer sealing mandrel 1935 , and expansion cone 1945 to move in an axial direction.
- the expansion cone 1945pulls the mandrel launcher 1950 and drag blocks 1965 along, which sets the mechanical slips 1960 and stops further axial movement of the mandrel launcher 1950 and casing 1970 .
- the axial movement of the expansion cone 1945radially expands the mandrel launcher 1950 and casing 1970 .
- the mandrel launcher 1950 and casing 1970are radial expanded through repeated axial strokes of the upper sealing head 1925 , outer sealing mandrel 1935 and expansion cone 1945 .
- the upper end of the casing 1970is preferably maintained in an overlapping relation with an existing section of wellbore casing.
- the upper end of the casing 1970is expanded into intimate contact with the inside surface of the lower end of the existing wellbore casing.
- the sealing members provided at the upper end of the casing 1970provide a fluidic seal between the outside surface of the upper end of the casing 1970 and the inside surface of the lower end of the existing wellbore casing.
- the contact pressure between the casing 1970 and the existing section of wellbore casingranges from about 400 to 10,000 psi in order to optimally provide contact pressure for activating sealing members, provide optimal resistance to axial movement of the expanded casing 1970 , and optimally support typical tensile and compressive loads.
- the apparatus 1900includes a shock absorber for absorbing the shock created by the completion of the radial expansion of the casing 1970 .
- the reduced operating pressure of the second fluidic materialranges from about 100 to 1,000 psi as the expansion cone 1945 nears the end of the casing 1970 in order to optimally provide reduced axial movement and velocity of the expansion cone 1945 .
- the operating pressure of the second fluidic materialis reduced during the return stroke of the apparatus 1900 to the range of about 0 to 500 psi in order minimize the resistance to the movement of the expansion cone 1945 .
- the stroke length of the apparatus 1900ranges from about 10 to 45 feet in order to optimally provide equipment lengths that can be handled by typical oil well rigging equipment while also minimizing the frequency at which the expansion cone 1945 must be stopped so the apparatus 1900 can be re-stroked for further expansion operations.
- At least a portion of the upper sealing head 1925includes an expansion cone for radially expanding the mandrel launcher 1950 and casing 1970 during operation of the apparatus 1900 in order to increase the surface area of the casing 1970 acted upon during the radial expansion process. In this manner, the operating pressures can be reduced.
- mechanical slipsare positioned in an axial location between the sealing sleeve 1915 and the inner sealing mandrel 1920 in order to simplify the operation and assembly of the apparatus 1900 .
- the first fluidic materialis permitted to cure within the annular region between the outside of the expanded casing 1970 and the interior walls of the wellbore.
- the cured fluidic materialwill preferably permeate and envelop the expanded casing. In this manner, a new section of wellbore casing is formed within a wellbore.
- the apparatus 1900may be used to join a first section of pipeline to an existing section of pipeline.
- the apparatus 1900may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material.
- the apparatus 1900may be used to expand a tubular support member in a hole.
- the pressurized areas of the apparatus 1900are limited to the fluid passages 1975 , 1980 , 1985 , and 1990 , and the pressure chamber 2030 .
- No fluid pressureacts directly on the mandrel launcher 1950 and casing 1970 . This permits the use of operating pressures higher than the mandrel launcher 1950 and casing 1970 could normally withstand.
- the apparatus 2100preferably includes a drillpipe 2105 , an innerstring adapter 2110 , a sealing sleeve 2115 , an inner sealing mandrel 2120 , slips 2125 , upper sealing head 2130 , lower sealing head 2135 , outer sealing mandrel 2140 , load mandrel 2145 , expansion cone 2150 , and casing 2155 .
- the drillpipe 2105is coupled to the innerstring adapter 2110 . During operation of the apparatus 2100 , the drillpipe 2105 supports the apparatus 2100 .
- the drillpipe 2105preferably comprises a substantially hollow tubular member or members.
- the drillpipe 2105may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength material.
- the drillpipe 2105is fabricated from coiled tubing in order to facilitate the placement of the apparatus 1900 in non-vertical wellbores.
- the drillpipe 2105may be coupled to the innerstring adapter 2110 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type connection, or a standard threaded connection.
- the drillpipe 2105is removably coupled to the innerstring adapter 2110 by a drill pipe connection.
- the drillpipe 2105preferably includes a fluid passage 2160 that is adapted to convey fluidic materials from a surface location into the fluid passage 2165 .
- the fluid passage 2160is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the innerstring adapter 2110is coupled to the drill string 2105 and the sealing sleeve 2115 .
- the innerstring adapter 2110preferably comprises a substantially hollow tubular member or members.
- the innerstring adapter 2110may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the innerstring adapter 2110is fabricated from stainless steel in order to optimally provide high strength, low friction, and resistance to corrosion and wear.
- the innerstring adapter 2110may be coupled to the drill string 2105 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type connection or a standard threaded connection.
- the innerstring adapter 2110is removably coupled to the drill pipe 2105 by a drillpipe connection.
- the innerstring adapter 2110may be coupled to the sealing sleeve 2115 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the innerstring adapter 2110is removably coupled to the sealing sleeve 2115 by a standard threaded connection.
- the innerstring adapter 2110preferably includes a fluid passage 2165 that is adapted to convey fluidic materials from the fluid passage 2160 into the fluid passage 2170 .
- the fluid passage 2165is adapted to convey fluidic materials such as, for example, cement, epoxy, water drilling muds, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the sealing sleeve 2115is coupled to the innerstring adapter 2110 and the inner sealing mandrel 2120 .
- the sealing sleeve 2115preferably comprises a substantially hollow tubular member or members.
- the sealing sleeve 2115may be fabricated from any number of conventional commercially available materials such as, for example, oil field tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the sealing sleeve 2115is fabricated from stainless steel in order to optimally provide high strength, low friction surfaces, and resistance to corrosion, wear, galling, and pitting.
- the sealing sleeve 2115may be coupled to the innerstring adapter 2110 using any number of conventional commercially available mechanical couplings such as, for example, a standard threaded connection, oilfield country tubular goods specialty type threaded connections, welding, amorphous bonding, or a standard threaded connection.
- the sealing sleeve 2115is removably coupled to the innerstring adapter 2110 by a standard threaded connection.
- the sealing sleeve 2115may be coupled to the inner sealing mandrel 2120 using any number of conventional commercially available mechanical couplings such as, for example, a standard threaded connection, oilfield country tubular goods specialty type threaded connections, welding, amorphous bonding, or a standard threaded connection.
- the sealing sleeve 2115is removably coupled to the inner sealing mandrel 2120 by a standard threaded connection.
- the sealing sleeve 2115preferably includes a fluid passage 2170 that is adapted to convey fluidic materials from the fluid passage 2165 into the fluid passage 2175 .
- the fluid passage 2170is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the inner sealing mandrel 2120is coupled to the sealing sleeve 2115 , slips 2125 , and the lower sealing head 2135 .
- the inner sealing mandrel 2120preferably comprises a substantially hollow tubular member or members.
- the inner sealing mandrel 2120may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the inner sealing mandrel 2120is fabricated from stainless steel in order to optimally provide high strength, low friction surfaces, and corrosion and wear resistance.
- the inner sealing mandrel 2120may be coupled to the sealing sleeve 2115 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the inner sealing mandrel 2120is removably coupled to the sealing sleeve 2115 by a standard threaded connection.
- the standard threaded connectionprovides high strength and permits easy replacement of components.
- the inner sealing mandrel 2120may be coupled to the slips 2125 using any number of conventional commercially available mechanical couplings such as, for example, welding, amorphous bonding, or a standard threaded connection.
- the inner sealing mandrel 2120is removably coupled to the slips 2125 by a standard threaded connection.
- the inner sealing mandrel 2120may be coupled to the lower sealing head 2135 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection.
- the inner sealing mandrel 2120is removably coupled to the lower sealing head 2135 by a standard threaded connection.
- the inner sealing mandrel 2120preferably includes a fluid passage 2175 that is adapted to convey fluidic materials from the fluid passage 2170 into the fluid passage 2180 .
- the fluid passage 2175is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the slips 2125are coupled to the outer surface of the inner sealing mandrel 2120 .
- the slips 2125preferably maintain the easing 2155 in a substantially stationary position during the radial expansion of the casing 2155 .
- the slips 2125are activated using the fluid passages 2185 to convey pressurized fluid material into the slips 2125 .
- the slips 2126may comprise any number of commercially available hydraulic slips such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L retrievable bridge plug hydraulic slips.
- the slips 2125comprise RTTS packer tungsten carbide hydraulic slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the casing 2155 during the expansion process.
- the slipsinclude a fluid passage 2190 , pressure chamber 2195 , spring return 2200 , and slip member 2205 .
- the slips 2125may be coupled to the inner sealing mandrel 2120 using any number of conventional mechanical couplings.
- the slips 2125are removably coupled to the outer surface of the inner sealing mandrel 2120 by a thread connection in order to optimally provide interchangeability of parts.
- the upper sealing head 2130is coupled to the outer sealing mandrel 2140 and expansion cone 2150 .
- the upper sealing head 2130is also movably coupled to the outer surface of the inner sealing mandrel 2120 and the inner surface of the casing 2155 . In this manner, the upper sealing head 2130 reciprocates in the axial direction.
- the radial clearance between the inner cylindrical surface of the upper sealing head 2130 and the outer surface of the inner sealing mandrel 2120may range, for example, from about 0.025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of the upper sealing head 2130 and the outer surface of the inner sealing mandrel 2120 ranges from about 0.005 to 0.010 inches in order to optimally provide a pressure seal.
- the radial clearance between the outer cylindrical surface of the upper sealing head 2130 and the inner surface of the casing 2155may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of the upper sealing head 2130 and the inner surface of the casing 2155 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 2130 during axial movement of the expansion cone 2130 .
- the upper sealing head 2130preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the upper sealing head 2130may be fabricated from any number of conventional commercially available materials such as, for example, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the upper sealing head 2130is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the inner surface of the upper sealing head 2130preferably includes one or more annular sealing members 2210 for sealing the interface between the upper sealing head 2130 and the inner sealing mandrel 2120 .
- the sealing members 2210may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 2210comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the upper sealing head 2130includes a shoulder 2215 for supporting the upper sealing head 2130 on the lower sealing head 2135 .
- the upper sealing head 2130may be coupled to the outer sealing mandrel 2140 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection.
- the upper sealing head 2130is removably coupled to the outer sealing mandrel 2140 by a standard threaded connection.
- the mechanical coupling between the upper sealing head 2130 and the outer sealing mandrel 2140includes one or more sealing members 2220 for fluidicly sealing the interface between the upper sealing head 2130 and the outer sealing mandrel 2140 .
- the sealing members 2220may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 2220comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 2135is coupled to the inner sealing mandrel 2120 and the load mandrel 2145 .
- the lower sealing head 2135is also movably coupled to the inner surface of the outer sealing mandrel 2140 .
- the upper sealing head 2130 , outer sealing mandrel 2140 , and expansion cone 2150reciprocate in the axial direction.
- the radial clearance between the outer surface of the lower sealing head 2135 and the inner surface of the outer sealing mandrel 2140may range, for example, from about 0.0025 to 0.05 inches.
- the radial clearance between the outer surface of the lower sealing head 2135 and the inner surface of the outer sealing mandrel 2140ranges from about 0.0025 to 0.05 inches in order to optimally provide minimal radial clearance.
- the lower sealing head 2135preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the lower sealing head 2135may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the lower sealing head 2135is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the outer surface of the lower sealing head 2135preferably includes one or more annular sealing members 2225 for sealing the interface between the lower sealing head 2135 and the outer sealing mandrel 2140 .
- the sealing members 2225may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2225comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 2135may be coupled to the inner sealing mandrel 2120 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the lower sealing head 2135is removably coupled to the inner sealing mandrel 2120 by a standard threaded connection.
- the mechanical coupling between the lower sealing head 2135 and the inner sealing mandrel 2120includes one or more sealing members 2230 for fluidicly sealing the interface between the lower sealing head 2135 and the inner sealing mandrel 2120 .
- the sealing members 2230may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 2230comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 2135may be coupled to the load mandrel 2145 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the lower sealing head 2135is removably coupled to the load mandrel 2145 by a standard threaded connection.
- the mechanical coupling between the lower sealing head 2135 and the load mandrel 2145includes one or more sealing members 2235 for fluidicly sealing the interface between the lower sealing head 1930 and the load mandrel 2145 .
- the sealing members 2235may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 2235comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 2135includes a throat passage 2240 fluidicly coupled between the fluid passages 2175 and 2180 .
- the throat passage 2240is preferably of reduced size and is adapted to receive and engage with a plug 2245 , or other similar device.
- the fluid passage 2175is fluidicly isolated from the fluid passage 2180 .
- the pressure chamber 2250is pressurized.
- the outer sealing mandrel 2140is coupled to the upper sealing head 2130 and the expansion cone 2150 .
- the outer sealing mandrel 2140is also movably coupled to the inner surface of the casing 2155 and the outer surface of the lower sealing head 2135 . In this manner, the upper sealing head 2130 , outer sealing mandrel 2140 , and the expansion cone 2150 reciprocate in the axial direction.
- the radial clearance between the outer surface of the outer sealing mandrel 2140 and the inner surface of the casing 2155may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer surface of the outer sealing mandrel 2140 and the inner surface of the casing 2155ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 2130 during the expansion process.
- the radial clearance between the inner surface of the outer sealing mandrel 2140 and the outer surface of the lower sealing head 2135may range, for example, from about 0.005 to 0.125 inches.
- the radial clearance between the inner surface of the outer sealing mandrel 2140 and the outer surface of the lower sealing head 2135ranges from about 0.005 to 0.010 inches in order to optimally provide minimal radial clearance.
- the outer sealing mandrel 2140preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the outer sealing mandrel 2140may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength materials.
- the outer sealing mandrel 2140is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the outer sealing mandrel 2140may be coupled to the upper sealing head 2130 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection.
- the outer sealing mandrel 2140is removably coupled to the upper sealing head 2130 by a standard threaded connection.
- the outer sealing mandrel 2140may be coupled to the expansion cone 2150 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the outer sealing mandrel 2140is removably coupled to the expansion cone 2150 by a standard threaded connection.
- the upper sealing head 2130 , the lower sealing head 2135 , inner sealing mandrel 2120 , and the outer sealing mandrel 2140together define a pressure chamber 2250 .
- the pressure chamber 2250is fluidicly coupled to the passage 2175 via one or more passages 2255 .
- the plug 2245engages with the throat passage 2240 to fluidicly isolate the fluid passage 2175 from the fluid passage 2180 .
- the pressure chamber 2250is then pressurized which in turn causes the upper sealing head 2130 , outer sealing mandrel 2140 , and expansion cone 2150 to reciprocate in the axial direction.
- the axial motion of the expansion cone 2150in turn expands the casing 2155 in the radial direction.
- the load mandrel 2145is coupled to the lower sealing head 2135 .
- the load mandrel 2145preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the load mandrel 2145may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the load mandrel 2145is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction bearing surfaces.
- the load mandrel 2145may be coupled to the lower sealing head 2135 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection.
- the load mandrel 2145is removably coupled to the lower sealing head 2135 by a standard threaded connection in order to optimally provide high strength and permit easy replacement of the load mandrel 2145 .
- the load mandrel 2145preferably includes a fluid passage 2180 that is adapted to convey fluidic materials from the fluid passage 2180 to the region outside of the apparatus 2100 .
- the fluid passage 2180is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the expansion cone 2150is coupled to the outer sealing mandrel 2140 .
- the expansion cone 2150is also movably coupled to the inner surface of the casing 2155 . In this manner, the upper sealing head 2130 , outer sealing mandrel 2140 , and the expansion cone 2150 reciprocate in the axial direction. The reciprocation of the expansion cone 2150 causes the casing 2155 to expand in the radial direction.
- the expansion cone 2150preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces.
- the outside radius of the outside conical surfacemay range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 inches in order to optimally provide cone dimensions that are optimal for typical casings.
- the axial length of the expansion cone 2150may range, for example, from about 2 to 6 times the largest outside diameter of the expansion cone 2150 . In an exemplary embodiment, the axial length of the expansion cone 2150 ranges from about 3 to 5 times the largest outside diameter of the expansion cone 2150 in order to optimally provide stability and centralization of the expansion cone 2150 during the expansion process.
- the maximum outside diameter of the expansion cone 2150is between about 90 to 100% of the inside diameter of the existing wellbore that the casing 2155 will be joined with.
- the angle of attack of the expansion cone 2150ranges from about 5 to 30 degrees in order to optimally balance friction forces and radial expansion forces. The optimal expansion cone 2150 angle of attack will vary as a function of the particular operating conditions of the expansion operation.
- the expansion cone 2150may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramics, or other similar high strength materials.
- the expansion cone 2150is fabricated from D2 machine tool steel in order to optimally provide high strength and resistance to wear and galling.
- the outside surface of the expansion cone 2150has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide resistance to wear.
- the expansion cone 2150may be coupled to the outside sealing mandrel 2140 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection.
- the expansion cone 2150is coupled to the outside sealing mandrel 2140 using a standard threaded connection in order to optimally provide high strength and permit the expansion cone 2150 to be easily replaced.
- the casing 2155is removably coupled to the slips 2125 and expansion cone 2150 .
- the casing 2155preferably comprises a tubular member.
- the casing 2155may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength material.
- the casing 2155is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength.
- the upper end 2260 of the casing 2155includes a thin wall section 2265 and an outer annular sealing member 2270 .
- the wall thickness of the thin wall section 2265is about 50 to 100% of the regular wall thickness of the casing 2155 .
- the upper end 2260 of the casing 2155may be easily expanded and deformed into intimate contact with the lower end of an existing section of wellbore casing.
- the lower end of the existing section of casingalso includes a thin wall section. In this manner, the radial expansion of the thin walled section 2265 of casing 2155 into the thin walled section of the existing wellbore casing results in a wellbore casing having a substantially constant inside diameter.
- the annular sealing member 2270may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal or plastic.
- the annular sealing member 2270is fabricated from StrataLock epoxy in order to optimally provide compressibility and resistance to wear.
- the outside diameter of the annular sealing member 2270preferably ranges from about 70 to 95% of the inside diameter of the lower section of the wellbore casing that the casing 2155 is pined to. In this manner, after expansion, the annular sealing member 2270 preferably provides a fluidic seal and also preferably provides sufficient frictional force with the inside surface of the existing section of wellbore casing during the radial expansion of the casing 2155 to support the casing 2155 .
- the lower end 2275 of the casing 2155includes a thin wall section 2280 and an outer annular sealing member 2285 .
- the wall thickness of the thin wall section 2280is about 50 to 100% of the regular wall thickness of the casing 2155 .
- the lower end 2275 of the casing 2155may be easily expanded and deformed.
- an other section of casingmay be easily joined with the lower end 2275 of the casing 2155 using a radial expansion process.
- the upper end of the other section of casingalso includes a thin wall section. In this manner, the radial expansion of the thin walled section of the upper end of the other casing into the thin walled section 2280 of the lower end of the casing 2155 results in a wellbore casing having a substantially constant inside diameter.
- the annular sealing member 2285may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal or plastic.
- the annular sealing member 2285is fabricated from StrataLock epoxy in order to optimally provide compressibility and wear resistance.
- the outside diameter of the annular sealing member 2285preferably ranges from about 70 to 95% of the inside diameter of the lower section of the existing wellbore casing that the casing 2155 is joined to. In this manner, the annular sealing member 2285 preferably provides a fluidic seal and also preferably provides sufficient frictional force with the inside wall of the wellbore during the radial expansion of the casing 2155 to support the casing 2155 .
- the apparatus 2100is preferably positioned in a wellbore with the upper end 2260 of the casing 2155 positioned in an overlapping relationship with the lower end of an existing wellbore casing.
- the thin wall section 2265 of the casing 2155is positioned in opposing overlapping relation with the thin wall section and outer annular sealing member of the lower end of the existing section of wellbore casing. In this manner, the radial expansion of the casing 2155 will compress the thin wall sections and annular compressible members of the upper end 2260 of the casing 2155 and the lower end of the existing wellbore casing into intimate contact.
- the casing 2155is supported by the expansion cone 2150 .
- the first fluidic materialmay comprise any number of conventional commercially available materials such as, for example, drilling mud, water, epoxy, or cement.
- the first fluidic materialcomprises a hardenable fluidic sealing material such as, for example, cement or epoxy in order to provide a hardenable outer annular body around the expanded casing 2155 .
- the first fluidic materialmay be pumped into the fluid passage 2160 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 3,000 gallons/minute. In an exemplary embodiment, the first fluidic material is pumped into the fluid passage 2160 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency.
- the first fluidic material pumped into the fluid passage 2160passes through the fluid passages 2165 , 2170 , 2175 , 2180 and then outside of the apparatus 2100 .
- the first fluidic materialthen fills the annular region between the outside of the apparatus 2100 and the interior walls of the wellbore.
- the plug 2245is then introduced into the fluid passage 2160 .
- the plug 2245lodges in the throat passage 2240 and fluidicly isolates and blocks off the fluid passage 2175 .
- a couple of volumes of a non-hardenable fluidic materialare then pumped into the fluid passage 2160 in order to remove any hardenable fluidic material contained within and to ensure that none of the fluid passages are blocked.
- a second fluidic materialis then pumped into the fluid passage 2160 .
- the second fluidic materialmay comprise any number of conventional commercially available materials such as, for example, drilling mud, water, drilling gases, or lubricants.
- the second fluidic materialcomprises a non-hardenable fluidic material such as, for example, water, drilling mud or lubricant in order to optimally provide pressurization of the pressure chamber 2250 and minimize frictional forces.
- the second fluidic materialmay be pumped into the fluid passage 2160 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute.
- the second fluidic materialis pumped into the fluid passage 2160 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency.
- the second fluidic material pumped into the fluid passage 2160passes through the fluid passages 2165 , 2170 , and 2175 into the pressure chambers 2195 of the slips 2125 , and into the pressure chamber 2250 . Continued pumping of the second fluidic material pressurizes the pressure chambers 2195 and 2250 .
- the pressurization of the pressure chambers 2195causes the slip members 2205 to expand in the radial direction and grip the interior surface of the casing 2155 .
- the casing 2155is then preferably maintained in a substantially stationary position.
- the pressurization of the pressure chamber 2250causes the upper sealing head 2130 , outer sealing mandrel 2140 and expansion cone 2150 to move in an axial direction relative to the casing 2155 .
- the expansion cone 2150will cause the casing 2155 to expand in the radial direction.
- the casing 2155is prevented from moving in an upward direction by the slips 2125 .
- a length of the casing 2155is then expanded in the radial direction through the pressurization of the pressure chamber 2250 .
- the length of the casing 2155 that is expanded during the expansion processwill be proportional to the stroke length of the upper sealing head 2130 , outer sealing mandrel 2140 , and expansion cone 2150 .
- the operating pressure of the second fluidic materialis reduced and the upper sealing head 2130 , outer sealing mandrel 2140 , and expansion cone 2150 drop to their rest positions with the casing 2155 supported by the expansion cone 2150 .
- the position of the drillpipe 2105is preferably adjusted throughout the radial expansion process in order to maintain the overlapping relationship between the thin walled sections of the lower end of the existing wellbore casing and the upper end of the casing 2155 .
- the stroking of the expansion cone 2150is then repeated, as necessary, until the thin walled section 2265 of the upper end 2260 of the casing 2155 is expanded into the thin walled section of the lower end of the existing wellbore casing.
- a wellbore casingis formed including two adjacent sections of casing having a substantially constant inside diameter. This process may then be repeated for the entirety of the wellbore to provide a wellbore casing thousands of feet in length having a substantially constant inside diameter.
- the slips 2125are positioned as close as possible to the thin walled section 2265 of the upper end of the casing 2155 in order minimize slippage between the casing 2155 and the existing wellbore casing at the end of the radial expansion process.
- the outside diameter of the annular sealing member 2270is selected to ensure sufficient interference fit with the inside diameter of the lower end of the existing casing to prevent axial displacement of the casing 2155 during the final stroke.
- the outside diameter of the annular sealing member 2285is selected to provide an interference fit with the inside walls of the wellbore at an earlier point in the radial expansion process so as to prevent further axial displacement of the casing 2155 .
- the interference fitis preferably selected to permit expansion of the casing 2155 by pulling the expansion cone 2150 out of the wellbore, without having to pressurize the pressure chamber 2250 .
- the pressurized areas of the apparatus 2100are limited to the fluid passages 2160 , 2165 , 2170 , and 2175 , the pressure chambers 2195 within the slips 2125 , and the pressure chamber 2250 . No fluid pressure acts directly on the casing 2155 . This permits the use of operating pressures higher than the casing 2155 could normally withstand.
- the contact pressure between the deformed thin wall sections and compressible annular members of the lower end of the existing casing and the upper end 2260 of the casing 2155ranges from about 500 to 40,000 psi in order to optimally support the casing 2155 using the existing wellbore casing.
- the casing 2155is radially expanded into contact with an existing section of casing by pressurizing the interior fluid passages 2160 , 2165 , 2170 , and 2175 and the pressure chamber 2250 of the apparatus 2100 .
- the annular body of hardenable fluidic materialis then allowed to cure to form a rigid outer annular body about the expanded casing 2155 .
- the cured fluidic materialpreferably permeates and envelops the expanded casing 2155 .
- the resulting new section of wellbore casingincludes the expanded casing 2155 and the rigid outer annular body.
- the overlapping joint between the pre-existing wellbore casing and the expanded casing 2155includes the deformed thin wall sections and the compressible outer annular bodies.
- the inner diameter of the resulting combined wellbore casingsis substantially constant. In this manner, a mono-diameter wellbore casing is formed.
- This process of expanding overlapping tubular members having thin wall end portions with compressible annular bodies into contactcan be repeated for the entire length of a wellbore.
- a mono-diameter wellbore casingcan be provided for thousands of feet in a subterranean formation.
- the apparatus 2100includes a shock absorber for absorbing the shock created by the completion of the radial expansion of the casing 2155 .
- the reduced operating pressure of the second fluidic materialranges from about 100 to 1,000 psi as the expansion cone 2130 nears the end of the casing 2155 in order to optimally provide reduced axial movement and velocity of the expansion cone 2130 .
- the operating pressure of the second fluidic materialis reduced during the return stroke of the apparatus 2100 to the range of about 0 to 500 psi in order minimize the resistance to the movement of the expansion cone 2130 during the return stroke.
- the stroke length of the apparatus 2100ranges from about 10 to 45 feet in order to optimally provide equipment lengths that can be handled by conventional oil well rigging equipment while also minimizing the frequency at which the expansion cone 2130 must be stopped so that the apparatus 2100 can be re-stroked.
- At least a portion of the upper sealing head 2130includes an expansion cone for radially expanding the casing 2155 during operation of the apparatus 2100 in order to increase the surface area of the casing 2155 acted upon during the radial expansion process. In this manner, the operating pressures can be reduced.
- the apparatus 2100may be used to join a first section of pipeline to an existing section of pipeline.
- the apparatus 2100may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material.
- the apparatus 2100may be used to expand a tubular support member in a hole.
- the apparatus 2300preferably includes a drillpipe 2305 , an innerstring adapter 2310 , a sealing sleeve 2315 , a hydraulic slip body 2320 , hydraulic slips 2325 , an inner sealing mandrel 2330 , an upper sealing head 2335 , a lower sealing head 2340 , a load mandrel 2345 , an outer sealing mandrel 2350 , an expansion cone 2355 , a mechanical slip body 2360 , mechanical slips 2365 , drag blocks 2370 , casing 2375 , fluid passages 2380 , 2385 , 2390 , 2395 , 2400 , 2405 , 2410 , 2415 , and 2485 , and mandrel launcher 2480 .
- the drillpipe 2305is coupled to the innerstring adapter 2310 .
- the drillpipe 2305supports the apparatus 2300 .
- the drillpipe 2305preferably comprises a substantially hollow tubular member or members.
- the drillpipe 2305may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the drillpipe 2305is fabricated from coiled tubing in order to facilitate the placement of the apparatus 2300 in non-vertical wellbores.
- the drillpipe 2305may be coupled to the innerstring adapter 2310 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection.
- the drillpipe 2305is removably coupled to the innerstring adapter 2310 by a drillpipe connection.
- the drillpipe 2305preferably includes a fluid passage 2380 that is adapted to convey fluidic materials from a surface location into the fluid passage 2385 .
- the fluid passage 2380is adapted to convey fluidic materials such as, for example, cement water, epoxy, drilling muds, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 5,000 gallons/minute in order to optimally provide operational efficiency.
- the innerstring adapter 2310is coupled to the drill string 2305 and the sealing sleeve 2315 .
- the innerstring adapter 2310preferably comprises a substantially hollow tubular member or members.
- the innerstring adapter 2310may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the innerstring adapter 2310is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the innerstring adapter 2310may be coupled to the drill string 2305 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection.
- the innerstring adapter 2310is removably coupled to the drill pipe 2305 by a drillpipe connection.
- the innerstring adapter 2310may be coupled to the sealing sleeve 2315 using any number of conventional commercially available mechanical couplings such as, for example, a drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection.
- the innerstring adapter 2310is removably coupled to the sealing sleeve 2315 by a standard threaded connection.
- the innerstring adapter 2310preferably includes a fluid passage 2385 that is adapted to convey fluidic materials from the fluid passage 2380 into the fluid passage 2390 .
- the fluid passage 2385is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, drilling gases or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the sealing sleeve 2315is coupled to the innerstring adapter 2310 and the hydraulic slip body 2320 .
- the sealing sleeve 2315preferably comprises a substantially hollow tubular member or members.
- the sealing sleeve 2315may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the sealing sleeve 2315is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low-friction surfaces.
- the sealing sleeve 2315may be coupled to the innerstring adapter 2310 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connections, oilfield country tubular goods specialty threaded connections, or a standard threaded connection, in an exemplary embodiment, the sealing sleeve 2315 is removably coupled to the innerstring adapter 2310 by a standard threaded connection.
- the sealing sleeve 2315may be coupled to the hydraulic slip body 2320 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, the sealing sleeve 2315 is removably coupled to the hydraulic slip body 2320 by a standard threaded connection.
- the sealing sleeve 2315preferably includes a fluid passage 2390 that is adapted to convey fluidic materials from the fluid passage 2385 into the fluid passage 2395 .
- the fluid passage 2315is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the hydraulic slip body 2320is coupled to the sealing sleeve 2315 , the hydraulic slips 2325 , and the inner sealing mandrel 2330 .
- the hydraulic slip body 2320preferably comprises a substantially hollow tubular member or members.
- the hydraulic slip body 2320may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other high strength material.
- the hydraulic slip body 2320is fabricated from carbon steel in order to optimally provide high strength at low cost.
- the hydraulic slip body 2320may be coupled to the sealing sleeve 2315 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection.
- the hydraulic slip body 2320is removably coupled to the sealing sleeve 2315 by a standard threaded connection.
- the hydraulic slip body 2320may be coupled to the slips 2325 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection.
- the hydraulic slip body 2320is removably coupled to the slips 2325 by a standard threaded connection.
- the hydraulic slip body 2320may be coupled to the inner sealing mandrel 2330 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection.
- the hydraulic slip body 2320is removably coupled to the inner sealing mandrel 2330 by a standard threaded connection.
- the hydraulic slips body 2320preferably includes a fluid passage 2395 that is adapted to convey fluidic materials from the fluid passage 2390 into the fluid passage 2405 .
- the fluid passage 2395is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the hydraulic slips body 2320preferably includes fluid passage 2400 that are adapted to convey fluidic materials from the fluid passage 2395 into the pressure chambers 2420 of the hydraulic slips 2325 . In this manner, the slips 2325 are activated upon the pressurization of the fluid passage 2395 into contact with the inside surface of the casing 2375 .
- the fluid passages 2400are adapted to convey fluidic materials such as, for example, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the slips 2325are coupled to the outside surface of the hydraulic slip body 2320 . During operation of the apparatus 2300 , the slips 2325 are activated upon the pressurization of the fluid passage 2395 into contact with the inside surface of the casing 2375 . In this manner, the slips 2325 maintain the casing 2375 in a substantially stationary position.
- the slips 2325preferably include the fluid passages 2400 , the pressure chambers 2420 , spring bias 2425 , and slip members 2430 .
- the slips 2325may comprise any number of conventional commercially available hydraulic slips such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L retrievable bridge plug with hydraulic slips.
- the slips 2325comprise RTTS packer tungsten carbide hydraulic slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the casing 2375 during the radial expansion process.
- the inner sealing mandrel 2330is coupled to the hydraulic slip body 2320 and the lower sealing head 2340 .
- the inner sealing mandrel 2330preferably comprises a substantially hollow tubular member or members.
- the inner sealing mandrel 2330may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the inner sealing mandrel 2330is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the inner sealing mandrel 2330may be coupled to the hydraulic slip body 2320 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the inner sealing mandrel 2330is removably coupled to the hydraulic slip body 2320 by a standard threaded connection.
- the inner sealing mandrel 2330may be coupled to the lower sealing head 2340 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the inner sealing mandrel 2330is removably coupled to the lower sealing head 2340 by a standard threaded connection.
- the inner sealing mandrel 2330preferably includes a fluid passage 2405 that is adapted to convey fluidic materials from the fluid passage 2395 into the fluid passage 2415 .
- the fluid passage 2405is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the upper sealing head 2335is coupled to the outer sealing mandrel 2345 and expansion cone 2355 .
- the upper sealing head 2335is also movably coupled to the outer surface of the inner sealing mandrel 2330 and the inner surface of the casing 2375 . In this manner, the upper sealing head 2335 reciprocates in the axial direction.
- the radial clearance between the inner cylindrical surface of the upper sealing head 2335 and the outer surface of the inner sealing mandrel 2330may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of the upper sealing head 2335 and the outer surface of the inner sealing mandrel 2330 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal clearance.
- the radial clearance between the outer cylindrical surface of the upper sealing head 2335 and the inner surface of the casing 2375may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of the upper sealing head 2335 and the inner surface of the casing 2375 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 2355 during the expansion process.
- the upper sealing head 2335preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the upper sealing head 2335may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the upper sealing head 2335is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the inner surface of the upper sealing head 2335preferably includes one or more annular sealing members 2435 for sealing the interface between the upper sealing head 2335 and the inner sealing mandrel 2330 .
- the sealing members 2435may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2435comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the upper sealing head 2335includes a shoulder 2440 for supporting the upper sealing head on the lower sealing head 1930 .
- the upper sealing head 2335may be coupled to the outer sealing mandrel 2350 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the upper sealing head 2335is removably coupled to the outer sealing mandrel 2350 by a standard threaded connection.
- the mechanical coupling between the upper sealing head 2335 and the outer sealing mandrel 2350includes one or more sealing members 2445 for fluidicly sealing the interface between the upper sealing head 2335 and the outer sealing mandrel 2350 .
- the sealing members 2445may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2445comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the lower sealing head 2340is coupled to the inner sealing mandrel 2330 and the load mandrel 2345 .
- the lower sealing head 2340is also movably coupled to the inner surface of the outer sealing mandrel 2350 .
- the upper sealing head 2335 and outer sealing mandrel 2350reciprocate in the axial direction.
- the radial clearance between the outer surface of the lower sealing head 2340 and the inner surface of the outer sealing mandrel 2350may range, for example, from about 0.0025 to 0.05 inches.
- the radial clearance between the outer surface of the lower sealing head 2340 and the inner surface of the outer sealing mandrel 2350ranges from about 0.005 to 0.010 inches in order to optimally provide minimal radial clearance.
- the lower sealing head 2340preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the lower sealing head 2340may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubular members, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the lower sealing head 2340is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the outer surface of the lower sealing head 2340preferably includes one or more annular sealing members 2450 for sealing the interface between the lower sealing head 2340 and the outer sealing mandrel 2350 .
- the sealing members 2450may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2450comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 2340may be coupled to the inner sealing mandrel 2330 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular specialty threaded connection, welding, amorphous bonding, or standard threaded connection.
- the lower sealing head 2340is removably coupled to the inner sealing mandrel 2330 by a standard threaded connection.
- the mechanical coupling between the lower sealing head 2340 and the inner sealing mandrel 2330includes one or more-sealing members 2455 for fluidicly sealing the interface between the lower sealing head 2340 and the inner sealing mandrel 2330 .
- the sealing members 2455may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak or metal spring energized seals.
- the sealing members 2455comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke length.
- the lower sealing head 2340may be coupled to the load mandrel 2345 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection.
- the lower sealing head 2340is removably coupled to the load mandrel 2345 by a standard threaded connection.
- the mechanical coupling between the lower sealing head 2340 and the load mandrel 2345includes one or more sealing members 2460 for fluidicly sealing the interface between the lower sealing head 2340 and the load mandrel 2345 .
- the sealing members 2460may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2460comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke length.
- the lower sealing head 2340includes a throat passage 2465 fluidicly coupled between the fluid passages 2405 and 2415 .
- the throat passage 2465is preferably of reduced size and is adapted to receive and engage with a plug 2470 , or other similar device. In this manner, the fluid passage 2405 is fluidicly isolated from the fluid passage 2415 . In this manner, the pressure chamber 2475 is pressurized.
- the outer sealing mandrel 2350is coupled to the upper sealing head 2335 and the expansion cone 2355 .
- the outer sealing mandrel 2350is also movably coupled to the inner surface of the casing 2375 and the outer surface of the lower sealing head 2340 . In this manner, the upper sealing head 2335 , outer sealing mandrel 2350 , and the expansion cone 2355 reciprocate in the axial direction.
- the radial clearance between the outer surface of the outer sealing mandrel 2350 and the inner surface of the casing 2375may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer surface of the outer sealing mandrel 2350 and the inner surface of the casing 2375ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 2355 during the expansion process.
- the radial clearance between the inner surface of the outer sealing mandrel 2350 and the outer surface of the lower sealing head 2340may range, for example, from about 0.0025 to 0.375 inches.
- the radial clearance between the inner surface of the outer sealing mandrel 2350 and the outer surface of the lower sealing head 2340ranges from about 0.005 to 0.010 inches in order to optimally provide minimal clearance.
- the outer sealing mandrel 2350preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the outer sealing mandrel 2350may be fabricated from any number of conventional commercially available materials such as, for example, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the outer sealing mandrel 2350is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the outer sealing mandrel 2350may be coupled to the upper sealing head 2335 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connections, oilfield country tubular goods specialty threaded connections, welding, amorphous bonding, or a standard threaded connection.
- the outer sealing mandrel 2350is removably coupled to the upper sealing head 2335 by a standard threaded connection.
- the outer sealing mandrel 2350may be coupled to the expansion cone 2355 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the outer sealing mandrel 2350is removably coupled to the expansion cone 2355 by a standard threaded connection.
- the upper sealing head 2335 , the lower sealing head 2340 , the inner sealing mandrel 2330 , and the outer sealing mandrel 2350together define a pressure chamber 2475 .
- the pressure chamber 2475is fluidicly coupled to the passage 2405 via one or more passages 2410 .
- the plug 2470engages with the throat passage 2465 to fluidicly isolate the fluid passage 2415 from the fluid passage 2405 .
- the pressure chamber 2475is then pressurized which in turn causes the upper sealing head 2335 , outer sealing mandrel 2350 , and expansion cone 2355 to reciprocate in the axial direction.
- the axial motion of the expansion cone 2355in turn expands the casing 2375 in the radial direction.
- the load mandrel 2345is coupled to the lower sealing head 2340 and the mechanical slip body 2360 .
- the load mandrel 2345preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the load mandrel 2345may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the load mandrel 2345is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the load mandrel 2345may be coupled to the lower sealing head 2340 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, the load mandrel 2345 is removably coupled to the lower sealing head 2340 by a standard threaded connection.
- the load mandrel 2345may be coupled to the mechanical slip body 2360 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, the load mandrel 2345 is removably coupled to the mechanical slip body 2360 by a standard threaded connection.
- the load mandrel 2345preferably includes a fluid passage 2415 that is adapted to convey fluidic materials from the fluid passage 2405 to the region outside of the apparatus 2300 .
- the fluid passage 2415is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the expansion cone 2355is coupled to the outer sealing mandrel 2350 .
- the expansion cone 2355is also movably coupled to the inner surface of the casing 2375 . In this manner, the upper sealing head 2335 , outer sealing mandrel 2350 , and the expansion cone 2355 reciprocate in the axial direction. The reciprocation of the expansion cone 2355 causes the casing 2375 to expand in the radial direction.
- the expansion cone 2355preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces.
- the outside radius of the outside conical surfacemay range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 inches in order to optimally provide radial expansion of the typical casings.
- the axial length of the expansion cone 2355may range, for example, from about 2 to 8 times the largest outside diameter of the expansion cone 2355 . In an exemplary embodiment, the axial length of the expansion cone 2355 ranges from about 3 to 5 times the largest outside diameter of the expansion cone 2355 in order to optimally provide stability and centralization of the expansion cone 2355 during the expansion process.
- the angle of attack of the expansion cone 2355ranges from about 5 to 30 degrees in order to optimally fractional forces with radial expansion forces.
- the optimum angle of attack of the expansion cone 2355will vary as a function of the operating parameters of the particular expansion operation.
- the expansion cone 2355may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramics or other similar high strength materials.
- the expansion cone 2355is fabricated from D2 machine tool steel in order to optimally provide high strength, abrasion resistance, and galling resistance.
- the outside surface of the expansion cone 2355has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide high strength, abrasion resistance, resistance to galling.
- the expansion cone 2355may be coupled to the outside sealing mandrel 2350 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection, in an exemplary embodiment, the expansion cone 2355 is coupled to the outside sealing mandrel 2350 using a standard threaded connection in order to optimally provide high strength and permit the expansion cone 2355 to be easily replaced.
- the mandrel launcher 2480is coupled to the casing 2375 .
- the mandrel launcher 2480comprises a tubular section of casing having a reduced wall thickness compared to the casing 2375 .
- the wall thickness of the mandrel launcher 2480is about 50 to 100% of the wall thickness of the casing 2375 . In this manner, the initiation of the radial expansion of the casing 2375 is facilitated, and the placement of the apparatus 2300 into a wellbore casing and wellbore is facilitated.
- the mandrel launcher 2480may be coupled to the casing 2375 using any number of conventional mechanical couplings.
- the mandrel launcher 2480may have a wall thickness ranging, for example, from about 0.15 to 1.5 inches. In an exemplary embodiment, the wall thickness of the mandrel launcher 2480 ranges from about 0.25 to 0.75 inches in order to optimally provide high strength in a minimal profile.
- the mandrel launcher 2480may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the mandrel launcher 2480is fabricated from oilfield tubular goods having a higher strength than that of the casing 2375 but with a smaller wall thickness than the casing 2375 in order to optimally provide a thin walled container having approximately the same burst strength as that of the casing 2375 .
- the mechanical slip body 2460is coupled to the load mandrel 2345 , the mechanical slips 2365 , and the drag blocks 2370 .
- the mechanical slip body 2460preferably comprises a tubular member having an inner passage 2485 fluidicly coupled to the passage 2415 . In this manner, fluidic materials may be conveyed from the passage 2484 to a region outside of the apparatus 2300 .
- the mechanical slip body 2360may be coupled to the load mandrel 2345 using any number of conventional mechanical couplings. In an exemplary embodiment, the mechanical slip body 2360 is removably coupled to the load mandrel 2345 using threads and sliding steel retaining rings in order to optimally provide a high strength attachment.
- the mechanical slip body 2360may be coupled to the mechanical slips 2365 using any number of conventional mechanical couplings. In an exemplary embodiment, the mechanical slip body 2360 is removably coupled to the mechanical slips 2365 using threads and sliding steel retaining rings in order to optimally provide a high strength attachment.
- the mechanical slip body 2360may be coupled to the drag blocks 2370 using any number of conventional mechanical couplings. In an exemplary embodiment, the mechanical slip body 2360 is removably coupled to the drag blocks 2365 using threads and sliding steel retaining rings in order to optimally provide a high strength attachment.
- the mechanical slips 2365are coupled to the outside surface of the mechanical slip body 2360 .
- the mechanical slips 2365prevent upward movement of the casing 2375 and mandrel launcher 2480 .
- the casing 2375 and mandrel launcher 2480are maintained in a substantially stationary position.
- the mandrel launcher 2480 and casing 2375are expanded in the radial direction by the axial movement of the expansion cone 2355 .
- the mechanical slips 2365may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L retrievable bridge plug tungsten carbide upper mechanical slips.
- the mechanical slips 2365comprise RTTS packer tungsten carbide mechanical slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the casing 2375 during the expansion process.
- the drag blocks 2370are coupled to the outside surface of the mechanical slip body 2360 .
- the drag blocks 2370prevent upward movement of the casing 2375 and mandrel launcher 2480 .
- the casing 2375 and mandrel launcher 2480are maintained in a substantially stationary position.
- the mandrel launcher 2480 and casing 2375are expanded in the radial direction by the axial movement of the expansion cone 2355 .
- the drag blocks 2370may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer mechanical drag blocks or Model 3L retrievable bridge plug drag blocks.
- the drag blocks 2370comprise RTTS packer mechanical drag blocks available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the casing 2375 during the expansion process.
- the casing 2375is coupled to the mandrel launcher 2480 .
- the casing 2375is further removably coupled to the mechanical slips 2365 and drag blocks 2370 .
- the casing 2375preferably comprises a tubular member.
- the casing 2375may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oil country tubular goods, carbon steel, low alloy steel, stainless steel or other similar high strength materials.
- the casing 2375is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength.
- the upper end of the casing 2375includes one or more sealing members positioned about the exterior of the casing 2375 .
- the apparatus 2300is positioned in a wellbore with the upper end of the casing 2375 positioned in an overlapping relationship within an existing wellbore casing.
- the fluid passage 2380is preferably provided with one or more pressure relief passages.
- the casing 2375is supported by the expansion cone 2355 .
- a first fluidic materialis pumped into the fluid passage 2380 from a surface location.
- the first fluidic materialis conveyed from the fluid passage 2380 to the fluid passages 2385 , 2390 , 2395 , 2405 , 2415 , and 2485 .
- the first fluidic materialwill then exit the apparatus 2300 and fill the annular region between the outside of the apparatus 2300 and the interior walls of the bore hole.
- the first fluidic materialmay comprise any number of conventional commercially available materials such as, for example, epoxy, drilling mud, slag mix, cement, or water.
- the first fluidic materialcomprises a hardenable fluidic sealing material such as, for example, slag mix, epoxy, or cement. In this manner, a wellbore casing having an outer annular layer of a hardenable material may be formed.
- the first fluidic materialmay be pumped into the apparatus 2300 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi, and 0 to 3,000 gallons/minute. In an exemplary embodiment, the first fluidic material is pumped into the apparatus 2300 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency.
- a plug 2470 , dart, or other similar deviceis introduced into the first fluidic material.
- the plug 2470lodges in the throat passage 2465 thereby fluidicly isolating the fluid passage 2405 from the fluid passage 2415 .
- a second fluidic materialis pumped into the fluid passage 2380 in order to pressurize the pressure chamber 2475 .
- the second fluidic materialmay comprise any number of conventional commercially available materials such as, for example, water, drilling gases, drilling mud or lubricants.
- the second fluidic materialcomprises a non-hardenable fluidic material such as, for example, water, drilling mud or lubricant.
- the second fluidic materialmay be pumped into the apparatus 2300 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute.
- the second fluidic materialis pumped into the apparatus 2300 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency.
- the pressurization of the pressure chamber 2475causes the upper sealing head 2335 , outer sealing, mandrel 2350 , and expansion cone 2355 to move in an axial direction.
- the pressurization of the pressure chamber 2475also causes the hydraulic slips 2325 to expand in the radial direction and hold the casing 2375 in a substantially stationary position.
- the expansion cone 2355pulls the mandrel launcher 2480 and drag blocks 2370 along, which sets the mechanical slips 2365 and stops further axial movement of the mandrel launcher 2480 and casing 2375 . In this manner, the axial movement of the expansion cone 2355 radially expands the mandrel launcher 2480 and casing 2375 .
- the operating pressure of the second fluidic materialis reduced.
- the reduction in the operating pressure of the second fluidic materialreleases the hydraulic slips 2325 .
- the drill string 2305is then raised. This causes the inner sealing mandrel 2330 , lower sealing head 2340 , load mandrel 2345 , and mechanical slip body 2360 to move upward. This unsets the mechanical slips 2365 and permits the mechanical slips 2365 and drag blocks 2370 to be moved within the mandrel launcher 2480 and casing 2375 .
- the second fluidic materialis again pressurized and the radial expansion process continues.
- the mandrel launcher 2480 and casing 2375are radial expanded through repeated axial strokes of the upper sealing head 2335 , outer sealing mandrel 2350 and expansion cone 2355 .
- Throughput the radial expansion process, the upper end of the casing 2375is preferably maintained in an overlapping relation with an existing section of wellbore casing.
- the upper end of the casing 2375is expanded into intimate contact with the inside surface of the lower end of the existing wellbore casing.
- the sealing members provided at the upper end of the casing 2375provide a fluidic seal between the outside surface of the upper end of the casing 2375 and the inside surface of the lower end of the existing wellbore casing.
- the contact pressure between the casing 2375 and the existing section of wellbore casingranges from about 400 to 10,000 psi in order to optimally provide contact pressure, activate the sealing members, and withstand typical tensile and compressive loading conditions.
- the apparatus 2300includes a shock absorber for absorbing the shock created by the completion of the radial expansion of the casing 2375 .
- the reduced operating pressure of the second fluidic materialranges from about 100 to 1,000 psi as the expansion cone 2355 nears the end of the casing 2375 in order to optimally provide reduced axial movement and velocity of the expansion cone 2355 .
- the operating pressure of the second fluidic materialis reduced during the return stroke of the apparatus 2300 to the range of about 0 to 500 psi in order minimize the resistance to the movement of the expansion cone 2355 during the return stroke.
- the stroke length of the apparatus 2300ranges from about 10 to 45 feet in order to optimally provide equipment that can be handled by typical oil well rigging equipment and minimize the frequency at which the expansion cone 2355 must be stopped to permit the apparatus 2300 to be re-stroked.
- At least a portion of the upper sealing head 2335includes an expansion cone for radially expanding the mandrel launcher 2480 and casing 2375 during operation of the apparatus 2300 in order to increase the surface area of the casing 2375 acted upon during the radial expansion process, in this manner, the operating pressures can be reduced.
- mechanical slips 2365are positioned in an axial location between the sealing sleeve 2315 and the inner sealing mandrel 2330 in order to optimally the construction and operation of the apparatus 2300 .
- the first fluidic materialis permitted to cure within the annular region between the outside of the expanded casing 2375 and the interior walls of the wellbore.
- the cured fluidic materialpreferably permeates and envelops the expanded casing 2375 .
- a new section of wellbore casingis formed within a wellbore.
- the apparatus 2300may be used to join a first section of pipeline to an existing section of pipeline.
- the apparatus 2300may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material.
- the apparatus 2300may be used to expand a tubular support member in a hole.
- the pressurized areas of the apparatus 2300are limited to the fluid passages 2380 , 2385 , 2390 , 2395 , 2400 , 2405 , and 2410 , and the pressure chamber 2475 .
- No fluid pressureacts directly on the mandrel launcher 2480 and casing 2375 . This permits the use of operating pressures higher than the mandrel launcher 2480 and casing 2375 could normally withstand.
- the apparatus 2500preferably includes a drillpipe 2505 , an innerstring adapter 2510 , a sealing sleeve 2515 , a hydraulic slip body 2520 , hydraulic slips 2525 , an inner sealing mandrel 2530 , upper sealing head 2535 , lower sealing head 2540 , outer sealing mandrel 2545 , load mandrel 2550 , expansion cone 2555 , casing 2550 , and fluid passages 2565 , 2570 , 2575 , 2580 , 2585 , 2590 , 2595 , and 2600 .
- the drillpipe 2505is coupled to the innerstring adapter 2510 . During operation of the apparatus 2500 , the drillpipe 2505 supports the apparatus 2500 .
- the drillpipe 2505preferably comprises a substantially hollow tubular member or members.
- the drillpipe 2505may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the drillpipe 2505is fabricated from coiled tubing in order to facilitate the placement of the apparatus 2500 in non-vertical wellbores.
- the drillpipe 2505may be coupled to the innerstring adapter 2510 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection.
- the drillpipe 2505is removably coupled to the innerstring adapter 2510 by a drillpipe connection, a drillpipe connection provides the advantages of high strength and easy disassembly.
- the drillpipe 2505preferably includes a fluid passage 2565 that is adapted to convey fluidic materials from a surface location into the fluid passage 2570 .
- the fluid passage 2565is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the innerstring adapter 2510is coupled to the drill string 2505 and the sealing sleeve 2515 .
- the innerstring adapter 2510preferably comprises a substantially hollow tubular member or members.
- the innerstring adapter 2510may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the innerstring adapter 2510is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the innerstring adapter 2610may be coupled to the drill string 2505 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the innerstring adapter 2510is removably coupled to the drill pipe 2505 by a drillpipe connection.
- the innerstring adapter 2510may be coupled to the sealing sleeve 2515 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the innerstring adapter 2510is removably coupled to the sealing sleeve 2515 by a standard threaded connection.
- the innerstring adapter 2510preferably includes a fluid passage 2570 that is adapted to convey fluidic materials from the fluid passage 2565 into the fluid passage 2575 .
- the fluid passage 2570is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the sealing sleeve 2515is coupled to the innerstring adapter 2510 and the hydraulic slip body 2520 .
- the sealing sleeve 2515preferably comprises a substantially hollow tubular member or members.
- the sealing sleeve 2515may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the sealing sleeve 2515is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low-friction surfaces.
- the sealing sleeve 2515may be coupled to the innerstring adapter 2510 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connections, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the sealing sleeve 2515is removably coupled to the innerstring adapter 2510 by a standard threaded connection.
- the sealing sleeve 2515may be coupled to the hydraulic slip body 2520 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the sealing sleeve 2515is removably coupled to the hydraulic slip body 2520 by a standard threaded connection.
- the sealing sleeve 2515preferably includes a fluid passage 2575 that is adapted to convey fluidic materials from the fluid passage 2570 into the fluid passage 2580 .
- the fluid passage 2575is adapted to convey fluidic materials such as, for example, cement, epoxy, wafer, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the hydraulic slip body 2520is coupled to the sealing sleeve 2515 , the hydraulic slips 2525 , and the inner sealing mandrel 2530 .
- the hydraulic slip body 2520preferably comprises a substantially hollow tubular member or members.
- the hydraulic slip body 2520may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the hydraulic slip body 2520is fabricated from carbon steel in order to optimally provide high strength.
- the hydraulic slip body 2520may be coupled to the sealing sleeve 2515 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the hydraulic slip body 2520is removably coupled to the sealing sleeve 2515 by a standard threaded, connection.
- the hydraulic slip body 2520may be coupled to the slips 2525 using any number of conventional commercially available mechanical couplings such as, for example, threaded connection or welding.
- the hydraulic slip body 2520is removably coupled to the slips 2525 by a threaded connection.
- the hydraulic slip body 2520may be coupled to the inner sealing mandrel 2530 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection.
- the hydraulic slip body 2520is removably coupled to the inner sealing mandrel 2530 by a standard threaded connection.
- the hydraulic slips body 2520preferably includes a fluid passage 2580 that is adapted to convey fluidic materials from the fluid passage 2575 into the fluid passage 2590 .
- the fluid passage 2580is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the hydraulic slips body 2520preferably includes fluid passages 2585 that are adapted to convey fluidic materials from the fluid passage 2580 into the pressure chambers of the hydraulic slips 2525 . In this manner, the slips 2525 are activated upon the pressurization of the fluid passage 2580 into contact with the inside surface of the casing 2660 .
- the fluid passages 2585are adapted to convey fluidic materials such as* for example, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the slips 2525are coupled to the outside surface of the hydraulic slip body 2520 . During operation of the apparatus 2500 , the slips 2525 are activated upon the pressurization of the fluid passage 2580 into contact with the inside surface of the casing 2560 . In this manner, the slips 2525 maintain the casing 2560 in a substantially stationary position.
- the slips 2525preferably include the fluid passages 2585 , the pressure chambers 2605 , spring bias 2610 , and slip members 2615 .
- the slips 2525may comprise any number of conventional commercially available hydraulic slips such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L retrievable bridge plug with hydraulic slips.
- the slips 2525comprise RTTS packer tungsten carbide hydraulic slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the casing 2560 during the expansion process.
- the inner sealing mandrel 2530is coupled to the hydraulic slip body 2520 and the lower sealing head 2540 .
- the inner sealing mandrel 2530preferably comprises a substantially hollow tubular member or members.
- the inner sealing mandrel 2530may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the inner sealing mandrel 2530is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the inner sealing mandrel 2530may be coupled to the hydraulic slip body 2520 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the inner sealing mandrel 2530is removably coupled to the hydraulic slip body 2520 by a standard threaded connection.
- the inner sealing mandrel 2530may be coupled to the lower sealing head 2540 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty type threaded connection, drillpipe connection, welding, amorphous bonding, or a standard threaded connection.
- the inner sealing mandrel 2530is removably coupled to the lower sealing head 2540 by a standard threaded connection.
- the inner sealing mandrel 2530preferably includes a fluid passage 2590 that is adapted to convey fluidic materials from the fluid passage 2580 into the fluid passage 2600 .
- the fluid passage 2590is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the upper sealing head 2535is coupled to the outer sealing mandrel 2545 and expansion cone 2555 .
- the upper sealing head 2535is also movably coupled to the outer surface of the inner sealing mandrel 2530 and the inner surface of the casing 2560 . In this manner, the upper sealing head 2535 reciprocates in the axial direction.
- the radial clearance between the inner cylindrical surface of the upper sealing head 2535 and the outer surface of the inner sealing mandrel 2530may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of the upper sealing head 2535 and the outer surface of the inner sealing mandrel 2530 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the radial clearance between the outer cylindrical surface of the upper sealing head 2535 and the inner surface of the casing 2560may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of the upper sealing head 2535 and the inner surface of the casing 2560 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 2535 during the expansion process.
- the upper sealing head 2535preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the upper sealing head 2535may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the upper sealing head 2535is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the inner surface of the upper sealing head 2535preferably includes one or more annular sealing members 2620 for sealing the interface between the upper sealing head 2535 and the inner sealing mandrel 2530 .
- the sealing members 2620may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 2620comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the upper sealing head 2535includes a shoulder 2625 for supporting the upper sealing head 2535 , outer sealing mandrel 2545 , and expansion cone 2555 on the lower sealing head 2540 .
- the upper sealing head 2535may be coupled to the outer sealing mandrel 2545 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty threaded connection, pipeline connection, welding, amorphous bonding, or a standard threaded connection.
- the upper sealing head 2535is removably coupled to the outer sealing mandrel 2545 by a standard threaded connection.
- the mechanical coupling between the upper sealing head 2535 and the outer sealing mandrel 2545includes one or more sealing members 2630 for fluidicly sealing the interface between the upper sealing head 2535 and the outer sealing mandrel 2545 .
- the sealing members 2630may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2630comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 2540is coupled to the inner sealing mandrel 2530 and the load mandrel 2550 .
- the lower sealing head 2540is also movably coupled to the inner surface of the outer sealing mandrel 2545 . In this manner, the upper sealing head 2535 , outer sealing mandrel 2545 , and expansion cone 2555 reciprocate in the axial direction.
- the radial clearance between the outer surface of the lower sealing head 2540 and the inner surface of the outer sealing mandrel 2545may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the outer surface of the lower sealing head 2540 and the inner surface of the outer sealing mandrel 2545 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the lower sealing head 2540preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the lower sealing head 2540may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the lower sealing head 2540is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the outer surface of the lower sealing head 2540preferably includes one or more annular sealing members 2635 for sealing the interface between the lower sealing head 2540 and the outer sealing mandrel 2545 .
- the sealing members 2635may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 2635compose polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 2540may be coupled to the inner sealing mandrel 2530 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connections, oilfield country tubular goods specialty threaded connection, or a standard threaded connection.
- the lower sealing head 2540is removably coupled to the inner sealing mandrel 2530 by a standard threaded connection.
- the mechanical coupling between the lower sealing head 2540 and the inner sealing mandrel 2530includes one or more sealing members 2640 for fluidicly sealing the interface between the lower sealing head 2540 and the inner sealing mandrel 2530 .
- the sealing members 2640may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2640comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 2540may be coupled to the load mandrel 2550 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection.
- the lower sealing head 2540is removably coupled to the load mandrel 2550 by a standard threaded connection.
- the mechanical coupling between the lower sealing head 2540 and the load mandrel 2550includes one or more sealing members 2645 for fluidicly sealing the interface between the lower sealing head 2540 and the load mandrel 2550 .
- the sealing members 2645may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2645comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the lower sealing head 2540includes a throat passage 2650 fluidicly coupled between the fluid passages 2590 and 2600 .
- the throat passage 2650is preferably of reduced size and is adapted to receive and engage with a plug 2655 , or other similar device.
- the fluid passage 2590is fluidicly isolated from the fluid passage 2600 .
- the pressure chamber 2660is pressurized.
- the outer sealing mandrel 2545is coupled to the upper sealing head 2535 and the expansion cone 2555 .
- the outer sealing mandrel 2545is also movably coupled to the inner surface of the casing 2560 and the outer surface of the lower sealing head 2540 . In this manner, the upper sealing head 2535 , outer sealing mandrel 2545 , and the expansion cone 2555 reciprocate in the axial direction.
- the radial clearance between the outer surface of the outer sealing mandrel 2545 and the inner surface of the casing 2560may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer surface of the outer sealing mandrel 2545 and the inner surface of the casing 2560ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 2535 during the expansion process.
- the radial clearance between the inner surface of the outer sealing mandrel 2545 and the outer surface of the lower sealing head 2540may range, for example, from about 0.005 to 0.01 inches.
- the radial clearance between the inner surface of the outer sealing mandrel 2545 and the outer surface of the lower sealing head 2540ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the outer sealing mandrel 2545preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the outer sealing mandrel 2545may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the outer sealing mandrel 2545is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the outer sealing mandrel 2545may be coupled to the upper sealing head 2535 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection, in an exemplary embodiment, the outer sealing mandrel 2545 is removably coupled to the upper sealing head 2535 by a standard threaded connection.
- the outer sealing mandrel 2545may be coupled to the expansion cone 2555 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, the outer sealing mandrel 2545 is removably coupled to the expansion cone 2555 by a standard threaded connection.
- the upper sealing head 2535 , the lower sealing head 2540 , the inner sealing mandrel 2530 , and the outer sealing mandrel 2545together define a pressure chamber 2660 .
- the pressure chamber 2660is fluidicly coupled to the passage 2590 via one or more passages 2595 .
- the plug 2655engages with the throat passage 2650 to fluidicly isolate the fluid passage 2590 from the fluid passage 2600 .
- the pressure chamber 2660is then pressurized which in turn causes the upper sealing head 2535 , outer sealing mandrel 2545 , and expansion cone 2555 to reciprocate in the axial direction.
- the axial motion of the expansion cone 2555in turn expands the casing 2560 in the radial direction.
- the load mandrel 2550is coupled to the lower sealing head 2540 .
- the load mandrel 2550preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the load mandrel 2550may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the load mandrel 2550is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the load mandrel 2550may be coupled to the lower sealing head 2540 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods, drillpipe connection, welding, amorphous bonding, or a standard threaded connection.
- the load mandrel 2550is removably coupled to the lower sealing head 2540 by a standard threaded connection.
- the load mandrel 2550preferably includes a fluid passage 2600 that is adapted to convey fluidic materials from the fluid passage 2590 to the region outside of the apparatus 2500 .
- the fluid passage 2600is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging, for example, from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the expansion cone 2555is coupled to the outer sealing mandrel 2545 .
- the expansion cone 2555is also movably coupled to the inner surface of the casing 2560 . In this manner, the upper sealing head 2535 , outer sealing mandrel 2545 , and the expansion cone 2555 reciprocate in the axial direction. The reciprocation of the expansion cone 2555 causes the casing 2560 to expand in the radial direction.
- the expansion cone 2555preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces.
- the outside radius of the outside conical surfacemay range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 in order to optimally provide radial expansion for the widest variety of tubular casings.
- the axial length of the expansion cone 2555may range, for example, from about 2 to 8 times the largest outside diameter of the expansion cone 2535 . In an exemplary embodiment, the axial length of the expansion cone 2535 ranges from about 3 to 5 times the largest outside diameter of the expansion cone 2535 in order to optimally provide stabilization and centralization of the expansion cone 2535 during the expansion process.
- the maximum outside diameter of the expansion cone 2555is between about 95 to 99% of the inside diameter of the existing wellbore that the casing 2560 will be joined with.
- the angle of attack of the expansion cone 2555ranges from about 5 to 30 degrees in order to-optimally balance frictional forces and radial expansion forces. The optimum angle of attack of the expansion cone 2535 will vary as a function of the particular operational features of the expansion operation.
- the expansion cone 2555may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramics or other similar high strength materials.
- the expansion cone 2555is fabricated from D2 machine tool steel in order to optimally provide high strength, and resistance to wear and galling.
- the outside surface of the expansion cone 2555has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide high strength and wear resistance.
- the expansion cone 2555may be coupled to the outside sealing mandrel 2545 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection.
- the expansion cone 2555is coupled to the outside sealing mandrel 2545 using a standard threaded connection in order to optimally provide high strength and easy replacement of the expansion cone 2555 .
- the casing 2560is removably coupled to the slips 2525 and expansion cone 2555 .
- the casing 2560preferably comprises a tubular member.
- the casing 2560may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the casing 2560is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength using standardized materials.
- the upper end 2665 of the casing 2560includes a thin wall section 2670 and an outer annular sealing member 2675 .
- the wall thickness of the thin wall section 2670is about 50 to 100% of the regular wall thickness of the casing 2560 . in this manner, the upper end 2665 of the casing 2560 may be easily radially expanded and deformed into intimate contact with the lower end of an existing section of wellbore casing.
- the lower end of the existing section of casingalso includes a thin wall section. In this manner, the radial expansion of the thin walled section 2670 of casing 2560 into the thin walled section of the existing wellbore casing results in a wellbore casing having a substantially constant inside diameter.
- the annular sealing member 2675may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal, or plastic, in an exemplary embodiment, the annular sealing member 2675 is fabricated from StrataLock epoxy in order to optimally provide compressibility and resistance to wear.
- the outside diameter of the annular sealing member 2675preferably ranges from about 70 to 95% of the inside diameter of the lower section of the wellbore casing that the casing 2560 is joined to. In this manner, after radial expansion, the annular sealing member 2670 optimally provides a fluidic seal and also preferably optimally provides sufficient frictional force with the inside surface of the existing section of wellbore casing during the radial expansion of the casing 2560 to support the casing 2560 .
- the lower end 2680 of the casing 2560includes a thin wall section 2685 and an outer annular sealing member 2690 .
- the wall thickness of the thin wall section 2685is about 50 to 100% of the regular wall thickness of the casing 2560 .
- the lower end 2680 of the casing 2560may be easily expanded and deformed.
- an other section of casingmay be easily joined with the lower end 2680 of the casing 2560 using a radial expansion process.
- the upper end of the other section of casingalso includes a thin wall section. In this manner, the radial expansion of the thin walled section of the upper end of the other casing into the thin walled section 2685 of the lower end 2680 of the casing 2560 results in a wellbore casing having a substantially constant inside diameter.
- the annular sealing member 2690may be fabricated from any number of conventional commercially available sealing materials such as, for example, rubber, metal, plastic or epoxy.
- the annular sealing member 2690is fabricated from StrataLock epoxy in order to optimally provide compressibility and resistance to wear.
- the outside diameter of the annular sealing member 2690preferably ranges from about 70 to 95% of the inside diameter of the lower section of the existing wellbore casing that the casing 2560 is pined to. In this manner, after radial expansion, the annular sealing member 2690 preferably provides a fluidic seal and also preferably provides sufficient frictional force with the inside wall of the wellbore during the radial expansion of the casing 2560 to support the casing 2560 .
- the apparatus 2500is preferably positioned in a wellbore with the upper end 2665 of the casing 2560 positioned in an overlapping relationship with the lower end of an existing wellbore casing.
- the thin wall section 2670 of the casing 2560is positioned in opposing overlapping relation with the thin wall section and outer annular sealing member of the lower end of the existing section of wellbore casing. In this manner, the radial expansion of the casing 2560 will compress the thin wall sections and annular compressible members of the upper end 2565 of the casing 2560 and the lower end of the existing wellbore casing into intimate contact.
- the casing 2560is supported by the expansion cone 2555 .
- the first fluidic materialmay comprise any number of conventional commercially available materials such as, for example, cement, water, slag-mix, epoxy or drilling mud.
- the first fluidic materialcomprises a hardenable fluidic sealing material such as, for example, cement, epoxy, or slag-mix in order to optimally provide a hardenable outer annular body around the expanded casing 2560 .
- the first fluidic materialmay be pumped into the fluid passage 2565 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 3,000 gallons/minute. In an exemplary embodiment, the first fluidic material is pumped into the fluid passage 2565 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency.
- the first fluidic material pumped into the fluid passage 2565passes through the fluid passages 2570 , 2575 , 2580 , 2590 , 2600 and then outside of the apparatus 2500 .
- the first fluidic materialthen preferably fills the annular region between the outside of the apparatus 2500 and the interior walls of the wellbore.
- the plug 2655is then introduced into the fluid passage 2565 .
- the plug 2655lodges in the throat passage 2650 and fluidicly isolates and blocks off the fluid passage 2590 .
- a couple of volumes of a non-hardenable fluidic materialare then pumped into the fluid passage 2565 in order to remove any hardenable fluidic material contained within and to ensure that none of the fluid passages are blocked.
- the second fluidic materialis then pumped into the fluid passage 2565 .
- the second fluidic materialmay comprise any number of conventional commercially available materials such as, for example, water, drilling gases, drilling mud or lubricant.
- the second fluidic materialcomprises a non-hardenable fluidic material such as, for example, water, drilling mud, or lubricant in order to optimally provide pressurization of the pressure chamber 2660 and minimize friction.
- the second fluidic materialmay be pumped into the fluid passage 2565 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute.
- the second fluidic materialis pumped into the fluid passage 2565 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency.
- the second fluidic material pumped into the fluid passage 2565passes through the fluid passages 2570 , 2575 , 2580 , 2590 and into the pressure chambers 2605 of the slips 2525 , and into the pressure chamber 2660 . Continued pumping of the second fluidic material pressurizes the pressure chambers 2605 and 2660 .
- the pressurization of the pressure chambers 2605causes the slip members 2525 to expand in the radial direction and grip the interior surface of the casing 2560 .
- the casing 2560is then preferably maintained in a substantially stationary position.
- the pressurization of the pressure chamber 2660causes the upper sealing head 2535 , outer sealing mandrel 2545 and expansion cone 2555 to move in an axial direction relative to the casing 2560 .
- the expansion cone 2555will cause the casing 2560 to expand in the radial direction, beginning with the lower end 2685 of the casing 2560 .
- the casing 2560is prevented from moving in an upward direction by the slips 2525 .
- a length of the casing 2560is then expanded in the radial direction through the pressurization of the pressure chamber 2660 .
- the length of the casing 2560 that is expanded during the expansion processwill be proportional to the stroke length of the upper sealing head 2535 , outer sealing mandrel 2545 , and expansion cone 2555 .
- the operating pressure of the second fluidic materialis reduced and the upper sealing head 2535 , outer sealing mandrel 2545 , and expansion cone 2555 drop to their rest positions with the casing 2560 supported by the expansion cone 2555 .
- the position of the drillpipe 2505is preferably adjusted throughout the radial expansion process in order to maintain the overlapping relationship between the thin walled sections of the lower end of the existing wellbore casing and the upper end of the casing 2560 .
- the stroking of the expansion cone 2555is then repeated, as necessary, until the thin walled section 2670 of the upper end 2665 of the casing 2560 is expanded into the thin waited section of the lower end of the existing wellbore casing. In this manner a wellbore casing is formed including two adjacent sections of casing having a substantially constant inside diameter. This process may then be repeated for the entirety of the wellbore to provide a wellbore casing thousands of feet in length having a substantially constant inside diameter.
- the slips 2525are positioned as close as possible to the thin walled section 2670 of the upper end 2665 of the casing 2560 in order minimize slippage between the casing 2560 and the existing wellbore casing at the end of the radial expansion process.
- the outside diameter of the annular sealing member 2675is selected to ensure sufficient interference fit with the inside diameter of the lower end of the existing casing to prevent axial displacement of the casing 2560 during the final stroke.
- the outside diameter of the annular sealing member 2690is selected to provide an interference fit with the inside walls of the wellbore at an earlier point in the radial expansion process so as to prevent further axial displacement of the casing 2560 .
- the interference fitis preferably selected to permit expansion of the casing 2560 by pulling the expansion cone 2555 out of the wellbore, without having to pressurize the pressure chamber 2660 .
- the pressurized areas of the apparatus 2500are preferably limited to the fluid passages 2565 , 2570 , 2575 , 2580 , and 2590 , the pressure chambers 2605 within the slips 2526 , and the pressure chamber 2660 .
- No fluid pressureacts directly on the casing 2560 . This permits the use of operating pressures higher than the casing 2560 could normally withstand.
- the contact pressure between the deformed thin wall sections and compressible annular members of the lower end of the existing casing and the upper end 2665 of the casing 2560ranges from about 400 to 10,000 psi In order to optimally support the casing 2560 using the existing wellbore casing.
- the casing 2560is radially expanded into contact with an existing section of casing by pressurizing the interior fluid passages 2565 , 2570 , 2575 , 2580 , and 2590 , the pressure chambers of the slips 2605 and the pressure chamber 2660 of the apparatus 2500 .
- the annular body of hardenable fluidic materialis then allowed to cure to form a rigid outer annular body about the expanded casing 2560 .
- the cured fluidic materialpreferably permeates and envelops the expanded casing 2560 .
- the resulting new section of wellbore casingincludes the expanded casing 2560 and the rigid outer annular body.
- the overlapping joint between the pre-existing wellbore casing and the expanded casing 2560includes the deformed thin wall sections and the compressible outer annular bodies.
- the inner diameter of the resulting combined wellbore casingsis substantially constant, in this manner, a mono-diameter wellbore casing is formed.
- This process of expanding overlapping tubular members having thin wall end portions with compressible annular bodies into contactcan be repeated for the entire length of a wellbore.
- a mono-diameter wellbore casingcan be provided for thousands of feet in a subterranean formation.
- the apparatus 2500includes a shock absorber for absorbing the shock created by the completion of the radial expansion of the casing 2560 .
- the reduced operating pressure of the second fluidic materialranges from about 100 to 1,000 psi as the expansion cone 2555 nears the end of the casing 2560 in order to optimally provide reduced axial movement and velocity of the expansion cone 2555 .
- the operating pressure of the second fluidic materialis reduced during the return stroke of the apparatus 2500 to the range of about 0 to 500 psi in order minimize the resistance to the movement of the expansion cone 2555 during the return stroke.
- the stroke length of the apparatus 2500ranges from about 10 to 45 feet in order to optimally provide equipments lengths that can be easily handled using typical oil well rigging equipment and also minimize the frequency at which apparatus 2500 must be re-stroked.
- At least a portion of the upper sealing head 2535includes an expansion cone for radially expanding the casing 2560 during operation of the apparatus 2500 in order to increase the surface area of the casing 2560 acted upon during the radial expansion process. In this manner, the operating pressures can be reduced.
- the apparatus 2500may be used to join a first section of pipeline to an existing section of pipeline.
- the apparatus 2500may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material.
- the apparatus 2500may be used to expand a tubular support member in a hole.
- the apparatus 2700preferably includes a drillpipe 2705 , an innerstring adapter 2710 , a sealing sleeve 2715 , a first inner sealing mandrel 2720 , a first upper sealing head 2725 , a first lower sealing head 2730 , a first outer sealing mandrel 2735 , a second inner sealing mandrel 2740 , a second upper sealing head 2745 , a second lower sealing head 2750 , a second outer sealing mandrel 2755 , a load mandrel 2760 , an expansion cone 2765 , a mandrel launcher 2770 , a mechanical slip body 2775 , mechanical slips 2780 , drag blocks 2785 , casing 2790 , and fluid passages 2795 , 2800 , 2805 , 2810 , 2815 , 2820 , 2825 , and
- the drillpipe 2705is coupled to the innerstring adapter 2710 .
- the drillpipe 2705supports the apparatus 2700 .
- the drillpipe 2705preferably comprises a substantially hollow tubular member or members.
- the drillpipe 2705may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength materials.
- the drillpipe 2705is fabricated from coiled tubing in order to facilitate the placement of the apparatus 2700 in non-vertical wellbores.
- the drillpipe 2705may be coupled to the innerstring adapter 2710 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection.
- the drillpipe 2705is removably coupled to the innerstring adapter 2710 by a drillpipe connection in order to optimally provide high strength and easy disassembly.
- the drillpipe 2705preferably includes a fluid passage 2795 that is adapted to convey fluidic materials from a surface location into the fluid passage 2800 .
- the fluid passage 2795is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the innerstring adapter 2710is coupled to the drill string 2705 and the sealing sleeve 2715 .
- the innerstring adapter 2710preferably comprises a substantially hollow tubular member or members.
- the innerstring adapter 2710may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the innerstring adapter 2710is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the innerstring adapter 2710may be coupled to the drill string 2705 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection.
- the innerstring adapter 2710is removably coupled to the drill pipe 2705 by a standard threaded connection in order to optimally provide high strength and easy disassembly.
- the innerstring adapter 2710may be coupled to the sealing sleeve 2715 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the innerstring adapter 2710is removably coupled to the sealing sleeve 2715 by a standard threaded connection.
- the innerstring adapter 2710preferably includes a fluid passage 2800 that is adapted to convey fluidic materials from the fluid passage 2795 into the fluid passage 2805 .
- the fluid passage 2800is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the sealing sleeve 2715is coupled to the innerstring adapter 2710 and the first inner sealing mandrel 2720 .
- the sealing sleeve 2715preferably comprises a substantially hollow tubular member or members.
- the sealing sleeve 2715may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the sealing sleeve 2715is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the sealing sleeve 2715may be coupled to the innerstring adapter 2710 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the sealing sleeve 2715is removably coupled to the innerstring adapter 2710 by a standard threaded connector.
- the sealing sleeve 2715may be coupled to the first inner sealing mandrel 2720 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection.
- the sealing sleeve 2715is removably coupled to the inner sealing mandrel 2720 by a standard threaded connection.
- the sealing sleeve 2715preferably includes a fluid passage 2802 that is adapted to convey fluidic materials from the fluid passage 2800 into the fluid passage 2805 .
- the fluid passage 2802is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the first inner sealing mandrel 2720is coupled to the sealing sleeve 2715 and the first lower sealing head 2730 .
- the first inner sealing mandrel 2720preferably comprises a substantially hollow tubular member or members.
- the first inner sealing mandrel 2720may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the first inner sealing mandrel 2720is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the first inner sealing mandrel 2720may be coupled to the sealing sleeve 2715 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the first inner sealing mandrel 2720is removably coupled to the sealing sleeve 2715 by a standard threaded connection.
- the first inner sealing mandrel 2720may be coupled to the first lower sealing head 2730 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the first inner sealing mandrel 2720is removably coupled to the first lower sealing head 2730 by a standard threaded connection.
- the first inner sealing mandrel 2720preferably includes a fluid passage 2805 that is adapted to convey fluidic materials from the fluid passage 2802 into the fluid passage 2810 .
- the fluid passage 2805is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the first upper sealing head 2725is coupled to the first outer sealing mandrel 2735 , the second upper sealing head 2745 , the second outer sealing mandrel 2755 , and the expansion cone 2765 .
- the first upper sealing head 2725is also movably coupled to the outer surface of the first inner sealing mandrel 2720 and the inner surface of the casing 2790 . In this manner, the first upper sealing head 2725 reciprocates in the axial direction.
- the radial clearance between the inner cylindrical surface of the first upper sealing head 2725 and the outer surface of the first inner sealing mandrel 2720may range, for example, from about 0.0025 to 0.05 inches.
- the radial clearance between the inner cylindrical surface of the first upper sealing head 2725 and the outer surface of the first inner sealing mandrel 2720ranges from about 0.005 to 0.125 inches in order to optimally provide minimal radial clearance.
- the radial clearance between the outer cylindrical surface of the first upper sealing head 2725 and the inner surface of the casing 2790may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer cylindrical surface of the first upper sealing head 2725 and the inner surface of the casing 2790ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 2765 during the expansion process.
- the first upper sealing head 2725preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the first upper sealing head 2725may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the first upper sealing head 2725is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance and low friction surfaces.
- the inner surface of the first upper sealing head 2725preferably includes one or more annular sealing members 2835 for sealing the interface between the first upper sealing head 2725 and the first inner sealing mandrel 2720 .
- the sealing members 2835may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2835comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the first upper sealing head 2725includes a shoulder 2840 for supporting the first upper sealing head 2725 on the first lower sealing head 2730 .
- the first upper sealing head 2725may be coupled to the first outer sealing mandrel 2735 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection.
- the first upper sealing head 2725is removably coupled to the first outer sealing mandrel 2735 by a standard threaded connection.
- the mechanical coupling between the first upper sealing head 2725 and the first outer sealing mandrel 2735includes one or more sealing members 2845 for fluidicly sealing the interface between the first upper sealing head 2725 and the first outer sealing mandrel 2735 .
- the sealing members 2845may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2845comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the first lower sealing head 2730is coupled to the first inner sealing mandrel 2720 and the second inner sealing mandrel 2740 .
- the first lower sealing head 2730is also movably coupled to the inner surface of the first outer sealing mandrel 2735 .
- the radial clearance between the outer surface of the first lower sealing head 2730 and the inner surface of the first outer sealing mandrel 2735may range, for example, from about 0.0025 to 0.05 inches.
- the radial clearance between the outer surface of the first lower sealing head 2730 and the inner surface of the first outer sealing mandrel 2735ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the first lower sealing head 2730preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the first lower sealing head 2730may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the first lower sealing head 2730is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the outer surface of the first lower sealing head 2730preferably includes one or more annular sealing members 2850 for sealing the interface between the first lower sealing head 2730 and the first outer sealing mandrel 2735 .
- the sealing members 2850may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2850comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the first lower sealing head 2730may be coupled to the first inner sealing mandrel 2720 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty threaded connections, welding, amorphous bonding, or standard threaded connection, in an exemplary embodiment, the first lower sealing head 2730 is removably coupled to the first inner sealing mandrel 2720 by a standard threaded connection.
- the mechanical coupling between the first lower sealing head 2730 and the first inner sealing mandrel 2720includes one or more sealing members 2855 for fluidicly sealing the interface between the first lower sealing head 2730 and the first inner sealing mandrel 2720 .
- the sealing members 2855may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2855comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the first lower sealing head 2730may be coupled to the second inner sealing mandrel 2740 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specially threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the lower sealing head 2730is removably coupled to the second inner sealing mandrel 2740 by a standard threaded connection.
- the mechanical coupling between the first lower sealing head 2730 and the second inner sealing mandrel 2740includes one or more sealing members 2860 for fluidicly sealing the interface between the first lower sealing head 2730 and the second inner sealing mandrel 2740 .
- the sealing members 2860may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2860comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the first outer sealing mandrel 2735is coupled to the first upper sealing head 2725 , the second upper sealing head 2745 , the second outer sealing mandrel 2755 , and the expansion cone 2765 .
- the first outer sealing mandrel 2735is also movably coupled to the inner surface of the casing 2790 and the outer surface of the first lower sealing head 2730 . In this manner, the first upper sealing head 2725 , first outer sealing mandrel 2735 , second upper sealing head 2745 , second outer sealing mandrel 2755 , and the expansion cone 2765 reciprocate in the axial direction.
- the radial clearance between the outer surface of the first outer sealing mandrel 2735 and the inner surface of the casing 2790may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer surface of the first outer sealing mandrel 2735 and the inner surface of the casing 2790 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 2765 during the expansion process.
- the radial clearance between the inner surface of the first outer sealing mandrel 2735 and the outer surface of the first lower sealing head 2730may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner surface of the first outer sealing mandrel 2735 and the outer surface of the first lower sealing head 2730 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the outer sealing mandrel 1935preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the first outer sealing mandrel 2735may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the first outer sealing mandrel 2735is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the first outer sealing mandrel 2735may be coupled to the first upper sealing head 2725 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods, welding, amorphous bonding, or a standard threaded connection, in an exemplary embodiment, the first outer sealing mandrel 2735 is removably coupled to the first upper sealing head 2725 by a standard threaded connection.
- the first outer sealing mandrel 2735may be coupled to the second upper sealing head 2745 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the first outer sealing mandrel 2735is removably coupled to the second upper sealing head 2745 by a standard threaded connection.
- the second inner sealing mandrel 2740is coupled to the first lower sealing head 2730 and the second lower sealing head 2750 .
- the second inner sealing mandrel 2740preferably comprises a substantially hollow tubular member or members.
- the second inner sealing mandrel 2740may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the second inner sealing mandrel 2740is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the second inner sealing mandrel 2740may be coupled to the first lower sealing head 2730 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the second inner sealing mandrel 2740is removably coupled to the first lower sealing head 2740 by a standard threaded connection.
- the mechanical coupling between the second inner sealing mandrel 2740 and the first lower sealing head 2730preferably includes sealing members 2860 .
- the second inner sealing mandrel 2740may be coupled to the second lower sealing head 2750 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection.
- the second inner sealing mandrel 2720is removably coupled to the second lower sealing head 2750 by a standard threaded connection.
- the mechanical coupling between the second inner sealing mandrel 2740 and the second lower sealing head 2750includes one or more sealing members 2865 .
- the sealing members 2865may comprise any number of conventional commercially available seals such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2865comprise polypak seals available from Parker Seals.
- the second inner sealing mandrel 2740preferably includes a fluid passage 2810 that is adapted to convey fluidic materials from the fluid passage 2805 into the fluid passage 2815 .
- the fluid passage 2810is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the second upper sealing head 2745is coupled to the first upper sealing head 2725 , the first outer sealing mandrel 2735 , the second outer sealing mandrel 2755 , and the expansion cone 2765 .
- the second upper sealing head 2745is also movably coupled to the outer surface of the second inner sealing mandrel 2740 and the inner surface of the casing 2790 . In this manner, the second upper sealing head 2745 reciprocates in the axial direction.
- the radial clearance between the inner cylindrical surface of the second upper sealing head 2745 and the outer surface of the second inner sealing mandrel 2740may range, for example, from about 0.0025 to 0.05 inches.
- the radial clearance between the inner cylindrical surface of the second upper sealing head 2745 and the outer surface of the second inner sealing mandrel 2740ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the radial clearance between the outer cylindrical surface of the second upper sealing head 2745 and the inner surface of the casing 2790may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer cylindrical surface of the second upper sealing head 2745 and the inner surface of the casing 2790ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 2765 during the expansion process.
- the second upper sealing head 2745preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the second upper sealing head 2745may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the second upper sealing head 2745is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the inner surface of the second upper sealing head 2745preferably includes one or more annular sealing members 2870 for sealing the interface between the second upper sealing head 2745 and the second inner sealing mandrel 2740 .
- the sealing members 2870may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals, in an exemplary embodiment, the sealing members 2870 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the second upper sealing head 2745includes a shoulder 2875 for supporting the second upper sealing head 2745 on the second lower sealing head 2750 .
- the second upper sealing head 2745may be coupled to the first outer sealing mandrel 2735 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the second upper sealing head 2745is removably coupled to the first outer sealing mandrel 2735 by a standard threaded connection.
- the mechanical coupling between the second upper sealing head 2745 and the first outer sealing mandrel 2735includes one or more sealing members 2880 for fluidicly sealing the interface between the second upper sealing head 2745 and the first outer sealing mandrel 2735 .
- the sealing members 2880may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2880comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the second upper sealing head 2745may be coupled to the second outer sealing mandrel 2755 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the second upper sealing head 2745is removably coupled to the second outer sealing mandrel 2755 by a standard threaded connection.
- the mechanical coupling between the second upper sealing head 2745 and the second outer sealing mandrel 2755includes one or more sealing members 2885 for fiuldicly sealing the interface between the second upper sealing head 2745 and the second outer sealing mandrel 2755 .
- the sealing members 2885may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2885comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the second lower sealing head 2750is coupled to the second inner sealing mandrel 2740 and the load mandrel 2760 .
- the second lower sealing head 2750is also movably coupled to the inner surface of the second outer sealing mandrel 2755 .
- the first upper sealing head 2725 , the first outer sealing mandrel 2735 , second upper sealing head 2745 , second outer sealing mandrel 2755 , and the expansion cone 2765reciprocate in the axial direction.
- the radial clearance between the outer surface of the second lower sealing head 2750 and the inner surface of the second outer sealing mandrel 2755may range, for example, from about 0.0025 to 0.05 inches.
- the radial clearance between the outer surface of the second lower sealing head 2750 and the inner surface of the second outer sealing mandrel 2755ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the second lower sealing head 2750preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the second lower sealing head 2750may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the second lower sealing head 2750is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the outer surface of the second lower sealing head 2750preferably includes one or more annular sealing members 2890 for sealing the interface between the second lower sealing head 2750 and the second outer sealing mandrel 2755 .
- the sealing members 2890may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2890comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the second lower sealing head 2750may be coupled to the second inner sealing mandrel 2740 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the second lower sealing head 2750is removably coupled to the second inner sealing mandrel 2740 by a standard threaded connection.
- the mechanical coupling between the second lower sealing head 2750 and the second inner sealing mandrel 2740includes one or more sealing members 2895 for fluidicly sealing the interface between the second sealing head 2750 and the second sealing mandrel 2740 .
- the sealing members 2895may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2895comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the second lower sealing head 2750may be coupled to the load mandrel 2760 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield tubular goods specialty threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the second lower sealing head 2750is removably coupled to the load mandrel 2760 by a standard threaded connection.
- the mechanical coupling between the second lower sealing head 2750 and the load mandrel 2760includes one or more sealing members 2900 for fluidicly sealing the interface between the second lower sealing head 2750 and the load mandrel 2760 .
- the sealing members 2900may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 2900comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the second lower sealing bead 2750includes a throat passage 2905 fiuldicly coupled between the fluid passages 2810 and 2815 .
- the throat passage 2905is preferably of reduced size and is adapted to receive and engage with a plug 2910 , or other similar device.
- the fluid passage 2810is fiuldicly isolated from the fluid passage 2815 .
- the pressure chambers 2915 and 2920are pressurized.
- the use of a plurality of pressure chambers in the apparatus 2700permits the effective driving force to be multiplied. While illustrated using a pair of pressure chambers, 2915 and 2920 , the apparatus 2700 may be further modified to employ additional pressure chambers.
- the second outer sealing mandrel 2755is coupled to the first upper sealing head 2725 , the first outer sealing mandrel 2735 , the second upper sealing head 2745 , and the expansion cone 2765 .
- the second outer sealing mandrel 2755is also movably coupled to the inner surface of the casing 2790 and the outer surface of the second lower sealing head 2750 . In this manner, the first upper sealing head 2725 , first outer sealing mandrel 2735 , second upper sealing head 2745 , second outer sealing mandrel 2755 , and the expansion cone 2765 reciprocate in the axial direction.
- the radial clearance between the outer surface of the second outer sealing mandrel 2755 and the inner surface of the casing 2790may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer surface of the second outer sealing mandrel 2755 and the inner surface of the casing 2790 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 2765 during the expansion process.
- the radial clearance between the inner surface of the second outer sealing mandrel 2755 and the outer surface of the second lower sealing head 2750may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner surface of the second outer sealing mandrel 2755 and the outer surface of the second lower sealing head 2750 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the second outer sealing mandrel 2755preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the second outer sealing mandrel 2755may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the second outer sealing mandrel 2755is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the second outer sealing mandrel 2755may be coupled to the second upper sealing head 2745 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the second outer sealing mandrel 2755is removably coupled to the second upper sealing head 2745 by a standard threaded connection.
- the second outer sealing mandrel 2755may be coupled to the expansion cone 2755 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the second outer sealing mandrel 2755is removably coupled to the expansion cone 2765 by a standard threaded connection.
- the load mandrel 2760is coupled to the second lower sealing head 2750 and the mechanical slip body 2755 .
- the load mandrel 2760preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the load mandrel 2760may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the load mandrel 2760is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the load mandrel 2760may be coupled to the second lower sealing head 2750 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the load mandrel 2760is removably coupled to the second lower sealing head 2750 by a standard threaded connection.
- the load mandrel 2760may be coupled to the mechanical slip body 2775 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the load mandrel 2760is removably coupled to the mechanical slip body 2775 by a standard threaded connection.
- the load mandrel 2760preferably includes a fluid passage 2815 that is adapted to convey fluidic materials from the fluid passage 2810 to the fluid passage 2820 .
- the fluid passage 2815is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the expansion cone 2765is coupled to the second outer sealing mandrel 2755 .
- the expansion cone 2765is also movably coupled to the inner surface of the casing 2790 .
- the first upper sealing head 2725 , first outer sealing mandrel 2735 , second upper sealing head 2745 , second outer sealing mandrel 2755 , and the expansion cone 2765reciprocate in the axial direction.
- the reciprocation of the expansion cone 2765causes the casing 2790 to expand in the radial direction.
- the expansion cone 2765preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces.
- the outside radius of the outside conical surfacemay range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 inches in order to optimally provide expansion cone dimensions that accommodate the typical range of casings.
- the axial length of the expansion cone 2765may range, for example, from about 2 to 8 times the largest outer diameter of the expansion cone 2765 . In an exemplary embodiment, the axial length of the expansion cone 2765 ranges from about 3 to 5 times the largest outer diameter of the expansion cone 2765 in order to optimally provide stabilization and centralization of the expansion cone 2765 . In an exemplary embodiment, the angle of attack of the expansion cone 2765 ranges from about 5 to 30 degrees in order to optimally balance frictional forces and radial expansion forces.
- the expansion cone 2765may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramics or other similar high strength materials.
- the expansion cone 2765is fabricated from D2 machine tool steel in order to optimally provide high strength and resistance to corrosion and galling.
- the outside surface of the expansion cone 2765has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide high strength and resistance to wear and galling.
- the expansion cone 2765may be coupled to the second outside sealing mandrel 2765 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the expansion cone 2765is coupled to the second outside sealing mandrel 2765 using a standard threaded connection in order to optimally provide high strength and easy replacement of the expansion cone 2765 .
- the mandrel launcher 2770is coupled to the casing 2790 .
- the mandrel launcher 2770comprises a tubular section of casing having a reduced wall thickness compared to the casing 2790 .
- the wall thickness of the mandrel launcher 2770is about 50 to 100% of the wall thickness of the casing 2790 .
- the wall thickness of the mandrel launcher 2770may range, for example, from about 0.15 to 1.5 inches. In an exemplary embodiment, the wall thickness of the mandrel launcher 2770 ranges from about 0.25 to 0.75 inches.
- the initiation of the radial expansion of the casing 2790is facilitated, the placement of the apparatus 2700 within a wellbore casing and wellbore is facilitated, and the mandrel launcher 2770 has a burst strength approximately equal to that of the casing 2790 .
- the mandrel launcher 2770may be coupled to the casing 2790 using any number of conventional mechanical couplings such as, for example, a standard threaded connection.
- the mandrel launcher 2770may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength materials, in an exemplary embodiment, the mandrel launcher 2770 is fabricated from oilfield country tubular goods of higher strength than that of the casing 2790 but with a reduced wall thickness in order to optimally provide a small compact tubular container having a burst strength approximately equal to that of the casing 2790 .
- the mechanical slip body 2775is coupled to the load mandrel 2760 , the mechanical slips 2780 , and the drag blocks 2785 .
- the mechanical slip body 2775preferably comprises a tubular member having an inner passage 2820 fluidicly coupled to the passage 2815 . In this manner, fluidic materials may be conveyed from the passage 2820 to a region outside of the apparatus 2700 .
- the mechanical slip body 2775may be coupled to the load mandrel 2760 using any number of conventional mechanical couplings. In an exemplary embodiment, the mechanical slip body 2775 is removably coupled to the load mandrel 2760 using a standard threaded connection in order to optimally provide high strength and easy disassembly. The mechanical slip body 2775 may be coupled to the mechanical slips 2780 using any number of conventional mechanical couplings. In an exemplary embodiment, the mechanical slip body 2755 is removably coupled to the mechanical slips 2780 using threaded connections and sliding steel retainer rings in order to optimally provide a high strength attachment. The mechanical slip body 2755 may be coupled to the drag blocks 2785 using any number of conventional mechanical couplings. In an exemplary embodiment, the mechanical slip body 2775 is removably coupled to the drag blocks 2785 using threaded connections and sliding steel retainer rings in order to optimally provide a high strength attachment.
- the mechanical slip body 2775preferably includes a fluid passage 2820 that is adapted to convey fluidic materials from the fluid passage 2815 to the region outside of the apparatus 2700 .
- the fluid passage 2820is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the mechanical slips 2780are coupled to the outside surface of the mechanical slip body 2775 .
- the mechanical slips 2780prevent upward movement of the casing 2790 and mandrel launcher 2770 .
- the casing 2790 and mandrel launcher 2770are maintained in a substantially stationary position.
- the mandrel launcher 2765 and casing 2790 and mandrel launcher 2770are expanded in the radial direction by the axial movement of the expansion cone 2765 .
- the mechanical slips 2780may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L retrievable bridge plug tungsten carbide upper mechanical slips.
- the mechanical slips 2780comprise RTTS packer tungsten carbide mechanical slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the casing 2790 and mandrel launcher 2770 during the expansion process.
- the drag blocks 2785are coupled to the outside surface of the mechanical slip body 2775 .
- the drag blocks 2785prevent upward movement of the casing 2790 and mandrel launcher 2770 .
- the casing 2790 and mandrel launcher 2770are maintained in a substantially stationary position.
- the mandrel launcher 2770 and casing 2790are expanded in the radial direction by the axial movement of the expansion cone 2765 .
- the drag blocks 2785may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer mechanical drag blocks or Model 3L retrievable bridge plug drag blocks.
- the drag blocks 2785comprise RTTS packer mechanical drag blocks available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the casing 2790 and mandrel launcher 2770 during the expansion process.
- the casing 2790is coupled to the mandrel launcher 2770 .
- the casing 2790is further removably coupled to the mechanical slips 2780 and drag blocks 2785 .
- the casing 2790preferably comprises a tubular member.
- the casing 2790may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the casing 2790is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength using standardized materials.
- the upper end of the casing 2790includes one or more sealing members positioned about the exterior of the casing 2790 .
- the apparatus 2700is positioned in a wellbore with the upper end of the casing 2790 positioned in an overlapping relationship within an existing wellbore casing.
- the fluid passage 2795is preferably provided with one or more pressure relief passages.
- the casing 2790is supported by the expansion cone 2765 .
- a first fluidic materialis pumped into the fluid passage 2795 from a surface location.
- the first fluidic materialis conveyed from the fluid passage 2795 to the fluid passages 2800 , 2802 , 2805 , 2810 , 2815 , and 2820 .
- the first fluidic materialwill then exit the apparatus 2700 and fill the annular region between the outside of the apparatus 2700 and the interior walls of the bore hole.
- the first fluidic materialmay comprise any number of conventional commercially available materials such as, for example, epoxy, drilling mud, slag mix, water or cement.
- the first fluidic materialcomprises a hardenable fluidic sealing material such as, for example, slag mix, epoxy, or cement. In this manner, a wellbore casing having an outer annular layer of a hardenable material may be formed.
- the first fluidic materialmay be pumped into the apparatus 2700 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 3,000 gallons/minute.
- the first fluidic materialis pumped into the apparatus 2700 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency.
- a plug 2910 , dart, or other similar deviceis introduced into the first fluidic material.
- the plug 2910lodges in the throat passage 2905 thereby fiuldicly isolating the fluid passage 2810 from the fluid passage 2815 .
- a second fluidic materialis pumped into the fluid passage 2795 in order to pressurize the pressure chambers 2915 and 2920 .
- the second fluidic materialmay comprise any number of conventional commercially available materials such as, for example, water, drilling gases, drilling mud or lubricants.
- the second fluidic materialcomprises a non-hardenable fluidic material such as, for example, water, drilling mud or lubricant. The use of lubricant optimally provides lubrication of the moving parts of the apparatus 2700 .
- the second fluidic materialmay be pumped into the apparatus 2700 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute.
- the second fluidic materialis pumped into the apparatus 2700 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency.
- the pressurization of the pressure chambers 2915 and 2920cause the upper sealing heads, 2725 and 2745 , outer sealing mandrels, 2735 and 2755 , and expansion cone 2765 to move in an axial direction.
- the expansion cone 2765pulls the mandrel launcher 2770 , casing 2790 , and drag blocks 2785 along, which sets the mechanical slips 2780 and stops further axial movement of the mandrel launcher 2770 and casing 2790 .
- the axial movement of the expansion cone 2765radially expands the mandrel launcher 2770 and casing 2790 .
- the mandrel launcher 2770 and casing 2790are radially expanded through repeated axial strokes of the upper sealing heads, 2725 and 2745 , outer sealing mandrels, 2735 and 2755 , and expansion cone 2765 .
- the upper end of the casing 2790is preferably maintained in an overlapping relation with an existing section of wellbore casing.
- the upper end of the casing 2790is expanded into intimate contact with the inside surface of the lower end of the existing wellbore casing.
- the sealing members provided at the upper end of the casing 2790provide a fluidic seal between the outside surface of the upper end of the casing 2790 and the inside surface of the lower end of the existing wellbore casing.
- the contact pressure between the casing 2790 and the existing section of wellbore casingranges from about 400 to 10,000 in order to optimally provide contact pressure for activating the sealing members, provide optimal resistance to axial movement of the expanded casing, and optimally resist typical tensile and compressive loads on the expanded casing.
- the apparatus 2700includes a shock absorber for absorbing the shock created by the completion of the radial expansion of the casing 2790 .
- the reduced operating pressure of the second fluidic materialranges from about 100 to 1,000 psi as the expansion cone 2765 nears the end of the casing 2790 in order to optimally provide reduced axial movement and velocity of the expansion cone 2765 .
- the operating pressure of the second fluidic materialis reduced during the return stroke of the apparatus 2700 to the range of about 0 to 500 psi in order minimize the resistance to the movement of the expansion cone 2765 during the return stroke.
- the stroke length of the apparatus 2700ranges from about 10 to 45 feet in order to optimally provide equipment that can be easily handled by typical oil well rigging equipment and minimize the frequency at which the apparatus 2700 must be re-stroked during an expansion operation.
- At least a portion of the upper sealing heads, 2725 and 2745include expansion cones for radially expanding the mandrel launcher 2770 and casing 2790 during operation of the apparatus 2700 in order to increase the surface area of the casing 2790 acted upon during the radial expansion process. In this manner, the operating pressures can be reduced.
- mechanical slipsare positioned in an axial location between the sealing sleeve 2715 and the first inner sealing mandrel 2720 in order to optimally provide a simplified assembly and operation of the apparatus 2700 .
- the first fluidic materialis permitted to cure within the annular region between the outside of the expanded casing 2790 and the interior walls of the wellbore.
- the cured fluidic materialpreferably permeates and envelops the expanded casing 2790 .
- a new section of wellbore casingis formed within a wellbore.
- the apparatus 2700may be used to join a first section of pipeline to an existing section of pipeline.
- the apparatus 2700may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material.
- the apparatus 2700may be used to expand a tubular support member in a hole.
- the pressurized areas of the apparatus 2700are limited to the fluid passages 2795 , 2800 , 2802 , 2805 , and 2810 , and the pressure chambers 2915 and 2920 .
- No fluid pressureacts directly on the mandrel launcher 2770 and casing 2790 . This permits the use of operating pressures higher than the mandrel launcher 2770 and casing 2790 could normally withstand.
- the apparatus 3000preferably includes a drillpipe 3005 , an innerstring adapter 3010 , a sealing sleeve 3015 , a first inner sealing mandrel 3020 , hydraulic slips 3025 , a first upper sealing head 3030 , a first lower sealing head 3035 , a first outer sealing mandrel 3040 , a second inner sealing mandrel 3045 , a second upper sealing head 3050 , a second lower sealing head 3055 , a second outer sealing mandrel 3060 , load mandrel 3065 , expansion cone 3070 , casing 3075 , and fluid passages 3080 , 3085 , 3090 , 3095 , 3100 , 3105 , 3110 , 3115 and 3120 .
- the drillpipe 3005is coupled to the innerstring adapter 3010 . During operation of the apparatus 3000 , the drillpipe 3005 supports the apparatus 3000 .
- the drillpipe 3005preferably comprises a substantially hollow tubular member or members.
- the drillpipe 3005may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the drillpipe 3005is fabricated from coiled tubing in order to facilitate the placement of the apparatus 3000 in non-vertical wellbores.
- the drillpipe 3005may be coupled to the innerstring adapter 3010 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection.
- the drillpipe 3005is removably coupled to the innerstring adapter 3010 by a drillpipe connection.
- the drillpipe 3005preferably includes a fluid passage 3080 that is adapted to convey fluidic materials from a surface location into the fluid passage 3085 .
- the fluid passage 3080is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the innerstring adapter 3010is coupled to the drill string 3005 and the sealing sleeve 3015 .
- the innerstring adapter 3010preferably comprises a substantially hollow tubular member or members.
- the innerstring adapter 3010may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength materials.
- the innerstring adapter 3010is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the innerstring adapter 3010may be coupled to the drill string 3005 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the innerstring adapter 3010is removably coupled to the drill pipe 3005 by a drillpipe connection.
- the innerstring adapter 3010may be coupled to the sealing sleeve 3015 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the innerstring adapter 3010is removably coupled to the sealing sleeve 3015 by a standard threaded connection.
- the innerstring adapter 3010preferably includes a fluid passage 3085 that is adapted to convey fluidic materials from the fluid passage 3080 into the fluid passage 3090 .
- the fluid passage 3085is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the sealing sleeve 3015is coupled to the innerstring adapter 3010 and the first inner sealing mandrel 3020 .
- the sealing sleeve 3015preferably comprises a substantially hollow tubular member or members.
- the sealing sleeve 3015may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the sealing sleeve 3015is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the sealing sleeve 3015may be coupled to the innerstring adapter 3010 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type connection or a standard threaded connection.
- the sealing sleeve 3015is removably coupled to the innerstring adapter 3010 by a standard threaded connection.
- the sealing sleeve 3015may be coupled to the first inner sealing mandrel 3020 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the sealing sleeve 3015is removably coupled to the first inner sealing mandrel 3020 by a standard threaded connection.
- the sealing sleeve 3015preferably includes a fluid passage 3090 that is adapted to convey fluidic materials from the fluid passage 3085 into the fluid passage 3095 .
- the fluid passage 3090is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the first inner sealing mandrel 3020is coupled to the sealing sleeve 3015 , the hydraulic slips 3025 , and the first lower sealing head 3035 .
- the first inner sealing mandrel 3020is further movably coupled to the first upper sealing head 3030 .
- the first inner sealing mandrel 3020preferably comprises a substantially hollow tubular member or members.
- the first inner sealing mandrel 3020may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or similar high strength materials.
- the first inner sealing mandrel 3020is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the first inner sealing mandrel 3020may be coupled to the sealing sleeve 3015 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the first inner sealing mandrel 3020is removably coupled to the sealing sleeve 3015 by a standard threaded connection.
- the first inner sealing mandrel 3020may be coupled to the hydraulic slips 3025 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the first inner sealing mandrel 3020is removably coupled to the hydraulic slips 3025 by a standard threaded connection.
- the first inner sealing mandrel 3020may be coupled to the first lower sealing head 3035 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the first inner sealing mandrel 3020is removably coupled to the first lower sealing head 3035 by a standard threaded connection.
- the first inner sealing mandrel 3020preferably includes a fluid passage 3095 that is adapted to convey fluidic materials from the fluid passage 3090 into the fluid passage 3100 .
- the fluid passage 3095is adapted to convey fluidic materials such as, for example, water, drilling mud, cement, epoxy, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the first inner sealing mandrel 3020further preferably includes fluid passages 3110 that are adapted to convey fluidic materials from the fluid passage 3095 into the pressure chambers of the hydraulic slips 3025 . In this manner, the slips 3025 are activated upon the pressurization of the fluid passage 3095 into contact with the inside surface of the casing 3075 .
- the fluid passages 3110are adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling fluids or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the first inner sealing mandrel 3020further preferably includes fluid passages 3115 that are adapted to convey fluidic materials from the fluid passage 3095 into the first pressure chamber 3175 defined by the first upper sealing head 3030 , the first lower sealing head 3035 , the first inner sealing mandrel 3020 , and the first outer sealing mandrel 3040 .
- pressurization of the pressure chamber 3175causes the first upper sealing head 3030 , the first outer sealing mandrel 3040 , the second upper sealing head 3050 , the second outer sealing mandrel 3060 , and the expansion cone 3070 to move in an axial direction.
- the slips 3025are coupled to the outside surface of the first inner sealing mandrel 3020 . During operation of the apparatus 3000 , the slips 3025 are activated upon the pressurization of the fluid passage 3095 into contact with the inside surface of the casing 3075 . In this manner, the slips 3025 maintain the casing 3075 in a substantially stationary position.
- the slips 3025preferably include fluid passages 3125 , pressure chambers 3130 , spring bias 3135 , and slip members 3140 .
- the slips 3025may comprise any number of conventional commercially available hydraulic slips such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L retrievable bridge plug with hydraulic slips.
- the slips 3025comprise RTTS packer tungsten carbide hydraulic slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the casing 3075 during the expansion process.
- the first upper sealing head 3030is coupled to the first outer sealing mandrel 3040 , the second upper sealing head 3050 , the second outer sealing mandrel 3060 , and the expansion cone 3070 .
- the first upper sealing head 3030is also movably coupled to the outer surface of the first inner sealing mandrel 3020 and the inner surface of the casing 3075 . In this manner, the first upper sealing head 3030 , the first outer sealing mandrel 3040 , the second upper sealing head 3050 , the second outer sealing mandrel 3060 , and the expansion cone 3070 reciprocate in the axial direction.
- the radial clearance between the inner cylindrical surface of the first upper sealing head 3030 and the outer surface of the first inner sealing mandrel 3020may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of the first upper sealing head 3030 and the outer surface of the first inner sealing mandrel 3020 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the radial clearance between the outer cylindrical surface of the first upper sealing head 3030 and the inner surface of the casing 3075may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer cylindrical surface of the first upper sealing head 3030 and the inner surface of the casing 3075ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 3070 during the expansion process.
- the first upper sealing head 3030preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the first upper sealing head 3030may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, or other similar high strength materials.
- the first upper sealing head 3030is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the inner surface of the first upper sealing head 3030preferably includes one or more annular sealing members 3145 for sealing the interface between the first upper sealing head 3030 and the first inner sealing mandrel 3020 .
- the sealing members 3145may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 3145comprise polypak seals available from Parker seals in order to optimally provide sealing for a long axial stroke.
- the first upper sealing head 3030includes a shoulder 3150 for supporting the first upper sealing head 3030 , first outer sealing mandrel 3040 , second upper sealing head 3050 , second outer sealing mandrel 3060 , and expansion cone 3070 on the first lower sealing head 3035 .
- the first upper sealing head 3030may be coupled to the first outer sealing mandrel 3040 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the first upper sealing head 3030is removably coupled to the first outer sealing mandrel 3040 by a standard threaded connection
- the mechanical coupling between the first upper sealing head 3030 and the first outer sealing mandrel 3040includes one or more sealing members 3155 for fluidicly sealing the interface between the first upper sealing head 3030 and the first outer sealing mandrel 3040 .
- the sealing members 3155may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 3155comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the first lower sealing head 3035is coupled to the first inner sealing mandrel 3020 and the second inner sealing mandrel 3045 .
- the first lower sealing head 3035is also movably coupled to the inner surface of the first outer sealing mandrel 3040 .
- the first upper sealing head 3030 , first outer sealing mandrel 3040 , second upper sealing head 3050 , second outer sealing mandrel 3060 , and expansion cone 3070reciprocate in the axial direction.
- the radial clearance between the outer surface of the first lower sealing head 3035 and the inner surface of the first outer sealing mandrel 3040may range, for example, from about 0.0025 to 0.05 inches.
- the radial clearance between the outer surface of the first lower sealing head 3035 and the inner surface of the outer sealing mandrel 3040ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the first lower sealing head 3035preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the first lower sealing head 3035may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the first lower sealing head 3035is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the outer surface of the first lower sealing head 3035preferably includes one or more annular sealing members 3160 for sealing the interface between the first lower sealing head 3035 and the first outer sealing mandrel 3040 .
- the sealing members 3160may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals, in an exemplary embodiment, the sealing members 3160 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the first lower sealing head 3035may be coupled to the first inner sealing mandrel 3020 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the first lower sealing head 3035is removably coupled to the first inner sealing mandrel 3020 by a standard threaded connection.
- the mechanical coupling between the first lower sealing head 3035 and the first inner sealing mandrel 3020includes one or more sealing members 3165 for fluidicly sealing the interface between the first lower sealing head 3035 and the first inner sealing mandrel 3020 .
- the sealing members 3165may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 3165comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke length.
- the first lower sealing head 3035may be coupled to the second inner sealing mandrel 3045 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the first lower sealing head 3035is removably coupled to the second inner sealing mandrel 3045 by a standard threaded connection.
- the mechanical coupling between the first lower sealing head 3035 and the second inner sealing mandrel 3045includes one or more sealing members 3170 for fluidicly sealing the interface between the first lower sealing head 3035 and the second inner sealing mandrel 3045 .
- the sealing members 3170may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 3170comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the first outer sealing mandrel 3040is coupled to the first upper sealing head 3030 and the second upper sealing head 3050 .
- the first outer sealing mandrel 3040is also movably coupled to the inner surface of the casing 3075 and the outer surface of the first lower sealing head 3035 .
- the first upper sealing head 3030 , first outer sealing mandrel 3040 , second upper sealing head 3050 , second outer sealing mandrel 3060 , and the expansion cone 3070reciprocate in the axial direction.
- the radial clearance between the outer surface of the first outer sealing mandrel 3040 and the inner surface of the casing 3075may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer surface of the first outer sealing mandrel 3040 and the inner surface of the casing 3075ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 3070 during the expansion process.
- the radial clearance between the inner surface of the first outer sealing mandrel 3040 and the outer surface of the first lower sealing head 3035may range, for example, from about 0.005 to 0.125 inches.
- the radial clearance between the inner surface of the first outer sealing mandrel 3040 and the outer surface of the first lower sealing head 3035ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the first outer sealing mandrel 3040preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the first outer sealing mandrel 3040may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the first outer sealing mandrel 3040is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the first outer sealing mandrel 3040may be coupled to the first upper sealing head 3030 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the first outer sealing mandrel 3040is removably coupled to the first upper sealing head 3030 by a standard threaded connection.
- the mechanical coupling between the first outer sealing mandrel 3040 and the first upper sealing head 3030includes one or more sealing members 3180 for sealing the interface between the first outer sealing mandrel 3040 and the first upper sealing head 3030 .
- the sealing members 3180may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 3180comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the first outer sealing mandrel 3040may be coupled to the second upper sealing head 3050 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the first outer sealing mandrel 3040is removably coupled to the second upper sealing head 3050 by a standard threaded connection.
- the mechanical coupling between the first outer sealing mandrel 3040 and the second upper sealing head 3050includes one or more sealing members 3185 for sealing the interface between the first outer sealing mandrel 3040 and the second upper sealing head 3050 .
- the sealing members 3185may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 3185compose polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the second inner sealing mandrel 3045is coupled to the first lower sealing head 3035 and the second lower sealing head 3055 .
- the second inner sealing mandrel 3045preferably comprises a substantially hollow tubular member or members.
- the second inner sealing mandrel 3045may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the second inner sealing mandrel 3045is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the second inner sealing mandrel 3045may be coupled to the first lower sealing head 3035 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection.
- the second inner sealing mandrel 3045is removably coupled to the first lower sealing head 3035 by a standard threaded connection.
- the second inner sealing mandrel 3045may be coupled to the second lower sealing head 3055 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type connection, or a standard threaded connection.
- the second inner sealing mandrel 3045is removably coupled to the second lower sealing head 3055 by a standard threaded connection.
- the second inner sealing mandrel 3045preferably includes a fluid passage 3100 that is adapted to convey fluidic materials from the fluid passage 3095 into the fluid passage 3105 .
- the fluid passage 3100is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the second inner sealing mandrel 3045further preferably includes fluid passages 3120 that are adapted to convey fluidic materials from the fluid passage 3100 into the second pressure chamber 3190 defined by the second upper sealing head 3050 , the second lower sealing head 3055 , the second inner sealing mandrel 3045 , and the second outer sealing mandrel 3060 .
- pressurization of the second pressure chamber 3190causes the first upper sealing head 3030 , the first outer sealing mandrel 3040 , the second upper sealing head 3050 , the second outer sealing mandrel 3060 , and the expansion cone 3070 to move in an axial direction.
- the second upper sealing head 3050is coupled to the first outer sealing mandrel 3040 and the second outer sealing mandrel 3060 .
- the second upper sealing head 3050is also movably coupled to the outer surface of the second inner sealing mandrel 3045 and the inner surface of the casing 3075 . In this manner, the second upper sealing head 3050 reciprocates in the axial direction.
- the radial clearance between the inner cylindrical surface of the second upper sealing head 3050 and the outer surface of the second inner sealing mandrel 3045may range, for example, from about 0.0025 to 0.05 inches.
- the radial clearance between the inner cylindrical surface of the second upper sealing head 3050 and the outer surface of the second inner sealing mandrel 3045ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the radial clearance between the outer cylindrical surface of the second upper sealing head 3050 and the inner surface of the casing 3075may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer cylindrical surface of the second upper sealing head 3050 and the inner surface of the casing 3075ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 3070 during the expansion process.
- the second upper sealing head 3050preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the second upper sealing head 3050may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the second upper sealing head 3050is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the inner surface of the second upper sealing head 3050preferably includes one or more annular sealing members 3195 for sealing the interface between the second upper sealing head 3050 and the second inner sealing mandrel 3045 .
- the sealing members 3195may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 3195comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the second upper sealing head 3050includes a shoulder 3200 for supporting the first upper sealing head 3030 , first outer sealing mandrel 3040 , second upper sealing head 3050 , second outer sealing mandrel 3060 , and expansion cone 3070 on the second lower sealing head 3055 .
- the second upper sealing head 3050may be coupled to the first outer sealing mandrel 3040 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the second upper sealing head 3050is removably coupled to the first outer sealing mandrel 3040 by a standard threaded connection.
- the mechanical coupling between the second upper sealing head 3050 and the first outer sealing mandrel 3040includes one or more sealing members 3185 for fluidicly sealing the interface between the second upper sealing head 3050 and the first outer sealing mandrel 3040 .
- the second upper sealing head 3050may be coupled to the second outer sealing mandrel 3060 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection.
- the second upper sealing head 3050is removably coupled to the second outer sealing mandrel 3060 by a standard threaded connection.
- the mechanical coupling between the second upper sealing head 3050 and the second outer sealing mandrel 3060includes one or more sealing members 3205 for fiuldicly sealing the interface between the second upper sealing head 3050 and the second outer sealing mandrel 3060 .
- the second lower sealing head 3055is coupled to the second inner sealing mandrel 3045 and the load mandrel 3065 .
- the second lower sealing head 3055is also movably coupled to the inner surface of the second outer sealing mandrel 3060 .
- the first upper sealing head 3030 , first outer sealing mandrel 3040 , second upper sealing mandrel 3050 , second outer sealing mandrel 3060 , and expansion cone 3070reciprocate in the axial direction.
- the radial clearance between the outer surface of the second lower sealing head 3055 and the inner surface of the second outer sealing mandrel 3060may range, for example, from about 0.0025 to 0.05 inches.
- the radial clearance between the outer surface of the second lower sealing head 3055 and the inner surface of the second outer sealing mandrel 3060ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the second lower sealing head 3055preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the second lower sealing head 3055may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength materials.
- the second lower sealing head 3055is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the outer surface of the second lower sealing head 3055preferably includes one or more annular sealing members 3210 for sealing the interface between the second lower sealing head 3055 and the second outer sealing mandrel 3060 .
- the sealing members 3210may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals.
- the sealing members 3210comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the second lower sealing head 3055may be coupled to the second inner sealing mandrel 3045 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the second lower sealing head 3055is removably coupled to the second inner sealing mandrel 3045 by a standard threaded connection.
- the mechanical coupling between the lower sealing head 3055 and the second inner sealing mandrel 3045includes one or more sealing members 3215 for fluidicly sealing the interface between the second lower sealing head 3055 and the second inner sealing mandrel 3045 .
- the sealing members 3215may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 3215comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes.
- the second lower sealing head 3055may be coupled to the load mandrel 3065 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the second lower sealing head 3055is removably coupled to the load mandrel 3065 by a standard threaded connection.
- the mechanical coupling between the second lower sealing head 3055 and the load mandrel 3065includes one or more sealing members 3220 for fluidicly sealing the interface between the second lower sealing head 3055 and the load mandrel 3065 .
- the sealing members 3220may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals.
- the sealing members 3220comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke.
- the second lower sealing head 3055includes a throat passage 3225 fluidicly coupled between the fluid passages 3100 and 3105 .
- the throat passage 3225is preferably of reduced size and is adapted to receive and engage with a plug 3230 , or other similar device.
- the fluid passage 3100is fluidicly isolated from the fluid passage 3105 .
- the pressure chambers 3175 and 3190are pressurized.
- the placement of the plug 3230 in the throat passage 3225also pressurizes the pressure chambers 3130 of the hydraulic slips 3025 .
- the second outer sealing mandrel 3060is coupled to the second upper sealing head 3050 and the expansion cone 3070 .
- the second outer sealing mandrel 3060is also movably coupled to the inner surface of the casing 3075 and the outer surface of the second lower sealing head 3055 .
- the first upper sealing head 3030 , first outer sealing mandrel 3040 , second upper sealing head 3050 , second outer sealing mandrel 3060 , and the expansion cone 3070reciprocate in the axial direction.
- the radial clearance between the outer surface of the second outer sealing mandrel 3060 and the inner surface of the casing 3075may range, for example, from about 0.025 to 0.375 inches.
- the radial clearance between the outer surface of the second outer sealing mandrel 3060 and the inner surface of the casing 3075ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for the expansion cone 3070 during the expansion process.
- the radial clearance between the inner surface of the second outer sealing mandrel 3060 and the outer surface of the second lower sealing head 3055may range, for example, from about 0.0025 to 0.05 inches.
- the radial clearance between the inner surface of the second outer sealing mandrel 3060 and the outer surface of the second lower sealing head 3055ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
- the second outer sealing mandrel 3060preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the second outer sealing mandrel 3060may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the second outer sealing mandrel 3060is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the second outer sealing mandrel 3060may be coupled to the second upper sealing head 3050 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the outer sealing mandrel 3060is removably coupled to the second upper sealing head 3050 by a standard threaded connection.
- the second outer sealing mandrel 3060may be coupled to the expansion cone 3070 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection.
- the second outer sealing mandrel 3060is removably coupled to the expansion cone 3070 by a standard threaded connection.
- the first upper sealing head 3030 , the first lower sealing head 3035 , the first inner sealing mandrel 3020 , and the first outer sealing mandrel 3040together define the first pressure chamber 3175 .
- the second upper sealing head 3050 , the second lower sealing head 3055 , the second inner sealing mandrel 3045 , and the second outer sealing mandrel 3060together define the second pressure chamber 3190 .
- the first and second pressure chambers, 3175 and 3190are fluidicly coupled to the passages, 3095 and 3100 , via one or more passages, 3115 and 3120 .
- the plug 3230engages with the throat passage 3225 to fluidicly isolate the fluid passage 3100 from the fluid passage 3105 .
- the pressure chambers, 3175 and 3190are then pressurized which in turn causes the first upper sealing head 3030 , the first outer sealing mandrel 3040 , the second upper sealing head 3050 , the second outer sealing mandrel 3060 , and expansion cone 3070 to reciprocate in the axial direction.
- the axial motion of the expansion cone 3070in turn expands the casing 3075 in the radial direction.
- the use of a plurality of pressure chambers, 3175 and 3190effectively multiplies the available driving force for the expansion cone 3070 .
- the load mandrel 3065is coupled to the second lower sealing head 3055 .
- the load mandrel 3065preferably comprises an annular member having substantially cylindrical inner and outer surfaces.
- the load mandrel 3065may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials.
- the load mandrel 3065is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces.
- the load mandrel 3065may be coupled to the lower sealing head 3055 using any number of conventional commercially available mechanical couplings such as, for example, epoxy, cement, water, drilling mud, or lubricants.
- the load mandrel 3065is removably coupled to the lower sealing head 3055 by a standard threaded connection.
- the load mandrel 3065preferably includes a fluid passage 3105 that is adapted to convey fluidic materials from the fluid passage 3100 to the region outside of the apparatus 3000 .
- the fluid passage 3105is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
- the expansion cone 3070is coupled to the second outer sealing mandrel 3060 .
- the expansion cone 3070is also movably coupled to the inner surface of the casing 3075 .
- the first upper sealing head 3030 , first outer sealing mandrel 3040 , second upper sealing head 3050 , second outer sealing mandrel 3060 , and the expansion cone 3070reciprocate in the axial direction.
- the reciprocation of the expansion cone 3070causes the casing 3075 to expand in the radial direction.
- the expansion cone 3070preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces.
- the outside radius of the outside conical surfacemay range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 inches in order to optimally provide an expansion cone 3070 for expanding typical casings.
- the axial length of the expansion cone 3070may range, for example, from about 2 to 8 times the maximum outer diameter of the expansion cone 3070 . In an exemplary embodiment, the axial length of the expansion cone 3070 ranges from about 3 to 5 times the maximum outer diameter of the expansion cone 3070 in order to optimally provide stabilization and centralization of the expansion cone 3070 during the expansion process.
- the maximum outside diameter of the expansion cone 3070is between about 95 to 99% of the inside diameter of the existing wellbore that the casing 3075 will be joined with.
- the angle of attack of the expansion cone 3070ranges from about 5 to 30 degrees in order to optimally balance the frictional forces with the radial expansion forces.
- the expansion cone 3070may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramics, or other similar high strength materials.
- the expansion cone 3070is fabricated from D2 machine tool steel in order to optimally provide high strength and resistance to wear and galling.
- the outside surface of the expansion cone 3070has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide high strength and resistance to wear and galling.
- the expansion cone 3070may be coupled to the second outside sealing mandrel 3060 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type connection or a standard threaded connection.
- the expansion cone 3070is coupled to the second outside sealing mandrel 3060 using a standard threaded connection in order to optimally provide high strength and easy disassembly.
- the casing 3075is removably coupled to the slips 3025 and the expansion cone 3070 .
- the casing 3075preferably comprises a tubular member.
- the casing 3075may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oilfield country tubular goods, carbon steel, low alloy steel, stainless steel or other similar high strength materials.
- the casing 3075is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength.
- the upper end 3235 of the casing 3075includes a thin wall section 3240 and an outer annular sealing member 3245 .
- the wall thickness of the thin wall section 3240is about 50 to 100% of the regular wall thickness of the casing 3075 .
- the upper end 3235 of the casing 3075may be easily radially expanded and deformed into intimate contact with the lower end of an existing section of wellbore casing.
- the lower end of the existing section of casingalso includes a thin wall section. In this manner, the radial expansion of the thin walled section 3240 of casing 3075 into the thin walled section of the existing wellbore casing results in a wellbore casing having a substantially constant inside diameter.
- the annular sealing member 3245may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal or plastic.
- the annular sealing member 3245is fabricated from StrataLock epoxy in order to optimally provide compressibility and wear resistance.
- the outside diameter of the annular sealing member 3245preferably ranges from about 70 to 95% of the inside diameter of the lower section of the wellbore casing that the casing 3075 is joined to. In this manner, after radial expansion, the annular sealing member 3245 optimally provides a fluidic seal and also preferably optimally provides sufficient frictional force with the inside surface of the existing section of wellbore casing during the radial expansion of the casing 3075 to support the casing 3075 .
- the lower end 3250 of the casing 3075includes a thin wall section 3255 and an outer annular sealing member 3260 .
- the wall thickness of the thin wall section 3255is about 50 to 100% of the regular wall thickness of the casing 3075 .
- the lower end 3250 of the casing 3075may be easily expanded and deformed.
- an other section of casingmay be easily joined with the lower end 3250 of the casing 3075 using a radial expansion process.
- the upper end of the other section of casingalso includes a thin wall section. In this manner, the radial expansion of the thin walled section of the upper end of the other casing into the thin walled section 3255 of the lower end 3250 of the casing 3075 results in a wellbore casing having a substantially constant inside diameter.
- the upper annular sealing member 3245may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal or plastic.
- the upper annular sealing member 3245is fabricated from Stratalock epoxy in order to optimally provide compressibility and resistance to wear.
- the outside diameter of the upper annular sealing member 3245preferably ranges from about 70 to 95% of the inside diameter of the lower section of the existing wellbore casing that the casing 3075 is joined to. In this manner, after radial expansion, the upper annular sealing member 3245 preferably provides a fluidic seal and also preferably provides sufficient frictional force with the inside wall of the wellbore during the radial expansion of the casing 3075 to support the casing 3075 .
- the lower annular sealing member 3260may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal or plastic.
- the lower annular sealing member 3260is fabricated from StrataLock epoxy in order to optimally provide compressibility and resistance to wear.
- the outside diameter of the lower annular sealing member 3260preferably ranges from about 70 to 95% of the inside diameter of the lower section of the existing wellbore casing that the casing 3075 is joined to.
- the lower annular sealing member 3260preferably provides a fluidic seal and also preferably provides sufficient frictional force with the inside wall of the wellbore during the radial expansion of the casing 3075 to support the casing 3075 .
- the apparatus 3000is preferably positioned in a wellbore with the upper end 3235 of the casing 3075 positioned in an overlapping relationship with the lower end of an existing wellbore casing.
- the thin wall section 3240 of the casing 3075is positioned in opposing overlapping relation with the thin wall section and outer annular sealing member of the lower end of the existing section of wellbore casing. In this manner, the radial expansion of the casing 3075 will compress the thin wall sections and annular compressible members of the upper end 3235 of the casing 3075 and the lower end of the existing wellbore casing into intimate contact.
- the casing 3000is preferably supported by the expansion cone 3070 .
- the first fluidic materialmay comprise any number of conventional commercially available materials such as, for example, drilling mud, water, epoxy, cement, slag mix or lubricants.
- the first fluidic materialcomprises a hardenable fluidic sealing material such as, for example, cement, epoxy, or slag mix in order to optimally provide a hardenable outer annular body around the expanded casing 3075 .
- the first fluidic materialmay be pumped into the fluid passage 3080 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute.
- the first fluidic materialis pumped into the fluid passage 3080 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operating efficiency.
- the first fluidic material pumped into the fluid passage 3080passes through the fluid passages 3085 , 3090 , 3095 , 3100 , and 3105 and then outside of the apparatus 3000 .
- the first fluidic materialthen preferably fills the annular region between the outside of the apparatus 3000 and the interior walls of the wellbore.
- the plug 3230is then introduced into the fluid passage 3080 .
- the plug 3230lodges in the throat passage 3225 and fluidicly isolates and blocks off the fluid passage 3100 .
- a couple of volumes of a non-hardenable fluidic materialare then pumped into the fluid passage 3080 in order to remove any hardenable fluidic material contained within and to ensure that none of the fluid passages are blocked.
- a second fluidic materialis then pumped into the fluid passage 3080 .
- the second fluidic materialmay comprise any number of conventional commercially available materials such as, for example, water, drilling gases, drilling mud or lubricant.
- the second fluidic materialcomprises a non-hardenable fluidic material such as, for example, water, drilling mud, drilling gases, or lubricant in order to optimally provide pressurization of the pressure chambers 3175 and 3190 .
- the second fluidic materialmay be pumped into the fluid passage 3080 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute.
- the second fluidic materialis pumped into the fluid passage 3080 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency.
- the second fluidic material pumped into the fluid passage 3080passes through the fluid passages 3085 , 3090 , 3095 , 3100 and into the pressure chambers 3130 of the slips 3025 , and into the pressure chambers 3175 and 3190 .
- Continued pumping of the second fluidic materialpressurizes the pressure chambers 3130 , 3175 , and 3190 .
- the pressurization of the pressure chambers 3130causes the hydraulic slip members 3140 to expand in the radial direction and grip the interior surface of the casing 3075 .
- the casing 3075is then preferably maintained in a substantially stationary position.
- the pressurization of the pressure chambers 3175 and 3190cause the first upper sealing head 3030 , first outer sealing mandrel 3040 , second upper sealing head 3050 , second outer sealing mandrel 3060 , and expansion cone 3070 to move in an axial direction relative to the casing 3075 .
- the expansion cone 3070will cause the casing 3075 to expand in the radial direction, beginning with the lower end 3250 of the casing 3075 .
- the casing 3075is prevented from moving in an upward direction by the slips 3025 .
- a length of the casing 3075is then expanded in the radial direction through the pressurization of the pressure chambers 3175 and 3190 .
- the length of the casing 3075 that is expanded during the expansion processwill be proportional to the stroke length of the first upper sealing head 3030 , first outer sealing mandrel 3040 , second upper sealing head 3050 , and expansion cone 3070 .
- the operating pressure of the second fluidic materialis reduced and the first upper sealing head 3030 , first outer sealing mandrel 3040 , second upper sealing head 3050 , second outer sealing mandrel 3060 , and expansion cone 3070 drop to their rest positions with the casing 3075 supported by the expansion cone 3070 .
- the reduction in the operating pressure of the second fluidic materialalso causes the spring bias 3135 of the slips 3025 to pull the slip members 3140 away from the inside walls of the casing 3075 .
- the position of the drillpipe 3005is preferably adjusted throughout the radial expansion process in order to maintain the overlapping relationship between the thin walled sections of the lower end of the existing wellbore casing and the upper end of the casing 3235 .
- the stroking of the expansion cone 3070is then repeated, as necessary, until the thin walled section 3240 of the upper end 3235 of the casing 3075 is expanded into the thin walled section of the lower end of the existing wellbore casing.
- a wellbore casingis formed including two adjacent sections of casing having a substantially constant inside diameter. This process may then be repeated for the entirety of the wellbore to provide a wellbore casing thousands of feet in length having a substantially constant inside diameter.
- the slips 3025are positioned as close as possible to the thin walled section 3240 of the upper end 3235 of the casing 3075 in order minimize slippage between the casing 3075 and the existing wellbore casing at the end of the radial expansion process.
- the outside diameter of the upper annular sealing member 3245is selected to ensure sufficient interference fit with the inside diameter of the lower end of the existing casing to prevent axial displacement of the casing 3075 during the final stroke.
- the outside diameter of the lower annular sealing member 3260is selected to provide an interference fit with the inside walls of the wellbore at an earlier point in the radial expansion process so as to prevent further axial displacement of the casing 3075 .
- the interference fitis preferably selected to permit expansion of the casing 3075 by pulling the expansion cone 3070 out of the wellbore, without having to pressurize the pressure chambers 3175 and 3190 .
- the pressurized areas of the apparatus 3000are preferably limited to the fluid passages 3080 , 3085 , 3090 , 3095 , 3100 , 3110 , 3115 , 3120 , the pressure chambers 3130 within the slips 3025 , and the pressure chambers 3175 and 3190 .
- No fluid pressureacts directly on the casing 3075 . This permits the use of operating pressures higher than the casing 3075 could normally withstand.
- the contact pressure between the deformed thin wall sections and compressible annular members of the lower end of the existing casing and the upper end 3235 of the casing 3075ranges from about 400 to 10,000 psi in order to optimally support the casing 3075 using the existing wellbore casing.
- the casing 3075is radially expanded into contact with an existing section of casing by pressurizing the interior fluid passages 3080 , 3085 , 3090 , 3095 , 3100 , 3110 , 3115 , and 3120 , the pressure chambers 3130 of the slips 3025 and the pressure chambers 3175 and 3190 of the apparatus 3000 .
- the annular body of hardenable fluidic materialis then allowed to cure to form a rigid outer annular body about the expanded casing 3075 .
- the cured fluidic materialpreferably permeates and envelops the expanded casing 3075 .
- the resulting new section of wellbore casingincludes the expanded casing 3075 and the rigid outer annular body.
- the overlapping joint between the pre-existing wellbore casing and the expanded casing 3075includes the deformed thin wall sections and the compressible outer annular bodies.
- the inner diameter of the resulting combined wellbore casingsis substantially constant. In this manner, a mono-diameter wellbore casing is formed.
- This process of expanding overlapping tubular members having thin wall end portions with compressible annular bodies into contactcan be repeated for the entire length of a wellbore.
- a mono-diameter wellbore casingcan be provided for thousands of feet in a subterranean formation.
- the apparatus 3000includes a shock absorber for absorbing the shock created by the completion of the radial expansion of the casing 3075 .
- the reduced operating pressure of the second fluidic materialranges from about 100 to 1,000 psi as the expansion cone 3070 nears the end of the casing 3075 in order to optimally provide reduced axial movement and velocity of the expansion cone 3070 .
- the operating pressure of the second fluidic materialis reduced during the return stroke of the apparatus 3000 to the range of about 0 to 500 psi in order minimize the resistance to the movement of the expansion cone 3070 during the return stroke.
- the stroke length of the apparatus 3000ranges from about 10 to 45 feet in order to optimally provide equipment that can be easily handled by typical oil well rigging equipment and also minimize the frequency at which the apparatus 3000 must be re-stroked.
- At least a portion of one or both of the upper sealing heads, 3030 and 3050includes an expansion cone for radially expanding the casing 3075 during operation of the apparatus 3000 in order to increase the surface area of the casing 3075 acted upon during the radial expansion process. In this manner, the operating pressures can be reduced.
- the apparatus 3000may be used to join a first section of pipeline to an existing section of pipeline.
- the apparatus 3000may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material.
- the apparatus 3000may be used to expand a tubular support member in a hole.
- a wellbore 3305 including a casing 3310are positioned in a subterranean formation 3315 .
- the subterranean formation 3315includes a number of productive and non-productive zones, including a water zone 3320 and a targeted oil sand zone 3325 .
- the wellbore 3305may be extended in a well known manner to traverse the various productive and non-productive zones, including the water zone 3320 and the targeted oil sand zone 3325 .
- an apparatus 3330in order to fluidicly isolate the water zone 3320 from the targeted oil sand zone 3325 , an apparatus 3330 is provided that includes one or more sections of solid casing 3335 , one or more external seals 3340 , one or more sections of slotted casing 3345 , one or more intermediate sections of solid casing 3350 , and a solid shoe 3355 .
- the solid casing 3335may provide a fluid conduit that transmits fluids and other materials from one end of the solid casing 3335 to the other end of the solid casing 3335 .
- the solid casing 3335may comprise any number of conventional commercially available sections of solid tubular casing such as, for example, oilfield tubulars fabricated from chromium steel or fiberglass.
- the solid casing 3335comprises oilfield tubulars available from various foreign and domestic steel mills.
- the solid casing 3335is preferably coupled to the casing 3310 .
- the solid casing 3335may be coupled to the casing 3310 using any number of conventional commercially available processes such as, for example, welding, slotted and expandable connectors, or expandable solid connectors.
- the solid casing 3335is coupled to the casing 3310 by using expandable solid connectors.
- the solid casing 3335may comprise a plurality of such solid casings 3335 .
- the solid casing 3335is preferably coupled to one more of the slotted casings 3345 .
- the solid casing 3335may be coupled to the slotted casing 3345 using any number of conventional commercially available processes such as, for example, welding, or slotted and expandable connectors.
- the solid casing 3335is coupled to the slotted casing 3345 by expandable solid connectors.
- the casing 3335includes one more valve members 3360 for controlling the flow of fluids and other materials within the interior region of the casing 3335 .
- an internal tubular string with various arrangements of packers, perforated tubing, sliding sleeves, and valvesmay be employed within the apparatus to provide various options for commingling and isolating subterranean zones from each other while providing a fluid path to the surface.
- the casing 3335is placed into the wellbore 3305 by expanding the casing 3335 in the radial direction into intimate contact with the interior walls of the wellbore 3305 .
- the casing 3335may be expanded in the radial direction using any number of conventional commercially available methods.
- the casing 3335is expanded in the radial direction using one or more of the processes and apparatus described within the present disclosure.
- the seals 3340prevent the passage of fluids and other materials within the annular region 3365 between the solid casings 3335 and 3350 and the wellbore 3305 .
- the seals 3340may comprise any number of conventional commercially available sealing materials suitable for sealing a casing in a wellbore such as, for example, lead, rubber or epoxy.
- the seals 3340comprise Stratalok epoxy material available from Halliburton Energy Services.
- the slotted casing 3345permits fluids and other materials to pass into and out of the interior of the slotted easing 3345 from and to the annular region 3365 . In this manner, oil and gas may be produced from a producing subterranean zone within a subterranean formation.
- the slotted casing 3345may comprise any number of conventional commercially available sections of slotted tubular casing.
- the slotted casing 3345comprises expandable slotted tubular casing available from Petroline in Abeerdeen, Scotland.
- the slotted casing 145comprises expandable slotted sandscreen tubular casing available from Petroline in Abeerdeen, Scotland.
- the slotted casing 3345is preferably coupled to one or more solid casing 3335 .
- the slotted casing 3345may be coupled to the solid casing 3335 using any number of conventional commercially available processes such as, for example, welding, or slotted or solid expandable connectors.
- the slotted casing 3345is coupled to the solid casing 3335 by expandable solid connectors.
- the slotted casing 3345is preferably coupled to one or more intermediate solid casings 3350 .
- the slotted casing 3345may be coupled to the intermediate solid casing 3350 using any number of conventional commercially available processes such as, for example, welding or expandable solid or slotted connectors.
- the slotted casing 3345is coupled to the intermediate solid casing 3350 by expandable solid connectors.
- the last section of slotted casing 3345is preferably coupled to the shoe 3355 .
- the last slotted casing 3345may be coupled to the shoe 3355 using any number of conventional commercially available processes such as, for example, welding or expandable solid or slotted connectors.
- the last slotted casing 3345is coupled to the shoe 3355 by an expandable solid connector.
- the shoe 3355is coupled directly to the last one of the intermediate solid casings 3350 .
- the slotted casings 3345are positioned within the wellbore 3305 by expanding the slotted casings 3345 in a radial direction into intimate contact with the interior walls of the wellbore 3305 .
- the slotted casings 3345may be expanded in a radial direction using any number of conventional commercially available processes.
- the slotted casings 3345are expanded in the radial direction using one or more of the processes and apparatus disclosed in the present disclosure with reference to FIGS. 14 a - 20 .
- the intermediate solid casing 3350permits fluids and other materials to pass between adjacent slotted casings 3345 .
- the intermediate solid casing 3350may comprise any number of conventional commercially available sections of solid tubular casing such as, for example, oilfield tubulars fabricated from chromium steel or fiberglass.
- the intermediate solid casing 3350comprises oilfield tubulars available from foreign and domestic steel mills.
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- Mining & Mineral Resources (AREA)
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- Fluid Mechanics (AREA)
- Environmental & Geological Engineering (AREA)
- General Life Sciences & Earth Sciences (AREA)
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- Exhaust-Gas Circulating Devices (AREA)
- Facsimile Heads (AREA)
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- Medicines That Contain Protein Lipid Enzymes And Other Medicines (AREA)
- Earth Drilling (AREA)
- Recrystallisation Techniques (AREA)
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Abstract
Description
- This application is a continuation of U.S. utility patent application Ser. No. 11/142,856, attorney docket number 25791.367, filed on Jun. 1, 2005, which is a division of U.S. utility patent application Ser. No. 10/769,726, attorney docket number 25791.310, filed on Jan. 30, 2004, that was a division of U.S. utility patent application Ser. No. 09/510,913, attorney docket number 25791.7.02, filed on Feb. 23, 2000, that claimed the benefit of the filing date of U.S. Provisional Patent Application Ser. No. 60/121,702, attorney docket number 25791.7, filed on Feb. 25, 1999, that was a continuation in part of U.S. utility patent application Ser. No. 09/502,350, attorney docket no. 25791.8.02, filed on Feb. 10, 2000, now U.S. Pat. No. 6,823,937 which issued Nov. 30, 2004, which claimed the benefit of the filing date of U.S. provisional patent application Ser. No. 60/119,611, attorney docket no. 25791.8, filed on Feb. 11, 1999, which was a continuation in part of U.S. utility patent application Ser. No. 09/454,139, attorney docket no. 25791.3.02. filed on Dec. 3, 1999, which claimed the benefit of the filing date of U.S. provisional patent application Ser. No. 60/111,293, attorney docket no. 25791.3, filed on Dec. 7, 1998, the disclosures of which are incorporated herein by reference.
- This application is related to the following co-pending applications: (1) U.S. Pat. No. 6,497,289, which was filed as U.S. patent application Ser. No. 09/454,139, attorney docket no. 25791.03.02, filed on Dec. 3, 1999, which claims priority from
provisional application 60/111,293, filed on Dec. 7, 1998, (2) U.S. patent application Ser. No. 09/510,913, attorney docket no. 25791.7.02, filed on Feb. 23, 2000, which claims priority fromprovisional application 60/121,702, filed on Feb. 25, 1999, (3) U.S. patent application Ser. No. 09/502,350, attorney docket no. 25791.8.02, filed on Feb. 10, 2000, now U.S. Pat. No. 6,823,937 which issued Nov. 30, 2004, which claims priority fromprovisional application 60/119,611, filed on Feb. 11, 1999, (4) U.S. Pat. No. 6,328,113, which was filed as U.S. patent application Ser. No. 09/440,338, attorney docket number 25791.9.02, filed on Nov. 15, 1999, which claims priority fromprovisional application 60/108,558, filed on Nov. 16, 1998, (5) U.S. patent application Ser. No. 10/169,434, attorney docket no. 25791.10.04, filed on Jul. 1, 2002, which claims priority fromprovisional application 60/183,546, filed on Feb. 18, 2000, (6) U.S. patent application Ser. No. 09/523,468, attorney docket no. 25791.11.02, filed on Mar. 10, 2000, now U.S. Pat. No. 6,640,903 which issued Nov. 4, 2003, which claims priority fromprovisional application 60/124,042, filed on Mar. 11, 1999, (7) U.S. Pat. No. 6,568,471, which was filed as patent application Ser. No. 09/512,895, attorney docket no. 25791.12.02, filed on Feb. 24, 2000, which claims priority fromprovisional application 60/121,841, filed on Feb. 26, 1999, (8) U.S. Pat. No. 6,575,240, which was filed as patent application Ser. No. 09/511,941, attorney docket no. 25791.16.02, filed on Feb. 24, 2000, which claims priority fromprovisional application 60/121,907, filed on Feb. 26, 2999, (9) U.S. Pat. No. 6,557,640, which was filed as patent application Ser. No. 09/588,946, attorney docket no. 25791.17.02, filed on Jun. 7, 2000, which claims priority fromprovisional application 60/137,998, filed on Jun. 7, 1999, (10) U.S. patent application Ser. No. 09/981,916, attorney docket no. 25791.18 filed on Oct. 18, 2001, now U.S. Pat. No. 6,712,154 which issued on Mar. 30, 2004 which was a continuation-in-part application of U.S. Pat. No. 6,328,113, which was filed as U.S. patent application Ser. No. 09/440,338, attorney docket number 25791.9.02, filed on Nov. 15, 1999, which claims priority fromprovisional application 60/108,558, filed on Nov. 16, 1998, (11) U.S. Pat. No. 6,604,763, which was filed as application Ser. No. 09/559,122, attorney docket no. 25791.23.02, filed on Apr. 26, 2000, which claims priority fromprovisional application 60/131,106, filed on Mar. 26, 1999, (12) U.S. patent application Ser. No. 10/030,593, attorney docket no. 25791.25.08, filed on Jan. 8, 2002, which claims priority fromprovisional application 60/146,203, filed on Jul. 29, 1999, (13) U.S. provisional patent application Ser. No. 60/143,039, attorney docket no. 25791.26, filed on Jul. 9, 1999, (14) U.S. patent application Ser. No. 10/111,982, attorney docket no. 25791.27.08, filed on Apr. 30, 2002, which claims priority from provisional patent application Ser. No. 60/162,671, attorney docket no. 25791.27, filed on Nov. 1, 1999, (15) U.S. provisional patent application Ser. No. 60/154,047, attorney docket no. 25791.29, filed on Sep. 16, 1999, (16) U.S. provisional patent application Ser. No. 60/438,828, attorney docket no. 25791.31, filed on Jan. 9, 2003, (17) U.S. Pat. No. 6,564,875, which was filed as application Ser. No. 09/679,907, attorney docket no. 25791.34.02, on Oct. 5, 2000, which claims priority from provisional patent application Ser. No. 60/159,082, attorney docket no. 25791.34, filed on Oct. 12, 1999, (18) U.S. patent application Ser. No. 10/089,419, filed on Mar. 27, 2002, now U.S. Pat. No. 6,695,012 which issued Feb. 24, 2004, attorney docket no. 25791.36.03, which claims priority from provisional patent application Ser. No. 60/159,039, attorney docket no. 25791.36, filed on Oct. 12, 1999, (19) U.S. patent application Ser. No. 09/679,906, filed on Oct. 5, 2000, attorney docket no. 25791.37.02, which claims priority from provisional patent application Ser. No. 60/159,033, attorney docket no. 25791.37, filed on Oct. 12, 1999, (20) U.S. patent application Ser. No. 10/303,992, filed on Nov. 22, 2002, attorney docket no. 25791.38.07, which claims priority from provisional patent application Ser. No. 60/212,359, attorney docket no. 25791.38, filed on Jun. 19, 2000, (21) U.S. provisional patent application Ser. No. 60/165,228, attorney docket no. 25791.39, filed on Nov. 12, 1999, (22) U.S. provisional patent application Ser. No. 60/455,051, attorney docket no. 25791.40, filed on Mar. 14, 2003, (23) PCT application US02/2477, filed on Jun. 26, 2002, attorney docket no. 25791.44.02, which claims priority from U.S. provisional patent application Ser. No. 60/303,711, attorney docket no. 25791.44, filed on Jul. 6, 2001, (24) U.S. patent application Ser. No. 10/311,412, filed on Dec. 12, 2002, attorney docket no. 25791.45.07, which claims priority from provisional patent application Ser. No. 60/221,443, attorney docket no. 25791.45, filed on Jul. 28, 2000, (25) U.S. patent application Ser. No. 10/, filed on Dec. 18, 2002, attorney docket no. 25791.46.07, which claims priority from provisional patent application Ser. No. 60/221,645, attorney docket no. 25791.46, filed on Jul. 28, 2000, (26) U.S. patent application Ser. No. 10/322,947, filed on Jan. 22, 2003, now U.S. Pat. No. 6,976,541 which issued Dec. 20, 2005, attorney docket no. 25791.47.03, which claims priority from provisional patent application Ser. No. 60/233,638, attorney docket no. 25791.47, filed on Sep. 18, 2000, (27) U.S. patent application Ser. No. 10/406,648, filed on Mar. 31, 2003, attorney docket no. 25791.48.06, which claims priority from provisional patent application Ser. No. 60/237,334, attorney docket no. 25791.48, filed on Oct. 2, 2000, (28) PCT application US02/04353, filed on Feb. 14, 2002, attorney docket no. 25791.50.02, which claims priority from U.S. provisional patent application Ser. No. 60/270,007, attorney docket no. 25791.50, filed on Feb. 20, 2001, (29) U.S. patent application Ser. No. 10/465,835, filed on Jun. 13, 2003, attorney docket no. 25791.51.06, which claims priority from provisional patent application Ser. No. 60/262,434, attorney docket no. 25791.51, filed on Jan. 17, 2001, (30) U.S. patent application Ser. No. 10/465,831, filed on Aug. 13, 2003, attorney docket no. 25791.52.06, which claims priority from U.S. provisional patent application Ser. No. 60/259,486, attorney docket no. 25791.52, filed on Jan. 3, 2001, (31) U.S. provisional patent application Ser. No. 60/452,303, filed on Mar. 5, 2003, attorney docket no. 25791.53, (32) U.S. Pat. No. 6,470,966, which was filed as patent application Ser. No. 09/850,093, filed on May 7, 2001, attorney docket no. 25791.55, as a divisional application of U.S. Pat. No. 6,497,289, which was filed as U.S. patent application Ser. No. 09/454,139, attorney docket no. 25791.03.02, filed on Dec. 3, 1999, which claims priority fromprovisional application 60/111,293, filed on Dec. 7, 1998, (33) U.S. Pat. No. 6,561,227, which was filed as patent application Ser. No. 09/852,026, filed on May 9, 2001, attorney docket no. 25791.56, as a divisional application of U.S. Pat. No. 6,497,289, which was filed as U.S. patent application Ser. No. 09/454,139, attorney docket no. 25791.03.02, filed on Dec. 3, 1999, which claims priority fromprovisional application 60/111,293, filed on Dec. 7, 1998, (34) U.S. patent application Ser. No. 09/852,027, filed on May 9, 2001, attorney docket no. 25791.57, as a divisional application of U.S. Pat. No. 6,497,289, which was filed as U.S. patent application Ser. No. 09/454,139, attorney docket no. 25791.03.02, filed on Dec. 3, 1999, which claims priority fromprovisional application 60/111,293, filed on Dec. 7, 1998, (35) PCT Application US02/25608, attorney docket no. 25791.58.02, filed on Aug. 13, 2002, which claims priority fromprovisional application 60/318,021, filed on Sep. 7, 2001, attorney docket no. 25791.58, (36) PCT Application US02/24399, attorney docket no. 25791.59.02, filed on Aug. 1, 2002, which claims priority from U.S. provisional patent application Ser. No. 60/313,453, attorney docket no. 25791.59, filed on Aug. 20, 2001, (37) PCT Application US02/29856, attorney docket no. 25791.60.02, filed on Aug. 19, 2002, which claims priority from U.S. provisional patent application Ser. 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No. 11/070,147, attorney docket no. 25791.351, filed on Mar. 2, 2005; (206) U.S. utility patent application Ser. No. 11/071,409, attorney docket no. 25791.352, filed on Mar. 2, 2005; (207) U.S. utility patent application Ser. No. 11/071,557, attorney docket no. 25791.353, filed on Mar. 3, 2005; (208) U.S. utility patent application Ser. No. 11/072,578, attorney docket no. 25791.354, filed on Mar. 4, 2005; (209) U.S. utility patent application Ser. No. 11/072,893, attorney docket no. 25791.355, filed on Mar. 4, 2005; (210) U.S. utility patent application Ser. No. 11/072,594, attorney docket no. 25791.356, filed on Mar. 4, 2005; (211) U.S. utility patent application Ser. No. 11/074,366, attorney docket no. 25791.357, filed on Mar. 7, 2005; and (212) U.S. utility patent application Ser. No. 11/074,266, attorney docket no. 25791.358, filed on Mar. 7, 2005. - This invention relates generally to wellbore casings, and in particular to wellbore casings that are formed using expandable tubing.
- Conventionally, when a wellbore is created, a number of casings are installed in the borehole to prevent collapse of the borehole wall and to prevent undesired outflow of drilling fluid into the formation or inflow of fluid from the formation into the borehole. The borehole is drilled in intervals whereby a casing which is to be installed in a lower borehole interval is lowered through a previously installed casing of an upper borehole interval. As a consequence of this procedure the casing of the lower interval is of smaller diameter than the casing of the upper interval. Thus, the casings are in a nested arrangement with casing diameters decreasing in downward direction. Cement annuli are provided between the outer surfaces of the casings and the borehole wall to seal the casings from the borehole wall. As a consequence of this nested arrangement a relatively large borehole diameter is required at the upper part of the wellbore. Such a large borehole diameter involves increased costs due to heavy casing handling equipment, large drill bits and increased volumes of drilling fluid and drill cuttings. Moreover, increased drilling rig time is involved due to required cement pumping, cement hardening, required equipment changes due to large variations in hole diameters drilled in the course of the well, and the large volume of cuttings drilled and removed.
- Conventionally, at the surface end of the wellbore, a wellhead is formed that typically includes a surface casing, a number of production and/or drilling spools, valving, and a Christmas tree. Typically the wellhead further includes a concentric arrangement of casings including a production casing and one or more intermediate casings. The casings are typically supported using load bearing slips positioned above the ground. The conventional design and construction of wellheads is expensive and complex.
- The present invention is directed to overcoming one or more of the limitations of the existing procedures for forming wellbores and wellheads.
FIG. 1 is a fragmentary cross-sectional view illustrating the drilling of a new section of a well borehole.FIG. 2 is a fragmentary cross-sectional view illustrating the placement of an embodiment of an apparatus for creating a casing within the new section of the well borehole.FIG. 3 is a fragmentary cross-sectional view illustrating the injection of a first quantity of a fluidic material into the new section of the well borehole.FIG. 3 ais another fragmentary cross-sectional view illustrating the injection of a first quantity of a hardenable fluidic sealing material into the new section of the well borehole.FIG. 4 is a fragmentary cross-sectional view illustrating the injection of a second quantity of a fluidic material into the new section of the well borehole.FIG. 5 is a fragmentary cross-sectional view illustrating the drilling out of a portion of the cured hardenable fluidic sealing material from the new section of the well borehole.FIG. 6 is a cross-sectional view of an embodiment of the overlapping joint between adjacent tubular members.FIG. 7 is a fragmentary cross-sectional view of an exemplary embodiment of the apparatus for creating a casing within a well borehole.FIG. 8 is a fragmentary cross-sectional illustration of the placement of an expanded tubular member within another tubular member.FIG. 9 is a cross-sectional illustration of an exemplary embodiment of an apparatus for forming a casing including a drillable mandrel and shoe.FIG. 9 ais another cross-sectional illustration of the apparatus ofFIG. 9 .FIG. 9 bis another cross-sectional illustration of the apparatus ofFIG. 9 .FIG. 9 cis another cross-sectional illustration of the apparatus ofFIG. 9 .FIG. 10 ais a cross-sectional illustration of a wellbore including a pair of adjacent overlapping casings.FIG. 10 bis a cross-sectional illustration of an apparatus and method for creating a tie-back liner using an expandable tubular member.FIG. 10 cis a cross-sectional illustration of the pumping of a fluidic sealing material into the annular region between the tubular member and the existing casing.FIG. 10 dis a cross-sectional illustration of the pressurizing of the interior of the tubular member below the mandrel.FIG. 10 eis a cross-sectional illustration of the extrusion of the tubular member off of the mandrel.FIG. 10 fis a cross-sectional illustration of the tie-back liner before drilling out the shoe and packer.FIG. 10 gis a cross-sectional illustration of the completed tie-back liner created using an expandable tubular member.FIG. 11 ais a fragmentary cross-sectional view illustrating the drilling of a new section of a well borehole.FIG. 11 bis a fragmentary cross-sectional view illustrating the placement of an embodiment of an apparatus for hanging a tubular liner within the new section of the well borehole.FIG. 11 cis a fragmentary cross-sectional view illustrating the injection of a first quantify of a hardenable fluidic sealing material into the new section of the well borehole.FIG. 11 dis a fragmentary cross-sectional view illustrating the introduction of a wiper dart into the new section of the well borehole.FIG. 11 eis a fragmentary cross-sectional view illustrating the injection of a second quantity of a hardenable fluidic sealing material into the new section of the well borehole.FIG. 11 fis a fragmentary cross-sectional view illustrating the completion of the tubular liner.FIG. 12 is a cross-sectional illustration of an exemplary embodiment of a wellhead system utilizing expandable tubular members.FIG. 13 is a partial cross-sectional illustration of an exemplary embodiment of the wellhead system ofFIG. 12 .FIG. 14 ais an illustration of the formation of an embodiment of a mono-diameter wellbore casing.FIG. 14 bis another illustration of the formation of the mono-diameter wellbore casing.FIG. 14 cis another illustration of the formation of the mono-diameter wellbore casing.FIG. 14 dis another illustration of the formation of the mono-diameter wellbore casing.FIG. 14 eis another illustration of the formation of the mono-diameter wellbore casing.FIG. 14 fis another illustration of the formation of the mono-diameter wellbore casing.FIG. 15 is an illustration of an embodiment of an apparatus for expanding a tubular member.FIG. 15 ais another illustration of the apparatus ofFIG. 15 .FIG. 15 bis another illustration of the apparatus ofFIG. 15 .FIG. 16 is an illustration of an embodiment of an apparatus for forming a mono-diameter wellbore casing.FIG. 17 is an illustration of an embodiment of an apparatus for expanding a tubular member.FIG. 17 ais another illustration of the apparatus ofFIG. 16 .FIG. 17 bis another illustration of the apparatus ofFIG. 16 .FIG. 18 is an illustration of an embodiment of an apparatus for forming a mono-diameter wellbore casing.FIG. 19 is an illustration of another embodiment of an apparatus for expanding a tubular member.FIG. 19 ais another illustration of the apparatus ofFIG. 17 .FIG. 19 bis another illustration of the apparatus ofFIG. 17 .FIG. 20 is an illustration of an embodiment of an apparatus for forming a mono-diameter wellbore casing.FIG. 21 is an illustration of the isolation of subterranean zones using expandable tubulars.- An apparatus and method for forming a wellbore casing within a subterranean formation is provided. The apparatus and method permits a wellbore casing to be formed in a subterranean formation by placing a tubular member and a mandrel in a new section of a wellbore, and then extruding the tubular member off of the mandrel by pressurizing an interior portion of the tubular member. The apparatus and method further permits adjacent tubular members in the wellbore to be joined using an overlapping joint that prevents fluid and or gas passage. The apparatus and method further permits a new tubular member to be supported by an existing tubular member by expanding the new tubular member into engagement with the existing tubular member. The apparatus and method further minimizes the reduction in the hole size of the wellbore casing necessitated by the addition of new sections of wellbore casing.
- An apparatus and method for forming a tie-back liner using an expandable tubular member is also provided. The apparatus and method permits a tie-back liner to be created by extruding a tubular member off of a mandrel by pressurizing and interior portion of the tubular member. In this manner, a tie-back liner is produced. The apparatus and method further permits adjacent tubular members in the wellbore to be joined using an overlapping joint that prevents fluid and/or gas passage. The apparatus and method further permits a new tubular member to be supported by an existing tubular member by expanding the new tubular member into engagement with the existing tubular member.
- An apparatus and method for expanding a tubular member is also provided that includes an expandable tubular member, mandrel and a shoe. In an exemplary embodiment, the interior portions of the apparatus is composed of materials that permit the interior portions to be removed using a conventional drilling apparatus. In this manner, in the event of a malfunction in a downhole region, the apparatus may be easily removed.
- An apparatus and method for hanging an expandable tubular liner in a wellbore is also provided. The apparatus and method permit a tubular liner to be attached to an existing section of casing. The apparatus and method further have application to the joining of tubular members in general.
- An apparatus and method for forming a wellhead system is also provided. The apparatus and method permit a wellhead to be formed including a number of expandable tubular members positioned in a concentric arrangement. The wellhead preferably includes an outer casing that supports a plurality of concentric casings using contact pressure between the inner casings and the outer casing. The resulting wellhead system eliminates many of the spools conventionally required, reduces the height of the Christmas tree facilitating servicing, lowers the load bearing areas of the wellhead resulting in a more stable system, and eliminates costly and expensive hanger systems.
- An apparatus and method for forming a mono-diameter well casing is also provided. The apparatus and method permit the creation of a well casing in a wellbore having a substantially constant internal diameter. In this manner, the operation of an oil or gas well is greatly simplified.
- An apparatus and method for expanding tubular members is also provided. The apparatus and method utilize a piston-cylinder configuration in which a pressurized chamber is used to drive a mandrel to radially expand tubular members. In this manner, higher operating pressures can be utilized. Throughout the radial expansion process, the tubular member is never placed in direct contact with the operating pressures. In this manner, damage to the tubular member is prevented while also permitting controlled radial expansion of the tubular member in a wellbore.
- An apparatus and method for forming a mono-diameter wellbore casing is also provided. The apparatus and method utilize a piston-cylinder configuration in which a pressurized chamber is used to drive a mandrel to radially expand tubular members. In this manner, higher operating pressures can be utilized. Throughput the radial expansion process, the tubular member is never placed in direct contact with the operating pressures. In this manner, damage to the tubular member is prevented while also permitting controlled radial expansion of the tubular member in a wellbore.
- An apparatus and method for isolating one or more subterranean zones from one or more other subterranean zones is also provided. The apparatus and method permits a producing zone to be isolated from a nonproducing zone using a combination of solid and slotted tubulars. In the production mode, the teachings of the present disclosure may be used in combination with conventional, well known, production completion equipment and methods using a series of packers, solid tubing, perforated tubing, and sliding sleeves, which will be inserted into the disclosed apparatus to permit the commingling and/or isolation of the subterranean zones from each other.
- Referring initially to
FIGS. 1-5 , an embodiment of an apparatus and method for forming a wellbore casing within a subterranean formation will now be described. As illustrated inFIG. 1 , awellbore 100 is positioned in asubterranean formation 105. Thewellbore 100 includes an existingcased section 110 having atubular casing 115 and an annular outer layer ofcement 120. - In order to extend the
wellbore 100 into thesubterranean formation 105, adrill string 125 is used in a well known manner to drill out material from thesubterranean formation 105 to form anew section 130. - As illustrated in
FIG. 2 , anapparatus 200 for forming a wellbore casing in a subterranean formation is then positioned in thenew section 130 of thewellbore 100. Theapparatus 200 preferably includes an expandable mandrel orpig 205, atubular member 210, ashoe 215, alower cup seal 220, anupper cup seal 225, afluid passage 230, afluid passage 235, afluid passage 240, seals245, and asupport member 250. - The
expandable mandrel 205 is coupled to and supported by thesupport member 250. Theexpandable mandrel 205 is preferably adapted to controllably expand in a radial direction. Theexpandable mandrel 205 may comprise any number of conventional commercially available expandable mandrels modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theexpandable mandrel 205 comprises a hydraulic expansion tool as disclosed in U.S. Pat. No. 5,348,095, the contents of which are incorporated herein by reference, modified in accordance with the teachings of the present disclosure. - The
tubular member 210 is supported by theexpandable mandrel 205. Thetubular member 210 is expanded in the radial direction and extruded off of theexpandable mandrel 205. Thetubular member 210 may be fabricated from any number of conventional commercially available materials such as, for example, Oilfield Country Tubular Goods (OCTG), 13 chromium steel tubing/casing, or plastic tubing/casing. In an exemplary embodiment, thetubular member 210 is fabricated from OCTG in order to maximize strength after expansion. The inner and outer diameters of thetubular member 210 may range, for example, from approximately 0.75 to 47 inches and 1.05 to 48 inches, respectively. In an exemplary embodiment, the inner and outer diameters of thetubular member 210 range from about 3 to 15.5 inches and 3.5 to 16 inches, respectively in order to optimally provide minimal telescoping effect in the most commonly drilled wellbore sizes. Thetubular member 210 preferably comprises a solid member. - In an exemplary embodiment, the
end portion 260 of thetubular member 210 is slotted, perforated, or otherwise modified to catch or slow down themandrel 205 when it completes the extrusion oftubular member 210. In an exemplary embodiment, the length of thetubular member 210 is limited to minimize the possibility of buckling. For typicaltubular member 210 materials, the length of thetubular member 210 is preferably limited to between about 40 to 20,000 feet in length. - The
shoe 215 is coupled to theexpandable mandrel 205 and thetubular member 210. Theshoe 215 includesfluid passage 240. Theshoe 215 may comprise any number of conventional commercially available shoes such as, for example, Super Seal II float shoe, Super Seal II Down-Jet float shoe or a guide shoe with a sealing sleeve for a latch down plug modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theshoe 215 comprises an aluminum down-jet guide shoe with a sealing sleeve for a latch-down plug available from Halliburton Energy Services in Dallas, Tex., modified in accordance with the teachings of the present disclosure, in order to optimally guide thetubular member 210 in the wellbore, optimally provide an adequate seal between the interior and exterior diameters of the overlapping joint between the tubular members, and to optimally allow the complete drill out of the shoe and plug after the completion of the cementing and expansion operations. - In an exemplary embodiment, the
shoe 215 includes one or more through and side outlet ports in fluidic communication with thefluid passage 240. In this manner, theshoe 215 optimally injects hardenable fluidic sealing material into the region outside theshoe 215 andtubular member 210. In an exemplary embodiment, theshoe 215 includes thefluid passage 240 having an inlet geometry that can receive a dart and/or a ball sealing member. In this manner, thefluid passage 240 can be optimally sealed off by introducing a plug, dart and/or ball sealing elements into thefluid passage 230. - The
lower cup seal 220 is coupled to and supported by thesupport member 250. Thelower cup seal 220 prevents foreign materials from entering the interior region of thetubular member 210 adjacent to theexpandable mandrel 205. Thelower cup seal 220 may comprise any number of conventional commercially available cup seals such as, for example, TP cups, or Selective Injection Packer (SIP) cups modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, thelower cup seal 220 comprises a SIP cup seal, available from Halliburton Energy Services in Dallas, Tex. in order to optimally block foreign material and contain a body of lubricant. - The
upper cup seal 225 is coupled to and supported by thesupport member 250. Theupper cup seal 225 prevents foreign materials from entering the interior region of thetubular member 210. Theupper cup seal 225 may comprise any number of conventional commercially available cup seals such as, for example, TP cups or SIP cups modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theupper cup seal 225 comprises a SIP cup, available from Halliburton Energy Services in Dallas, Tex. in order to optimally block the entry of foreign materials and contain a body of lubricant. - The
fluid passage 230 permits fluidic materials to be transported to and from the interior region of thetubular member 210 below theexpandable mandrel 205. Thefluid passage 230 is coupled to and positioned within thesupport member 250 and theexpandable mandrel 205. Thefluid passage 230 preferably extends from a position adjacent to the surface to the bottom of theexpandable mandrel 205. Thefluid passage 230 is preferably positioned along a centerline of theapparatus 200. - The
fluid passage 230 is preferably selected, in the casing running mode of operation, to transport materials such as drilling mud or formation fluids at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to minimize drag on the tubular member being run and to minimize surge pressures exerted on the wellbore which could cause a loss of wellbore fluids and lead to hole collapse. - The
fluid passage 235 permits fluidic materials to be released from thefluid passage 230. In this manner, during placement of theapparatus 200 within thenew section 130 of thewellbore 100,fluidic materials 255 forced up thefluid passage 230 can be released into thewellbore 100 above thetubular member 210 thereby minimizing surge pressures on thewellbore section 130. Thefluid passage 235 is coupled to and positioned within thesupport member 250. The fluid passage is further fluidicly coupled to thefluid passage 230. - The
fluid passage 235 preferably includes a control valve for controllably opening and closing thefluid passage 235. In an exemplary embodiment, the control valve is pressure activated in order to controllably minimize surge pressures. Thefluid passage 235 is preferably positioned substantially orthogonal to the centerline of theapparatus 200. - The
fluid passage 235 is preferably selected to convey fluidic materials at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to reduce the drag on theapparatus 200 during insertion into thenew section 130 of thewellbore 100 and to minimize surge pressures on thenew wellbore section 130. - The
fluid passage 240 permits fluidic materials to be transported to and from the region exterior to thetubular member 210 andshoe 215. Thefluid passage 240 is coupled to and positioned within theshoe 215 in fluidic communication with the interior region of thetubular member 210 below theexpandable mandrel 205. Thefluid passage 240 preferably has a cross-sectional shape that permits a plug, or other similar device, to be placed influid passage 240 to thereby block further passage of fluidic materials. In this manner, the interior region of thetubular member 210 below theexpandable mandrel 205 can be fluidicly isolated from the region exterior to thetubular member 210. This permits the interior region of thetubular member 210 below theexpandable mandrel 205 to be pressurized. Thefluid passage 240 is preferably positioned substantially along the centerline of theapparatus 200. - The
fluid passage 240 is preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the annular region between thetubular member 210 and thenew section 130 of thewellbore 100 with fluidic materials. In an exemplary embodiment, thefluid passage 240 includes an inlet geometry that can receive a dart and/or a ball sealing member. In this manner, thefluid passage 240 can be sealed of by introducing a plug, dart and/or ball sealing elements into thefluid passage 230. - The
seals 245 are coupled to and supported by anend portion 260 of thetubular member 210. Theseals 245 are further positioned on anouter surface 265 of theend portion 260 of thetubular member 210. Theseals 245 permit the overlapping joint between theend portion 270 of thecasing 115 and theportion 260 of thetubular member 210 to be fluidicly sealed. Theseals 245 may comprise any number of conventional commercially available seals such as, for example, lead, rubber, Teflon, or epoxy seals modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theseals 245 are molded from Stratalock epoxy available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide a load bearing interference fit between theend 260 of thetubular member 210 and theend 270 of the existingcasing 115. - In an exemplary embodiment, the
seals 245 are selected to optimally provide a sufficient frictional force to support the expandedtubular member 210 from the existingcasing 115. In an exemplary embodiment, the frictional force optimally provided by theseals 245 ranges from about 1,000 to 1,000,000 lbf in order to optimally support the expandedtubular member 210. - The
support member 250 is coupled to theexpandable mandrel 205,tubular member 210,shoe 215, and seals220 and225. Thesupport member 250 preferably comprises an annular member having sufficient strength to carry theapparatus 200 into thenew section 130 of thewellbore 100. In an exemplary embodiment, thesupport member 250 further includes one or more conventional centralizers (not illustrated) to help stabilize theapparatus 200. - In an exemplary embodiment, a quantity of
lubricant 275 is provided in the annular region above theexpandable mandrel 205 within the interior of thetubular member 210. In this manner, the extrusion of thetubular member 210 off of theexpandable mandrel 205 is facilitated. Thelubricant 275 may comprise any number of conventional commercially available lubricants such as, for example, Lubriplate, chlorine based lubricants, oil based lubricants orClimax 1500 Antisieze (3100). In an exemplary embodiment, thelubricant 275 comprisesClimax 1500 Antisieze (3100) available from Climax Lubricants and Equipment Co. in Houston, Tex. in order to optimally provide optimum lubrication to facilitate the expansion process. - In an exemplary embodiment, the
support member 250 is thoroughly cleaned prior to assembly to the remaining portions of theapparatus 200. In this manner, the introduction of foreign material into theapparatus 200 is minimized. This minimizes the possibility of foreign material clogging the various flow passages and valves of theapparatus 200. - In an exemplary embodiment, before or after positioning the
apparatus 200 within thenew section 130 of thewellbore 100, a couple of wellbore volumes are circulated in order to ensure that no foreign materials are located within thewellbore 100 that might clog up the various flow passages and valves of theapparatus 200 and to ensure that no foreign material interferes with the expansion process. - As illustrated in
FIG. 3 , thefluid passage 235 is then closed and a hardenablefluidic sealing material 305 is then pumped from a surface location into thefluid passage 230. The material305 then passes from thefluid passage 230 into theinterior region 310 of thetubular member 210 below theexpandable mandrel 205. The material305 then passes from theinterior region 310 into thefluid passage 240. The material305 then exits theapparatus 200 and fills theannular region 315 between the exterior of thetubular member 210 and the interior wall of thenew section 130 of thewellbore 100. Continued pumping of the material305 causes thematerial 305 to fill up at least a portion of theannular region 315. - The
material 305 is preferably pumped into theannular region 315 at pressures and flow rates ranging, for example, from about 0 to 5000 psi and 0 to 1,500 gallons/min, respectively. The optimum flow rate and operating pressures vary as a function of the casing and wellbore sizes, wellbore section length, available pumping equipment, and fluid properties of the fluidic material being pumped. The optimum flow rate and operating pressure are preferably determined using conventional empirical methods. - The hardenable
fluidic sealing material 305 may comprise any number of conventional commercially available hardenable fluidic sealing materials such as, for example, slag mix, cement or epoxy. In an exemplary embodiment, the hardenablefluidic sealing material 305 comprises a blended cement prepared specifically for the particular well section being drilled from Halliburton Energy Services in Dallas, Tex. in order to provide optimal support fortubular member 210 while also maintaining optimum flow characteristics so as to minimize difficulties during the displacement of cement in theannular region 315. The optimum blend of the blended cement is preferably determined using conventional empirical methods. - The
annular region 315 preferably is filled with the material305 in sufficient quantities to ensure that, upon radial expansion of thetubular member 210, theannular region 315 of thenew section 130 of thewellbore 100 will be filled withmaterial 305. - In an exemplary embodiment, as illustrated in
FIG. 3 a,the wall thickness and/or the outer diameter of thetubular member 210 is reduced in the region adjacent to themandrel 205 in order optimally permit placement of theapparatus 200 in positions in the wellbore with tight clearances. Furthermore, in this manner, the initiation of the radial expansion of thetubular member 210 during the extrusion process is optimally facilitated. - As illustrated in
FIG. 4 , once theannular region 315 has been adequately filled withmaterial 305, aplug 405, or other similar device, is introduced into thefluid passage 240 thereby fluidicly isolating theinterior region 310 from theannular region 315. In an exemplary embodiment, a non-hardenablefluidic material 306 is then pumped into theinterior region 310 causing the interior region to pressurize. In this manner, the interior of the expandedtubular member 210 will not contain significant amounts of curedmaterial 305. This reduces and simplifies the cost of the entire process. Alternatively, thematerial 305 may be used during this phase of the process. - Once the
interior region 310 becomes sufficiently pressurized, thetubular member 210 is extruded off of theexpandable mandrel 205. During the extrusion process, theexpandable mandrel 205 may be raised out of the expanded portion of thetubular member 210. In an exemplary embodiment, during the extrusion process, themandrel 205 is raised at approximately the same rate as thetubular member 210 is expanded in order to keep thetubular member 210 stationary relative to thenew wellbore section 130. In an exemplary embodiment, the extrusion process is commenced with thetubular member 210 positioned above the bottom of thenew wellbore section 130, keeping themandrel 205 stationary, and allowing thetubular member 210 to extrude off of themandrel 205 and fall down thenew wellbore section 130 under the force of gravity. - The
plug 405 is preferably placed into thefluid passage 240 by introducing theplug 405 into thefluid passage 230 at a surface location in a conventional manner. Theplug 405 preferably acts to fluidicly isolate the hardenablefluidic sealing material 305 from the non hardenablefluidic material 306. - The
plug 405 may comprise any number of conventional commercially available devices from plugging a fluid passage such as, for example, Multiple Stage Cementer (MSC) latch-down plug, Omega latch-down plug or three-wiper latch-down plug modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theplug 405 comprises a MSC latch-down plug available from Halliburton Energy Services in Dallas, Tex. - After placement of the
plug 405 in thefluid passage 240, a non hardenablefluidic material 306 is preferably pumped into theinterior region 310 at pressures and flow rates ranging, for example, from approximately 400 to 10,000 psi and 30 to 4,000 gallons/min. In this manner, the amount of hardenable fluidic sealing material within theinterior 310 of thetubular member 210 is minimized. In an exemplary embodiment, after placement of theplug 405 in thefluid passage 240, the nonhardenable material 306 is preferably pumped into theinterior region 310 at pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to 3,000 gallons/min in order to maximize the extrusion speed. - In an exemplary embodiment, the
apparatus 200 is adapted to minimize tensile, burst, and friction effects upon thetubular member 210 during the expansion process. These effects will depend upon the geometry of theexpansion mandrel 205, the material composition of thetubular member 210 andexpansion mandrel 205, the inner diameter of thetubular member 210, the wall thickness of thetubular member 210, the type of lubricant, and the yield strength of thetubular member 210. In general, the thicker the wall thickness, the smaller the inner diameter, and the greater the yield strength of thetubular member 210, then the greater the operating pressures required to extrude thetubular member 210 off of themandrel 205. - For typical
tubular members 210, the extrusion of thetubular member 210 off of the expandable mandrel will begin when the pressure of theinterior region 310 reaches, for example, approximately 500 to 9,000 psi. - During the extrusion process, the
expandable mandrel 205 may be raised out of the expanded portion of thetubular member 210 at rates ranging, for example, from about 0 to 5 ft/sec. In an exemplary embodiment, during the extrusion process, theexpandable mandrel 205 is raised out of the expanded portion of thetubular member 210 at rates ranging from about 0 to 2 ft/sec in order to minimize the time required for the expansion process while also permitting easy control of the expansion process. - When the
end portion 260 of thetubular member 210 is extruded off of theexpandable mandrel 205, theouter surface 265 of theend portion 260 of thetubular member 210 will preferably contact theinterior surface 410 of theend portion 270 of thecasing 115 to form an fluid tight overlapping joint. The contact pressure of the overlapping joint may range, for example, from approximately 50 to 20,000 psi. In an exemplary embodiment, the contact pressure of the overlapping joint ranges from approximately 400 to 10,000 psi in order to provide optimum pressure to activate theannular sealing members 245 and optimally provide resistance to axial motion to accommodate typical tensile and compressive loads. - The overlapping joint between the
section 410 of the existingcasing 115 and thesection 265 of the expandedtubular member 210 preferably provides a gaseous and fluidic seal. In an exemplary embodiment, the sealingmembers 245 optimally provide a fluidic and gaseous seal in the overlapping joint. - In an exemplary embodiment, the operating pressure and flow rate of the non hardenable
fluidic material 306 is controllably ramped down when theexpandable mandrel 205 reaches theend portion 260 of thetubular member 210. In this manner, the sudden release of pressure caused by the complete extrusion of thetubular member 210 off of theexpandable mandrel 205 can be minimized. In an exemplary embodiment, the operating pressure is reduced in a substantially linear fashion from 100% to about 10% during the end of the extrusion process beginning when themandrel 205 is within about 5 feet from completion of the extrusion process. - Alternatively, or in combination, a shock absorber is provided in the
support member 250 in order to absorb the shock caused by the sudden release of pressure. The shock absorber may comprise, for example, any conventional commercially available shock absorber adapted for use in wellbore operations. - Alternatively, or in combination, a mandrel catching structure is provided in the
end portion 260 of thetubular member 210 in order to catch or at least decelerate themandrel 205. - Once the extrusion process is completed, the
expandable mandrel 205 is removed from thewellbore 100. In an exemplary embodiment, either before or after the removal of theexpandable mandrel 205, the integrity of the fluidic seal of the overlapping joint between theupper portion 260 of thetubular member 210 and thelower portion 270 of thecasing 115 is tested using conventional methods. - If the fluidic seal of the overlapping joint between the
upper portion 260 of thetubular member 210 and thelower portion 270 of thecasing 115 is satisfactory, then any uncured portion of thematerial 305 within the expandedtubular member 210 is then removed in a conventional manner such as, for example, circulating the uncured material out of the interior of the expandedtubular member 210. Themandrel 205 is then pulled out of thewellbore section 130 and a drill bit or mill is used in combination with aconventional drilling assembly 505 to drill out anyhardened material 305 within thetubular member 210. Thematerial 305 within theannular region 315 is then allowed to cure. - As illustrated in
FIG. 5 , preferably any remaining curedmaterial 305 within the interior of the expandedtubular member 210 is then removed in a conventional manner using aconventional drill string 505. The resulting new section of casing510 includes the expandedtubular member 210 and an outer annular layer515 of curedmaterial 305. The bottom portion of theapparatus 200 comprising theshoe 215 and dart405 may then be removed by drilling out theshoe 215 and dart405 using conventional drilling methods. - In an exemplary embodiment, as illustrated in
FIG. 6 , theupper portion 260 of thetubular member 210 includes one ormore sealing members 605 and one or more pressure relief holes610. In this manner, the overlapping joint between thelower portion 270 of thecasing 115 and theupper portion 260 of thetubular member 210 is pressure-tight and the pressure on the interior and exterior surfaces of thetubular member 210 is equalized during the extrusion process. - In an exemplary embodiment, the sealing
members 605 are seated withinrecesses 615 formed in theouter surface 265 of theupper portion 260 of thetubular member 210. In an exemplary embodiment, the sealingmembers 605 are bonded or molded onto theouter surface 265 of theupper portion 260 of thetubular member 210. Thepressure relief holes 610 are preferably positioned in the last few feet of thetubular member 210. The pressure relief holes reduce the operating pressures required to expand theupper portion 260 of thetubular member 210. This reduction in required operating pressure in turn reduces the velocity of themandrel 205 upon the completion of the extrusion process. This reduction in velocity in turn minimizes the mechanical shock to theentire apparatus 200 upon the completion of the extrusion process. - Referring now to
FIG. 7 , an exemplary embodiment of an apparatus700 for forming a casing within a wellbore preferably includes an expandable mandrel orpig 705, an expandable mandrel orpig container 710, atubular member 715, afloat shoe 720, alower cup seal 725, an upper cup seal730, afluid passage 735, afluid passage 740, asupport member 745, a body of lubricant750, anovershot connection 755, anothersupport member 760, and astabilizer 765. - The
expandable mandrel 705 is coupled to and supported by thesupport member 745. Theexpandable mandrel 705 is further coupled to theexpandable mandrel container 710. Theexpandable mandrel 705 is preferably adapted to controllably expand in a radial direction. Theexpandable mandrel 705 may comprise any number of conventional commercially available expandable mandrels modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theexpandable mandrel 705 comprises a hydraulic expansion tool substantially as disclosed in U.S. Pat. No. 5,348,095, the contents of which are incorporated herein by reference, modified in accordance with the teachings of the present disclosure. - The
expandable mandrel container 710 is coupled to and supported by thesupport member 745. Theexpandable mandrel container 710 is further coupled to theexpandable mandrel 705. Theexpandable mandrel container 710 may be constructed from any number of conventional commercially available materials such as, for example, Oilfield Country Tubular Goods, stainless steel, titanium or high strength steels. In an exemplary embodiment, theexpandable mandrel container 710 is fabricated from material having a greater strength than the material from which thetubular member 715 is fabricated. In this manner, thecontainer 710 can be fabricated from a tubular material having a thinner wall thickness than thetubular member 210. This permits thecontainer 710 to pass through tight clearances thereby facilitating its placement within the wellbore. - In an exemplary embodiment, once the expansion process begins, and the thicker, lower strength material of the
tubular member 715 is expanded, the outside diameter of thetubular member 715 is greater than the outside diameter of thecontainer 710. - The
tubular member 715 is coupled to and supported by theexpandable mandrel 705. Thetubular member 715 is preferably expanded in the radial direction and extruded off of theexpandable mandrel 705 substantially as described above with reference toFIGS. 1-6 . Thetubular member 715 may be fabricated from any number of materials such as, for example, Oilfield Country Tubular Goods (OCTG), automotive grade steel or plastics. In an exemplary embodiment, thetubular member 715 is fabricated from OCTG. - In an exemplary embodiment, the
tubular member 715 has a substantially annular cross-section. In an exemplary embodiment, thetubular member 715 has a substantially circular annular cross-section. - The
tubular member 715 preferably includes anupper section 805, anintermediate section 810, and alower section 815. Theupper section 805 of thetubular member 715 preferably is defined by the region beginning in the vicinity of themandrel container 710 and ending with thetop section 820 of thetubular member 715. Theintermediate section 810 of thetubular member 715 is preferably defined by the region beginning in the vicinity of the top of themandrel container 710 and ending with the region in the vicinity of themandrel 705. The lower section of thetubular member 715 is preferably defined by the region beginning in the vicinity of themandrel 705 and ending at the bottom825 of thetubular member 715. - In an exemplary embodiment, the wall thickness of the
upper section 805 of thetubular member 715 is greater than the wall thicknesses of the intermediate andlower sections tubular member 715 in order to optimally facilitate the initiation of the extrusion process and optimally permit the apparatus700 to be positioned in locations in the wellbore having tight clearances. - The outer diameter and wall thickness of the
upper section 805 of thetubular member 715 may range, for example, from about 1.05 to 48 inches and ⅛ to 2 inches, respectively. In an exemplary embodiment, the outer diameter and wall thickness of theupper section 805 of thetubular member 715 range from about 3.5 to 16 inches and ⅜ to 1.5 inches, respectively. - The outer diameter and wall thickness of the
intermediate section 810 of thetubular member 715 may range, for example, from about 2.5 to 50 inches and 1/16 to 1.5 inches, respectively. In an exemplary embodiment, the outer diameter and wall thickness of theintermediate section 810 of thetubular member 715 range from about 3.5 to 19 inches and ⅛ to 1.25 inches, respectively. - The outer diameter and wall thickness of the
lower section 815 of thetubular member 715 may range, for example, from about 2.5 to 50 inches and 1/16 to 1.25 inches, respectively. In an exemplary embodiment, the outer diameter and wall thickness of thelower section 810 of thetubular member 715 range from about 3.5 to 19 inches and ⅛ to 1.25 inches, respectively. In an exemplary embodiment, the wall thickness of thelower section 815 of thetubular member 715 is further increased to increase the strength of theshoe 720 when drillable materials such as, for example, aluminum are used. - The
tubular member 715 preferably comprises a solid tubular member. In an exemplary embodiment, theend portion 820 of thetubular member 715 is slotted, perforated, or otherwise modified to catch or slow down themandrel 705 when it completes the extrusion oftubular member 715. In an exemplary embodiment, the length of thetubular member 715 is limited to minimize the possibility of buckling. For typicaltubular member 715 materials, the length of thetubular member 715 is preferably limited to between about 40 to 20,000 feet in length. - The
shoe 720 is coupled to theexpandable mandrel 705 and thetubular member 715. Theshoe 720 includes thefluid passage 740. In an exemplary embodiment, theshoe 720 further includes aninlet passage 830, and one ormore jet ports 835. In an exemplary embodiment, the cross-sectional shape of theinlet passage 830 is adapted to receive a latch-down dart, or other similar elements, for blocking theinlet passage 830. The interior of theshoe 720 preferably includes a body ofsolid material 840 for increasing the strength of theshoe 720. In an exemplary embodiment, the body ofsolid material 840 comprises aluminum. - The
shoe 720 may comprise any number of conventional commercially available shoes such as, for example, Super Seal II Down-Jet float shoe, or guide shoe with a sealing sleeve for a latch down plug modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theshoe 720 comprises an aluminum down-jet guide shoe with a sealing sleeve for a latch-down plug available from Halliburton Energy Services in Dallas, Tex., modified in accordance with the teachings of the present disclosure, in order to optimize guiding thetubular member 715 in the wellbore, optimize the seal between thetubular member 715 and an existing wellbore casing, and to optimally facilitate the removal of theshoe 720 by drilling it out after completion of the extrusion process. - The
lower cup seal 725 is coupled to and supported by thesupport member 745. Thelower cup seal 725 prevents foreign materials from entering the interior region of thetubular member 715 above theexpandable mandrel 705. Thelower cup seal 725 may comprise any number of conventional commercially available cup seals such as, for example, TP cups or Selective Injection Packer (SIP) cups modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, thelower cup seal 725 comprises a SIP cup, available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide a debris barrier and hold a body of lubricant. - The upper cup seal730 is coupled to and supported by the
support member 760. The upper cup seal730 prevents foreign materials from entering the interior region of thetubular member 715. The upper cup seal730 may comprise any number of conventional commercially available cup seals such as, for example, TP cups or Selective Injection Packer (SIP) cup modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, the upper cup seal730 comprises a SIP cup available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide a debris barrier and contain a body of lubricant. - The
fluid passage 735 permits fluidic materials to be transported to and from the interior region of thetubular member 715 below theexpandable mandrel 705. Thefluid passage 735 is fluidicly coupled to thefluid passage 740. Thefluid passage 735 is preferably coupled to and positioned within thesupport member 760, thesupport member 745, themandrel container 710, and theexpandable mandrel 705. Thefluid passage 735 preferably extends from a position adjacent to the surface to the bottom of theexpandable mandrel 705. Thefluid passage 735 is preferably positioned along a centerline of the apparatus700. Thefluid passage 735 is preferably selected to transport materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 40 to 3,000 gallons/minute and 500 to 9,000 psi in order to optimally provide sufficient operating pressures to extrude thetubular member 715 off of theexpandable mandrel 705. - As described above with reference to
FIGS. 1-6 , during placement of the apparatus700 within a new section of a wellbore, fluidic materials forced up thefluid passage 735 can be released into the wellbore above thetubular member 715. In an exemplary embodiment, the apparatus700 further includes a pressure release passage that is coupled to and positioned within thesupport member 260. The pressure release passage is further fluidicly coupled to thefluid passage 735. The pressure release passage preferably includes a control valve for controllably opening and closing the fluid passage. In an exemplary embodiment, the control valve is pressure activated in order to controllably minimize surge pressures. The pressure release passage is preferably positioned substantially orthogonal to the centerline of the apparatus700. The pressure release passage is preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 500 gallons/minute and 0 to 1,000 psi in order to reduce the drag on the apparatus700 during insertion into a new section of a wellbore and to minimize surge pressures on the new wellbore section. - The
fluid passage 740 permits fluidic materials to be transported to and from the region exterior to thetubular member 715. Thefluid passage 740 is preferably coupled to and positioned within theshoe 720 in fluidic communication with the interior region of thetubular member 715 below theexpandable mandrel 705. Thefluid passage 740 preferably has a cross-sectional shape that permits a plug, or other similar device, to be placed in theinlet 830 of thefluid passage 740 to thereby block further passage of fluidic materials. In this manner, the interior region of thetubular member 715 below theexpandable mandrel 705 can be optimally fluidicly isolated from the region exterior to thetubular member 715. This permits the interior region of thetubular member 715 below theexpandable mandrel 205 to be pressurized. - The
fluid passage 740 is preferably positioned substantially along the centerline of the apparatus700. Thefluid passage 740 is preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill an annular region between thetubular member 715 and a new section of a wellbore with fluidic materials. In an exemplary embodiment, thefluid passage 740 includes aninlet passage 830 having a geometry that can receive a dart and/or a ball sealing member. In this manner, thefluid passage 240 can be sealed off by introducing a plug, dart and/or ball sealing elements into thefluid passage 230. - In an exemplary embodiment, the apparatus700 further includes one or
more seals 845 coupled to and supported by theend portion 820 of thetubular member 715. Theseals 845 are further positioned on an outer surface of theend portion 820 of thetubular member 715. Theseals 845 permit the overlapping joint between an end portion of preexisting casing and theend portion 820 of thetubular member 715 to be fluidicly sealed. Theseals 845 may comprise any number of conventional commercially available seals such as, for example, lead, rubber, Teflon, or epoxy seals modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theseals 845 comprise seals molded from StrataLock epoxy available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide a hydraulic seal and a load bearing interference fit in the overlapping joint between thetubular member 715 and an existing casing with optimal load bearing capacity to support thetubular member 715. - In an exemplary embodiment, the
seals 845 are selected to provide a sufficient frictional force to support the expandedtubular member 715 from the existing casing. In an exemplary embodiment, the frictional force provided by theseals 845 ranges from about 1,000 to 1,000,000 lbf in order to optimally support the expandedtubular member 715. - The
support member 745 is preferably coupled to theexpandable mandrel 705 and theovershot connection 755. Thesupport member 745 preferably comprises an annular member having sufficient strength to carry the apparatus700 into a new section of a wellbore. Thesupport member 745 may comprise any number of conventional commercially available support members such as, for example, steel drill pipe, coiled tubing or other high strength tubular modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, thesupport member 745 comprises conventional drill pipe available from various steel mills in the United States. - In an exemplary embodiment, a body of lubricant750 is provided in the annular region above the
expandable mandrel container 710 within the interior of thetubular member 715. In this manner, the extrusion of thetubular member 715 off of theexpandable mandrel 705 is facilitated. Thelubricant 705 may comprise any number of conventional commercially available lubricants such as, for example, Lubriplate, chlorine based lubricants, oil based lubricants, orClimax 1500 Antisieze (3100). In an exemplary embodiment, the lubricant750 comprisesClimax 1500 Antisieze (3100) available from Halliburton Energy Services in Houston, Tex. in order to optimally provide lubrication to facilitate the extrusion process. - The
overshot connection 755 is coupled to thesupport member 745 and thesupport member 760. Theovershot connection 755 preferably permits thesupport member 745 to be removably coupled to thesupport member 760. Theovershot connection 755 may comprise any number of conventional commercially available overshot connections such as, for example, Innerstring Sealing Adapter, Innerstring Flat-Face Sealing Adapter or EZ Drill Setting Tool Stinger. In an exemplary embodiment, theovershot connection 755 comprises a Innerstring Adapter with an Upper Guide available from Halliburton Energy Services in Dallas, Tex. - The
support member 760 is preferably coupled to theovershot connection 755 and a surface support structure (not illustrated). Thesupport member 760 preferably comprises an annular member having sufficient strength to carry the apparatus700 into a new section of a wellbore. Thesupport member 760 may comprise any number of conventional commercially available support members such as, for example, steel drill pipe, coiled tubing or other high strength tubulars modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, thesupport member 760 comprises a conventional drill pipe available from steel mills in the United States. - The
stabilizer 765 is preferably coupled to thesupport member 760. Thestabilizer 765 also preferably stabilizes the components of the apparatus700 within thetubular member 715. Thestabilizer 765 preferably comprises a spherical member having an outside diameter that is about 80 to 99% of the interior diameter of thetubular member 715 in order to optimally minimize buckling of thetubular member 715. Thestabilizer 765 may comprise any number of conventional commercially available stabilizers such as, for example, EZ Drill Star Guides, packer shoes or drag blocks modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, thestabilizer 765 comprises a sealing adapter upper guide available from Halliburton Energy Services in Dallas, Tex. - In an exemplary embodiment, the
support members - In an exemplary embodiment, before or after positioning the apparatus700 within a new section of a wellbore, a couple of wellbore volumes are circulated through the various flow passages of the apparatus700 in order to ensure that no foreign materials are located within the wellbore that might clog up the various flow passages and valves of the apparatus700 and to ensure that no foreign material interferes with the
expansion mandrel 705 during the expansion process. - In an exemplary embodiment, the apparatus700 is operated substantially as described above with reference to
FIGS. 1-7 to form a new section of casing within a wellbore. - As illustrated in
FIG. 8 , in an exemplary embodiment, the method and apparatus described herein is used to repair an existingwellbore casing 805 by forming atubular liner 810 inside of the existingwellbore casing 805. In an exemplary embodiment, an outer annular lining of cement is not provided in the repaired section. In the exemplary embodiment, any number of fluidic materials can be used to expand thetubular liner 810 into intimate contact with the damaged section of the wellbore casing such as, for example, cement, epoxy, slag mix, or drilling mud. In the exemplary embodiment, sealingmembers 815 are preferably provided at both ends of the tubular member in order to optimally provide a fluidic seal. In an exemplary embodiment, thetubular liner 810 is formed within a horizontally positioned pipeline section, such as those used to transport hydrocarbons or water, with thetubular liner 810 placed in an overlapping relationship with the adjacent pipeline section. In this manner, underground pipelines can be repaired without having to dig out and replace the damaged sections. - In another exemplary embodiment, the method and apparatus described herein is used to directly line a wellbore with a
tubular liner 810. In an exemplary embodiment, an outer annular lining of cement is not provided between thetubular liner 810 and the wellbore. In the exemplary embodiment, any number of fluidic materials can be used to expand thetubular liner 810 into intimate contact with the wellbore such as, for example, cement, epoxy, slag mix, or drilling mud. - Referring now to
FIGS. 9 ,9a,9band9c,an exemplary embodiment of anapparatus 900 for forming a wellbore casing includes anexpandable tubular member 902, asupport member 904, an expandable mandrel orpig 906, and ashoe 908. In an exemplary embodiment, the design and construction of themandrel 908 andshoe 908 permits easy removal of those elements by drilling them out. In this manner, theassembly 900 can be easily removed from a wellbore using a conventional drilling apparatus and corresponding drilling methods. - The
expandable tubular member 902 preferably includes anupper portion 910, anintermediate portion 912 and alower portion 914. During operation of theapparatus 900, thetubular member 902 is preferably extruded off of themandrel 906 by pressurizing aninterior region 966 of thetubular member 902. Thetubular member 902 preferably has a substantially annular cross-section. - In an exemplary embodiment, an
expandable tubular member 915 is coupled to theupper portion 910 of theexpandable tubular member 902. During operation of theapparatus 900, thetubular member 915 is preferably extruded off of themandrel 906 by pressurizing theinterior region 966 of thetubular member 902. Thetubular member 915 preferably has a substantially annular cross-section. In an exemplary embodiment, the wall thickness of thetubular member 915 is greater than the wall thickness of thetubular member 902. - The
tubular member 915 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steels, titanium or stainless steels. In an exemplary embodiment, thetubular member 915 is fabricated from oilfield tubulars in order to optimally provide approximately the same mechanical properties as thetubular member 902. In an exemplary embodiment, thetubular member 915 has a plastic yield point ranging from about 40,000 to 135,000 psi in order to optimally provide approximately the same yield properties as thetubular member 902. Thetubular member 915 may comprise a plurality of tubular members coupled end to end. - In an exemplary embodiment, the upper end portion of the
tubular member 915 includes one or more sealing members for optimally providing a fluidic and/or gaseous seal with an existing section of wellbore casing. - In an exemplary embodiment, the combined length of the
tubular members tubular members - The
lower portion 914 of thetubular member 902 is preferably coupled to theshoe 908 by a threadedconnection 968. Theintermediate portion 912 of thetubular member 902 preferably is placed in intimate sliding contact with themandrel 906. - The
tubular member 902 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steels, titanium or stainless steels. In an exemplary embodiment, thetubular member 902 is fabricated from oilfield tubulars in order to optimally provide approximately the same mechanical properties as thetubular member 915. In an exemplary embodiment, thetubular member 902 has a plastic yield point ranging from about 40,000 to 135,000 psi in order to optimally provide approximately the same yield properties as thetubular member 915. - The wall thickness of the upper, intermediate, and lower portions,910,912 and914 of the
tubular member 902 may range, for example, from about 1/16 to 1.5 inches. In an exemplary embodiment, the wall thickness of the upper, intermediate, and lower portions,910,912 and914 of thetubular member 902 range from about ⅛ to 1.25 in order to optimally provide wall thickness that are about the same as thetubular member 915. In an exemplary embodiment, the wall thickness of thelower portion 914 is less than or equal to the wall thickness of theupper portion 910 in order to optimally provide a geometry that will fit into tight clearances downhole. - The outer diameter of the upper, intermediate, and lower portions,910,912 and914 of the
tubular member 902 may range, for example, from about 1.05 to 48 inches. In an exemplary embodiment, the outer diameter of the upper, intermediate, and lower portions,910,912 and914 of thetubular member 902 range from about 3½ to 19 inches in order to optimally provide the ability to expand the most commonly used oilfield tubulars. - The length of the
tubular member 902 is preferably limited to between about 2 to 5 feet in order to optimally provide enough length to contain the mandrel90t and a body of lubricant. - The
tubular member 902 may comprise any number of conventional commercially available tubular members modified in accordance with the teachings of the present disclosure. In an exemplary embodiment thetubular member 902 comprises Oilfield Country Tubular Goods available from various U.S. steel mills. Thetubular member 915 may comprise any number of conventional commercially available tubular members modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, thetubular member 915 comprises Oilfield Country Tubular Goods available from various U.S. steel mills. - The various elements of the
tubular member 902 may be coupled using any number of conventional process such as, for example, threaded connections, welding or machined from one piece. In an exemplary embodiment, the various elements of thetubular member 902 are coupled using welding. Thetubular member 902 may comprise a plurality of tubular elements that are coupled end to end. The various elements of thetubular member 915 may be coupled using any number of conventional process such as, for example, threaded connections, welding or machined from one piece. In an exemplary embodiment, the various elements of thetubular member 915 are coupled using welding. Thetubular member 915 may comprise a plurality of tubular elements that are coupled end to end. Thetubular members - The
support member 904 preferably includes aninnerstring adapter 916, afluid passage 918, anupper guide 920, and acoupling 922. During operation of theapparatus 900, thesupport member 904 preferably supports theapparatus 900 during movement of theapparatus 900 within a wellbore. Thesupport member 904 preferably has a substantially annular cross-section. - The
support member 904 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steel, coiled tubing or stainless steel. In an exemplary embodiment, thesupport member 904 is fabricated from low alloy steel in order to optimally provide high yield strength. - The
innerstring adaptor 916 preferably is coupled to and supported by a conventional drill string support from a surface location. Theinnerstring adaptor 916 may be coupled to a conventionaldrill string support 971 by a threadedconnection 970. - The
fluid passage 918 is preferably used to convey fluids and other materials to and from theapparatus 900. In an exemplary embodiment, thefluid passage 918 is fluidicly coupled to thefluid passage 952. In an exemplary embodiment, thefluid passage 918 is used to convey hardenable fluidic sealing materials to and from theapparatus 900. In an exemplary embodiment, thefluid passage 918 may include one or more pressure relief passages (not illustrated) to release fluid pressure during positioning of theapparatus 900 within a wellbore. In an exemplary embodiment, thefluid passage 918 is positioned along a longitudinal centerline of theapparatus 900. In an exemplary embodiment, thefluid passage 918 is selected to permit the conveyance of hardenable fluidic materials at operating pressures ranging from about 0 to 9,000 psi. - The
upper guide 920 is coupled to an upper portion of thesupport member 904. Theupper guide 920 preferably is adapted to center thesupport member 904 within thetubular member 915. Theupper guide 920 may comprise any number of conventional guide members modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theupper guide 920 comprises an innerstring adapter available from Halliburton Energy Services in Dallas, Tex. order to optimally guide theapparatus 900 within thetubular member 915. - The
coupling 922 couples thesupport member 904 to themandrel 906. Thecoupling 922 preferably comprises a conventional threaded connection. - The various elements of the
support member 904 may be coupled using any number of conventional processes such as, for example, welding, threaded connections or machined from one piece. In an exemplary embodiment, the various elements of thesupport member 904 are coupled using threaded connections. - The
mandrel 906 preferably includes aretainer 924, arubber cup 926, anexpansion cone 928, alower cone retainer 930, a body ofcement 932, alower guide 934, anextension sleeve 936, aspacer 938, ahousing 940, a sealingsleeve 942, anupper cone retainer 944, alubricator mandrel 946, alubricator sleeve 948, aguide 950, and afluid passage 952. - The
retainer 924 is coupled to thelubricator mandrel 946,lubricator sleeve 948, and therubber cup 926. Theretainer 924 couples therubber cup 926 to thelubricator sleeve 948. Theretainer 924 preferably has a substantially annular cross-section. Theretainer 924 may comprise any number of conventional commercially available retainers such as, for example, slotted spring pins or roil pin. - The
rubber cup 926 is coupled to theretainer 924, thelubricator mandrel 946, and thelubricator sleeve 948. Therubber cup 926 prevents the entry of foreign materials into theinterior region 972 of thetubular member 902 below therubber cup 926. Therubber cup 926 may comprise any number of conventional commercially available rubber cups such as, for example, TP cups or Selective Injection Packer (SIP) cup. In an exemplary embodiment therubber cup 926 comprises a SIP cup available from Halliburton Energy Services in Dallas, Tex. in order to optimally block foreign materials. - In an exemplary embodiment, a body of lubricant is further provided in the
interior region 972 of thetubular member 902 in order to lubricate the interface between the exterior surface of themandrel 902 and the interior surface of thetubular members Climax 1500 Antisieze (3100). In an exemplary embodiment, the lubricant comprisesClimax 1500 Antisieze (3100) available from Climax Lubricants and Equipment Co. in Houston, Tex. in order to optimally provide lubrication to facilitate the extrusion process. - The
expansion cone 928 is coupled to thelower cone retainer 930, the body ofcement 932, thelower guide 934, theextension sleeve 936, thehousing 940, and theupper cone retainer 944. In an exemplary embodiment, during operation of theapparatus 900, thetubular members expansion cone 928. In an exemplary embodiment, axial movement of theexpansion cone 928 is prevented by thelower cone retainer 930,housing 940 and theupper cone retainer 944. Inner radial movement of theexpansion cone 928 is prevented by the body ofcement 932, thehousing 940, and theupper cone retainer 944. - The
expansion cone 928 preferably has a substantially annular cross section. The outside diameter of theexpansion cone 928 is preferably tapered to provide a cone shape. The wall thickness of theexpansion cone 928 may range, for example, from about 0.125 to 3 inches. In an exemplary embodiment, the wall thickness of theexpansion cone 928 ranges from about 0.25 to 0.75 inches in order to optimally provide adequate compressive strength with minimal material. The maximum and minimum outside diameters of theexpansion cone 928 may range, for example, from about 1 to 47 inches. In an exemplary embodiment, the maximum and minimum outside diameters of theexpansion cone 928 range from about 3.5 to 19 in order to optimally provide expansion of generally available oilfield tubulars - The
expansion cone 928 may be fabricated from any number of conventional commercially available materials such as, for example, ceramic, tool steel, titanium or low alloy steel. In an exemplary embodiment, theexpansion cone 928 is fabricated from tool steel in order to optimally provide high strength and abrasion resistance. The surface hardness of the outer surface of theexpansion cone 928 may range, for example, from about 50 Rockwell C to 70 Rockwell C. In an exemplary embodiment, the surface hardness of the outer surface of theexpansion cone 928 ranges from about 58 Rockwell C to 62 Rockwell C in order to optimally provide high yield strength. In an exemplary embodiment, theexpansion cone 928 is heat treated to optimally provide a hard outer surface and a resilient interior body in order to optimally provide abrasion resistance and fracture toughness. - The
lower cone retainer 930 is coupled to theexpansion cone 928 and thehousing 940. In an exemplary embodiment, axial movement of theexpansion cone 928 is prevented by thelower cone retainer 930. Preferably, thelower cone retainer 930 has a substantially annular cross-section. - The
lower cone retainer 930 may be fabricated from any number of conventional commercially available materials such as, for example, ceramic, tool steel, titanium or low alloy steel. In an exemplary embodiment, thelower cone retainer 930 is fabricated from tool steel in order to optimally provide high strength and abrasion resistance. The surface hardness of the outer surface of thelower cone retainer 930 may range, for example, from about 50 Rockwell C to 70 Rockwell C. In an exemplary embodiment, the surface hardness of the outer surface of thelower cone retainer 930 ranges from about 58 Rockwell C to 62 Rockwell C in order to optimally provide high yield strength. In an exemplary embodiment, thelower cone retainer 930 is heat treated to optimally provide a hard outer surface and a resilient interior body in order to optimally provide abrasion resistance and fracture toughness. - In an exemplary embodiment, the
lower cone retainer 930 and theexpansion cone 928 are formed as an integral one-piece element in order reduce the number of components and increase the overall strength of the apparatus. The outer surface of thelower cone retainer 930 preferably mates with the inner surfaces of thetubular members - The body of
cement 932 is positioned within the interior of themandrel 906. The body ofcement 932 provides an inner bearing structure for themandrel 906. The body ofcement 932 further may be easily drilled out using a conventional drill device. In this manner, themandrel 906 may be easily removed using a conventional drilling device. - The body of
cement 932 may comprise any number of conventional commercially available cement compounds. Alternatively, aluminum, cast iron or some other drillable metallic, composite, or aggregate material may be substituted for cement. The body ofcement 932 preferably has a substantially annular cross-section. - The
lower guide 934 is coupled to theextension sleeve 936 andhousing 940. During operation of theapparatus 900, thelower guide 934 preferably helps guide the movement of themandrel 906 within thetubular member 902. Thelower guide 934 preferably has a substantially annular cross-section. - The
lower guide 934 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steel or stainless steel. In an exemplary embodiment, thelower guide 934 is fabricated from low alloy steel in order to optimally provide high yield strength. The outer surface of thelower guide 934 preferably mates with the inner surface of thetubular member 902 to provide a sliding fit. - The
extension sleeve 936 is coupled to thelower guide 934 and thehousing 940. During operation of theapparatus 900, theextension sleeve 936 preferably helps guide the movement of themandrel 906 within thetubular member 902. Theextension sleeve 936 preferably has a substantially annular cross-section. - The
extension sleeve 936 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steel or stainless steel. In an exemplary embodiment, theextension sleeve 936 is fabricated from low alloy steel in order to optimally provide high yield strength. The outer surface of theextension sleeve 936 preferably mates with the inner surface of thetubular member 902 to provide a sliding fit. In an exemplary embodiment, theextension sleeve 936 and thelower guide 934 are formed as an integral one-piece element in order to minimize the number of components and increase the strength of the apparatus. - The
spacer 938 is coupled to the sealingsleeve 942. Thespacer 938 preferably includes thefluid passage 952 and is adapted to mate with theextension tube 960 of theshoe 908. In this manner, a plug or dart can be conveyed from the surface through thefluid passages fluid passage 962. Preferably, thespacer 938 has a substantially annular cross-section. - The
spacer 938 may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, thespacer 938 is fabricated from aluminum in order to optimally provide disability. The end of thespacer 938 preferably mates with the end of theextension tube 960. In an exemplary embodiment, thespacer 938 and the sealingsleeve 942 are formed as an integral one-piece element in order to reduce the number of components and increase the strength of the apparatus. - The
housing 940 is coupled to thelower guide 934,extension sleeve 936,expansion cone 928, body ofcement 932, andlower cone retainer 930. During operation of theapparatus 900, thehousing 940 preferably prevents inner radial motion of theexpansion cone 928. Preferably, thehousing 940 has a substantially annular cross-section. - The
housing 940 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubulars, low alloy steel or stainless steel. In an exemplary embodiment, thehousing 940 is fabricated from low alloy steel in order to optimally provide high yield strength. In an exemplary embodiment, thelower guide 934,extension sleeve 936 andhousing 940 are formed as an integral one-piece element in order to minimize the number of components and increase the strength of the apparatus. - In an exemplary embodiment, the interior surface of the
housing 940 includes one or more protrusions to facilitate the connection between thehousing 940 and the body ofcement 932. - The sealing
sleeve 942 is coupled to thesupport member 904, the body ofcement 932, thespacer 938, and theupper cone retainer 944. During operation of the apparatus, the sealingsleeve 942 preferably provides support for themandrel 906. The sealingsleeve 942 is preferably coupled to thesupport member 904 using thecoupling 922. Preferably, the sealingsleeve 942 has a substantially annular cross-section. - The sealing
sleeve 942 may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, the sealingsleeve 942 is fabricated from aluminum in order to optimally provide drillability of the sealingsleeve 942. - In an exemplary embodiment, the outer surface of the sealing
sleeve 942 includes one or more protrusions to facilitate the connection between the sealingsleeve 942 and the body ofcement 932. - In an exemplary embodiment, the
spacer 938 and the sealingsleeve 942 are integrally formed as a one-piece element in order to minimize the number of components. - The
upper cone retainer 944 is coupled to theexpansion cone 928, the sealingsleeve 942, and the body ofcement 932. During operation of theapparatus 900, theupper cone retainer 944 preferably prevents axial motion of theexpansion cone 928. Preferably, theupper cone retainer 944 has a substantially annular cross-section. - The
upper cone retainer 944 may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, theupper cone retainer 944 is fabricated from aluminum in order to optimally provide drillability of theupper cone retainer 944. - In an exemplary embodiment, the
upper cone retainer 944 has a cross-sectional shape designed to provide increased rigidity. In an exemplary embodiment, theupper cone retainer 944 has a cross-sectional shape that is substantially I-shaped to provide increased rigidity and minimize the amount of material that would have to be drilled out. - The
lubricator mandrel 946 is coupled to theretainer 924, therubber cup 926, theupper cone retainer 944, thelubricator sleeve 948, and theguide 950. During operation of theapparatus 900, thelubricator mandrel 946 preferably contains the body of lubricant in theannular region 972 for lubricating the interface between themandrel 906 and thetubular member 902. Preferably, thelubricator mandrel 946 has a substantially annular cross-section. - The
lubricator mandrel 946 may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, thelubricator mandrel 946 is fabricated from aluminum in order to optimally provide drillability of thelubricator mandrel 946. - The
lubricator sleeve 948 is coupled to thelubricator mandrel 946, theretainer 924, therubber cup 926, theupper cone retainer 944, thelubricator sleeve 948, and theguide 950. During operation of theapparatus 900, thelubricator sleeve 948 preferably supports therubber cup 926. Preferably, thelubricator sleeve 948 has a substantially annular cross-section. - The
lubricator sleeve 948 may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, thelubricator sleeve 948 is fabricated from aluminum in order to optimally provide drillability of thelubricator sleeve 948. - As illustrated in
FIG. 9 c,thelubricator sleeve 948 is supported by thelubricator mandrel 946. Thelubricator sleeve 948 in turn supports therubber cup 926. Theretainer 924 couples therubber cup 926 to thelubricator sleeve 948. In an exemplary embodiment, seals949aand949bare provided between thelubricator mandrel 948,lubricator sleeve 948, andrubber cup 926 in order to optimally seal off theinterior region 972 of thetubular member 902. - The
guide 950 is coupled to thelubricator mandrel 946, theretainer 924, and thelubricator sleeve 948. During operation of theapparatus 900, theguide 950 preferably guides the apparatus on thesupport member 904. Preferably, theguide 950 has a substantially annular cross-section. - The
guide 950 may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, theguide 950 is fabricated from aluminum order to optimally provide drillability of theguide 950. - The
fluid passage 952 is coupled to themandrel 906. During operation of the apparatus, thefluid passage 952 preferably conveys hardenable fluidic materials. In an exemplary embodiment, thefluid passage 952 is positioned about the centerline of theapparatus 900. In an exemplary embodiment, thefluid passage 952 is adapted to convey hardenable fluidic materials at pressures and flow rate ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/min in order to optimally provide pressures and flow rates to displace and circulate fluids during the installation of theapparatus 900. - The various elements of the
mandrel 906 may be coupled using any number of conventional process such as, for example, threaded connections, welded connections or cementing. In an exemplary embodiment, the various elements of themandrel 906 are coupled using threaded connections and cementing. - The
shoe 908 preferably includes ahousing 954, a body ofcement 956, a sealingsleeve 958, anextension tube 960, afluid passage 962, and one ormore outlet jets 964. - The
housing 954 is coupled to the body ofcement 956 and thelower portion 914 of thetubular member 902. During operation of theapparatus 900, thehousing 954 preferably couples the lower portion of thetubular member 902 to theshoe 908 to facilitate the extrusion and positioning of thetubular member 902. Preferably, thehousing 954 has a substantially annular cross-section. - The
housing 954 may be fabricated from any number of conventional commercially available materials such as, for example, steel or aluminum. In an exemplary embodiment, thehousing 954 is fabricated from aluminum in order to optimally provide drillability of thehousing 954. - In an exemplary embodiment, the interior surface of the
housing 954 includes one or more protrusions to facilitate the connection between the body ofcement 956 and thehousing 954. - The body of
cement 956 is coupled to thehousing 954, and the sealingsleeve 958. In an exemplary embodiment, the composition of the body ofcement 956 is selected to permit the body of cement to be easily drilled out using conventional drilling machines and processes. - The composition of the body of
cement 956 may include any number of conventional cement compositions. In an alternative embodiment, a drillable material such as, for example, aluminum or iron may be substituted for the body ofcement 956. - The sealing
sleeve 958 is coupled to the body ofcement 956, theextension tube 960, thefluid passage 962, and one ormore outlet jets 964. During operation of theapparatus 900, the sealingsleeve 958 preferably is adapted to convey a hardenable fluidic material from thefluid passage 952 into thefluid passage 962 and then into theoutlet jets 964 in order to inject the hardenable fluidic material into an annular region external to thetubular member 902. In an exemplary embodiment, during operation of theapparatus 900, the sealingsleeve 958 further includes an inlet geometry that permits a conventional plug or dart974 to become lodged in the inlet of the sealingsleeve 958. In this manner, thefluid passage 962 may be blocked thereby fluidicly isolating theinterior region 966 of thetubular member 902. - In an exemplary embodiment, the sealing
sleeve 958 has a substantially annular cross-section. The sealingsleeve 958 may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, the sealingsleeve 958 is fabricated from aluminum in order to optimally provide drillability of the sealingsleeve 958. - The
extension tube 960 is coupled to the sealingsleeve 958, thefluid passage 962, and one ormore outlet jets 964. During operation of theapparatus 900, theextension tube 960 preferably is adapted to convey a hardenable fluidic material from thefluid passage 952 into thefluid passage 962 and then into theoutlet jets 964 in order to inject the hardenable fluidic material into an annular region external to thetubular member 902. In an exemplary embodiment, during operation of theapparatus 900, the sealingsleeve 960 further includes an inlet geometry that permits a conventional plug or dart974 to become lodged in the inlet of the sealingsleeve 958. In this manner, thefluid passage 962 is blocked thereby fluidicly isolating theinterior region 966 of thetubular member 902. In an exemplary embodiment, one end of theextension tube 960 mates with one end of thespacer 938 in order to optimally facilitate the transfer of material between the two. - In an exemplary embodiment, the
extension tube 960 has a substantially annular cross-section. Theextension tube 960 may be fabricated from any number of conventional commercially available materials such as, for example, steel, aluminum or cast iron. In an exemplary embodiment, theextension tube 960 is fabricated from aluminum in order to optimally provide drillability of theextension tube 960. - The
fluid passage 962 is coupled to the sealingsleeve 958, theextension tube 960, and one ormore outlet jets 964. During operation of theapparatus 900, thefluid passage 962 is preferably conveys hardenable fluidic materials. In an exemplary embodiment, thefluid passage 962 is positioned about the centerline of theapparatus 900. In an exemplary embodiment, thefluid passage 962 is adapted to convey hardenable fluidic materials at pressures and flow rate ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/min in order to optimally provide fluids at operationally efficient rates. - The
outlet jets 964 are coupled to the sealingsleeve 958, theextension tube 960, and thefluid passage 962. During operation of theapparatus 900, theoutlet jets 964 preferably convey hardenable fluidic material from thefluid passage 962 to the region exterior of theapparatus 900. In an exemplary embodiment, theshoe 908 includes a plurality ofoutlet jets 964. - In an exemplary embodiment, the
outlet jets 964 comprise passages drilled in thehousing 954 and the body ofcement 956 in order to simplify the construction of theapparatus 900. - The various elements of the
shoe 908 may be coupled using any number of conventional process such as, for example, threaded connections, cement or machined from one piece of material. In an exemplary embodiment, the various elements of theshoe 908 are coupled using cement. - In an exemplary embodiment, the
assembly 900 is operated substantially as described above with reference toFIGS. 1-8 to create a new section of casing in a wellbore or to repair a wellbore casing or pipeline. - In particular, in order to extend a wellbore into a subterranean formation, a drill string is used in a well known manner to drill out material from the subterranean formation to form a new section.
- The
apparatus 900 for forming a wellbore casing in a subterranean formation is then positioned in the new section of the wellbore. In an exemplary embodiment, theapparatus 900 includes thetubular member 915. In an exemplary embodiment, a hardenable fluidic sealing hardenable fluidic sealing material is then pumped from a surface location into thefluid passage 918. The hardenable fluidic sealing material then passes from thefluid passage 918 into theinterior region 966 of thetubular member 902 below themandrel 906. The hardenable fluidic sealing material then passes from theinterior region 966 into thefluid passage 962. The hardenable fluidic sealing material then exits theapparatus 900 via theoutlet jets 964 and fills an annular region between the exterior of thetubular member 902 and the interior wall of the new section of the wellbore. Continued pumping of the hardenable fluidic sealing material causes the material to fill up at least a portion of the annular region. - The hardenable fluidic sealing material is preferably pumped into the annular region at pressures and flow rates ranging, for example, from about 0 to 5,000 psi and 0 to 1,500 gallons/min, respectively. In an exemplary embodiment, the hardenable fluidic sealing material is pumped into the annular region at pressures and flow rates that are designed for the specific wellbore section in order to optimize the displacement of the hardenable fluidic sealing material while not creating high enough circulating pressures such that circulation might be lost and that could cause the wellbore to collapse. The optimum pressures and flow rates are preferably determined using conventional empirical methods.
- The hardenable fluidic sealing material may comprise any number of conventional commercially available hardenable fluidic sealing materials such as, for example, slag mix, cement or epoxy. In an exemplary embodiment, the hardenable fluidic sealing material comprises blended cements designed specifically for the well section being lined available from Halliburton Energy Services in Dallas, Tex. In order to optimally provide support for the new tubular member while also maintaining optimal flow characteristics so as to minimize operational difficulties during the displacement of the cement in the annular region. The optimum composition of the blended cements is preferably determined using conventional empirical methods.
- The annular region preferably is filled with the hardenable fluidic sealing material in sufficient quantities to ensure that, upon radial expansion of the
tubular member 902, the annular region of the new section of the wellbore will be filled with hardenable material. - Once the annular region has been adequately filled with hardenable fluidic sealing material, a plug or dart974, or other similar device, preferably is introduced into the
fluid passage 962 thereby fluidicly isolating theinterior region 966 of thetubular member 902 from the external annular region. In an exemplary embodiment, a non hardenable fluidic material is then pumped into theinterior region 966 causing theinterior region 966 to pressurize. In an exemplary embodiment, the plug or dart974, or other similar device, preferably is introduced into thefluid passage 962 by introducing the plug or dart974, or other similar device into the non hardenable fluidic material. In this manner, the amount of cured material within the interior of thetubular members - Once the
interior region 966 becomes sufficiently pressurized, thetubular members mandrel 906. Themandrel 906 may be fixed or it may be expandable. During the extrusion process, themandrel 906 is raised out of the expanded portions of thetubular members support member 904. During this extrusion process, theshoe 908 is preferably substantially stationary. - The plug or dart974 is preferably placed into the
fluid passage 962 by introducing the plug or dart974 into thefluid passage 918 at a surface location in a conventional manner. The plug or dart974 may comprise any number of conventional commercially available devices for plugging a fluid passage such as, for example, Multiple Stage Cementer (MSC) latch-down plug, Omega latch-down plug or three-wiper latch down plug modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, the plug or dart974 comprises a MSC latch-down plug available from Halliburton Energy Services in Dallas, Tex. - After placement of the plug or dart974 in the
fluid passage 962, the non hardenable fluidic material is preferably pumped into theinterior region 966 at pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to 3,000 gallons/min in order to optimally extrude thetubular members mandrel 906. - For typical
tubular members tubular members interior region 966 reaches approximately 500 to 9,000 psi. In an exemplary embodiment, the extrusion of thetubular members mandrel 906 begins when the pressure of theinterior region 966 reaches approximately 1,200 to 8,500 psi with a flow rate of about 40 to 1250 gallons/minute. - During the extrusion process, the
mandrel 906 may be raised out of the expanded portions of thetubular members mandrel 906 is raised out of the expanded portions of thetubular members tubular members - When the upper end portion of the
tubular member 915 is extruded off of themandrel 906, the outer surface of the upper end portion of thetubular member 915 will preferably contact the interior surface of the lower end portion of the existing casing to form an fluid tight overlapping joint. The contact pressure of the overlapping joint may range, for example, from approximately 50 to 20,000 psi. In an exemplary embodiment, the contact pressure of the overlapping joint between the upper end of thetubular member 915 and the existing section of wellbore casing ranges from approximately 400 to 10,000 psi in order to optimally provide contact pressure to activate the sealing members and provide optimal resistance such that thetubular member 915 and existing wellbore casing will carry typical tensile and compressive loads. - In an exemplary embodiment, the operating pressure and flow rate of the non hardenable fluidic material will be controllably ramped down when the
mandrel 906 reaches the upper end portion of thetubular member 915. In this manner, the sudden release of pressure caused by the complete extrusion of thetubular member 915 off of theexpandable mandrel 906 can be minimized. In an exemplary embodiment, the operating pressure is reduced in a substantially linear fashion from 100% to about 10% during the end of the extrusion process beginning when themandrel 906 has completed approximately all but about the last 5 feet of the extrusion process. - In an exemplary embodiment, the operating pressure and/or flow rate of the hardenable fluidic seating material and/or the non hardenable fluidic material are controlled during all phases of the operation of the
apparatus 900 to minimize shock. - Alternatively, or in combination, a shock absorber is provided in the
support member 904 in order to absorb the shock caused by the sudden release of pressure. - Alternatively, or in combination, a mandrel catching structure is provided above the
support member 904 in order to catch or at least decelerate themandrel 906. - Once the extrusion process is completed, the
mandrel 906 is removed from the wellbore. In an exemplary embodiment, either before or after the removal of themandrel 906, the integrity of the fluidic seal of the overlapping joint between the upper portion of thetubular member 915 and the lower portion of the existing casing is tested using conventional methods. If the fluidic seal of the overlapping joint between the upper portion of thetubular member 915 and the lower portion of the existing casing is satisfactory, then the uncured portion of any of the hardenable fluidic sealing material within the expandedtubular member 915 is then removed in a conventional manner. The hardenable fluidic sealing material within the annular region between the expandedtubular member 915 and the existing casing and new section of wellbore is then allowed to cure. - Preferably any remaining cured hardenable fluidic sealing material within the interior of the expanded
tubular members tubular members apparatus 900 comprising theshoe 908 may then be removed by drilling out theshoe 908 using conventional drilling methods. - In an alternative embodiment, during the extrusion process, it may be necessary to remove the
entire apparatus 900 from the interior of the wellbore due to a malfunction. In this circumstance, a conventional drill string is used to drill out the interior sections of theapparatus 900 in order to facilitate the removal of the remaining sections. In an exemplary embodiment, the interior elements of theapparatus 900 are fabricated from materials such as, for example, cement and aluminum, that permit a conventional drill string to be employed to drill out the interior components. - In particular, in an exemplary embodiment, the composition of the interior sections of the
mandrel 906 andshoe 908, including one or more of the body ofcement 932, thespacer 938, the sealingsleeve 942, theupper cone retainer 944, thelubricator mandrel 946, thelubricator sleeve 948, theguide 950, thehousing 954, the body ofcement 956, the sealingsleeve 958, and theextension tube 960, are selected to permit at least some of these components to be drilled out using conventional drilling methods and apparatus. In this manner, in the event of a malfunction downhole, theapparatus 900 may be easily removed from the wellbore. - Referring now to
FIGS. 10 a,10b,10c,10d,10e,10f,and10ga method and apparatus for creating a tie-back liner in a wellbore will now be described. As illustrated inFIG. 10 a,awellbore 1000 positioned in asubterranean formation 1002 includes afirst casing 1004 and asecond casing 1006. - The
first casing 1004 preferably includes atubular liner 1008 and acement annulus 1010. Thesecond casing 1006 preferably includes atubular liner 1012 and acement annulus 1014. In an exemplary embodiment, thesecond casing 1006 is formed by expanding a tubular member substantially as described above with reference toFIGS. 1-9 cor below with reference toFIGS. 11 a-11f. - In an exemplary embodiment, an upper portion of the
tubular liner 1012 overlaps with a lower portion of thetubular liner 1008. In an exemplary embodiment, an outer surface of the upper portion of thetubular liner 1012 includes one ormore sealing members 1016 for providing a fluidic seal between thetubular liners - Referring to
FIG. 10 b,in order to create a tie-back liner that extends from the overlap between the first and second casings,1004 and1006, anapparatus 1100 is preferably provided that includes an expandable mandrel orpig 1105, atubular member 1110, ashoe 1115, one ormore cup seals 1120, afluid passage 1130, afluid passage 1135, one or morefluid passages 1140, seals1145, and asupport member 1150. - The expandable mandrel or
pig 1105 is coupled to and supported by thesupport member 1150. Theexpandable mandrel 1105 is preferably adapted to controllably expand in a radial direction. Theexpandable mandrel 1105 may comprise any number of conventional commercially available expandable mandrels modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theexpandable mandrel 1105 comprises a hydraulic expansion tool substantially as disclosed in U.S. Pat. No. 5,348,095, the disclosure of which is incorporated herein by reference, modified in accordance with the teachings of the present disclosure. - The
tubular member 1110 is coupled to and supported by theexpandable mandrel 1105. Thetubular member 1105 is expanded in the radial direction and extruded off of theexpandable mandrel 1105. Thetubular member 1110 may be fabricated from any number of materials such as, for example, Oilfield Country Tubular Goods, 13 chromium tubing or plastic piping. In an exemplary embodiment, thetubular member 1110 is fabricated from Oilfield Country Tubular Goods. - The inner and outer diameters of the
tubular member 1110 may range, for example, from approximately 0.75 to 47 inches and 1.05 to 48 inches, respectively. In an exemplary embodiment, the inner and outer diameters of thetubular member 1110 range from about 3 to 15.5 inches and 3.5 to 16 inches, respectively in order to optimally provide coverage for typical oilfield casing sizes. Thetubular member 1110 preferably comprises a solid member. - In an exemplary embodiment, the upper end portion of the
tubular member 1110 is slotted, perforated, or otherwise modified to catch or slow down themandrel 1105 when it completes the extrusion oftubular member 1110. In an exemplary embodiment, the length of thetubular member 1110 is limited to minimize the possibility of buckling. Fortypical tubular member 1110 materials, the length of thetubular member 1110 is preferably limited to between about 40 to 20,000 feet in length. - The
shoe 1115 is coupled to theexpandable mandrel 1105 and thetubular member 1110. Theshoe 1115 includes thefluid passage 1135. Theshoe 1115 may comprise any number of conventional commercially available shoes such as, for example, Super Seal II float shoe, Super Seal II Down-Jet float shoe or a guide shoe with a sealing sleeve for a latch down plug modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theshoe 1115 comprises an aluminum down-jet guide shoe with a sealing sleeve for a latch-down plug with side ports radiating off of the exit flow port available from Halliburton Energy Services in Dallas, Tex., modified in accordance with the teachings of the present disclosure, in order to optimally guide thetubular member 1100 to the overlap between thetubular member 1100 and thecasing 1012, optimally fluidicly isolate the interior of thetubular member 1100 after the latch down plug has seated, and optimally permit drilling out of theshoe 1115 after completion of the expansion and cementing operations. - In an exemplary embodiment, the
shoe 1115 includes one or moreside outlet ports 1140 in fluidic communication with thefluid passage 1135. In this manner, theshoe 1115 injects hardenable fluidic sealing material into the region outside theshoe 1115 andtubular member 1110. In an exemplary embodiment, theshoe 1115 includes one or more of thefluid passages 1140 each having an inlet geometry that can receive a dart and/or a ball sealing member. In this manner, thefluid passages 1140 can be sealed off by introducing a plug, dart and/or ball sealing elements into thefluid passage 1130. - The
cup seal 1120 is coupled to and supported by thesupport member 1150. Thecup seal 1120 prevents foreign materials from entering the interior region of thetubular member 1110 adjacent to theexpandable mandrel 1105. Thecup seal 1120 may comprise any number of conventional commercially available cup seals such as, for example, TP cups or Selective injection Packer (SIP) cups modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, thecup seal 1120 comprises a SIP cup, available from Halliburton Energy Services in Dallas, Tex. In order to optimally provide a barrier to debris and contain a body of lubricant. - The
fluid passage 1130 permits fluidic materials to be transported to and from the interior region of thetubular member 1110 below theexpandable mandrel 1105. Thefluid passage 1130 is coupled to and positioned within thesupport member 1150 and theexpandable mandrel 1105. Thefluid passage 1130 preferably extends from a position adjacent to the surface to the bottom of theexpandable mandrel 1105. Thefluid passage 1130 is preferably positioned along a centerline of theapparatus 1100. Thefluid passage 1130 is preferably selected to transport materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally provide sufficient operating pressures to circulate fluids at operationally efficient rates. - The
fluid passage 1135 permits fluidic materials to be transmitted fromfluid passage 1130 to the interior of thetubular member 1110 below themandrel 1105. - The
fluid passages 1140 permits fluidic materials to be transported to and from the region exterior to thetubular member 1110 andshoe 1115. Thefluid passages 1140 are coupled to and positioned within theshoe 1115 in fluidic communication with the interior region of thetubular member 1110 below theexpandable mandrel 1105. Thefluid passages 1140 preferably have a cross-sectional shape that permits a plug, or other similar device, to be placed in thefluid passages 1140 to thereby block further passage of fluidic materials. In this manner, the interior region of thetubular member 1110 below theexpandable mandrel 1105 can be fluidicly isolated from the region exterior to thetubular member 1105. This permits the interior region of thetubular member 1110 below theexpandable mandrel 1105 to be pressurized. - The
fluid passages 1140 are preferably positioned along the periphery of theshoe 1115. Thefluid passages 1140 are preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the annular region between thetubular member 1110 and thetubular liner 1008 with fluidic materials. In an exemplary embodiment, thefluid passages 1140 include an inlet geometry that can receive a dart and/or a ball sealing member. In this manner, thefluid passages 1140 can be sealed off by introducing a plug, dart and/or ball sealing elements into thefluid passage 1130. In an exemplary embodiment, theapparatus 1100 includes a plurality offluid passage 1140. - In an alternative embodiment, the base of the
shoe 1115 includes a single inlet passage coupled to thefluid passages 1140 that is adapted to receive a plug, or other similar device, to permit the interior region of thetubular member 1110 to be fluidicly isolated from the exterior of thetubular member 1110. - The
seals 1145 are coupled to and supported by a lower end portion of thetubular member 1110. Theseals 1145 are further positioned on an outer surface of the lower end portion of thetubular member 1110. Theseals 1145 permit the overlapping joint between the upper end portion of thecasing 1012 and the lower end portion of thetubular member 1110 to be fluidicly sealed. - The
seals 1145 may comprise any number of conventional commercially available seals such as, for example, lead, rubber, Teflon or epoxy seals modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theseals 1145 comprise seals molded from Stratalock epoxy available from Halliburton Energy Services in Dallas, Tex. In order to optimally provide a hydraulic seal in the overlapping joint and optimally provide load carrying capacity to withstand the range of typical tensile and compressive loads. - In an exemplary embodiment, the
seals 1145 are selected to optimally provide a sufficient frictional force to support the expandedtubular member 1110 from thetubular liner 1008. In an exemplary embodiment, the frictional force provided by theseals 1145 ranges from about 1,000 to 1,000,000 lbf in tension and compression in order to optimally support the expandedtubular member 1110. - The
support member 1150 is coupled to theexpandable mandrel 1105,tubular member 1110,shoe 1115, andseal 1120. Thesupport member 1150 preferably comprises an annular member having sufficient strength to carry theapparatus 1100 into thewellbore 1000. In an exemplary embodiment, thesupport member 1150 further includes one or more conventional centralizers (not illustrated) to help stabilize thetubular member 1110. - In an exemplary embodiment, a quantity of
lubricant 1150 is provided in the annular region above theexpandable mandrel 1105 within the interior of thetubular member 1110. In this manner, the extrusion of thetubular member 1110 off of theexpandable mandrel 1105 is facilitated. Thelubricant 1150 may comprise any number of conventional commercially available lubricants such as, for example, Lubriplate, chlorine based lubricants orClimax 1500 Antisieze (3100). In an exemplary embodiment, thelubricant 1150 comprisesClimax 1500 Antiseize (3100) available from Climax Lubricants and Equipment Co. in Houston, Tex. in order to optimally provide lubrication for the extrusion process. - In an exemplary embodiment, the
support member 1150 is thoroughly cleaned prior to assembly to the remaining portions of theapparatus 1100. In this manner, the introduction of foreign material into theapparatus 1100 is minimized. This minimizes the possibility of foreign material clogging the various flow passages and valves of theapparatus 1100 and to ensure that no foreign material interferes with theexpansion mandrel 1105 during the extrusion process. - In an exemplary embodiment, the
apparatus 1100 includes apacker 1155 coupled to the bottom section of theshoe 1115 for fluidicly isolating the region of thewellbore 1000 below theapparatus 1100. In this manner, fluidic materials are prevented from entering the region of thewellbore 1000 below theapparatus 1100. Thepacker 1155 may comprise any number of conventional commercially available packers such as, for example, EZ Drill Packer, EZ SV Packer or a drillable cement retainer. In an exemplary embodiment, thepacker 1155 comprises an EZ Drill Packer available from Halliburton Energy Services in Dallas, Tex. In an alternative embodiment, a high gel strength pill may be set below the tie-back in place of thepacker 1155. In another alternative embodiment, thepacker 1155 may be omitted. - In an exemplary embodiment, before or after positioning the
apparatus 1100 within thewellbore 1100, a couple of wellbore volumes are circulated in order to ensure that no foreign materials are located within thewellbore 1000 that might clog up the various flow passages and valves of theapparatus 1100 and to ensure that no foreign material interferes with the operation of theexpansion mandrel 1105. - As illustrated in
FIG. 10 c,a hardenablefluidic sealing material 1160 is then pumped from a surface location into thefluid passage 1130. Thematerial 1160 then passes from thefluid passage 1130 into the interior region of thetubular member 1110 below theexpandable mandrel 1105. Thematerial 1160 then passes from the interior region of thetubular member 1110 into thefluid passages 1140. Thematerial 1160 then exits theapparatus 1100 and fills the annular region between the exterior of thetubular member 1110 and the interior wall of thetubular liner 1008. Continued pumping of thematerial 1160 causes thematerial 1160 to fill up at least a portion of the annular region. - The
material 1160 may be pumped into the annular region at pressures and flow rates ranging, for example, from about 0 to 5,000 psi and 0 to 1,500 gallons/min, respectively. In an exemplary embodiment, thematerial 1160 is pumped into the annular region at pressures and flow rates specifically designed for the casing sizes being run, the annular spaces being filled, the pumping equipment available, and the properties of the fluid being pumped. The optimum flow rates and pressures are preferably calculated using conventional empirical methods. - The hardenable
fluidic sealing material 1160 may comprise any number of conventional commercially available hardenable fluidic sealing materials such as, for example, slag mix, cement or epoxy. In an exemplary embodiment, the hardenablefluidic sealing material 1160 comprises blended cements specifically designed for well section being tied-back, available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide proper support for thetubular member 1110 while maintaining optimum flow characteristics so as to minimize operational difficulties during the displacement of cement in the annular region. The optimum blend of the blended cements are preferably determined using conventional empirical methods. - The annular region may be filled with the
material 1160 in sufficient quantities to ensure that, upon radial expansion of thetubular member 1110, the annular region will be filled withmaterial 1160. - As illustrated in
FIG. 10 d,once the annular region has been adequately filled withmaterial 1160, one ormore plugs 1165, or other similar devices, preferably are introduced into thefluid passages 1140 thereby fluidicly isolating the interior region of thetubular member 1110 from the annular region external to thetubular member 1110. In an exemplary embodiment, a non hardenablefluidic material 1161 is then pumped into the interior region of thetubular member 1110 below themandrel 1105 causing the interior region to pressurize. In an exemplary embodiment, the one ormore plugs 1165, or other similar devices, are introduced into thefluid passage 1140 with the introduction of the non hardenable fluidic material. In this manner, the amount of hardenable fluidic material within the interior of thetubular member 1110 is minimized. - As illustrated in
FIG. 10 e,once the interior region becomes sufficiently pressurized, thetubular member 1110 is extruded off of theexpandable mandrel 1105. During the extrusion process, theexpandable mandrel 1105 is raised out of the expanded portion of thetubular member 1110. - The
plugs 1165 are preferably placed into thefluid passages 1140 by introducing theplugs 1165 into thefluid passage 1130 at a surface location in a conventional manner. Theplugs 1165 may comprise any number of conventional commercially available devices from plugging a fluid passage such as, for example, brass balls, plugs, rubber balls, or darts modified in accordance with the teachings of the present disclosure. - In an exemplary embodiment, the
plugs 1165 comprise low density rubber balls. In an alternative embodiment, for ashoe 1105 having a common central inlet passage, theplugs 1165 comprise a single latch down dart. - After placement of the
plugs 1165 in thefluid passages 1140, the non hardenablefluidic material 1161 is preferably pumped into the interior region of thetubular member 1110 below themandrel 1105 at pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to 3,000 gallons/min. - In an exemplary embodiment, after placement of the
plugs 1165 in thefluid passages 1140, the non hardenablefluidic material 1161 is preferably pumped into the interior region of thetubular member 1110 below themandrel 1105 at pressures and flow rates ranging from approximately 1200 to 8500 psi and 40 to 1250 gallons/min in order to optimally provide extrusion of typical tubulars. - For typical
tubular members 1110, the extrusion of thetubular member 1110 off of theexpandable mandrel 1105 will begin when the pressure of the interior region of thetubular member 1110 below themandrel 1105 reaches, for example, approximately 1200 to 8500 psi. In an exemplary embodiment, the extrusion of thetubular member 1110 off of theexpandable mandrel 1105 begins when the pressure of the interior region of thetubular member 1110 below themandrel 1105 reaches approximately 1200 to 8500 psi. - During the extrusion process, the
expandable mandrel 1105 may be raised out of the expanded portion of thetubular member 1110 at rates ranging, for example, from about 0 to 5 ft/sec. In an exemplary embodiment, during the extrusion process, theexpandable mandrel 1105 is raised out of the expanded portion of thetubular member 1110 at rates ranging from about 0 to 2 ft/sec in order to optimally provide permit adjustment of operational parameters, and optimally ensure that the extrusion process will be completed before the material1160 cures. - In an exemplary embodiment, at least a
portion 1180 of thetubular member 1110 has an internal diameter less than the outside diameter of themandrel 1105. In this manner, when themandrel 1105 expands thesection 1180 of thetubular member 1110, at least a portion of the expandedsection 1180 effects a seal with at least thewellbore casing 1012. In an exemplary embodiment, the seal is effected by compressing theseals 1016 between the expandedsection 1180 and thewellbore casing 1012. In an exemplary embodiment, the contact pressure of the joint between the expandedsection 1180 of thetubular member 1110 and thecasing 1012 ranges from about 500 to 10,000 psi in order to optimally provide pressure to activate thesealing members 1145 and provide optimal resistance to ensure that the joint will withstand typical extremes of tensile and compressive loads. - In an exemplary embodiment, substantially all of the entire length of the
tubular member 1110 has an infernal diameter less than the outside diameter of themandrel 1105. In this manner, extrusion of thetubular member 1110 by themandrel 1105 results in contact between substantially all of the expandedtubular member 1110 and the existingcasing 1008. In an exemplary embodiment, the contact pressure of the joint between the expandedtubular member 1110 and thecasings sealing members 1145 and provide optimal resistance to ensure that the joint will withstand typical extremes of tensile and compressive loads. - In an exemplary embodiment, the operating pressure and flow rate of the
material 1161 is controllably ramped down when theexpandable mandrel 1105 reaches the upper end portion of thetubular member 1110. In this manner, the sudden release of pressure caused by the complete extrusion of thetubular member 1110 off of theexpandable mandrel 1105 can be minimized. In an exemplary embodiment, the operating pressure of thefluidic material 1161 is reduced in a substantially linear fashion from 100% to about 10% during the end of the extrusion process beginning when themandrel 1105 has completed approximately all but about 5 feet of the extrusion process. - Alternatively, or in combination, a shock absorber is provided in the
support member 1150 in order to absorb the shock caused by the sudden release of pressure. - Alternatively, or in combination, a mandrel catching structure is provided in the upper end portion of the
tubular member 1110 in order to catch or at least decelerate themandrel 1105. - Referring to
FIG. 10 f,once the extrusion process is completed, theexpandable mandrel 1105 is removed from thewellbore 1000. In an exemplary embodiment, either before or after the removal of theexpandable mandrel 1105, the integrity of the fluidic seal of the joint between the upper portion of thetubular member 1110 and the upper portion of the tubular liner1108 is tested using conventional methods. If the fluidic seal of the joint between the upper portion of thetubular member 1110 and the upper portion of thetubular liner 1008 is satisfactory, then the uncured portion of thematerial 1160 within the expandedtubular member 1110 is then removed in a conventional manner. Thematerial 1160 within the annular region between thetubular member 1110 and thetubular liner 1008 is then allowed to cure. - As illustrated in
FIG. 10 f,preferably any remaining curedmaterial 1160 within the interior of the expandedtubular member 1110 is then removed in a conventional manner using a conventional drill string. The resulting tie-back liner ofcasing 1170 includes the expandedtubular member 1110 and an outerannular layer 1175 of curedmaterial 1160. - As illustrated in
FIG. 10 g,the remaining bottom portion of theapparatus 1100 comprising theshoe 1115 andpacker 1155 is then preferably removed by drilling out theshoe 1115 andpacker 1155 using conventional drilling methods. - In an exemplary embodiment, the
apparatus 1100 incorporates theapparatus 900. - Referring now to
FIGS. 11 a-11f,an embodiment of an apparatus and method for hanging a tubular liner off of an existing wellbore casing will now be described. As illustrated inFIG. 11 a,awellbore 1200 is positioned in asubterranean formation 1205. Thewellbore 1200 includes an existing casedsection 1210 having atubular casing 1215 and an annular outer layer ofcement 1220. - In order to extend the
wellbore 1200 into thesubterranean formation 1205, adrill string 1225 is used in a well known manner to drill out material from thesubterranean formation 1205 to form anew section 1230. - As illustrated in
FIG. 11 b,anapparatus 1300 for forming a wellbore casing in a subterranean formation is then positioned in thenew section 1230 of thewellbore 100. Theapparatus 1300 preferably includes an expandable mandrel orpig 1305, atubular member 1310, ashoe 1315, afluid passage 1320, afluid passage 1330, afluid passage 1335, seals1340, asupport member 1345, and awiper plug 1350. - The
expandable mandrel 1305 is coupled to and supported by thesupport member 1345. Theexpandable mandrel 1305 is preferably adapted to controllably expand in a radial direction. Theexpandable mandrel 1305 may comprise any number of conventional commercially available expandable mandrels modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theexpandable mandrel 1305 comprises a hydraulic expansion tool substantially as disclosed in U.S. Pat. No. 5,348,095, the disclosure of which is incorporated herein by reference, modified in accordance with the teachings of the present disclosure. - The
tubular member 1310 is coupled to and supported by theexpandable mandrel 1305. Thetubular member 1310 is preferably expanded in the radial direction and extruded off of theexpandable mandrel 1305. Thetubular member 1310 may be fabricated from any number of materials such as, for example, Oilfield Country Tubular Goods (OCTG), 13 chromium steel tubing/casing or plastic casing. In an exemplary embodiment, thetubular member 1310 is fabricated from OCTG. The inner and outer diameters of thetubular member 1310 may range, for example, from approximately 0.75 to 47 inches and 1.05 to 48 inches, respectively. In an exemplary embodiment, the inner and outer diameters of thetubular member 1310 range from about 3 to 15.5 inches and 3.5 to 16 inches, respectively in order to optimally provide minimal telescoping effect in the most commonly encountered wellbore sizes. - In an exemplary embodiment, the
tubular member 1310 includes anupper portion 1355, anintermediate portion 1360, and alower portion 1365. In an exemplary embodiment, the wall thickness and outer diameter of theupper portion 1355 of thetubular member 1310 range from about ⅜ to 1½ inches and 3½ to 16 inches, respectively. In an exemplary embodiment, the wall thickness and outer diameter of theintermediate portion 1360 of thetubular member 1310 range from about 0.625 to 0.75 inches and 3 to 19 inches, respectively. In an exemplary embodiment, the wall thickness and outer diameter of thelower portion 1365 of thetubular member 1310 range from about ⅜ to 1.5 inches and 3.5 to 16 inches, respectively. - In an exemplary embodiment, the outer diameter of the
lower portion 1365 of thetubular member 1310 is significantly less than the outer diameters of the upper and intermediate portions,1355 and1360, of thetubular member 1310 in order to optimize the formation of a concentric and overlapping arrangement of wellbore casings. In this manner, as will be described below with reference toFIGS. 12 and 13 , a wellhead system is optimally provided. In an exemplary embodiment, the formation of a wellhead system does not include the use of a hardenable fluidic material. - In an exemplary embodiment, the wall thickness of the
intermediate section 1360 of thetubular member 1310 is less than or equal to the wall thickness of the upper and lower sections,1355 and1365, of thetubular member 1310 in order to optimally facilitate the initiation of the extrusion process and optimally permit the placement of the apparatus in areas of the wellbore having tight clearances. - The
tubular member 1310 preferably comprises a solid member. In an exemplary embodiment, theupper end portion 1355 of thetubular member 1310 is slotted, perforated, or otherwise modified to catch or slow down themandrel 1305 when it completes the extrusion oftubular member 1310. In an exemplary embodiment, the length of thetubular member 1310 is limited to minimize the possibility of buckling. Fortypical tubular member 1310 materials, the length of thetubular member 1310 is preferably limited to between about 40 to 20,000 feet in length. - The
shoe 1315 is coupled to thetubular member 1310. Theshoe 1315 preferably includesfluid passages shoe 1315 may comprise any number of conventional commercially available shoes such as, for example, Super Seal II float shoe, Super Seal II Down-Jet float shoe or guide shoe with a sealing sleeve for a latch-down plug modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theshoe 1315 comprises an aluminum down-jet guide shoe with a sealing sleeve for a latch-down plug available from Halliburton Energy Services in Dallas, Tex., modified in accordance with the teachings of the present disclosure, in order to optimally guide thetubular member 1310 into thewellbore 1200, optimally fluidicly isolate the interior of thetubular member 1310, and optimally permit the complete drill out of theshoe 1315 upon the completion of the extrusion and cementing operations. - In an exemplary embodiment, the
shoe 1315 further includes one or more side outlet ports in fluidic communication with thefluid passage 1330. In this manner, theshoe 1315 preferably injects hardenable fluidic sealing material into the region outside theshoe 1315 andtubular member 1310. In an exemplary embodiment, theshoe 1315 includes thefluid passage 1330 having an inlet geometry that can receive a fluidic sealing member. In this manner, thefluid passage 1330 can be sealed off by introducing a plug, dart and/or ball sealing elements into thefluid passage 1330. - The
fluid passage 1320 permits fluidic materials to be transported to and from the interior region of thetubular member 1310 below theexpandable mandrel 1305. Thefluid passage 1320 is coupled to and positioned within thesupport member 1345 and theexpandable mandrel 1305. Thefluid passage 1320 preferably extends from a position adjacent to the surface to the bottom of theexpandable mandrel 1305. Thefluid passage 1320 is preferably positioned along a centerline of theapparatus 1300. Thefluid passage 1320 is preferably selected to transport materials such as cement, drilling mud, or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally provide sufficient operating pressures to circulate fluids at operationally efficient rates. - The
fluid passage 1330 permits fluidic materials to be transported to and from the region exterior to thetubular member 1310 andshoe 1315. Thefluid passage 1330 is coupled to and positioned within theshoe 1315 in fluidic communication with theinterior region 1370 of thetubular member 1310 below theexpandable mandrel 1305. Thefluid passage 1330 preferably has a cross-sectional shape that permits a plug, or other similar device, to be placed influid passage 1330 to thereby block further passage of fluidic materials. In this manner, theinterior region 1370 of thetubular member 1310 below theexpandable mandrel 1305 can be fluidicly isolated from the region exterior to thetubular member 1310. This permits theinterior region 1370 of thetubular member 1310 below theexpandable mandrel 1305 to be pressurized. Thefluid passage 1330 is preferably positioned substantially along the centerline of theapparatus 1300. - The
fluid passage 1330 is preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the annular region between thetubular member 1310 and thenew section 1230 of thewellbore 1200 with fluidic materials. In an exemplary embodiment, thefluid passage 1330 includes an inlet geometry that can receive a dart and/or a ball sealing member. In this manner, thefluid passage 1330 can be sealed off by introducing a plug, dart and/or ball sealing elements into thefluid passage 1320. - The
fluid passage 1335 permits fluidic materials to be transported to and from the region exterior to thetubular member 1310 andshoe 1315. Thefluid passage 1335 is coupled to and positioned within theshoe 1315 in fluidic communication with thefluid passage 1330. Thefluid passage 1335 is preferably positioned substantially along the centerline of theapparatus 1300. Thefluid passage 1335 is preferably selected to convey materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the annular region between thetubular member 1310 and thenew section 1230 of thewellbore 1200 with fluidic materials. - The
seals 1340 are coupled to and supported by theupper end portion 1355 of thetubular member 1310. Theseals 1340 are further positioned on an outer surface of theupper end portion 1355 of thetubular member 1310. Theseals 1340 permit the overlapping joint between the lower end portion of thecasing 1215 and theupper portion 1355 of thetubular member 1310 to be fluidicly sealed. Theseals 1340 may comprise any number of conventional commercially available seals such as, for example, lead, rubber, Teflon, or epoxy seals modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theseals 1340 comprise seals molded from Stratalock epoxy available from Halliburton Energy Services in Dallas, Tex. in order to optimally provide a hydraulic seal in the annulus of the overlapping joint while also creating optimal load bearing capability to withstand typical tensile and compressive loads. - In an exemplary embodiment, the
seals 1340 are selected to optimally provide a sufficient frictional force to support the expandedtubular member 1310 from the existingcasing 1215. In an exemplary embodiment, the frictional force provided by theseals 1340 ranges from about 1,000 to 1,000,000 lbf in order to optimally support the expandedtubular member 1310. - The
support member 1345 is coupled to theexpandable mandrel 1305,tubular member 1310,shoe 1315, and seals1340. Thesupport member 1345 preferably comprises an annular member having sufficient strength to carry theapparatus 1300 into thenew section 1230 of thewellbore 1200. In an exemplary embodiment, thesupport member 1345 further includes one or more conventional centralizers (not illustrated) to help stabilize thetubular member 1310. - In an exemplary embodiment, the
support member 1345 is thoroughly cleaned prior to assembly to the remaining portions of theapparatus 1300. In this manner, the introduction of foreign material into theapparatus 1300 is minimized. This minimizes the possibility of foreign material clogging the various flow passages and valves of theapparatus 1300 and to ensure that no foreign material interferes with the expansion process. - The
wiper plug 1350 is coupled to themandrel 1305 within theinterior region 1370 of thetubular member 1310. Thewiper plug 1350 includes afluid passage 1375 that is coupled to thefluid passage 1320. Thewiper plug 1350 may comprise one or more conventional commercially available wiper plugs such as, for example, Multiple Stage Cementer latch-down plugs, Omega latch-down plugs or three-wiper latch-down plug modified in accordance with the teachings of the present disclosure. In an exemplary embodiment thewiper plug 1350 comprises a Multiple Stage Cementer latch-down plug available from Halliburton Energy Services in Dallas, Tex. modified in a conventional manner for releasable attachment to theexpansion mandrel 1305. - In an exemplary embodiment, before or after positioning the
apparatus 1300 within thenew section 1230 of thewellbore 1200, a couple of wellbore volumes are circulated in order to ensure that no foreign materials are located within thewellbore 1200 that might clog up the various flow passages and valves of theapparatus 1300 and to ensure that no foreign material interferes with the extrusion process. - As illustrated in
FIG. 11 c,a hardenablefluidic sealing material 1380 is then pumped from a surface location into thefluid passage 1320. Thematerial 1380 then passes from thefluid passage 1320, through thefluid passage 1375, and into theinterior region 1370 of thetubular member 1310 below theexpandable mandrel 1305. Thematerial 1380 then passes from theinterior region 1370 into thefluid passage 1330. Thematerial 1380 then exits theapparatus 1300 via thefluid passage 1335 and fills theannular region 1390 between the exterior of thetubular member 1310 and the interior wall of thenew section 1230 of thewellbore 1200. Continued pumping of thematerial 1380 causes thematerial 1380 to fill up at least a portion of theannular region 1390. - The
material 1380 may be pumped into theannular region 1390 at pressures and flow rates ranging, for example, from about 0 to 5000 psi and 0 to 1,500 gallons/min, respectively. In an exemplary embodiment, thematerial 1380 is pumped into theannular region 1390 at pressures and flow rates ranging from about 0 to 5000 psi and 0 to 1,500 gallons/min, respectively, in order to optimally fill the annular region between thetubular member 1310 and thenew section 1230 of thewellbore 1200 with the hardenablefluidic sealing material 1380. - The hardenable
fluidic sealing material 1380 may comprise any number of conventional commercially available hardenable fluidic sealing materials such as, for example, slag mix, cement or epoxy. In an exemplary embodiment, the hardenablefluidic sealing material 1380 comprises blended cements designed specifically for the well section being drilled and available from Halliburton Energy Services in order to optimally provide support for thetubular member 1310 during displacement of thematerial 1380 in theannular region 1390. The optimum blend of the cement is preferably determined using conventional empirical methods. - The
annular region 1390 preferably is filled with thematerial 1380 in sufficient quantities to ensure that, upon radial expansion of thetubular member 1310, theannular region 1390 of thenew section 1230 of thewellbore 1200 will be filled withmaterial 1380. - As illustrated in
FIG. 11 d,once theannular region 1390 has been adequately filled withmaterial 1380, awiper dart 1395, or other similar device, is introduced into thefluid passage 1320. Thewiper dart 1395 is preferably pumped through thefluid passage 1320 by a non hardenablefluidic material 1381. Thewiper dart 1395 then preferably engages thewiper plug 1350. - As illustrated in
FIG. 11 e,in an exemplary embodiment, engagement of thewiper dart 1395 with thewiper plug 1350 causes thewiper plug 1350 to decouple from themandrel 1305. Thewiper dart 1395 andwiper plug 1350 then preferably will lodge in thefluid passage 1330, thereby blocking fluid flow through thefluid passage 1330, and fluidicly isolating theinterior region 1370 of thetubular member 1310 from theannular region 1390. In an exemplary embodiment, the non hardenablefluidic material 1381 is then pumped into theinterior region 1370 causing theinterior region 1370 to pressurize. Once theinterior region 1370 becomes sufficiently pressurized, thetubular member 1310 is extruded off of theexpandable mandrel 1305. During the extrusion process, theexpandable mandrel 1305 is raised out of the expanded portion of thetubular member 1310 by thesupport member 1345. - The
wiper dart 1395 is preferably placed into thefluid passage 1320 by introducing thewiper dart 1395 into thefluid passage 1320 at a surface location in a conventional manner. Thewiper dart 1395 may comprise any number of conventional commercially available devices from plugging a fluid passage such as, for example, Multiple Stage Cementer latch-down plugs, Omega latch-down plugs or three wiper latch-down plug/dart modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, thewiper dart 1395 comprises a three wiper latch-down plug modified to latch and seal in the Multiple Stage Cementer latch downplug 1350. The three wiper latch-down plug is available from Halliburton Energy Services in Dallas, Tex. - After blocking the
fluid passage 1330 using thewiper plug 1330 andwiper dart 1395, the non hardenablefluidic material 1381 may be pumped into theinterior region 1370 at pressures and flow rates ranging, for example, from approximately 0 to 5000 psi and 0 to 1,500 gallons/min in order to optimally extrude thetubular member 1310 off of themandrel 1305. In this manner, the amount of hardenable fluidic material within the interior of thetubular member 1310 is minimized. - In an exemplary embodiment, after blocking the
fluid passage 1330, the non hardenablefluidic material 1381 is preferably pumped into theinterior region 1370 at pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to 3,000 gallons/min in order to optimally provide operating pressures to maintain the expansion process at rates sufficient to permit adjustments to be made in operating parameters during the extrusion process. - For typical
tubular members 1310, the extrusion of thetubular member 1310 off of theexpandable mandrel 1305 will begin when the pressure of theinterior region 1370 reaches, for example, approximately 500 to 9,000 psi. In an exemplary embodiment, the extrusion of thetubular member 1310 off of theexpandable mandrel 1305 is a function of the tubular member diameter, wall thickness of the tubular member, geometry of the mandrel, the type of lubricant, the composition of the shoe and tubular member, and the yield strength of the tubular member. The optimum flow rate and operating pressures are preferably determined using conventional empirical methods. - During the extrusion process, the
expandable mandrel 1305 may be raised out of the expanded portion of thetubular member 1310 at rates ranging, for example, from about 0 to 5 ft/sec. In an exemplary embodiment, during the extrusion process, theexpandable mandrel 1305 is raised out of the expanded portion of thetubular member 1310 at rates ranging from about 0 to 2 ft/sec in order to optimally provide an efficient process, optimally permit operator adjustment of operation parameters, and ensure optimal completion of the extrusion process before curing of thematerial 1380. - When the
upper end portion 1355 of thetubular member 1310 is extruded off of theexpandable mandrel 1305, the outer surface of theupper end portion 1355 of thetubular member 1310 will preferably contact the interior surface of the lower end portion of thecasing 1215 to form an fluid tight overlapping joint. The contact pressure of the overlapping joint may range, for example, from approximately 50 to 20,000 psi. In an exemplary embodiment, the contact pressure of the overlapping joint ranges from approximately 400 to 10,000 psi in order to optimally provide contact pressure sufficient to ensure annular sealing and provide enough resistance to withstand typical tensile and compressive loads. In an exemplary embodiment, the sealingmembers 1340 will ensure an adequate fluidic and gaseous seal in the overlapping joint. - In an exemplary embodiment, the operating pressure and flow rate of the non hardenable
fluidic material 1381 is controllably ramped down when theexpandable mandrel 1305 reaches theupper end portion 1355 of thetubular member 1310. In this manner, the sudden release of pressure caused by the complete extrusion of thetubular member 1310 off of theexpandable mandrel 1305 can be minimized. In an exemplary embodiment, the operating pressure is reduced in a substantially linear fashion from 100% to about 10% during the end of the extrusion process beginning when themandrel 1305 has completed approximately all but about 5 feet of the extrusion process. - Alternatively, or in combination, a shock absorber is provided in the
support member 1345 in order to absorb the shock caused by the sudden release of pressure. - Alternatively, or in combination, a mandrel catching structure is provided in the
upper end portion 1355 of thetubular member 1310 in order to catch or at least decelerate themandrel 1305. - Once the extrusion process is completed, the
expandable mandrel 1305 is removed from thewellbore 1200. In an exemplary embodiment, either before or after the removal of theexpandable mandrel 1305, the integrity of the fluidic seal of the overlapping joint between theupper portion 1355 of thetubular member 1310 and the lower portion of thecasing 1215 is tested using conventional methods. If the fluidic seal of the overlapping joint between theupper portion 1355 of thetubular member 1310 and the lower portion of thecasing 1215 is satisfactory, then the uncured portion of thematerial 1380 within the expandedtubular member 1310 is then removed in a conventional manner. Thematerial 1380 within theannular region 1390 is then allowed to cure. - As illustrated in
FIG. 11 f,preferably any remaining curedmaterial 1380 within the interior of the expandedtubular member 1310 is then removed in a conventional manner using a conventional drill string. The resulting new section ofcasing 1400 includes the expandedtubular member 1310 and an outerannular layer 1405 of curedmaterial 305. The bottom portion of theapparatus 1300 comprising theshoe 1315 may then be removed by drilling out theshoe 1315 using conventional drilling methods. - Referring now to
FIGS. 12 and 13 , an exemplary embodiment of awellhead system 1500 formed using one or more of the apparatus and processes described above with reference toFIGS. 1-11 fwill be described. Thewellhead system 1500 preferably includes a conventional Christmas tree/drilling spool assembly 1505, athick wall casing 1510, an annular body ofcement 1515, anouter casing 1520, an annular body ofcement 1525, anintermediate casing 1530, and aninner casing 1535. - The Christmas tree/
drilling spool assembly 1505 may comprise any number of conventional Christmas tree/drilling spool assemblies such as, for example, the SS-15 Subsea Wellhead System, Spool Tree Subsea Production System or the Compact Wellhead System available from suppliers such as Dril-Quip, Cameron or Breda, modified in accordance with the teachings of the present disclosure. Thedrilling spool assembly 1505 is preferably operably coupled to thethick wall casing 1510 and/or theouter casing 1520. Theassembly 1505 may be coupled to thethick wall casing 1510 and/orouter casing 1520, for example, by welding, a threaded connection or made from single stock. In an exemplary embodiment, theassembly 1505 is coupled to thethick wall casing 1510 and/orouter casing 1520 by welding. - The
thick wall casing 1510 is positioned in the upper end of awellbore 1540. In an exemplary embodiment, at least a portion of thethick wall casing 1510 extends above the surface1545 in order to optimally provide easy access and attachment to the Christmas tree/drilling spool assembly 1505. Thethick wall casing 1510 is preferably coupled to the Christmas tree/drilling spool assembly 1505, the annular body ofcement 1515, and theouter casing 1520. - The
thick wall casing 1510 may comprise any number of conventional commercially available high strength wellbore casings such as, for example, Oilfield Country Tubular Goods, titanium tubing or stainless steel tubing. In an exemplary embodiment, thethick wall casing 1510 comprises Oilfield Country Tubular Goods available from various foreign and domestic steel mills. In an exemplary embodiment, thethick wall casing 1510 has a yield strength of about 40,000 to 135,000 psi in order to optimally provide maximum burst, collapse, and tensile strengths. In an exemplary embodiment, thethick wall casing 1510 has a failure strength in excess of about 5,000 to 20,000 psi in order to optimally provide maximum operating capacity and resistance to degradation of capacity after being drilled through for an extended time period. - The annular body of
cement 1515 provides support for thethick wall casing 1510. The annular body ofcement 1515 may be provided using any number of conventional processes for forming an annular body of cement in a wellbore. The annular body ofcement 1515 may comprise any number of conventional cement mixtures. - The
outer casing 1520 is coupled to thethick wall casing 1510. Theouter casing 1520 may be fabricated from any number of conventional commercially available tubular members modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theouter casing 1520 comprises any one of the expandable tubular members described above with reference toFIGS. 1-11 f. - In an exemplary embodiment, the
outer casing 1520 is coupled to thethick wall casing 1510 by expanding theouter casing 1520 into contact with at least a portion of the interior surface of thethick wall casing 1510 using any one of the embodiments of the processes and apparatus described above with reference toFIGS. 1-11 f.In an alternative embodiment, substantially all of the overlap of theouter casing 1520 with thethick wall casing 1510 contacts with the interior surface of thethick wall casing 1510. - The contact pressure of the interface between the
outer casing 1520 and thethick wall casing 1510 may range, for example, from about 500 to 10,000 psi. In an exemplary embodiment, the contact pressure between theouter casing 1520 and thethick wall casing 1510 ranges from about 500 to 10,000 psi in order to optimally activate the pressure activated sealing members and to ensure that the overlapping joint will optimally withstand typical extremes of tensile and compressive loads that are experienced during drilling and production operations. - As illustrated in
FIG. 13 , in an exemplary embodiment, the upper end of theouter casing 1520 includes one or more sealing members1550 that provide a gaseous and fluidic seal between the expandedouter casing 1520 and the interior wall of thethick wall casing 1510. The sealing members1550 may comprise any number of conventional commercially available seals such as, for example, lead, plastic, rubber, Teflon or epoxy, modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, the sealing members1550 comprise seals molded from StrataLock epoxy available from Halliburton Energy Services in order to optimally provide an hydraulic seal and a load bearing interference fit between the tubular members. In an exemplary embodiment, the contact pressure of the interface between thethick wall casing 1510 and theouter casing 1520 ranges from about 500 to 10,000 psi in order to optimally activate the sealing members1550 and also optimally ensure that the joint will withstand the typical operating extremes of tensile and compressive loads during drilling and production operations. - In an exemplary embodiment, the
outer casing 1520 and the thickwalled casing 1510 are combined in one unitary member. - The annular body of
cement 1525 provides support for theouter casing 1520. In an exemplary embodiment, the annular body ofcement 1525 is provided using any one of the embodiments of the apparatus and processes described above with reference toFIGS. 1-11 f. - The
intermediate casing 1530 may be coupled to theouter casing 1520 or thethick wall casing 1510. In an exemplary embodiment, theintermediate casing 1530 is coupled to thethick wall casing 1510. Theintermediate casing 1530 may be fabricated from any number of conventional commercially available tubular members modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theintermediate casing 1530 comprises any one of the expandable tubular members described above with reference toFIGS. 1-11 f. - In an exemplary embodiment, the
intermediate casing 1530 is coupled to thethick wall casing 1510 by expanding at least a portion of theintermediate casing 1530 into contact with the interior surface of thethick wall casing 1510 using any one of the processes and apparatus described above with reference toFIGS. 1-11 f.In an exemplary embodiment, the entire length of the overlap of theintermediate casing 1530 with thethick wall casing 1510 contacts the inner surface of thethick wall casing 1510. The contact pressure of the interface between theintermediate casing 1530 and thethick wall casing 1510 may range, for example from about 500 to 10,000 psi. In an exemplary embodiment, the contact pressure between theintermediate casing 1530 and thethick wall casing 1510 ranges from about 500 to 10,000 psi in order to optimally activate the pressure activated sealing members and to optimally ensure that the joint will withstand typical operating extremes of tensile and compressive loads experienced during drilling and production operations. - As illustrated in
FIG. 13 , in an exemplary embodiment, the upper end of theintermediate casing 1530 includes one ormore sealing members 1560 that provide a gaseous and fluidic seal between the expanded end of theintermediate casing 1530 and the interior wall of thethick wall casing 1510. The sealingmembers 1560 may comprise any number of conventional commercially available seals such as, for example, plastic, lead, rubber, Teflon or epoxy, modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, the sealingmembers 1560 comprise seals molded from StrataLock epoxy available from Halliburton Energy Services in order to optimally provide a hydraulic seal and a load bearing interference fit between the tubular members. - In an exemplary embodiment, the contact pressure of the interface between the expanded end of the
intermediate casing 1530 and thethick wall casing 1510 ranges from about 500 to 10,000 psi in order to optimally activate thesealing members 1560 and also optimally ensure that the joint will withstand typical operating extremes of tensile and compressive loads that are experienced during drilling and production operations. - The
inner casing 1535 may be coupled to theouter casing 1520 or thethick wall casing 1510. In an exemplary embodiment, theinner casing 1535 is coupled to thethick wall casing 1510. Theinner casing 1535 may be fabricated from any number of conventional commercially available tubular members modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, theinner casing 1535 comprises any one of the expandable tubular members described above with reference toFIGS. 1-11 f. - In an exemplary embodiment, the
inner casing 1535 is coupled to theouter casing 1520 by expanding at least a portion of theinner casing 1535 into contact with the interior surface of thethick wall casing 1510 using any one of the processes and apparatus described above with reference toFIGS. 1-11 f.In an exemplary embodiment, the entire length of the overlap of theinner casing 1535 with thethick wall casing 1510 andintermediate casing 1530 contacts the inner surfaces of thethick wall casing 1510 andintermediate casing 1530. The contact pressure of the interface between theinner casing 1535 and thethick wall casing 1510 may range, for example from about 500 to 10,000 psi. In an exemplary embodiment, the contact pressure between theinner casing 1535 and thethick wall casing 1510 ranges from about 500 to 10,000 psi in order to optimally activate the pressure activated sealing members and to ensure that the joint will withstand typical extremes of tensile and compressive loads that are commonly experienced during drilling and production operations. - As illustrated in
FIG. 13 , in an exemplary embodiment, the upper end of theinner easing 1535 includes one ormore sealing members 1570 that provide a gaseous and fluidic seal between the expanded end of theinner casing 1535 and the interior wall of thethick wall casing 1510. The sealingmembers 1570 may comprise any number of conventional commercially available seals such as, for example, lead, plastic, rubber, Teflon or epoxy, modified in accordance with the teachings of the present disclosure. In an exemplary embodiment, the sealingmembers 1570 comprise seals molded from StrataLock epoxy available from Halliburton Energy Services in order to optimally provide an hydraulic seal and a load bearing interference fit. In an exemplary embodiment, the contact pressure of the interface between the expanded end of theinner casing 1535 and thethick wall casing 1510 ranges from about 500 to 10,000 psi in order to optimally activate thesealing members 1570 and also to optimally ensure that the joint will withstand typical operating extremes of tensile and compressive loads that are experienced during drilling and production operations. - In an alternative embodiment, the inner casings,1520,1530 and1535, may be coupled to a previously positioned tubular member that is in turn coupled to the
outer casing 1510. More generally, the exemplary embodiments may be used to form a concentric arrangement of tubular members. - Referring now to
FIGS. 14 a,14b,14c,14d,14eand14f,an exemplary embodiment of a method and apparatus for forming a mono-diameter well casing within a subterranean formation will now be described. - As illustrated in
FIG. 14 a,awellbore 1600 is positioned in asubterranean formation 1605. A first section ofcasing 1610 is formed in thewellbore 1600. The first section ofcasing 1610 includes an annular outer body ofcement 1615 and a tubular section ofcasing 1620. The first section ofcasing 1610 may be formed in thewellbore 1600 using conventional methods and apparatus. In an exemplary embodiment, the first section ofcasing 1610 is formed using one or more of the methods and apparatus described above with reference toFIGS. 1-13 or below with reference toFIGS. 14 b-17b. - The annular body of
cement 1615 may comprise any number of conventional commercially available cement, or other load bearing, compositions. Alternatively, the body ofcement 1615 may be omitted or replaced with an epoxy mixture. - The tubular section of
casing 1620 preferably includes anupper end 1625 and alower end 1630. Preferably, thelower end 1625 of the tubular section ofcasing 1620 includes an outerannular recess 1635 extending from thelower end 1630 of the tubular section ofcasing 1620. In this manner, thelower end 1625 of the tubular section ofcasing 1620 includes a thinwalled section 1640. In an exemplary embodiment, anannular body 1645 of a compressible material is coupled to and at least partially positioned within the outerannular recess 1635. In this manner, the body ofcompressible material 1645 surrounds at least a portion of the thinwalled section 1640. - The tubular section of
casing 1620 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, automotive grade steel, carbon steel, low alloy steel, fiberglass or plastics. In an exemplary embodiment, the tubular section ofcasing 1620 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills. The wall thickness of the thinwalled section 1640 may range from about 0.125 to 1.5 inches. In an exemplary embodiment, the wall thickness of the thinwalled section 1640 ranges from 0.25 to 1.0 inches in order to optimally provide burst strength for typical operational conditions while also minimizing resistance to radial expansion. The axial length of the thinwalled section 1640 may range from about 120 to 2400 inches. In an exemplary embodiment, the axial length of the thinwalled section 1640 ranges from about 240 to 480 inches. - The annular body of
compressible material 1645 helps to minimize the radial force required to expand thetubular casing 1620 in the overlap with thetubular member 1715, helps to create a fluidic seal in the overlap with thetubular member 1715, and helps to create an interference fit sufficient to permit thetubular member 1715 to be supported by thetubular casing 1620. The annular body ofcompressible material 1645 may comprise any number of commercially available compressible materials such as, for example, epoxy, rubber, Teflon, plastics or lead tubes. In an exemplary embodiment, the annular body ofcompressible material 1645 comprises StrataLock epoxy available from Halliburton Energy Services in order to optimally provide an hydraulic seal in the overlapped joint while also having compliance to thereby minimize the radial force required to expand the tubular casing. The wall thickness of the annular body ofcompressible material 1645 may range from about 0.05 to 0.75 inches. In an exemplary embodiment, the wall thickness of the annular body ofcompressible material 1645 ranges from about 0.1 to 0.5 inches in order to optimally provide a large compressible zone, minimize the radial forces required to expand the tubular casing, provide thickness for casing strings to provide contact with the inner surface of the wellbore upon radial expansion, and provide an hydraulic seal. - As illustrated in
FIG. 14 b,in order to extend thewellbore 1600 into thesubterranean formation 1605, a drill string is used in a well known manner to drill out material from thesubterranean formation 1605 to form anew wellbore section 1650. The diameter of thenew section 1650 is preferably equal to or greater than the inner diameter of the tubular section ofcasing 1620. - As illustrated in
FIG. 14 c,an exemplary embodiment of anapparatus 1700 for forming a mono-diameter wellbore casing in a subterranean formation is then positioned in thenew section 1650 of thewellbore 1600. Theapparatus 1700 preferably includes asupport member 1705, an expandable mandrel orpig 1710, atubular member 1715, ashoe 1720, slips1725, afluid passage 1730, one or morefluid passages 1735, afluid passage 1740, a first compressibleannular body 1745, a second compressibleannular body 1750, and apressure chamber 1755. - The
support member 1705 supports theapparatus 1700 within thewellbore 1600. Thesupport member 1705 is coupled to themandrel 1710, thetubular member 1715, theshoe 1720, and theslips 1725. The support member1075 preferably comprises a substantially hollow tubular member. Thefluid passage 1730 is positioned within thesupport member 1705. Thefluid passages 1735 fluidicly couple thefluid passage 1730 with thepressure chamber 1755. Thefluid passage 1740 fluidicly couples thefluid passage 1730 with the region outside of theapparatus 1700. - The
support member 1705 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, low alloy steel, carbon steel, 13 chromium steel, fiberglass, or other high strength materials. In an exemplary embodiment, thesupport member 1705 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide operational strength and facilitate the use of other standard oil exploration handling equipment. In an exemplary embodiment, at least a portion of thesupport member 1705 comprises coiled tubing or a drill pipe. In an exemplary embodiment, thesupport member 1705 includes aload shoulder 1820 for supporting themandrel 1710 when thepressure chamber 1755 is unpressurized. - The
mandrel 1710 is supported by and slidingly coupled to thesupport member 1705 and theshoe 1720. Themandrel 1710 preferably includes anupper portion 1760 and alower portion 1765. Preferably, theupper portion 1760 of themandrel 1710 and thesupport member 1705 together define thepressure chamber 1755. Preferably, thelower portion 1765 of themandrel 1710 includes anexpansion member 1770 for radially expanding thetubular member 1715. - In an exemplary embodiment, the
upper portion 1760 of themandrel 1710 includes atubular member 1775 having an inner diameter greater than an outer diameter of thesupport member 1705. In this manner, anannular pressure chamber 1755 is defined by and positioned between thetubular member 1775 and thesupport member 1705. The top1780 of thetubular member 1775 preferably includes a bearing and a seal for sealing and supporting the top1780 of thetubular member 1775 against the outer surface of thesupport member 1705. Thebottom 1785 of thetubular member 1775 preferably includes a bearing and seal for sealing and supporting thebottom 1785 of thetubular member 1775 against the outer surface of thesupport member 1705 orshoe 1720. In this manner, themandrel 1710 moves in an axial direction upon the pressurization of thepressure chamber 1755. - The
lower portion 1765 of themandrel 1710 preferably includes anexpansion member 1770 for radially expanding thetubular member 1715 during the pressurization of thepressure chamber 1755. In an exemplary embodiment, the expansion member is expandable in the radial direction. In an exemplary embodiment, the inner surface of thelower portion 1765 of themandrel 1710 mates with and slides with respect to the outer surface of theshoe 1720. The outer diameter of theexpansion member 1770 may range from about 90 to 100% of the inner diameter of thetubular casing 1620. In an exemplary embodiment, the outer diameter of theexpansion member 1770 ranges from about 95 to 99% of the inner diameter of thetubular casing 1620. Theexpansion member 1770 may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, ceramics, tungsten carbide, titanium or other high strength alloys. In an exemplary embodiment, theexpansion member 1770 is fabricated from D2 machine tool steel in order to optimally provide high strength and abrasion resistance. - The
tubular member 1715 is coupled to and supported by thesupport member 1705 and slips1725. Thetubular member 1715 includes anupper portion 1790 and alower portion 1795. - The
upper portion 1790 of thetubular member 1715 preferably includes an innerannular recess 1800 that extends from theupper portion 1790 of thetubular member 1715. In this manner, at least a portion of theupper portion 1790 of thetubular member 1715 includes a thinwalled section 1805. The first compressibleannular member 1745 is preferably coupled to and supported by the outer surface of theupper portion 1790 of thetubular member 1715 in opposing relation to thethin wall section 1805. - The
lower portion 1795 of thetubular member 1715 preferably includes an outerannular recess 1810 that extends from thelower portion 1790 of thetubular member 1715. In this manner, at least a portion of thelower portion 1795 of thetubular member 1715 includes a thinwalled section 1815. The second compressibleannular member 1750 is coupled to and at least partially supported within the outerannular recess 1810 of theupper portion 1790 of thetubular member 1715 in opposing relation to thethin wall section 1815. - The
tubular member 1715 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, low alloy steel, carbon steel, automotive grade steel, fiberglass, 13 chrome steel, other high strength material, or high strength plastics. In an exemplary embodiment, thetubular member 1715 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide operational strength. - The
shoe 1720 is supported by and coupled to thesupport member 1705. Theshoe 1720 preferably comprises a substantially hollow tubular member. In an exemplary embodiment, the wall thickness of theshoe 1720 is greater than the wall thickness of thesupport member 1705 in order to optimally provide increased radial support to themandrel 1710. Theshoe 1720 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, automotive grade steel, low alloy steel, carbon steel, or high strength plastics. In an exemplary embodiment, theshoe 1720 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide matching operational strength throughout the apparatus. - The
slips 1725 are coupled to and supported by thesupport member 1705. Theslips 1725 removably support thetubular member 1715. In this manner, during the radial expansion of thetubular member 1715, theslips 1725 help to maintain thetubular member 1715 in a substantially stationary position by preventing upward movement of thetubular member 1715. - The
slips 1725 may comprise any number of conventional commercially available slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips, or Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In an exemplary embodiment, theslips 1725 comprise RTTS packer tungsten carbide mechanical slips available from Halliburton Energy Services. In an exemplary embodiment, theslips 1725 are adapted to support axial forces ranging from about 0 to 750,000 lbf. - The
fluid passage 1730 conveys fluidic materials from a surface location into the interior of thesupport member 1705, thepressure chamber 1755, and the region exterior of theapparatus 1700. Thefluid passage 1730 is fluidicly coupled to thepressure chamber 1755 by thefluid passages 1735. Thefluid passage 1730 is fluidicly coupled to the region exterior to theapparatus 1700 by thefluid passage 1740. - In an exemplary embodiment, the
fluid passage 1730 is adapted to convey fluidic materials such as, for example, cement, epoxy, drilling muds, slag mix, water or drilling gasses. In an exemplary embodiment, thefluid passage 1730 is adapted to convey fluidic materials at flow rate and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi. In order to optimally provide flow rates and operational pressures for the radial expansion processes. - The
fluid passages 1735 convey fluidic material from thefluid passage 1730 to thepressure chamber 1755. In an exemplary embodiment, thefluid passage 1735 is adapted to convey fluidic materials such as, for example, cement, epoxy, drilling muds, water or drilling gasses. In an exemplary embodiment, thefluid passage 1735 is adapted to convey fluidic materials at flow rate and pressures ranging from about 0 to 500 gallons/minute and 0 to 9,000 psi. in order to optimally provide operating pressures and flow rates for the various expansion processes. - The
fluid passage 1740 conveys fluidic materials from thefluid passage 1730 to the region exterior to theapparatus 1700. In an exemplary embodiment, thefluid passage 1740 is adapted to convey fluidic materials such as, for example, cement, epoxy, drilling muds, water or drilling gasses. In an exemplary embodiment, thefluid passage 1740 is adapted to convey fluidic materials at flow rate and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi. in order to optimally provide operating pressures and flow rates for the various radial expansion processes. - In an exemplary embodiment, the
fluid passage 1740 is adapted to receive a plug or other similar device for sealing thefluid passage 1740. In this manner, thepressure chamber 1755 may be pressurized. - The first compressible
annular body 1745 is coupled to and supported by an exterior surface of theupper portion 1790 of thetubular member 1715. In an exemplary embodiment, the first compressibleannular body 1745 is positioned in opposing relation to the thinwalled section 1805 of thetubular member 1715. - The first compressible
annular body 1745 helps to minimize the radial force required to expand thetubular member 1715 in the overlap with thetubular casing 1620, helps to create a fluidic seal in the overlap with thetubular casing 1620, and helps to create an interference fit sufficient to permit thetubular member 1715 to be supported by thetubular casing 1620. The first compressibleannular body 1745 may comprise any number of commercially available compressible materials such as, for example, epoxy, rubber, Teflon, plastics, or hollow lead tubes. In an exemplary embodiment, the first compressibleannular body 1745 comprises StrataLock epoxy available from Halliburton Energy Services in order to optimally provide an hydraulic seal, and compressibility to minimize the radial expansion force. - The wall thickness of the first compressible
annular body 1745 may range from about 0.05 to 0.75 inches. In an exemplary embodiment, the wall thickness of the first compressibleannular body 1745 ranges from about 0.1 to 0.5 inches in order to optimally (1) provide a large compressible zone, (2) minimize the required radial expansion force, (3) transfer the radial force to the tubular casings. As a result, in an exemplary embodiment, overall the outer diameter of thetabular member 1715 is approximately equal to the overall inner diameter of thetubular member 1620. - The second compressible
annular body 1750 is coupled to and at least partially supported within the outerannular recess 1810 of thetubular member 1715. In an exemplary embodiment, the second compressibleannular body 1750 is positioned in opposing relation to the thinwalled section 1815 of thetubular member 1715. - The second compressible
annular body 1750 helps to minimize the radial force required to expand thetubular member 1715 in the overlap with another tubular member, helps to create a fluidic seal in the overlap of thetubular member 1715 with another tubular member, and helps to create an interference fit sufficient to permit another tubular member to be supported by thetubular member 1715. The second compressibleannular body 1750 may comprise any number of commercially available compressible materials such as, for example, epoxy, rubber, Teflon, plastics or hollow lead tubing. In an exemplary embodiment, the first compressibleannular body 1750 comprises StrataLock epoxy available from Halliburton Energy Services in order to optimally provide an hydraulic seal in the overlapped joint, and compressibility that minimizes the radial expansion force. - The wall thickness of the second compressible
annular body 1750 may range from about 0.05 to 0.75 inches. In an exemplary embodiment, the wall thickness of the second compressibleannular body 1750 ranges from about 0.1 to 0.5 inches in order to optimally provide a large compressible zone, and minimize the radial force required to expand thetubular member 1715 during subsequent radial expansion operations. - In an alternative embodiment, the outside diameter of the second compressible
annular body 1750 is adapted to provide a seal against the surrounding formation thereby eliminating the need for an outer annular body of cement. - The
pressure chamber 1755 is fluidicly coupled to thefluid passage 1730 by thefluid passages 1735. Thepressure chamber 1755 is preferably adapted to receive fluidic materials such as, for example, drilling muds, water or drilling gases. In an exemplary embodiment, thepressure chamber 1755 is adapted to receive fluidic materials at flow rate and pressures ranging from about 0 to 500 gallons/minute and 0 to 9,000 psi. in order to optimally provide expansion pressure. In an exemplary embodiment, during pressurization of thepressure chamber 1755, the operating pressure of the pressure chamber ranges from about 0 to 5,000 psi in order to optimally provide expansion pressure while minimizing the possibility of a catastrophic failure due to over pressurization. - As illustrated in
FIG. 14 d,theapparatus 1700 is preferably positioned in thewellbore 1600 with thetubular member 1715 positioned in an overlapping relationship with thetubular casing 1620. In an exemplary embodiment, the thin wall sections,1640 and1805, of thetubular casing 1620 andtubular member 1725 are positioned in opposing overlapping relation. In this manner, the radial expansion of thetubular member 1725 will compress the thin wall sections,1640 and1605, and annular compressible members,1645 and1745, into intimate contact. - After positioning of the
apparatus 1700, afluidic material 1825 is then pumped into thefluid passage 1730. Thefluidic material 1825 may comprise any number of conventional commercially available materials such as, for example, water, drilling mud, drilling gases, cement or epoxy. In an exemplary embodiment, thefluidic material 1825 comprises a hardenable fluidic sealing material such as, for example, cement in order to provide an outer annular body around the expandedtubular member 1715. - The
fluidic material 1825 may be pumped into thefluid passage 1730 at operating pressures and flow rates, for example, ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
fluidic material 1825 pumped into thefluid passage 1730 passes through thefluid passage 1740 and outside of theapparatus 1700. Thefluidic material 1825 fills theannular region 1830 between the outside of theapparatus 1700 and the interior walls of thewellbore 1600. - As illustrated in
FIG. 14 e,aplug 1835 is then introduced into thefluid passage 1730. Theplug 1835 lodges in the inlet to thefluid passage 1740 fluidicly isolating and blocking off thefluid passage 1730. - A
fluidic material 1840 is then pumped into thefluid passage 1730. Thefluidic material 1840 may comprise any number of conventional commercially available materials such as, for example, water, drilling mud or drilling gases. In an exemplary embodiment, thefluidic material 1825 comprises a non-hardenable fluidic material such as, for example, drilling mud or drilling gases in order to optimally provide pressurization of thepressure chamber 1755. - The
fluidic material 1840 may be pumped into thefluid passage 1730 at operating pressures and flow rates ranging, for example, from about 0 to 9,000 psi and 0 to 500 gallons/minute. In an exemplary embodiment, thefluidic material 1840 is pumped into thefluid passage 1730 at operating pressures and flow rates ranging from about 500 to 5,000 psi and 0 to 500 gallons/minute in order to optimally provide operating pressures and flow rates for radial expansion. - The
fluidic material 1840 pumped into thefluid passage 1730 passes through thefluid passages 1735 and into thepressure chamber 1755. Continued pumping of thefluidic material 1840 pressurizes thepressure chamber 1755. The pressurization of thepressure chamber 1755 causes themandrel 1710 to move relative to thesupport member 1705 in the direction indicated by thearrows 1845. In this manner, themandrel 1710 will cause thetubular member 1715 to expand in the radial direction. - During the radial expansion process, the
tubular member 1715 is prevented from moving in an upward direction by theslips 1725. A length of thetubular member 1715 is then expanded in the radial direction through the pressurization of thepressure chamber 1755. The length of thetubular member 1715 that is expanded during the expansion process will be proportional to the stroke length of themandrel 1710. Upon the completion of a stroke, the operating pressure of thepressure chamber 1755 is then reduced and themandrel 1710 drops to it rest position with thetubular member 1715 supported by themandrel 1715. The position of thesupport member 1705 may be adjusted throughout the radial expansion process in order to maintain the overlapping relationship between the thin walled sections,1640 and1805, of thetubular casing 1620 andtubular member 1715. The stroking of themandrel 1710 is then repeated, as necessary, until the thinwalled section 1805 of thetubular member 1715 is expanded into the thinwalled section 1640 of thetubular casing 1620. - In an exemplary embodiment, during the final stroke of the
mandrel 1710, theslips 1725 are positioned as close as possible to the thinwalled section 1805 of thetubular member 1715 in order minimize slippage between thetubular member 1715 andtubular casing 1620 at the end of the radial expansion process. Alternatively, or in addition, the outside diameter of the first compressiveannular member 1745 is selected to ensure sufficient interference fit with thetubular casing 1620 to prevent axial displacement of thetubular member 1715 during the final stroke. Alternatively, or in addition, the outside diameter of the second compressiveannular body 1750 is large enough to provide an interference fit with the inside walls of thewellbore 1600 at an earlier point in the radial expansion process so as to prevent further axial displacement of thetubular member 1715. In this final alternative, the interference fit is preferably selected to permit expansion of thetubular member 1715 by pulling themandrel 1710 out of thewellbore 1600, without having to pressurize thepressure chamber 1755. - During the radial expansion process, the pressurized areas of the
apparatus 1700 are limited to thefluid passages 1730 within thesupport member 1705 and thepressure chamber 1755 within themandrel 1710. No fluid pressure acts directly on thetubular member 1715. This permits the use of operating pressures higher than thetubular member 1715 could normally withstand. - Once the
tubular member 1715 has been completely expanded off of themandrel 1710, thesupport member 1705 andmandrel 1710 are removed from thewellbore 1600. In an exemplary embodiment, the contact pressure between the deformed thin wall sections,1640 and1805, and compressible annular members,1645 and1745, ranges from about 400 to 10,000 psi in order to optimally support thetubular member 1715 using thetubular casing 1620. - In this manner, the
tubular member 1715 is radially expanded into contact with thetubular casing 1620 by pressurizing the interior of thefluid passage 1730 and thepressure chamber 1755. - As illustrated in
FIG. 14 f,in an exemplary embodiment, once thetubular member 1715 is completely expanded in the radial direction by themandrel 1710, thesupport member 1705 andmandrel 1710 are removed from thewellbore 1600. In an exemplary embodiment, the annular body of hardenable fluidic material is then allowed to cure to form a rigid outer annular body1850. In the case where thetubular member 1715 is slotted, the hardenable fluidic material will preferably permeate and envelop the expandedtubular member 1715. - The resulting new section of
wellbore casing 1855 includes the expandedtubular member 1715 and the rigid outer annular body1850. The overlapping joint1860 between thetubular casing 1620 and the expandedtubular member 1715 includes the deformed thin wall sections,1640 and1805, and the compressible annular bodies,1645 and1745. The inner diameter of the resulting combined wellbore casings is substantially constant. In this manner, a mono-diameter wellbore casing is formed. This process of expanding overlapping tubular members having thin wall end portions with compressible annular bodies into contact can be repeated for the entire length of a wellbore. In this manner, a mono-diameter wellbore casing can be provided for thousands of feet in a subterranean formation. - Referring now to
FIGS. 15 ,15aand15b,an embodiment of anapparatus 1900 for expanding a tubular member will be described. Theapparatus 1900 preferably includes adrillpipe 1905, aninnerstring adapter 1910, a sealingsleeve 1915, aninner sealing mandrel 1920, anupper sealing head 1925, alower sealing head 1930, anouter sealing mandrel 1935, aload mandrel 1940, anexpansion cone 1945, amandrel launcher 1950, amechanical slip body 1955,mechanical slips 1960, drag blocks1965,casing 1970, andfluid passages - The
drillpipe 1905 is coupled to theinnerstring adapter 1910. During operation of theapparatus 1900, thedrillpipe 1905 supports theapparatus 1900. Thedrillpipe 1905 preferably comprises a substantially hollow tubular member or members. Thedrillpipe 1905 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular drillpipe, fiberglass or coiled tubing. In an exemplary embodiment, thedrillpipe 1905 is fabricated from coiled tubing in order to facilitate the placement of theapparatus 1900 in non-vertical wellbores. Thedrillpipe 1905 may be coupled to theinnerstring adapter 1910 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connectors, OCTG specialty type box and pin connectors, a ratchet-latch type connector or a standard box by pin connector. In an exemplary embodiment, thedrillpipe 1905 is removably coupled to theinnerstring adapter 1910 by a drillpipe connection. - The
drillpipe 1905 preferably includes afluid passage 1975 that is adapted to convey fluidic materials from a surface location into thefluid passage 1980. In an exemplary embodiment, thefluid passage 1975 is adapted to convey fluidic materials such as, for example, cement, drilling mud, epoxy or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
innerstring adapter 1910 is coupled to thedrill string 1905 and thesealing sleeve 1915. Theinnerstring adapter 1910 preferably comprises a substantially hollow tubular member or members. Theinnerstring adapter 1910 may be fabricated from any number of conventional commercially available materials such as, for example, oil country tubular goods, low alloy steel, carbon steel, stainless steel or other high strength materials. In an exemplary embodiment, theinnerstring adapter 1910 is fabricated from oilfield country tubular goods in order to optimally provide mechanical properties that closely match those of thedrill string 1905. - The
innerstring adapter 1910 may be coupled to thedrill string 1905 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connectors, oilfield country tubular goods specialty type threaded connectors, ratchet-latch type stab in connector, or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 1910 is removably coupled to thedrill pipe 1905 by a drillpipe connection. Theinnerstring adapter 1910 may be coupled to thesealing sleeve 1915 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connector, ratchet-latch type stab in connectors, or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 1910 is removably coupled to thesealing sleeve 1915 by a standard threaded connection. - The
innerstring adapter 1910 preferably includes afluid passage 1980 that is adapted to convey fluidic materials from thefluid passage 1975 into thefluid passage 1985. In an exemplary embodiment, thefluid passage 1980 is adapted to convey fluidic materials such as, for example, cement, drilling mud, epoxy, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The sealing
sleeve 1915 is coupled to theinnerstring adapter 1910 and theinner sealing mandrel 1920. The sealingsleeve 1915 preferably comprises a substantially hollow tubular member or members. The sealingsleeve 1915 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, carbon steel, low alloy steel, stainless steel or other high strength materials. In an exemplary embodiment, the sealingsleeve 1915 is fabricated from oilfield country tubular goods in order to optimally provide mechanical properties that substantially match the remaining components of theapparatus 1900. - The sealing
sleeve 1915 may be coupled to theinnerstring adapter 1910 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type stab in connection, or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 1915 is removably coupled to theinnerstring adapter 1910 by a standard threaded connection. The sealingsleeve 1915 may be coupled to theinner sealing mandrel 1920 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 1915 is removably coupled to theinner sealing mandrel 1920 by a standard threaded connection. - The sealing
sleeve 1915 preferably includes afluid passage 1985 that is adapted to convey fluidic materials from thefluid passage 1980 into thefluid passage 1990. In an exemplary embodiment, thefluid passage 1985 is adapted to convey fluidic materials such as, for example, cement, drilling mud, epoxy or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
inner sealing mandrel 1920 is coupled to thesealing sleeve 1915 and thelower sealing head 1930. Theinner sealing mandrel 1920 preferably comprises a substantially hollow tubular member or members. Theinner sealing mandrel 1920 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, low alloy steel, carbon steel or other similar high strength materials. In an exemplary embodiment, theinner sealing mandrel 1920 is fabricated from stainless steel in order to optimally provide mechanical properties similar to the other components of theapparatus 1900 while also providing a smooth outer surface to support seals and other moving parts that can operate with minimal wear, corrosion and pitting. - The
inner sealing mandrel 1920 may be coupled to thesealing sleeve 1915 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, theinner sealing mandrel 1920 is removably coupled to thesealing sleeve 1915 by a standard threaded connections. Theinner sealing mandrel 1920 may be coupled to thelower sealing head 1930 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type stab in connectors or standard threaded connections. In an exemplary embodiment, theinner sealing mandrel 1920 is removably coupled to thelower sealing head 1930 by a standard threaded connections connection. - The
inner sealing mandrel 1920 preferably includes afluid passage 1990 that is adapted to convey fluidic materials from thefluid passage 1985 into thefluid passage 1995. In an exemplary embodiment, thefluid passage 1990 is adapted to convey fluidic materials such as, for example, cement, drilling mud, epoxy or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
upper sealing head 1925 is coupled to theouter sealing mandrel 1935 and theexpansion cone 1945. Theupper sealing head 1925 is also movably coupled to the outer surface of theinner sealing mandrel 1920 and the inner surface of thecasing 1970. In this manner, theupper sealing head 1925,outer sealing mandrel 1935, and theexpansion cone 1945 reciprocate in the axial direction. The radial clearance between the inner cylindrical surface of theupper sealing head 1925 and the outer surface of theinner sealing mandrel 1920 may range, for example, from about 0.025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of theupper sealing head 1925 and the outer surface of theinner sealing mandrel 1920 ranges from about 0.005 to 0.01 inches in order to optimally provide clearance for pressure seal placement. The radial clearance between the outer cylindrical surface of theupper sealing head 1925 and the inner surface of thecasing 1970 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of theupper sealing head 1925 and the inner surface of thecasing 1970 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 1945 as theexpansion cone 1945 is upwardly moved inside thecasing 1970. - The
upper sealing head 1925 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theupper sealing head 1925 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, machine tool steel, or similar high strength materials. In an exemplary embodiment, theupper sealing head 1925 is fabricated from stainless steel in order to optimally provide high strength and smooth outer surfaces that are resistant to wear, galling, corrosion and pitting. - The inner surface of the
upper sealing head 1925 preferably includes one or moreannular sealing members 2000 for sealing the interface between theupper sealing head 1925 and theinner sealing mandrel 1920. The sealingmembers 2000 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2000 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial motion. - In an exemplary embodiment, the
upper sealing head 1925 includes ashoulder 2005 for supporting theupper sealing head 1925 on thelower sealing head 1930. - The
upper sealing head 1925 may be coupled to theouter sealing mandrel 1935 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connections. In an exemplary embodiment, theupper sealing head 1925 is removably coupled to theouter sealing mandrel 1935 by a standard threaded connections. In an exemplary embodiment, the mechanical coupling between theupper sealing head 1925 and theouter sealing mandrel 1935 includes one ormore sealing members 2010 for fluidicly sealing the interface between theupper sealing head 1925 and theouter sealing mandrel 1935. The sealingmembers 2010 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2010 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroking motion. - The
lower sealing head 1930 is coupled to theinner sealing mandrel 1920 and theload mandrel 1940. Thelower sealing head 1930 is also movably coupled to the inner surface of theouter sealing mandrel 1935. In this manner, theupper sealing head 1925 andouter sealing mandrel 1935 reciprocate in the axial direction. The radial clearance between the outer surface of thelower sealing head 1930 and the inner surface of theouter sealing mandrel 1935 may range, for example, from about 0.025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the outer surface of thelower sealing head 1930 and the inner surface of theouter sealing mandrel 1935 ranges from about 0.005 to 0.010 inches in order to optimally provide a close tolerance having room for the installation of pressure seal rings. - The
lower sealing head 1930 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Thelower sealing head 1930 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, stainless steel, machine tool steel or other similar high strength materials. In an exemplary embodiment, thelower sealing head 1930 is fabricated from stainless steel in order to optimally provide high strength and resistance to wear, galling, corrosion, and pitting. - The outer surface of the
lower sealing head 1930 preferably includes one or moreannular sealing members 2015 for sealing the interface between thelower sealing head 1930 and theouter sealing mandrel 1935. The sealingmembers 2015 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2015 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The
lower sealing head 1930 may be coupled to theinner sealing mandrel 1920 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, thelower sealing head 1930 is removably coupled to theinner sealing mandrel 1920 by a standard threaded connection. - in an exemplary embodiment, the mechanical coupling between the
lower sealing head 1930 and theinner sealing mandrel 1920 includes one ormore sealing members 2020 for fluidicly sealing the interface between thelower sealing head 1930 and theinner sealing mandrel 1920. The sealingmembers 2020 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2020 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial motion. - The
lower sealing head 1930 may be coupled to theload mandrel 1940 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connections, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, thelower sealing head 1930 is removably coupled to theload mandrel 1940 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between thelower sealing head 1930 and theload mandrel 1940 includes one ormore sealing members 2025 for fluidicly sealing the interface between thelower sealing head 1930 and theload mandrel 1940. The sealingmembers 2025 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2025 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - In an exemplary embodiment, the
lower sealing head 1930 includes athroat passage 2040 fluidicly coupled between thefluid passages throat passage 2040 is preferably of reduced size and is adapted to receive and engage with aplug 2045, or other similar device. In this manner, thefluid passage 1990 is fluidicly isolated from thefluid passage 1995. In this manner, thepressure chamber 2030 is pressurized. - The
outer sealing mandrel 1935 is coupled to theupper sealing head 1925 and theexpansion cone 1945. Theouter sealing mandrel 1935 is also movably coupled to the inner surface of thecasing 1970 and the outer surface of thelower sealing head 1930. In this manner, theupper sealing head 1925,outer sealing mandrel 1935, and theexpansion cone 1945 reciprocate in the axial direction. The radial clearance between the outer surface of theouter sealing mandrel 1935 and the inner surface of thecasing 1970 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer surface of theouter sealing mandrel 1935 and the inner surface of thecasing 1970 ranges from about 0.025 to 0.125 inches in order to optimally provide maximum piston surface area to maximize the radial expansion force. The radial clearance between the inner surface of theouter sealing mandrel 1935 and the outer surface of thelower sealing head 1930 may range, for example, from about 0.025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner surface of theouter sealing mandrel 1935 and the outer surface of thelower sealing head 1930 ranges from about 0.005 to 0.010 inches in order to optimally provide a minimum gap for the sealing elements to bridge and seal. - The
outer sealing mandrel 1935 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theouter sealing mandrel 1935 may be fabricated from any number of conventional commercially available materials such as, for example, low alloy steel, carbon steel, 13 chromium steel or stainless steel. In an exemplary embodiment, theouter sealing mandrel 1935 is fabricated from stainless steel in order to optimally provide maximum strength and minimum wall thickness while also providing resistance to corrosion, galling and pitting. - The
outer sealing mandrel 1935 may be coupled to theupper sealing head 1925 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, standard threaded connections, or welding. In an exemplary embodiment, theouter sealing mandrel 1935 is removably coupled to theupper sealing head 1925 by a standard threaded connections connection. Theouter sealing mandrel 1935 may be coupled to theexpansion cone 1945 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connections connection, or welding. In an exemplary embodiment, theouter sealing mandrel 1935 is removably coupled to theexpansion cone 1945 by a standard threaded connections connection. - The
upper sealing head 1925, thelower sealing head 1930, theinner sealing mandrel 1920, and theouter sealing mandrel 1935 together define apressure chamber 2030. Thepressure chamber 2030 is fluidicly coupled to thepassage 1990 via one ormore passages 2035. During operation of theapparatus 1900, theplug 2045 engages with thethroat passage 2040 to fluidicly isolate thefluid passage 1990 from thefluid passage 1995. Thepressure chamber 2030 is then pressurized which in turn causes theupper sealing head 1925,outer sealing mandrel 1935, andexpansion cone 1945 to reciprocate in the axial direction. The axial motion of theexpansion cone 1945 in turn expands thecasing 1970 in the radial direction. - The
load mandrel 1940 is coupled to thelower sealing head 1930 and themechanical slip body 1955. Theload mandrel 1940 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theload mandrel 1940 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theload mandrel 1940 is fabricated from oilfield country tubular goods in order to optimally provide high strength. - The
load mandrel 1940 may be coupled to thelower sealing head 1930 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, theload mandrel 1940 is removably coupled to thelower sealing head 1930 by a standard threaded connection. Theload mandrel 1940 may be coupled to themechanical slip body 1955 using any number of conventional commercially available mechanical couplings such as, for example, a drillpipe connection, oilfield country tubular goods specialty type threaded connections, welding, amorphous bonding, or a standard threaded connections connection. In an exemplary embodiment, theload mandrel 1940 is removably coupled to themechanical slip body 1955 by a standard threaded connections connection. - The
load mandrel 1940 preferably includes afluid passage 1995 that is adapted to convey fluidic materials from thefluid passage 1990 to the region outside of theapparatus 1900. In an exemplary embodiment, thefluid passage 1995 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
expansion cone 1945 is coupled to theouter sealing mandrel 1935. Theexpansion cone 1945 is also movably coupled to the inner surface of thecasing 1970. In this manner, theupper sealing head 1925,outer sealing mandrel 1935, and theexpansion cone 1945 reciprocate in the axial direction. The reciprocation of theexpansion cone 1945 causes thecasing 1970 to expand in the radial direction. - The
expansion cone 1945 preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces. The outside radius of the outside conical surface may range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 inches in order to optimally provide cone dimensions for the typical range of tubular members. - The axial length of the
expansion cone 1945 may range, for example, from about 2 to 8 times the largest outer diameter of theexpansion cone 1945. In an exemplary embodiment, the axial length of theexpansion cone 1945 ranges from about 3 to 5 times the largest outer diameter of theexpansion cone 1945 in order to optimally provide stability and centralization of theexpansion cone 1945 during the expansion process. In an exemplary embodiment, the angle of attack of theexpansion cone 1945 ranges from about 5 to 30 degrees in order to optimally balance friction forces with the desired amount of radial expansion. Theexpansion cone 1945 angle of attack will vary as a function of the operating parameters of the particular expansion operation. - The
expansion cone 1945 may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, ceramics, tungsten carbide, nitride steel, or other similar high strength materials. In an exemplary embodiment, theexpansion cone 1945 is fabricated from D2 machine tool steel in order to optimally provide high strength and resistance to corrosion, wear, galling, and pitting. In an exemplary embodiment, the outside surface of theexpansion cone 1945 has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide high strength and resist wear and galling. - The
expansion cone 1945 may be coupled to theoutside sealing mandrel 1935 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield tubular country goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connections connection. In an exemplary embodiment, theexpansion cone 1945 is coupled to theoutside sealing mandrel 1935 using a standard threaded connections connection in order to optimally provide connector strength for the typical operating loading conditions while also permitting easy replacement of theexpansion cone 1945. - The
mandrel launcher 1950 is coupled to thecasing 1970. Themandrel launcher 1950 comprises a tubular section of casing having a reduced wall thickness compared to thecasing 1970. In an exemplary embodiment, the wall thickness of the mandrel launcher is about 50 to 100% of the wall thickness of thecasing 1970. In this manner, the initiation of the radial expansion of thecasing 1970 is facilitated, and the insertion of the larger outsidediameter mandrel launcher 1950 into the wellbore and/or casing is facilitated. - The
mandrel launcher 1950 may be coupled to thecasing 1970 using any number of conventional mechanical couplings. Themandrel launcher 1950 may have a wall thickness ranging, for example, from about 0.15 to 1.5 inches. In an exemplary embodiment, the wall thickness of themandrel launcher 1950 ranges from about 0.25 to 0.75 inches in order to optimally provide high strength with a small overall profile. Themandrel launcher 1950 may be fabricated from any number of conventional commercially available materials such as, for example, oil field tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, themandrel launcher 1950 is fabricated from oil field tubular goods of higher strength but lower wall thickness than thecasing 1970 in order to optimally provide a thin walled container with approximately the same burst strength as thecasing 1970. - The
mechanical slip body 1955 is coupled to theload mandrel 1970, themechanical slips 1960, and the drag blocks1965. Themechanical slip body 1955 preferably comprises a tubular member having aninner passage 2050 fluidicly coupled to thepassage 1995. In this manner, fluidic materials may be conveyed from thepassage 2050 to a region outside of theapparatus 1900. - The
mechanical slip body 1955 may be coupled to theload mandrel 1940 using any number of conventional mechanical couplings. In an exemplary embodiment, themechanical slip body 1955 is removably coupled to theload mandrel 1940 using a standard threaded connection in order to optimally provide high strength and permit themechanical slip body 1955 to be easily replaced. Themechanical slip body 1955 may be coupled to themechanical slips 1955 using any number of conventional mechanical couplings. In an exemplary embodiment, themechanical slip body 1955 is removably coupled to themechanical slips 1955 using threads and sliding steel retainer rings in order to optimally provide high strength coupling and also permit easy replacement of themechanical slips 1955. Themechanical slip body 1955 may be coupled to the drag blocks1965 using any number of conventional mechanical couplings. In an exemplary embodiment, themechanical slip body 1955 is removably coupled to the drag blocks1965 using threaded connections and sliding steel retainer rings in order to optimally provide high strength and also permit easy replacement of the drag blocks1965. - The
mechanical slips 1960 are coupled to the outside surface of themechanical slip body 1955. During operation of theapparatus 1900, themechanical slips 1960 prevent upward movement of thecasing 1970 andmandrel launcher 1950. In this manner, during the axial reciprocation of theexpansion cone 1945, thecasing 1970 andmandrel launcher 1950 are maintained in a substantially stationary position. In this manner, themandrel launcher 1950 andcasing 1970 are expanded in the radial direction by the axial movement of theexpansion cone 1945. - The
mechanical slips 1960 may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In an exemplary embodiment, themechanical slips 1960 comprise RTTS packer tungsten carbide mechanical slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of thecasing 1970 during the expansion process. - The drag blocks1965 are coupled to the outside surface of the
mechanical slip body 1955. During operation of theapparatus 1900, the drag blocks1965 prevent upward movement of thecasing 1970 andmandrel launcher 1950. In this manner, during the axial reciprocation of theexpansion cone 1945, thecasing 1970 andmandrel launcher 1950 are maintained in a substantially stationary position. In this manner, themandrel launcher 1950 andcasing 1970 are expanded in the radial direction by the axial movement of theexpansion cone 1945. - The drag blocks1965 may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In an exemplary embodiment, the drag blocks1965 comprise RTTS packer tungsten carbide mechanical slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the
casing 1970 during the expansion process. - The
casing 1970 is coupled to themandrel launcher 1950. Thecasing 1970 is further removably coupled to themechanical slips 1960 and drag blocks1965. Thecasing 1970 preferably comprises a tubular member. Thecasing 1970 may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oil field country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thecasing 1970 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength. In an exemplary embodiment, the upper end of thecasing 1970 includes one or more sealing members positioned about the exterior of thecasing 1970. - During operation, the
apparatus 1900 is positioned in a wellbore with the upper end of thecasing 1970 positioned in an overlapping relationship within an existing wellbore casing. In order minimize surge pressures within the borehole during placement of theapparatus 1900, the fluid passage1976 is preferably provided with one or more pressure relief passages. During the placement of theapparatus 1900 in the wellbore, thecasing 1970 is supported by theexpansion cone 1945. - After positioning of the
apparatus 1900 within the bore hole in an overlapping relationship with an existing section of wellbore casing, a first fluidic material is pumped into thefluid passage 1975 from a surface location. The first fluidic material is conveyed from thefluid passage 1975 to thefluid passages apparatus 1900 and the interior walls of the bore hole. - The first fluidic material may comprise any number of conventional commercially available materials such as, for example, drilling mud, wafer, epoxy or cement. In an exemplary embodiment, the first fluidic material comprises a hardenable fluidic sealing material such as, for example, cement or epoxy. In this manner, a wellbore casing having an outer annular layer of a hardenable material may be formed.
- The first fluidic material may be pumped into the
apparatus 1900 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi, and 0 to 3,000 gallons/minute. In an exemplary embodiment, the first fluidic material is pumped into theapparatus 1900 at operating pressures and flow rates ranging from about 0 to 4,500 psi and 0 to 3,000 gallons/minute in order to optimally provide operating pressures and flow rates for typical operating conditions. - At a predetermined point in the injection of the first fluidic material such as, for example, after the annular region outside of the
apparatus 1900 has been filled to a predetermined level, aplug 2045, dart, or other similar device is introduced into the first fluidic material. Theplug 2045 lodges in thethroat passage 2040 thereby fluidicly isolating thefluid passage 1990 from thefluid passage 1995. - After placement of the
plug 2045 in thethroat passage 2040, a second fluidic material is pumped into thefluid passage 1975 in order to pressurize thepressure chamber 2030. The second fluidic material may comprise any number of conventional commercially available materials such as, for example, water, drilling gases, drilling mud or lubricant. In an exemplary embodiment, the second fluidic material comprises a non-hardenable fluidic material such as, for example, water, drilling mud or lubricant in order minimize frictional forces. - The second fluidic material may be pumped into the
apparatus 1900 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute. In an exemplary embodiment, the second fluidic material is pumped into theapparatus 1900 at operating pressures and flow rates ranging from about 0 to 3,500 psi, and 0 to 1,200 gallons/minute in order to optimally provide expansion of thecasing 1970. - The pressurization of the
pressure chamber 2030 causes theupper sealing head 1925,outer sealing mandrel 1935, andexpansion cone 1945 to move in an axial direction. As theexpansion cone 1945 moves in the axial direction, theexpansion cone 1945 pulls themandrel launcher 1950 anddrag blocks 1965 along, which sets themechanical slips 1960 and stops further axial movement of themandrel launcher 1950 andcasing 1970. In this manner, the axial movement of theexpansion cone 1945 radially expands themandrel launcher 1950 andcasing 1970. - Once the
upper sealing head 1925,outer sealing mandrel 1935, andexpansion cone 1945 complete an axial stroke, the operating pressure of the second fluidic material is reduced and thedrill string 1905 is raised. This causes theinner sealing mandrel 1920,lower sealing head 1930,load mandrel 1940, andmechanical slip body 1955 to move upward. This unsets themechanical slips 1960 and permits themechanical slips 1960 anddrag blocks 1965 to be moved upward within the mandrel launcher andcasing 1970. When thelower sealing head 1930 contacts theupper sealing head 1925, the second fluidic material is again pressurized and the radial expansion process continues. In this manner, themandrel launcher 1950 andcasing 1970 are radial expanded through repeated axial strokes of theupper sealing head 1925,outer sealing mandrel 1935 andexpansion cone 1945. Throughput the radial expansion process, the upper end of thecasing 1970 is preferably maintained in an overlapping relation with an existing section of wellbore casing. - At the end of the radial expansion process, the upper end of the
casing 1970 is expanded into intimate contact with the inside surface of the lower end of the existing wellbore casing. In an exemplary embodiment, the sealing members provided at the upper end of thecasing 1970 provide a fluidic seal between the outside surface of the upper end of thecasing 1970 and the inside surface of the lower end of the existing wellbore casing. In an exemplary embodiment, the contact pressure between thecasing 1970 and the existing section of wellbore casing ranges from about 400 to 10,000 psi in order to optimally provide contact pressure for activating sealing members, provide optimal resistance to axial movement of the expandedcasing 1970, and optimally support typical tensile and compressive loads. - In an exemplary embodiment, as the
expansion cone 1945 nears the end of thecasing 1970, the operating flow rate of the second fluidic material is reduced in order to minimize shock to theapparatus 1900. In an alternative embodiment, theapparatus 1900 includes a shock absorber for absorbing the shock created by the completion of the radial expansion of thecasing 1970. - In an exemplary embodiment, the reduced operating pressure of the second fluidic material ranges from about 100 to 1,000 psi as the
expansion cone 1945 nears the end of thecasing 1970 in order to optimally provide reduced axial movement and velocity of theexpansion cone 1945. In an exemplary embodiment, the operating pressure of the second fluidic material is reduced during the return stroke of theapparatus 1900 to the range of about 0 to 500 psi in order minimize the resistance to the movement of theexpansion cone 1945. In an exemplary embodiment, the stroke length of theapparatus 1900 ranges from about 10 to 45 feet in order to optimally provide equipment lengths that can be handled by typical oil well rigging equipment while also minimizing the frequency at which theexpansion cone 1945 must be stopped so theapparatus 1900 can be re-stroked for further expansion operations. - In an alternative embodiment, at least a portion of the
upper sealing head 1925 includes an expansion cone for radially expanding themandrel launcher 1950 andcasing 1970 during operation of theapparatus 1900 in order to increase the surface area of thecasing 1970 acted upon during the radial expansion process. In this manner, the operating pressures can be reduced. - In an alternative embodiment, mechanical slips are positioned in an axial location between the sealing
sleeve 1915 and theinner sealing mandrel 1920 in order to simplify the operation and assembly of theapparatus 1900. - Upon the complete radial expansion of the
casing 1970, if applicable, the first fluidic material is permitted to cure within the annular region between the outside of the expandedcasing 1970 and the interior walls of the wellbore. In the case where the expandedcasing 1970 is slotted, the cured fluidic material will preferably permeate and envelop the expanded casing. In this manner, a new section of wellbore casing is formed within a wellbore. Alternatively, theapparatus 1900 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, theapparatus 1900 may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material. Alternatively, theapparatus 1900 may be used to expand a tubular support member in a hole. - During the radial expansion process, the pressurized areas of the
apparatus 1900 are limited to thefluid passages pressure chamber 2030. No fluid pressure acts directly on themandrel launcher 1950 andcasing 1970. This permits the use of operating pressures higher than themandrel launcher 1950 andcasing 1970 could normally withstand. - Referring now to
FIG. 16 , an exemplary embodiment of an apparatus2100 for forming a mono-diameter wellbore casing will be described. The apparatus2100 preferably includes adrillpipe 2105, aninnerstring adapter 2110, a sealingsleeve 2115, aninner sealing mandrel 2120, slips2125,upper sealing head 2130,lower sealing head 2135,outer sealing mandrel 2140,load mandrel 2145, expansion cone2150, andcasing 2155. - The
drillpipe 2105 is coupled to theinnerstring adapter 2110. During operation of the apparatus2100, thedrillpipe 2105 supports the apparatus2100. Thedrillpipe 2105 preferably comprises a substantially hollow tubular member or members. Thedrillpipe 2105 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength material. In an exemplary embodiment, thedrillpipe 2105 is fabricated from coiled tubing in order to facilitate the placement of theapparatus 1900 in non-vertical wellbores. Thedrillpipe 2105 may be coupled to theinnerstring adapter 2110 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type connection, or a standard threaded connection. In an exemplary embodiment, thedrillpipe 2105 is removably coupled to theinnerstring adapter 2110 by a drill pipe connection. - The
drillpipe 2105 preferably includes afluid passage 2160 that is adapted to convey fluidic materials from a surface location into thefluid passage 2165. In an exemplary embodiment, thefluid passage 2160 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
innerstring adapter 2110 is coupled to thedrill string 2105 and thesealing sleeve 2115. Theinnerstring adapter 2110 preferably comprises a substantially hollow tubular member or members. Theinnerstring adapter 2110 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theinnerstring adapter 2110 is fabricated from stainless steel in order to optimally provide high strength, low friction, and resistance to corrosion and wear. - The
innerstring adapter 2110 may be coupled to thedrill string 2105 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type connection or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 2110 is removably coupled to thedrill pipe 2105 by a drillpipe connection. Theinnerstring adapter 2110 may be coupled to thesealing sleeve 2115 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 2110 is removably coupled to thesealing sleeve 2115 by a standard threaded connection. - The
innerstring adapter 2110 preferably includes afluid passage 2165 that is adapted to convey fluidic materials from thefluid passage 2160 into thefluid passage 2170. In an exemplary embodiment, thefluid passage 2165 is adapted to convey fluidic materials such as, for example, cement, epoxy, water drilling muds, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The sealing
sleeve 2115 is coupled to theinnerstring adapter 2110 and theinner sealing mandrel 2120. The sealingsleeve 2115 preferably comprises a substantially hollow tubular member or members. The sealingsleeve 2115 may be fabricated from any number of conventional commercially available materials such as, for example, oil field tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the sealingsleeve 2115 is fabricated from stainless steel in order to optimally provide high strength, low friction surfaces, and resistance to corrosion, wear, galling, and pitting. - The sealing
sleeve 2115 may be coupled to theinnerstring adapter 2110 using any number of conventional commercially available mechanical couplings such as, for example, a standard threaded connection, oilfield country tubular goods specialty type threaded connections, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 2115 is removably coupled to theinnerstring adapter 2110 by a standard threaded connection. The sealingsleeve 2115 may be coupled to theinner sealing mandrel 2120 using any number of conventional commercially available mechanical couplings such as, for example, a standard threaded connection, oilfield country tubular goods specialty type threaded connections, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 2115 is removably coupled to theinner sealing mandrel 2120 by a standard threaded connection. - The sealing
sleeve 2115 preferably includes afluid passage 2170 that is adapted to convey fluidic materials from thefluid passage 2165 into thefluid passage 2175. In an exemplary embodiment, thefluid passage 2170 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
inner sealing mandrel 2120 is coupled to thesealing sleeve 2115, slips2125, and thelower sealing head 2135. Theinner sealing mandrel 2120 preferably comprises a substantially hollow tubular member or members. Theinner sealing mandrel 2120 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theinner sealing mandrel 2120 is fabricated from stainless steel in order to optimally provide high strength, low friction surfaces, and corrosion and wear resistance. - The
inner sealing mandrel 2120 may be coupled to thesealing sleeve 2115 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, theinner sealing mandrel 2120 is removably coupled to thesealing sleeve 2115 by a standard threaded connection. The standard threaded connection provides high strength and permits easy replacement of components. Theinner sealing mandrel 2120 may be coupled to theslips 2125 using any number of conventional commercially available mechanical couplings such as, for example, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theinner sealing mandrel 2120 is removably coupled to theslips 2125 by a standard threaded connection. Theinner sealing mandrel 2120 may be coupled to thelower sealing head 2135 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, theinner sealing mandrel 2120 is removably coupled to thelower sealing head 2135 by a standard threaded connection. - The
inner sealing mandrel 2120 preferably includes afluid passage 2175 that is adapted to convey fluidic materials from thefluid passage 2170 into the fluid passage2180. In an exemplary embodiment, thefluid passage 2175 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
slips 2125 are coupled to the outer surface of theinner sealing mandrel 2120. During operation of the apparatus2100, theslips 2125 preferably maintain the easing2155 in a substantially stationary position during the radial expansion of thecasing 2155. In an exemplary embodiment, theslips 2125 are activated using thefluid passages 2185 to convey pressurized fluid material into theslips 2125. - The slips2126 may comprise any number of commercially available hydraulic slips such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L retrievable bridge plug hydraulic slips. In an exemplary embodiment, the
slips 2125 comprise RTTS packer tungsten carbide hydraulic slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of thecasing 2155 during the expansion process. In an exemplary embodiment, the slips include afluid passage 2190,pressure chamber 2195, spring return2200, andslip member 2205. - The
slips 2125 may be coupled to theinner sealing mandrel 2120 using any number of conventional mechanical couplings. In an exemplary embodiment, theslips 2125 are removably coupled to the outer surface of theinner sealing mandrel 2120 by a thread connection in order to optimally provide interchangeability of parts. - The
upper sealing head 2130 is coupled to theouter sealing mandrel 2140 and expansion cone2150. Theupper sealing head 2130 is also movably coupled to the outer surface of theinner sealing mandrel 2120 and the inner surface of thecasing 2155. In this manner, theupper sealing head 2130 reciprocates in the axial direction. The radial clearance between the inner cylindrical surface of theupper sealing head 2130 and the outer surface of theinner sealing mandrel 2120 may range, for example, from about 0.025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of theupper sealing head 2130 and the outer surface of theinner sealing mandrel 2120 ranges from about 0.005 to 0.010 inches in order to optimally provide a pressure seal. The radial clearance between the outer cylindrical surface of theupper sealing head 2130 and the inner surface of thecasing 2155 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of theupper sealing head 2130 and the inner surface of thecasing 2155 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 2130 during axial movement of theexpansion cone 2130. - The
upper sealing head 2130 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theupper sealing head 2130 may be fabricated from any number of conventional commercially available materials such as, for example, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theupper sealing head 2130 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The inner surface of theupper sealing head 2130 preferably includes one or moreannular sealing members 2210 for sealing the interface between theupper sealing head 2130 and theinner sealing mandrel 2120. The sealingmembers 2210 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2210 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - In an exemplary embodiment, the
upper sealing head 2130 includes a shoulder2215 for supporting theupper sealing head 2130 on thelower sealing head 2135. - The
upper sealing head 2130 may be coupled to theouter sealing mandrel 2140 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, theupper sealing head 2130 is removably coupled to theouter sealing mandrel 2140 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between theupper sealing head 2130 and theouter sealing mandrel 2140 includes one ormore sealing members 2220 for fluidicly sealing the interface between theupper sealing head 2130 and theouter sealing mandrel 2140. The sealingmembers 2220 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2220 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The
lower sealing head 2135 is coupled to theinner sealing mandrel 2120 and theload mandrel 2145. Thelower sealing head 2135 is also movably coupled to the inner surface of theouter sealing mandrel 2140. In this manner, theupper sealing head 2130,outer sealing mandrel 2140, and expansion cone2150 reciprocate in the axial direction. The radial clearance between the outer surface of thelower sealing head 2135 and the inner surface of theouter sealing mandrel 2140 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the outer surface of thelower sealing head 2135 and the inner surface of theouter sealing mandrel 2140 ranges from about 0.0025 to 0.05 inches in order to optimally provide minimal radial clearance. - The
lower sealing head 2135 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Thelower sealing head 2135 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thelower sealing head 2135 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The outer surface of thelower sealing head 2135 preferably includes one or moreannular sealing members 2225 for sealing the interface between thelower sealing head 2135 and theouter sealing mandrel 2140. The sealingmembers 2225 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2225 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The
lower sealing head 2135 may be coupled to theinner sealing mandrel 2120 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, thelower sealing head 2135 is removably coupled to theinner sealing mandrel 2120 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between thelower sealing head 2135 and theinner sealing mandrel 2120 includes one ormore sealing members 2230 for fluidicly sealing the interface between thelower sealing head 2135 and theinner sealing mandrel 2120. The sealingmembers 2230 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2230 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The
lower sealing head 2135 may be coupled to theload mandrel 2145 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, thelower sealing head 2135 is removably coupled to theload mandrel 2145 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between thelower sealing head 2135 and theload mandrel 2145 includes one ormore sealing members 2235 for fluidicly sealing the interface between thelower sealing head 1930 and theload mandrel 2145. The sealingmembers 2235 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2235 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - In an exemplary embodiment, the
lower sealing head 2135 includes athroat passage 2240 fluidicly coupled between thefluid passages 2175 and2180. Thethroat passage 2240 is preferably of reduced size and is adapted to receive and engage with aplug 2245, or other similar device. In this manner, thefluid passage 2175 is fluidicly isolated from the fluid passage2180. In this manner, thepressure chamber 2250 is pressurized. - The
outer sealing mandrel 2140 is coupled to theupper sealing head 2130 and the expansion cone2150. Theouter sealing mandrel 2140 is also movably coupled to the inner surface of thecasing 2155 and the outer surface of thelower sealing head 2135. In this manner, theupper sealing head 2130,outer sealing mandrel 2140, and the expansion cone2150 reciprocate in the axial direction. The radial clearance between the outer surface of theouter sealing mandrel 2140 and the inner surface of thecasing 2155 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer surface of theouter sealing mandrel 2140 and the inner surface of thecasing 2155 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 2130 during the expansion process. The radial clearance between the inner surface of theouter sealing mandrel 2140 and the outer surface of thelower sealing head 2135 may range, for example, from about 0.005 to 0.125 inches. In an exemplary embodiment, the radial clearance between the inner surface of theouter sealing mandrel 2140 and the outer surface of thelower sealing head 2135 ranges from about 0.005 to 0.010 inches in order to optimally provide minimal radial clearance. - The
outer sealing mandrel 2140 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theouter sealing mandrel 2140 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength materials. In an exemplary embodiment, theouter sealing mandrel 2140 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
outer sealing mandrel 2140 may be coupled to theupper sealing head 2130 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, theouter sealing mandrel 2140 is removably coupled to theupper sealing head 2130 by a standard threaded connection. Theouter sealing mandrel 2140 may be coupled to the expansion cone2150 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theouter sealing mandrel 2140 is removably coupled to the expansion cone2150 by a standard threaded connection. - The
upper sealing head 2130, thelower sealing head 2135,inner sealing mandrel 2120, and theouter sealing mandrel 2140 together define apressure chamber 2250. Thepressure chamber 2250 is fluidicly coupled to thepassage 2175 via one ormore passages 2255. During operation of the apparatus2100, theplug 2245 engages with thethroat passage 2240 to fluidicly isolate thefluid passage 2175 from the fluid passage2180. Thepressure chamber 2250 is then pressurized which in turn causes theupper sealing head 2130,outer sealing mandrel 2140, and expansion cone2150 to reciprocate in the axial direction. The axial motion of the expansion cone2150 in turn expands thecasing 2155 in the radial direction. - The
load mandrel 2145 is coupled to thelower sealing head 2135. Theload mandrel 2145 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theload mandrel 2145 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theload mandrel 2145 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction bearing surfaces. - The
load mandrel 2145 may be coupled to thelower sealing head 2135 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, theload mandrel 2145 is removably coupled to thelower sealing head 2135 by a standard threaded connection in order to optimally provide high strength and permit easy replacement of theload mandrel 2145. - The
load mandrel 2145 preferably includes a fluid passage2180 that is adapted to convey fluidic materials from the fluid passage2180 to the region outside of the apparatus2100. In an exemplary embodiment, the fluid passage2180 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The expansion cone2150 is coupled to the
outer sealing mandrel 2140. The expansion cone2150 is also movably coupled to the inner surface of thecasing 2155. In this manner, theupper sealing head 2130,outer sealing mandrel 2140, and the expansion cone2150 reciprocate in the axial direction. The reciprocation of the expansion cone2150 causes thecasing 2155 to expand in the radial direction. - The expansion cone2150 preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces. The outside radius of the outside conical surface may range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 inches in order to optimally provide cone dimensions that are optimal for typical casings. The axial length of the expansion cone2150 may range, for example, from about 2 to 6 times the largest outside diameter of the expansion cone2150. In an exemplary embodiment, the axial length of the expansion cone2150 ranges from about 3 to 5 times the largest outside diameter of the expansion cone2150 in order to optimally provide stability and centralization of the expansion cone2150 during the expansion process. In an exemplary embodiment, the maximum outside diameter of the expansion cone2150 is between about 90 to 100% of the inside diameter of the existing wellbore that the
casing 2155 will be joined with. In an exemplary embodiment, the angle of attack of the expansion cone2150 ranges from about 5 to 30 degrees in order to optimally balance friction forces and radial expansion forces. The optimal expansion cone2150 angle of attack will vary as a function of the particular operating conditions of the expansion operation. - The expansion cone2150 may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramics, or other similar high strength materials. In an exemplary embodiment, the expansion cone2150 is fabricated from D2 machine tool steel in order to optimally provide high strength and resistance to wear and galling. In an exemplary embodiment, the outside surface of the expansion cone2150 has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide resistance to wear.
- The expansion cone2150 may be coupled to the
outside sealing mandrel 2140 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, the expansion cone2150 is coupled to theoutside sealing mandrel 2140 using a standard threaded connection in order to optimally provide high strength and permit the expansion cone2150 to be easily replaced. - The
casing 2155 is removably coupled to theslips 2125 and expansion cone2150. Thecasing 2155 preferably comprises a tubular member. Thecasing 2155 may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength material. In an exemplary embodiment, thecasing 2155 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength. - In an exemplary embodiment, the
upper end 2260 of thecasing 2155 includes athin wall section 2265 and an outerannular sealing member 2270. In an exemplary embodiment, the wall thickness of thethin wall section 2265 is about 50 to 100% of the regular wall thickness of thecasing 2155. In this manner, theupper end 2260 of thecasing 2155 may be easily expanded and deformed into intimate contact with the lower end of an existing section of wellbore casing. In an exemplary embodiment, the lower end of the existing section of casing also includes a thin wall section. In this manner, the radial expansion of the thinwalled section 2265 ofcasing 2155 into the thin walled section of the existing wellbore casing results in a wellbore casing having a substantially constant inside diameter. - The
annular sealing member 2270 may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal or plastic. In an exemplary embodiment, theannular sealing member 2270 is fabricated from StrataLock epoxy in order to optimally provide compressibility and resistance to wear. The outside diameter of theannular sealing member 2270 preferably ranges from about 70 to 95% of the inside diameter of the lower section of the wellbore casing that thecasing 2155 is pined to. In this manner, after expansion, theannular sealing member 2270 preferably provides a fluidic seal and also preferably provides sufficient frictional force with the inside surface of the existing section of wellbore casing during the radial expansion of thecasing 2155 to support thecasing 2155. - In an exemplary embodiment, the
lower end 2275 of thecasing 2155 includes a thin wall section2280 and an outer annular sealing member2285. In an exemplary embodiment, the wall thickness of the thin wall section2280 is about 50 to 100% of the regular wall thickness of thecasing 2155. In this manner, thelower end 2275 of thecasing 2155 may be easily expanded and deformed. Furthermore, in this manner, an other section of casing may be easily joined with thelower end 2275 of thecasing 2155 using a radial expansion process. In an exemplary embodiment, the upper end of the other section of casing also includes a thin wall section. In this manner, the radial expansion of the thin walled section of the upper end of the other casing into the thin walled section2280 of the lower end of thecasing 2155 results in a wellbore casing having a substantially constant inside diameter. - The annular sealing member2285 may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal or plastic. In an exemplary embodiment, the annular sealing member2285 is fabricated from StrataLock epoxy in order to optimally provide compressibility and wear resistance. The outside diameter of the annular sealing member2285 preferably ranges from about 70 to 95% of the inside diameter of the lower section of the existing wellbore casing that the
casing 2155 is joined to. In this manner, the annular sealing member2285 preferably provides a fluidic seal and also preferably provides sufficient frictional force with the inside wall of the wellbore during the radial expansion of thecasing 2155 to support thecasing 2155. - During operation, the apparatus2100 is preferably positioned in a wellbore with the
upper end 2260 of thecasing 2155 positioned in an overlapping relationship with the lower end of an existing wellbore casing. In an exemplary embodiment, thethin wall section 2265 of thecasing 2155 is positioned in opposing overlapping relation with the thin wall section and outer annular sealing member of the lower end of the existing section of wellbore casing. In this manner, the radial expansion of thecasing 2155 will compress the thin wall sections and annular compressible members of theupper end 2260 of thecasing 2155 and the lower end of the existing wellbore casing into intimate contact. During the positioning of the apparatus2100 in the wellbore, thecasing 2155 is supported by the expansion cone2150. - After positioning of the apparatus2100, a first fluidic material is then pumped into the
fluid passage 2160. The first fluidic material may comprise any number of conventional commercially available materials such as, for example, drilling mud, water, epoxy, or cement. In an exemplary embodiment, the first fluidic material comprises a hardenable fluidic sealing material such as, for example, cement or epoxy in order to provide a hardenable outer annular body around the expandedcasing 2155. - The first fluidic material may be pumped into the
fluid passage 2160 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 3,000 gallons/minute. In an exemplary embodiment, the first fluidic material is pumped into thefluid passage 2160 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency. - The first fluidic material pumped into the
fluid passage 2160 passes through thefluid passages - The
plug 2245 is then introduced into thefluid passage 2160. Theplug 2245 lodges in thethroat passage 2240 and fluidicly isolates and blocks off thefluid passage 2175. In an exemplary embodiment, a couple of volumes of a non-hardenable fluidic material are then pumped into thefluid passage 2160 in order to remove any hardenable fluidic material contained within and to ensure that none of the fluid passages are blocked. - A second fluidic material is then pumped into the
fluid passage 2160. The second fluidic material may comprise any number of conventional commercially available materials such as, for example, drilling mud, water, drilling gases, or lubricants. In an exemplary embodiment, the second fluidic material comprises a non-hardenable fluidic material such as, for example, water, drilling mud or lubricant in order to optimally provide pressurization of thepressure chamber 2250 and minimize frictional forces. - The second fluidic material may be pumped into the
fluid passage 2160 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute. In an exemplary embodiment, the second fluidic material is pumped into thefluid passage 2160 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency. - The second fluidic material pumped into the
fluid passage 2160 passes through thefluid passages pressure chambers 2195 of theslips 2125, and into thepressure chamber 2250. Continued pumping of the second fluidic material pressurizes thepressure chambers - The pressurization of the
pressure chambers 2195 causes theslip members 2205 to expand in the radial direction and grip the interior surface of thecasing 2155. Thecasing 2155 is then preferably maintained in a substantially stationary position. - The pressurization of the
pressure chamber 2250 causes theupper sealing head 2130,outer sealing mandrel 2140 and expansion cone2150 to move in an axial direction relative to thecasing 2155. In this manner, the expansion cone2150 will cause thecasing 2155 to expand in the radial direction. - During the radial expansion process, the
casing 2155 is prevented from moving in an upward direction by theslips 2125. A length of thecasing 2155 is then expanded in the radial direction through the pressurization of thepressure chamber 2250. The length of thecasing 2155 that is expanded during the expansion process will be proportional to the stroke length of theupper sealing head 2130,outer sealing mandrel 2140, and expansion cone2150. - Upon the completion of a stroke, the operating pressure of the second fluidic material is reduced and the
upper sealing head 2130,outer sealing mandrel 2140, and expansion cone2150 drop to their rest positions with thecasing 2155 supported by the expansion cone2150. The position of thedrillpipe 2105 is preferably adjusted throughout the radial expansion process in order to maintain the overlapping relationship between the thin walled sections of the lower end of the existing wellbore casing and the upper end of thecasing 2155. In an exemplary embodiment, the stroking of the expansion cone2150 is then repeated, as necessary, until the thinwalled section 2265 of theupper end 2260 of thecasing 2155 is expanded into the thin walled section of the lower end of the existing wellbore casing. In this manner, a wellbore casing is formed including two adjacent sections of casing having a substantially constant inside diameter. This process may then be repeated for the entirety of the wellbore to provide a wellbore casing thousands of feet in length having a substantially constant inside diameter. - In an exemplary embodiment, during the final stroke of the expansion cone2150, the
slips 2125 are positioned as close as possible to the thinwalled section 2265 of the upper end of thecasing 2155 in order minimize slippage between thecasing 2155 and the existing wellbore casing at the end of the radial expansion process. Alternatively, or in addition, the outside diameter of theannular sealing member 2270 is selected to ensure sufficient interference fit with the inside diameter of the lower end of the existing casing to prevent axial displacement of thecasing 2155 during the final stroke. Alternatively, or in addition, the outside diameter of the annular sealing member2285 is selected to provide an interference fit with the inside walls of the wellbore at an earlier point in the radial expansion process so as to prevent further axial displacement of thecasing 2155. In this final alternative, the interference fit is preferably selected to permit expansion of thecasing 2155 by pulling the expansion cone2150 out of the wellbore, without having to pressurize thepressure chamber 2250. - During the radial expansion process, the pressurized areas of the apparatus2100 are limited to the
fluid passages pressure chambers 2195 within theslips 2125, and thepressure chamber 2250. No fluid pressure acts directly on thecasing 2155. This permits the use of operating pressures higher than thecasing 2155 could normally withstand. - Once the
casing 2155 has been completely expanded off of the expansion cone2150, remaining portions of the apparatus2100 are removed from the wellbore. In an exemplary embodiment, the contact pressure between the deformed thin wall sections and compressible annular members of the lower end of the existing casing and theupper end 2260 of thecasing 2155 ranges from about 500 to 40,000 psi in order to optimally support thecasing 2155 using the existing wellbore casing. - In this manner, the
casing 2155 is radially expanded into contact with an existing section of casing by pressurizing theinterior fluid passages pressure chamber 2250 of the apparatus2100. - In an exemplary embodiment, as required, the annular body of hardenable fluidic material is then allowed to cure to form a rigid outer annular body about the expanded
casing 2155. In the case where thecasing 2155 is slotted, the cured fluidic material preferably permeates and envelops the expandedcasing 2155. The resulting new section of wellbore casing includes the expandedcasing 2155 and the rigid outer annular body. The overlapping joint between the pre-existing wellbore casing and the expandedcasing 2155 includes the deformed thin wall sections and the compressible outer annular bodies. The inner diameter of the resulting combined wellbore casings is substantially constant. In this manner, a mono-diameter wellbore casing is formed. This process of expanding overlapping tubular members having thin wall end portions with compressible annular bodies into contact can be repeated for the entire length of a wellbore. In this manner, a mono-diameter wellbore casing can be provided for thousands of feet in a subterranean formation. - In an exemplary embodiment, as the expansion cone2150 nears the upper end of the
casing 2155, the operating flow rate of the second fluidic material is reduced in order to minimize shock to the apparatus2100. In an alternative embodiment, the apparatus2100 includes a shock absorber for absorbing the shock created by the completion of the radial expansion of thecasing 2155. - In an exemplary embodiment, the reduced operating pressure of the second fluidic material ranges from about 100 to 1,000 psi as the
expansion cone 2130 nears the end of thecasing 2155 in order to optimally provide reduced axial movement and velocity of theexpansion cone 2130. In an exemplary embodiment, the operating pressure of the second fluidic material is reduced during the return stroke of the apparatus2100 to the range of about 0 to 500 psi in order minimize the resistance to the movement of theexpansion cone 2130 during the return stroke. In an exemplary embodiment, the stroke length of the apparatus2100 ranges from about 10 to 45 feet in order to optimally provide equipment lengths that can be handled by conventional oil well rigging equipment while also minimizing the frequency at which theexpansion cone 2130 must be stopped so that the apparatus2100 can be re-stroked. - In an alternative embodiment, at least a portion of the
upper sealing head 2130 includes an expansion cone for radially expanding thecasing 2155 during operation of the apparatus2100 in order to increase the surface area of thecasing 2155 acted upon during the radial expansion process. In this manner, the operating pressures can be reduced. - Alternatively, the apparatus2100 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, the apparatus2100 may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material. Alternatively, the apparatus2100 may be used to expand a tubular support member in a hole.
- Referring now to
FIGS. 17 ,17aand17b,another embodiment of anapparatus 2300 for expanding a tubular member will be described. Theapparatus 2300 preferably includes adrillpipe 2305, aninnerstring adapter 2310, a sealingsleeve 2315, ahydraulic slip body 2320,hydraulic slips 2325, aninner sealing mandrel 2330, anupper sealing head 2335, alower sealing head 2340, aload mandrel 2345, anouter sealing mandrel 2350, anexpansion cone 2355, amechanical slip body 2360,mechanical slips 2365, drag blocks2370,casing 2375,fluid passages mandrel launcher 2480. - The
drillpipe 2305 is coupled to theinnerstring adapter 2310. During operation of theapparatus 2300, thedrillpipe 2305 supports theapparatus 2300. Thedrillpipe 2305 preferably comprises a substantially hollow tubular member or members. Thedrillpipe 2305 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thedrillpipe 2305 is fabricated from coiled tubing in order to facilitate the placement of theapparatus 2300 in non-vertical wellbores. Thedrillpipe 2305 may be coupled to theinnerstring adapter 2310 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, thedrillpipe 2305 is removably coupled to theinnerstring adapter 2310 by a drillpipe connection. - The
drillpipe 2305 preferably includes afluid passage 2380 that is adapted to convey fluidic materials from a surface location into thefluid passage 2385. In an exemplary embodiment, thefluid passage 2380 is adapted to convey fluidic materials such as, for example, cement water, epoxy, drilling muds, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 5,000 gallons/minute in order to optimally provide operational efficiency. - The
innerstring adapter 2310 is coupled to thedrill string 2305 and thesealing sleeve 2315. Theinnerstring adapter 2310 preferably comprises a substantially hollow tubular member or members. Theinnerstring adapter 2310 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theinnerstring adapter 2310 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
innerstring adapter 2310 may be coupled to thedrill string 2305 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 2310 is removably coupled to thedrill pipe 2305 by a drillpipe connection. Theinnerstring adapter 2310 may be coupled to thesealing sleeve 2315 using any number of conventional commercially available mechanical couplings such as, for example, a drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 2310 is removably coupled to thesealing sleeve 2315 by a standard threaded connection. - The
innerstring adapter 2310 preferably includes afluid passage 2385 that is adapted to convey fluidic materials from thefluid passage 2380 into thefluid passage 2390. In an exemplary embodiment, thefluid passage 2385 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, drilling gases or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The sealing
sleeve 2315 is coupled to theinnerstring adapter 2310 and thehydraulic slip body 2320. The sealingsleeve 2315 preferably comprises a substantially hollow tubular member or members. The sealingsleeve 2315 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the sealingsleeve 2315 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low-friction surfaces. - The sealing
sleeve 2315 may be coupled to theinnerstring adapter 2310 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connections, oilfield country tubular goods specialty threaded connections, or a standard threaded connection, in an exemplary embodiment, the sealingsleeve 2315 is removably coupled to theinnerstring adapter 2310 by a standard threaded connection. The sealingsleeve 2315 may be coupled to thehydraulic slip body 2320 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 2315 is removably coupled to thehydraulic slip body 2320 by a standard threaded connection. - The sealing
sleeve 2315 preferably includes afluid passage 2390 that is adapted to convey fluidic materials from thefluid passage 2385 into thefluid passage 2395. In an exemplary embodiment, thefluid passage 2315 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
hydraulic slip body 2320 is coupled to thesealing sleeve 2315, thehydraulic slips 2325, and theinner sealing mandrel 2330. Thehydraulic slip body 2320 preferably comprises a substantially hollow tubular member or members. Thehydraulic slip body 2320 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other high strength material. In an exemplary embodiment, thehydraulic slip body 2320 is fabricated from carbon steel in order to optimally provide high strength at low cost. - The
hydraulic slip body 2320 may be coupled to thesealing sleeve 2315 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, thehydraulic slip body 2320 is removably coupled to thesealing sleeve 2315 by a standard threaded connection. Thehydraulic slip body 2320 may be coupled to theslips 2325 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, thehydraulic slip body 2320 is removably coupled to theslips 2325 by a standard threaded connection. Thehydraulic slip body 2320 may be coupled to theinner sealing mandrel 2330 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, thehydraulic slip body 2320 is removably coupled to theinner sealing mandrel 2330 by a standard threaded connection. - The
hydraulic slips body 2320 preferably includes afluid passage 2395 that is adapted to convey fluidic materials from thefluid passage 2390 into thefluid passage 2405. In an exemplary embodiment, thefluid passage 2395 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
hydraulic slips body 2320 preferably includesfluid passage 2400 that are adapted to convey fluidic materials from thefluid passage 2395 into thepressure chambers 2420 of thehydraulic slips 2325. In this manner, theslips 2325 are activated upon the pressurization of thefluid passage 2395 into contact with the inside surface of thecasing 2375. In an exemplary embodiment, thefluid passages 2400 are adapted to convey fluidic materials such as, for example, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
slips 2325 are coupled to the outside surface of thehydraulic slip body 2320. During operation of theapparatus 2300, theslips 2325 are activated upon the pressurization of thefluid passage 2395 into contact with the inside surface of thecasing 2375. In this manner, theslips 2325 maintain thecasing 2375 in a substantially stationary position. - The
slips 2325 preferably include thefluid passages 2400, thepressure chambers 2420,spring bias 2425, andslip members 2430. Theslips 2325 may comprise any number of conventional commercially available hydraulic slips such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L retrievable bridge plug with hydraulic slips. In an exemplary embodiment, theslips 2325 comprise RTTS packer tungsten carbide hydraulic slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of thecasing 2375 during the radial expansion process. - The
inner sealing mandrel 2330 is coupled to thehydraulic slip body 2320 and thelower sealing head 2340. Theinner sealing mandrel 2330 preferably comprises a substantially hollow tubular member or members. Theinner sealing mandrel 2330 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theinner sealing mandrel 2330 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
inner sealing mandrel 2330 may be coupled to thehydraulic slip body 2320 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theinner sealing mandrel 2330 is removably coupled to thehydraulic slip body 2320 by a standard threaded connection. Theinner sealing mandrel 2330 may be coupled to thelower sealing head 2340 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theinner sealing mandrel 2330 is removably coupled to thelower sealing head 2340 by a standard threaded connection. - The
inner sealing mandrel 2330 preferably includes afluid passage 2405 that is adapted to convey fluidic materials from thefluid passage 2395 into thefluid passage 2415. In an exemplary embodiment, thefluid passage 2405 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
upper sealing head 2335 is coupled to theouter sealing mandrel 2345 andexpansion cone 2355. Theupper sealing head 2335 is also movably coupled to the outer surface of theinner sealing mandrel 2330 and the inner surface of thecasing 2375. In this manner, theupper sealing head 2335 reciprocates in the axial direction. The radial clearance between the inner cylindrical surface of theupper sealing head 2335 and the outer surface of theinner sealing mandrel 2330 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of theupper sealing head 2335 and the outer surface of theinner sealing mandrel 2330 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal clearance. The radial clearance between the outer cylindrical surface of theupper sealing head 2335 and the inner surface of thecasing 2375 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of theupper sealing head 2335 and the inner surface of thecasing 2375 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 2355 during the expansion process. - The
upper sealing head 2335 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theupper sealing head 2335 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theupper sealing head 2335 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The inner surface of theupper sealing head 2335 preferably includes one or moreannular sealing members 2435 for sealing the interface between theupper sealing head 2335 and theinner sealing mandrel 2330. The sealingmembers 2435 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2435 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - In an exemplary embodiment, the
upper sealing head 2335 includes ashoulder 2440 for supporting the upper sealing head on thelower sealing head 1930. - The
upper sealing head 2335 may be coupled to theouter sealing mandrel 2350 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theupper sealing head 2335 is removably coupled to theouter sealing mandrel 2350 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between theupper sealing head 2335 and theouter sealing mandrel 2350 includes one ormore sealing members 2445 for fluidicly sealing the interface between theupper sealing head 2335 and theouter sealing mandrel 2350. The sealingmembers 2445 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2445 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - The
lower sealing head 2340 is coupled to theinner sealing mandrel 2330 and theload mandrel 2345. Thelower sealing head 2340 is also movably coupled to the inner surface of theouter sealing mandrel 2350. In this manner, theupper sealing head 2335 andouter sealing mandrel 2350 reciprocate in the axial direction. The radial clearance between the outer surface of thelower sealing head 2340 and the inner surface of theouter sealing mandrel 2350 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the outer surface of thelower sealing head 2340 and the inner surface of theouter sealing mandrel 2350 ranges from about 0.005 to 0.010 inches in order to optimally provide minimal radial clearance. - The
lower sealing head 2340 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Thelower sealing head 2340 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubular members, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thelower sealing head 2340 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The outer surface of thelower sealing head 2340 preferably includes one or moreannular sealing members 2450 for sealing the interface between thelower sealing head 2340 and theouter sealing mandrel 2350. The sealingmembers 2450 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2450 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The
lower sealing head 2340 may be coupled to theinner sealing mandrel 2330 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular specialty threaded connection, welding, amorphous bonding, or standard threaded connection. In an exemplary embodiment, thelower sealing head 2340 is removably coupled to theinner sealing mandrel 2330 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between thelower sealing head 2340 and theinner sealing mandrel 2330 includes one or more-sealingmembers 2455 for fluidicly sealing the interface between thelower sealing head 2340 and theinner sealing mandrel 2330. The sealingmembers 2455 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak or metal spring energized seals. In an exemplary embodiment the sealingmembers 2455 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke length. - The
lower sealing head 2340 may be coupled to theload mandrel 2345 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, thelower sealing head 2340 is removably coupled to theload mandrel 2345 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between thelower sealing head 2340 and theload mandrel 2345 includes one ormore sealing members 2460 for fluidicly sealing the interface between thelower sealing head 2340 and theload mandrel 2345. The sealingmembers 2460 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2460 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke length. - In an exemplary embodiment, the
lower sealing head 2340 includes athroat passage 2465 fluidicly coupled between thefluid passages throat passage 2465 is preferably of reduced size and is adapted to receive and engage with aplug 2470, or other similar device. In this manner, thefluid passage 2405 is fluidicly isolated from thefluid passage 2415. In this manner, thepressure chamber 2475 is pressurized. - The
outer sealing mandrel 2350 is coupled to theupper sealing head 2335 and theexpansion cone 2355. Theouter sealing mandrel 2350 is also movably coupled to the inner surface of thecasing 2375 and the outer surface of thelower sealing head 2340. In this manner, theupper sealing head 2335,outer sealing mandrel 2350, and theexpansion cone 2355 reciprocate in the axial direction. The radial clearance between the outer surface of theouter sealing mandrel 2350 and the inner surface of thecasing 2375 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer surface of theouter sealing mandrel 2350 and the inner surface of thecasing 2375 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 2355 during the expansion process. The radial clearance between the inner surface of theouter sealing mandrel 2350 and the outer surface of thelower sealing head 2340 may range, for example, from about 0.0025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the inner surface of theouter sealing mandrel 2350 and the outer surface of thelower sealing head 2340 ranges from about 0.005 to 0.010 inches in order to optimally provide minimal clearance. - The
outer sealing mandrel 2350 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theouter sealing mandrel 2350 may be fabricated from any number of conventional commercially available materials such as, for example, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theouter sealing mandrel 2350 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
outer sealing mandrel 2350 may be coupled to theupper sealing head 2335 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connections, oilfield country tubular goods specialty threaded connections, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theouter sealing mandrel 2350 is removably coupled to theupper sealing head 2335 by a standard threaded connection. Theouter sealing mandrel 2350 may be coupled to theexpansion cone 2355 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theouter sealing mandrel 2350 is removably coupled to theexpansion cone 2355 by a standard threaded connection. - The
upper sealing head 2335, thelower sealing head 2340, theinner sealing mandrel 2330, and theouter sealing mandrel 2350 together define apressure chamber 2475. Thepressure chamber 2475 is fluidicly coupled to thepassage 2405 via one ormore passages 2410. During operation of theapparatus 2300, theplug 2470 engages with thethroat passage 2465 to fluidicly isolate thefluid passage 2415 from thefluid passage 2405. Thepressure chamber 2475 is then pressurized which in turn causes theupper sealing head 2335,outer sealing mandrel 2350, andexpansion cone 2355 to reciprocate in the axial direction. The axial motion of theexpansion cone 2355 in turn expands thecasing 2375 in the radial direction. - The
load mandrel 2345 is coupled to thelower sealing head 2340 and themechanical slip body 2360. Theload mandrel 2345 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theload mandrel 2345 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theload mandrel 2345 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
load mandrel 2345 may be coupled to thelower sealing head 2340 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, theload mandrel 2345 is removably coupled to thelower sealing head 2340 by a standard threaded connection. Theload mandrel 2345 may be coupled to themechanical slip body 2360 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theload mandrel 2345 is removably coupled to themechanical slip body 2360 by a standard threaded connection. - The
load mandrel 2345 preferably includes afluid passage 2415 that is adapted to convey fluidic materials from thefluid passage 2405 to the region outside of theapparatus 2300. In an exemplary embodiment, thefluid passage 2415 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
expansion cone 2355 is coupled to theouter sealing mandrel 2350. Theexpansion cone 2355 is also movably coupled to the inner surface of thecasing 2375. In this manner, theupper sealing head 2335,outer sealing mandrel 2350, and theexpansion cone 2355 reciprocate in the axial direction. The reciprocation of theexpansion cone 2355 causes thecasing 2375 to expand in the radial direction. - The
expansion cone 2355 preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces. The outside radius of the outside conical surface may range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 inches in order to optimally provide radial expansion of the typical casings. The axial length of theexpansion cone 2355 may range, for example, from about 2 to 8 times the largest outside diameter of theexpansion cone 2355. In an exemplary embodiment, the axial length of theexpansion cone 2355 ranges from about 3 to 5 times the largest outside diameter of theexpansion cone 2355 in order to optimally provide stability and centralization of theexpansion cone 2355 during the expansion process. In an exemplary embodiment, the angle of attack of theexpansion cone 2355 ranges from about 5 to 30 degrees in order to optimally fractional forces with radial expansion forces. The optimum angle of attack of theexpansion cone 2355 will vary as a function of the operating parameters of the particular expansion operation. - The
expansion cone 2355 may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramics or other similar high strength materials. In an exemplary embodiment, theexpansion cone 2355 is fabricated from D2 machine tool steel in order to optimally provide high strength, abrasion resistance, and galling resistance. In an exemplary embodiment, the outside surface of theexpansion cone 2355 has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide high strength, abrasion resistance, resistance to galling. - The
expansion cone 2355 may be coupled to theoutside sealing mandrel 2350 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection, in an exemplary embodiment, theexpansion cone 2355 is coupled to theoutside sealing mandrel 2350 using a standard threaded connection in order to optimally provide high strength and permit theexpansion cone 2355 to be easily replaced. - The
mandrel launcher 2480 is coupled to thecasing 2375. Themandrel launcher 2480 comprises a tubular section of casing having a reduced wall thickness compared to thecasing 2375. In an exemplary embodiment, the wall thickness of themandrel launcher 2480 is about 50 to 100% of the wall thickness of thecasing 2375. In this manner, the initiation of the radial expansion of thecasing 2375 is facilitated, and the placement of theapparatus 2300 into a wellbore casing and wellbore is facilitated. - The
mandrel launcher 2480 may be coupled to thecasing 2375 using any number of conventional mechanical couplings. Themandrel launcher 2480 may have a wall thickness ranging, for example, from about 0.15 to 1.5 inches. In an exemplary embodiment, the wall thickness of themandrel launcher 2480 ranges from about 0.25 to 0.75 inches in order to optimally provide high strength in a minimal profile. Themandrel launcher 2480 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, themandrel launcher 2480 is fabricated from oilfield tubular goods having a higher strength than that of thecasing 2375 but with a smaller wall thickness than thecasing 2375 in order to optimally provide a thin walled container having approximately the same burst strength as that of thecasing 2375. - The
mechanical slip body 2460 is coupled to theload mandrel 2345, themechanical slips 2365, and the drag blocks2370. Themechanical slip body 2460 preferably comprises a tubular member having aninner passage 2485 fluidicly coupled to thepassage 2415. In this manner, fluidic materials may be conveyed from the passage2484 to a region outside of theapparatus 2300. - The
mechanical slip body 2360 may be coupled to theload mandrel 2345 using any number of conventional mechanical couplings. In an exemplary embodiment, themechanical slip body 2360 is removably coupled to theload mandrel 2345 using threads and sliding steel retaining rings in order to optimally provide a high strength attachment. Themechanical slip body 2360 may be coupled to themechanical slips 2365 using any number of conventional mechanical couplings. In an exemplary embodiment, themechanical slip body 2360 is removably coupled to themechanical slips 2365 using threads and sliding steel retaining rings in order to optimally provide a high strength attachment. Themechanical slip body 2360 may be coupled to the drag blocks2370 using any number of conventional mechanical couplings. In an exemplary embodiment, themechanical slip body 2360 is removably coupled to the drag blocks2365 using threads and sliding steel retaining rings in order to optimally provide a high strength attachment. - The
mechanical slips 2365 are coupled to the outside surface of themechanical slip body 2360. During operation of theapparatus 2300, themechanical slips 2365 prevent upward movement of thecasing 2375 andmandrel launcher 2480. In this manner, during the axial reciprocation of theexpansion cone 2355, thecasing 2375 andmandrel launcher 2480 are maintained in a substantially stationary position. In this manner, themandrel launcher 2480 andcasing 2375 are expanded in the radial direction by the axial movement of theexpansion cone 2355. - The
mechanical slips 2365 may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In an exemplary embodiment, themechanical slips 2365 comprise RTTS packer tungsten carbide mechanical slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of thecasing 2375 during the expansion process. - The drag blocks2370 are coupled to the outside surface of the
mechanical slip body 2360. During operation of theapparatus 2300, the drag blocks2370 prevent upward movement of thecasing 2375 andmandrel launcher 2480. In this manner, during the axial reciprocation of theexpansion cone 2355, thecasing 2375 andmandrel launcher 2480 are maintained in a substantially stationary position. In this manner, themandrel launcher 2480 andcasing 2375 are expanded in the radial direction by the axial movement of theexpansion cone 2355. - The drag blocks2370 may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer mechanical drag blocks or Model 3L retrievable bridge plug drag blocks. In an exemplary embodiment, the drag blocks2370 comprise RTTS packer mechanical drag blocks available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the
casing 2375 during the expansion process. - The
casing 2375 is coupled to themandrel launcher 2480. Thecasing 2375 is further removably coupled to themechanical slips 2365 and drag blocks2370. Thecasing 2375 preferably comprises a tubular member. Thecasing 2375 may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oil country tubular goods, carbon steel, low alloy steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thecasing 2375 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength. In an exemplary embodiment, the upper end of thecasing 2375 includes one or more sealing members positioned about the exterior of thecasing 2375. - During operation, the
apparatus 2300 is positioned in a wellbore with the upper end of thecasing 2375 positioned in an overlapping relationship within an existing wellbore casing. In order minimize surge pressures within the borehole during placement of theapparatus 2300, thefluid passage 2380 is preferably provided with one or more pressure relief passages. During the placement of theapparatus 2300 in the wellbore, thecasing 2375 is supported by theexpansion cone 2355. - After positioning of the
apparatus 2300 within the bore hole in an overlapping relationship with an existing section of wellbore casing, a first fluidic material is pumped into thefluid passage 2380 from a surface location. The first fluidic material is conveyed from thefluid passage 2380 to thefluid passages apparatus 2300 and fill the annular region between the outside of theapparatus 2300 and the interior walls of the bore hole. - The first fluidic material may comprise any number of conventional commercially available materials such as, for example, epoxy, drilling mud, slag mix, cement, or water. In an exemplary embodiment the first fluidic material comprises a hardenable fluidic sealing material such as, for example, slag mix, epoxy, or cement. In this manner, a wellbore casing having an outer annular layer of a hardenable material may be formed.
- The first fluidic material may be pumped into the
apparatus 2300 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi, and 0 to 3,000 gallons/minute. In an exemplary embodiment, the first fluidic material is pumped into theapparatus 2300 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency. - At a predetermined point in the injection of the first fluidic material such as, for example, after the annular region outside of the
apparatus 2300 has been filled to a predetermined level, aplug 2470, dart, or other similar device is introduced into the first fluidic material. Theplug 2470 lodges in thethroat passage 2465 thereby fluidicly isolating thefluid passage 2405 from thefluid passage 2415. - After placement of the
plug 2470 in thethroat passage 2465, a second fluidic material is pumped into thefluid passage 2380 in order to pressurize thepressure chamber 2475. The second fluidic material may comprise any number of conventional commercially available materials such as, for example, water, drilling gases, drilling mud or lubricants. In an exemplary embodiment, the second fluidic material comprises a non-hardenable fluidic material such as, for example, water, drilling mud or lubricant. - The second fluidic material may be pumped into the
apparatus 2300 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute. In an exemplary embodiment, the second fluidic material is pumped into theapparatus 2300 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency. - The pressurization of the
pressure chamber 2475 causes theupper sealing head 2335, outer sealing,mandrel 2350, andexpansion cone 2355 to move in an axial direction. The pressurization of thepressure chamber 2475 also causes thehydraulic slips 2325 to expand in the radial direction and hold thecasing 2375 in a substantially stationary position. Furthermore, as theexpansion cone 2355 moves in the axial direction, theexpansion cone 2355 pulls themandrel launcher 2480 anddrag blocks 2370 along, which sets themechanical slips 2365 and stops further axial movement of themandrel launcher 2480 andcasing 2375. In this manner, the axial movement of theexpansion cone 2355 radially expands themandrel launcher 2480 andcasing 2375. - Once the
upper sealing head 2335,outer sealing mandrel 2350, andexpansion cone 2355 complete an axial stroke, the operating pressure of the second fluidic material is reduced. The reduction in the operating pressure of the second fluidic material releases thehydraulic slips 2325. Thedrill string 2305 is then raised. This causes theinner sealing mandrel 2330,lower sealing head 2340,load mandrel 2345, andmechanical slip body 2360 to move upward. This unsets themechanical slips 2365 and permits themechanical slips 2365 anddrag blocks 2370 to be moved within themandrel launcher 2480 andcasing 2375. When thelower sealing head 2340 contacts theupper sealing head 2335, the second fluidic material is again pressurized and the radial expansion process continues. In this manner, themandrel launcher 2480 andcasing 2375 are radial expanded through repeated axial strokes of theupper sealing head 2335,outer sealing mandrel 2350 andexpansion cone 2355. Throughput the radial expansion process, the upper end of thecasing 2375 is preferably maintained in an overlapping relation with an existing section of wellbore casing. - At the end of the radial expansion process, the upper end of the
casing 2375 is expanded into intimate contact with the inside surface of the lower end of the existing wellbore casing. In an exemplary embodiment, the sealing members provided at the upper end of thecasing 2375 provide a fluidic seal between the outside surface of the upper end of thecasing 2375 and the inside surface of the lower end of the existing wellbore casing. In an exemplary embodiment, the contact pressure between thecasing 2375 and the existing section of wellbore casing ranges from about 400 to 10,000 psi in order to optimally provide contact pressure, activate the sealing members, and withstand typical tensile and compressive loading conditions. - In an exemplary embodiment, as the
expansion cone 2355 nears the upper end of thecasing 2375, the operating pressure of the second fluidic material is reduced in order to minimize shock to theapparatus 2300. In an alternative embodiment, theapparatus 2300 includes a shock absorber for absorbing the shock created by the completion of the radial expansion of thecasing 2375. - In an exemplary embodiment, the reduced operating pressure of the second fluidic material ranges from about 100 to 1,000 psi as the
expansion cone 2355 nears the end of thecasing 2375 in order to optimally provide reduced axial movement and velocity of theexpansion cone 2355. In an exemplary embodiment, the operating pressure of the second fluidic material is reduced during the return stroke of theapparatus 2300 to the range of about 0 to 500 psi in order minimize the resistance to the movement of theexpansion cone 2355 during the return stroke. In an exemplary embodiment, the stroke length of theapparatus 2300 ranges from about 10 to 45 feet in order to optimally provide equipment that can be handled by typical oil well rigging equipment and minimize the frequency at which theexpansion cone 2355 must be stopped to permit theapparatus 2300 to be re-stroked. - In an alternative embodiment, at least a portion of the
upper sealing head 2335 includes an expansion cone for radially expanding themandrel launcher 2480 andcasing 2375 during operation of theapparatus 2300 in order to increase the surface area of thecasing 2375 acted upon during the radial expansion process, in this manner, the operating pressures can be reduced. - In an alternative embodiment,
mechanical slips 2365 are positioned in an axial location between the sealingsleeve 2315 and theinner sealing mandrel 2330 in order to optimally the construction and operation of theapparatus 2300. - Upon the complete radial expansion of the
casing 2375, if applicable, the first fluidic material is permitted to cure within the annular region between the outside of the expandedcasing 2375 and the interior walls of the wellbore. In the case where thecasing 2375 is slotted, the cured fluidic material preferably permeates and envelops the expandedcasing 2375. In this manner, a new section of wellbore casing is formed within a wellbore. Alternatively, theapparatus 2300 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, theapparatus 2300 may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material. Alternatively, theapparatus 2300 may be used to expand a tubular support member in a hole. - During the radial expansion process, the pressurized areas of the
apparatus 2300 are limited to thefluid passages pressure chamber 2475. No fluid pressure acts directly on themandrel launcher 2480 andcasing 2375. This permits the use of operating pressures higher than themandrel launcher 2480 andcasing 2375 could normally withstand. - Referring now to
FIG. 18 , an exemplary embodiment of anapparatus 2500 for forming a mono-diameter wellbore casing will be described. Theapparatus 2500 preferably includes a drillpipe2505, aninnerstring adapter 2510, a sealingsleeve 2515, ahydraulic slip body 2520,hydraulic slips 2525, aninner sealing mandrel 2530,upper sealing head 2535,lower sealing head 2540,outer sealing mandrel 2545,load mandrel 2550,expansion cone 2555,casing 2550, andfluid passages - The drillpipe2505 is coupled to the
innerstring adapter 2510. During operation of theapparatus 2500, the drillpipe2505 supports theapparatus 2500. The drillpipe2505 preferably comprises a substantially hollow tubular member or members. The drillpipe2505 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the drillpipe2505 is fabricated from coiled tubing in order to facilitate the placement of theapparatus 2500 in non-vertical wellbores. The drillpipe2505 may be coupled to theinnerstring adapter 2510 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, the drillpipe2505 is removably coupled to theinnerstring adapter 2510 by a drillpipe connection, a drillpipe connection provides the advantages of high strength and easy disassembly. - The drillpipe2505 preferably includes a
fluid passage 2565 that is adapted to convey fluidic materials from a surface location into thefluid passage 2570. In an exemplary embodiment, thefluid passage 2565 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
innerstring adapter 2510 is coupled to the drill string2505 and thesealing sleeve 2515. Theinnerstring adapter 2510 preferably comprises a substantially hollow tubular member or members. Theinnerstring adapter 2510 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theinnerstring adapter 2510 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
innerstring adapter 2610 may be coupled to the drill string2505 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 2510 is removably coupled to the drill pipe2505 by a drillpipe connection. Theinnerstring adapter 2510 may be coupled to thesealing sleeve 2515 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 2510 is removably coupled to thesealing sleeve 2515 by a standard threaded connection. - The
innerstring adapter 2510 preferably includes afluid passage 2570 that is adapted to convey fluidic materials from thefluid passage 2565 into thefluid passage 2575. In an exemplary embodiment, thefluid passage 2570 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The sealing
sleeve 2515 is coupled to theinnerstring adapter 2510 and thehydraulic slip body 2520. The sealingsleeve 2515 preferably comprises a substantially hollow tubular member or members. The sealingsleeve 2515 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the sealingsleeve 2515 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low-friction surfaces. - The sealing
sleeve 2515 may be coupled to theinnerstring adapter 2510 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connections, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 2515 is removably coupled to theinnerstring adapter 2510 by a standard threaded connection. The sealingsleeve 2515 may be coupled to thehydraulic slip body 2520 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 2515 is removably coupled to thehydraulic slip body 2520 by a standard threaded connection. - The sealing
sleeve 2515 preferably includes afluid passage 2575 that is adapted to convey fluidic materials from thefluid passage 2570 into thefluid passage 2580. In an exemplary embodiment, thefluid passage 2575 is adapted to convey fluidic materials such as, for example, cement, epoxy, wafer, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
hydraulic slip body 2520 is coupled to thesealing sleeve 2515, thehydraulic slips 2525, and theinner sealing mandrel 2530. Thehydraulic slip body 2520 preferably comprises a substantially hollow tubular member or members. Thehydraulic slip body 2520 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thehydraulic slip body 2520 is fabricated from carbon steel in order to optimally provide high strength. - The
hydraulic slip body 2520 may be coupled to thesealing sleeve 2515 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, thehydraulic slip body 2520 is removably coupled to thesealing sleeve 2515 by a standard threaded, connection. Thehydraulic slip body 2520 may be coupled to theslips 2525 using any number of conventional commercially available mechanical couplings such as, for example, threaded connection or welding. In an exemplary embodiment, thehydraulic slip body 2520 is removably coupled to theslips 2525 by a threaded connection. Thehydraulic slip body 2520 may be coupled to theinner sealing mandrel 2530 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, thehydraulic slip body 2520 is removably coupled to theinner sealing mandrel 2530 by a standard threaded connection. - The
hydraulic slips body 2520 preferably includes afluid passage 2580 that is adapted to convey fluidic materials from thefluid passage 2575 into thefluid passage 2590. In an exemplary embodiment, thefluid passage 2580 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
hydraulic slips body 2520 preferably includesfluid passages 2585 that are adapted to convey fluidic materials from thefluid passage 2580 into the pressure chambers of thehydraulic slips 2525. In this manner, theslips 2525 are activated upon the pressurization of thefluid passage 2580 into contact with the inside surface of thecasing 2660. In an exemplary embodiment, thefluid passages 2585 are adapted to convey fluidic materials such as* for example, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
slips 2525 are coupled to the outside surface of thehydraulic slip body 2520. During operation of theapparatus 2500, theslips 2525 are activated upon the pressurization of thefluid passage 2580 into contact with the inside surface of thecasing 2560. In this manner, theslips 2525 maintain thecasing 2560 in a substantially stationary position. - The
slips 2525 preferably include thefluid passages 2585, thepressure chambers 2605,spring bias 2610, and slip members2615. Theslips 2525 may comprise any number of conventional commercially available hydraulic slips such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L retrievable bridge plug with hydraulic slips. In an exemplary embodiment, theslips 2525 comprise RTTS packer tungsten carbide hydraulic slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of thecasing 2560 during the expansion process. - The
inner sealing mandrel 2530 is coupled to thehydraulic slip body 2520 and thelower sealing head 2540. Theinner sealing mandrel 2530 preferably comprises a substantially hollow tubular member or members. Theinner sealing mandrel 2530 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theinner sealing mandrel 2530 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
inner sealing mandrel 2530 may be coupled to thehydraulic slip body 2520 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theinner sealing mandrel 2530 is removably coupled to thehydraulic slip body 2520 by a standard threaded connection. Theinner sealing mandrel 2530 may be coupled to thelower sealing head 2540 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty type threaded connection, drillpipe connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theinner sealing mandrel 2530 is removably coupled to thelower sealing head 2540 by a standard threaded connection. - The
inner sealing mandrel 2530 preferably includes afluid passage 2590 that is adapted to convey fluidic materials from thefluid passage 2580 into thefluid passage 2600. In an exemplary embodiment, thefluid passage 2590 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
upper sealing head 2535 is coupled to theouter sealing mandrel 2545 andexpansion cone 2555. Theupper sealing head 2535 is also movably coupled to the outer surface of theinner sealing mandrel 2530 and the inner surface of thecasing 2560. In this manner, theupper sealing head 2535 reciprocates in the axial direction. The radial clearance between the inner cylindrical surface of theupper sealing head 2535 and the outer surface of theinner sealing mandrel 2530 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of theupper sealing head 2535 and the outer surface of theinner sealing mandrel 2530 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. The radial clearance between the outer cylindrical surface of theupper sealing head 2535 and the inner surface of thecasing 2560 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of theupper sealing head 2535 and the inner surface of thecasing 2560 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 2535 during the expansion process. - The
upper sealing head 2535 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theupper sealing head 2535 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theupper sealing head 2535 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The inner surface of theupper sealing head 2535 preferably includes one or more annular sealing members2620 for sealing the interface between theupper sealing head 2535 and theinner sealing mandrel 2530. The sealing members2620 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealing members2620 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - In an exemplary embodiment, the
upper sealing head 2535 includes ashoulder 2625 for supporting theupper sealing head 2535,outer sealing mandrel 2545, andexpansion cone 2555 on thelower sealing head 2540. - The
upper sealing head 2535 may be coupled to theouter sealing mandrel 2545 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty threaded connection, pipeline connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theupper sealing head 2535 is removably coupled to theouter sealing mandrel 2545 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between theupper sealing head 2535 and theouter sealing mandrel 2545 includes one ormore sealing members 2630 for fluidicly sealing the interface between theupper sealing head 2535 and theouter sealing mandrel 2545. The sealingmembers 2630 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2630 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The
lower sealing head 2540 is coupled to theinner sealing mandrel 2530 and theload mandrel 2550. Thelower sealing head 2540 is also movably coupled to the inner surface of theouter sealing mandrel 2545. In this manner, theupper sealing head 2535,outer sealing mandrel 2545, andexpansion cone 2555 reciprocate in the axial direction. - The radial clearance between the outer surface of the
lower sealing head 2540 and the inner surface of theouter sealing mandrel 2545 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the outer surface of thelower sealing head 2540 and the inner surface of theouter sealing mandrel 2545 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. - The
lower sealing head 2540 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Thelower sealing head 2540 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thelower sealing head 2540 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The outer surface of thelower sealing head 2540 preferably includes one or moreannular sealing members 2635 for sealing the interface between thelower sealing head 2540 and theouter sealing mandrel 2545. The sealingmembers 2635 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2635 compose polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The
lower sealing head 2540 may be coupled to theinner sealing mandrel 2530 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connections, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, thelower sealing head 2540 is removably coupled to theinner sealing mandrel 2530 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between thelower sealing head 2540 and theinner sealing mandrel 2530 includes one ormore sealing members 2640 for fluidicly sealing the interface between thelower sealing head 2540 and theinner sealing mandrel 2530. The sealingmembers 2640 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2640 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The
lower sealing head 2540 may be coupled to theload mandrel 2550 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, thelower sealing head 2540 is removably coupled to theload mandrel 2550 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between thelower sealing head 2540 and theload mandrel 2550 includes one ormore sealing members 2645 for fluidicly sealing the interface between thelower sealing head 2540 and theload mandrel 2550. The sealingmembers 2645 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2645 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - In an exemplary embodiment, the
lower sealing head 2540 includes athroat passage 2650 fluidicly coupled between thefluid passages throat passage 2650 is preferably of reduced size and is adapted to receive and engage with aplug 2655, or other similar device. In this manner, thefluid passage 2590 is fluidicly isolated from thefluid passage 2600. In this manner, thepressure chamber 2660 is pressurized. - The
outer sealing mandrel 2545 is coupled to theupper sealing head 2535 and theexpansion cone 2555. Theouter sealing mandrel 2545 is also movably coupled to the inner surface of thecasing 2560 and the outer surface of thelower sealing head 2540. In this manner, theupper sealing head 2535,outer sealing mandrel 2545, and theexpansion cone 2555 reciprocate in the axial direction. The radial clearance between the outer surface of theouter sealing mandrel 2545 and the inner surface of thecasing 2560 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer surface of theouter sealing mandrel 2545 and the inner surface of thecasing 2560 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 2535 during the expansion process. The radial clearance between the inner surface of theouter sealing mandrel 2545 and the outer surface of thelower sealing head 2540 may range, for example, from about 0.005 to 0.01 inches. In an exemplary embodiment, the radial clearance between the inner surface of theouter sealing mandrel 2545 and the outer surface of thelower sealing head 2540 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. - The
outer sealing mandrel 2545 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theouter sealing mandrel 2545 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theouter sealing mandrel 2545 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
outer sealing mandrel 2545 may be coupled to theupper sealing head 2535 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection, in an exemplary embodiment, theouter sealing mandrel 2545 is removably coupled to theupper sealing head 2535 by a standard threaded connection. Theouter sealing mandrel 2545 may be coupled to theexpansion cone 2555 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theouter sealing mandrel 2545 is removably coupled to theexpansion cone 2555 by a standard threaded connection. - The
upper sealing head 2535, thelower sealing head 2540, theinner sealing mandrel 2530, and theouter sealing mandrel 2545 together define apressure chamber 2660. Thepressure chamber 2660 is fluidicly coupled to thepassage 2590 via one ormore passages 2595. During operation of theapparatus 2500, theplug 2655 engages with thethroat passage 2650 to fluidicly isolate thefluid passage 2590 from thefluid passage 2600. Thepressure chamber 2660 is then pressurized which in turn causes theupper sealing head 2535,outer sealing mandrel 2545, andexpansion cone 2555 to reciprocate in the axial direction. The axial motion of theexpansion cone 2555 in turn expands thecasing 2560 in the radial direction. - The
load mandrel 2550 is coupled to thelower sealing head 2540. Theload mandrel 2550 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theload mandrel 2550 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theload mandrel 2550 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
load mandrel 2550 may be coupled to thelower sealing head 2540 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods, drillpipe connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, theload mandrel 2550 is removably coupled to thelower sealing head 2540 by a standard threaded connection. - The
load mandrel 2550 preferably includes afluid passage 2600 that is adapted to convey fluidic materials from thefluid passage 2590 to the region outside of theapparatus 2500. In an exemplary embodiment, thefluid passage 2600 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging, for example, from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
expansion cone 2555 is coupled to theouter sealing mandrel 2545. Theexpansion cone 2555 is also movably coupled to the inner surface of thecasing 2560. In this manner, theupper sealing head 2535,outer sealing mandrel 2545, and theexpansion cone 2555 reciprocate in the axial direction. The reciprocation of theexpansion cone 2555 causes thecasing 2560 to expand in the radial direction. - The
expansion cone 2555 preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces. The outside radius of the outside conical surface may range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 in order to optimally provide radial expansion for the widest variety of tubular casings. The axial length of theexpansion cone 2555 may range, for example, from about 2 to 8 times the largest outside diameter of theexpansion cone 2535. In an exemplary embodiment, the axial length of theexpansion cone 2535 ranges from about 3 to 5 times the largest outside diameter of theexpansion cone 2535 in order to optimally provide stabilization and centralization of theexpansion cone 2535 during the expansion process. In an exemplary embodiment, the maximum outside diameter of theexpansion cone 2555 is between about 95 to 99% of the inside diameter of the existing wellbore that thecasing 2560 will be joined with. In an exemplary embodiment, the angle of attack of theexpansion cone 2555 ranges from about 5 to 30 degrees in order to-optimally balance frictional forces and radial expansion forces. The optimum angle of attack of theexpansion cone 2535 will vary as a function of the particular operational features of the expansion operation. - The
expansion cone 2555 may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramics or other similar high strength materials. In an exemplary embodiment, theexpansion cone 2555 is fabricated from D2 machine tool steel in order to optimally provide high strength, and resistance to wear and galling. In an exemplary embodiment, the outside surface of theexpansion cone 2555 has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide high strength and wear resistance. - The
expansion cone 2555 may be coupled to theoutside sealing mandrel 2545 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, theexpansion cone 2555 is coupled to theoutside sealing mandrel 2545 using a standard threaded connection in order to optimally provide high strength and easy replacement of theexpansion cone 2555. - The
casing 2560 is removably coupled to theslips 2525 andexpansion cone 2555. Thecasing 2560 preferably comprises a tubular member. Thecasing 2560 may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thecasing 2560 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength using standardized materials. - In an exemplary embodiment, the
upper end 2665 of thecasing 2560 includes athin wall section 2670 and an outerannular sealing member 2675. In an exemplary embodiment, the wall thickness of thethin wall section 2670 is about 50 to 100% of the regular wall thickness of thecasing 2560. in this manner, theupper end 2665 of thecasing 2560 may be easily radially expanded and deformed into intimate contact with the lower end of an existing section of wellbore casing. In an exemplary embodiment, the lower end of the existing section of casing also includes a thin wall section. In this manner, the radial expansion of the thinwalled section 2670 ofcasing 2560 into the thin walled section of the existing wellbore casing results in a wellbore casing having a substantially constant inside diameter. - The
annular sealing member 2675 may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal, or plastic, in an exemplary embodiment, theannular sealing member 2675 is fabricated from StrataLock epoxy in order to optimally provide compressibility and resistance to wear. The outside diameter of theannular sealing member 2675 preferably ranges from about 70 to 95% of the inside diameter of the lower section of the wellbore casing that thecasing 2560 is joined to. In this manner, after radial expansion, theannular sealing member 2670 optimally provides a fluidic seal and also preferably optimally provides sufficient frictional force with the inside surface of the existing section of wellbore casing during the radial expansion of thecasing 2560 to support thecasing 2560. - In an exemplary embodiment, the
lower end 2680 of thecasing 2560 includes athin wall section 2685 and an outerannular sealing member 2690. In an exemplary embodiment the wall thickness of thethin wall section 2685 is about 50 to 100% of the regular wall thickness of thecasing 2560. In this manner, thelower end 2680 of thecasing 2560 may be easily expanded and deformed. Furthermore, in this manner, an other section of casing may be easily joined with thelower end 2680 of thecasing 2560 using a radial expansion process. In an exemplary embodiment, the upper end of the other section of casing also includes a thin wall section. In this manner, the radial expansion of the thin walled section of the upper end of the other casing into the thinwalled section 2685 of thelower end 2680 of thecasing 2560 results in a wellbore casing having a substantially constant inside diameter. - The
annular sealing member 2690 may be fabricated from any number of conventional commercially available sealing materials such as, for example, rubber, metal, plastic or epoxy. In an exemplary embodiment, theannular sealing member 2690 is fabricated from StrataLock epoxy in order to optimally provide compressibility and resistance to wear. The outside diameter of theannular sealing member 2690 preferably ranges from about 70 to 95% of the inside diameter of the lower section of the existing wellbore casing that thecasing 2560 is pined to. In this manner, after radial expansion, theannular sealing member 2690 preferably provides a fluidic seal and also preferably provides sufficient frictional force with the inside wall of the wellbore during the radial expansion of thecasing 2560 to support thecasing 2560. - During operation, the
apparatus 2500 is preferably positioned in a wellbore with theupper end 2665 of thecasing 2560 positioned in an overlapping relationship with the lower end of an existing wellbore casing. In an exemplary embodiment, thethin wall section 2670 of thecasing 2560 is positioned in opposing overlapping relation with the thin wall section and outer annular sealing member of the lower end of the existing section of wellbore casing. In this manner, the radial expansion of thecasing 2560 will compress the thin wall sections and annular compressible members of theupper end 2565 of thecasing 2560 and the lower end of the existing wellbore casing into intimate contact. During the positioning of theapparatus 2500 in the wellbore, thecasing 2560 is supported by theexpansion cone 2555. - After positioning of the
apparatus 2500, a first fluidic material is then pumped into thefluid passage 2565. The first fluidic material may comprise any number of conventional commercially available materials such as, for example, cement, water, slag-mix, epoxy or drilling mud. In an exemplary embodiment, the first fluidic material comprises a hardenable fluidic sealing material such as, for example, cement, epoxy, or slag-mix in order to optimally provide a hardenable outer annular body around the expandedcasing 2560. - The first fluidic material may be pumped into the
fluid passage 2565 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 3,000 gallons/minute. In an exemplary embodiment, the first fluidic material is pumped into thefluid passage 2565 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency. - The first fluidic material pumped into the
fluid passage 2565 passes through thefluid passages apparatus 2500. The first fluidic material then preferably fills the annular region between the outside of theapparatus 2500 and the interior walls of the wellbore. - The
plug 2655 is then introduced into thefluid passage 2565. Theplug 2655 lodges in thethroat passage 2650 and fluidicly isolates and blocks off thefluid passage 2590. In an exemplary embodiment, a couple of volumes of a non-hardenable fluidic material are then pumped into thefluid passage 2565 in order to remove any hardenable fluidic material contained within and to ensure that none of the fluid passages are blocked. - A second fluidic material is then pumped into the
fluid passage 2565. The second fluidic material may comprise any number of conventional commercially available materials such as, for example, water, drilling gases, drilling mud or lubricant. In an exemplary embodiment, the second fluidic material comprises a non-hardenable fluidic material such as, for example, water, drilling mud, or lubricant in order to optimally provide pressurization of thepressure chamber 2660 and minimize friction. - The second fluidic material may be pumped into the
fluid passage 2565 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute. In an exemplary embodiment, the second fluidic material is pumped into thefluid passage 2565 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency. - The second fluidic material pumped into the
fluid passage 2565 passes through thefluid passages pressure chambers 2605 of theslips 2525, and into thepressure chamber 2660. Continued pumping of the second fluidic material pressurizes thepressure chambers - The pressurization of the
pressure chambers 2605 causes theslip members 2525 to expand in the radial direction and grip the interior surface of thecasing 2560. Thecasing 2560 is then preferably maintained in a substantially stationary position. - The pressurization of the
pressure chamber 2660 causes theupper sealing head 2535,outer sealing mandrel 2545 andexpansion cone 2555 to move in an axial direction relative to thecasing 2560. In this manner, theexpansion cone 2555 will cause thecasing 2560 to expand in the radial direction, beginning with thelower end 2685 of thecasing 2560. - During the radial expansion process, the
casing 2560 is prevented from moving in an upward direction by theslips 2525. A length of thecasing 2560 is then expanded in the radial direction through the pressurization of thepressure chamber 2660. The length of thecasing 2560 that is expanded during the expansion process will be proportional to the stroke length of theupper sealing head 2535,outer sealing mandrel 2545, andexpansion cone 2555. - Upon the completion of a stroke, the operating pressure of the second fluidic material is reduced and the
upper sealing head 2535,outer sealing mandrel 2545, andexpansion cone 2555 drop to their rest positions with thecasing 2560 supported by theexpansion cone 2555. The position of the drillpipe2505 is preferably adjusted throughout the radial expansion process in order to maintain the overlapping relationship between the thin walled sections of the lower end of the existing wellbore casing and the upper end of thecasing 2560. In an exemplary embodiment, the stroking of theexpansion cone 2555 is then repeated, as necessary, until the thinwalled section 2670 of theupper end 2665 of thecasing 2560 is expanded into the thin waited section of the lower end of the existing wellbore casing. In this manner a wellbore casing is formed including two adjacent sections of casing having a substantially constant inside diameter. This process may then be repeated for the entirety of the wellbore to provide a wellbore casing thousands of feet in length having a substantially constant inside diameter. - In an exemplary embodiment, during the final stroke of the
expansion cone 2555, theslips 2525 are positioned as close as possible to the thinwalled section 2670 of theupper end 2665 of thecasing 2560 in order minimize slippage between thecasing 2560 and the existing wellbore casing at the end of the radial expansion process. Alternatively, or in addition, the outside diameter of theannular sealing member 2675 is selected to ensure sufficient interference fit with the inside diameter of the lower end of the existing casing to prevent axial displacement of thecasing 2560 during the final stroke. Alternatively, or in addition, the outside diameter of theannular sealing member 2690 is selected to provide an interference fit with the inside walls of the wellbore at an earlier point in the radial expansion process so as to prevent further axial displacement of thecasing 2560. In this final alternative, the interference fit is preferably selected to permit expansion of thecasing 2560 by pulling theexpansion cone 2555 out of the wellbore, without having to pressurize thepressure chamber 2660. - During the radial expansion process, the pressurized areas of the
apparatus 2500 are preferably limited to thefluid passages pressure chambers 2605 within the slips2526, and thepressure chamber 2660. No fluid pressure acts directly on thecasing 2560. This permits the use of operating pressures higher than thecasing 2560 could normally withstand. - Once the
casing 2560 has been completely expanded off of theexpansion cone 2555, the remaining portions of theapparatus 2500 are removed from the wellbore. In an exemplary embodiment, the contact pressure between the deformed thin wall sections and compressible annular members of the lower end of the existing casing and theupper end 2665 of thecasing 2560 ranges from about 400 to 10,000 psi In order to optimally support thecasing 2560 using the existing wellbore casing. - In this manner, the
casing 2560 is radially expanded into contact with an existing section of casing by pressurizing theinterior fluid passages slips 2605 and thepressure chamber 2660 of theapparatus 2500. - In an exemplary embodiment, as required, the annular body of hardenable fluidic material is then allowed to cure to form a rigid outer annular body about the expanded
casing 2560. In the case where thecasing 2560 is slotted, the cured fluidic material preferably permeates and envelops the expandedcasing 2560. The resulting new section of wellbore casing includes the expandedcasing 2560 and the rigid outer annular body. The overlapping joint between the pre-existing wellbore casing and the expandedcasing 2560 includes the deformed thin wall sections and the compressible outer annular bodies. The inner diameter of the resulting combined wellbore casings is substantially constant, in this manner, a mono-diameter wellbore casing is formed. This process of expanding overlapping tubular members having thin wall end portions with compressible annular bodies into contact can be repeated for the entire length of a wellbore. In this manner, a mono-diameter wellbore casing can be provided for thousands of feet in a subterranean formation. - In an exemplary embodiment, as the
expansion cone 2555 nears theupper end 2665 of thecasing 2560, the operating pressure of the second fluidic material is reduced in order to minimize shock to theapparatus 2500. In an alternative embodiment, theapparatus 2500 includes a shock absorber for absorbing the shock created by the completion of the radial expansion of thecasing 2560. - In an exemplary embodiment, the reduced operating pressure of the second fluidic material ranges from about 100 to 1,000 psi as the
expansion cone 2555 nears the end of thecasing 2560 in order to optimally provide reduced axial movement and velocity of theexpansion cone 2555. In an exemplary embodiment, the operating pressure of the second fluidic material is reduced during the return stroke of theapparatus 2500 to the range of about 0 to 500 psi in order minimize the resistance to the movement of theexpansion cone 2555 during the return stroke. In an exemplary embodiment, the stroke length of theapparatus 2500 ranges from about 10 to 45 feet in order to optimally provide equipments lengths that can be easily handled using typical oil well rigging equipment and also minimize the frequency at whichapparatus 2500 must be re-stroked. - In an alternative embodiment, at least a portion of the
upper sealing head 2535 includes an expansion cone for radially expanding thecasing 2560 during operation of theapparatus 2500 in order to increase the surface area of thecasing 2560 acted upon during the radial expansion process. In this manner, the operating pressures can be reduced. - Alternatively, the
apparatus 2500 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, theapparatus 2500 may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material. Alternatively, theapparatus 2500 may be used to expand a tubular support member in a hole. - Referring now to
FIGS. 19 ,19aand19b,another embodiment of anapparatus 2700 for expanding a tubular member will be described. Theapparatus 2700 preferably includes adrillpipe 2705, aninnerstring adapter 2710, a sealingsleeve 2715, a firstinner sealing mandrel 2720, a firstupper sealing head 2725, a firstlower sealing head 2730, a firstouter sealing mandrel 2735, a secondinner sealing mandrel 2740, a secondupper sealing head 2745, a secondlower sealing head 2750, a secondouter sealing mandrel 2755, aload mandrel 2760, anexpansion cone 2765, amandrel launcher 2770, amechanical slip body 2775,mechanical slips 2780, drag blocks2785,casing 2790, andfluid passages - The
drillpipe 2705 is coupled to theinnerstring adapter 2710. During operation of theapparatus 2700, thedrillpipe 2705 supports theapparatus 2700. Thedrillpipe 2705 preferably comprises a substantially hollow tubular member or members. Thedrillpipe 2705 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength materials. In an exemplary embodiment, thedrillpipe 2705 is fabricated from coiled tubing in order to facilitate the placement of theapparatus 2700 in non-vertical wellbores. Thedrillpipe 2705 may be coupled to theinnerstring adapter 2710 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, thedrillpipe 2705 is removably coupled to theinnerstring adapter 2710 by a drillpipe connection in order to optimally provide high strength and easy disassembly. - The
drillpipe 2705 preferably includes afluid passage 2795 that is adapted to convey fluidic materials from a surface location into thefluid passage 2800. In an exemplary embodiment, thefluid passage 2795 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
innerstring adapter 2710 is coupled to thedrill string 2705 and thesealing sleeve 2715. Theinnerstring adapter 2710 preferably comprises a substantially hollow tubular member or members. Theinnerstring adapter 2710 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theinnerstring adapter 2710 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
innerstring adapter 2710 may be coupled to thedrill string 2705 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 2710 is removably coupled to thedrill pipe 2705 by a standard threaded connection in order to optimally provide high strength and easy disassembly. Theinnerstring adapter 2710 may be coupled to thesealing sleeve 2715 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 2710 is removably coupled to thesealing sleeve 2715 by a standard threaded connection. - The
innerstring adapter 2710 preferably includes afluid passage 2800 that is adapted to convey fluidic materials from thefluid passage 2795 into thefluid passage 2805. In an exemplary embodiment, thefluid passage 2800 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The sealing
sleeve 2715 is coupled to theinnerstring adapter 2710 and the firstinner sealing mandrel 2720. The sealingsleeve 2715 preferably comprises a substantially hollow tubular member or members. The sealingsleeve 2715 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the sealingsleeve 2715 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The sealing
sleeve 2715 may be coupled to theinnerstring adapter 2710 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 2715 is removably coupled to theinnerstring adapter 2710 by a standard threaded connector. The sealingsleeve 2715 may be coupled to the firstinner sealing mandrel 2720 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 2715 is removably coupled to theinner sealing mandrel 2720 by a standard threaded connection. - The sealing
sleeve 2715 preferably includes afluid passage 2802 that is adapted to convey fluidic materials from thefluid passage 2800 into thefluid passage 2805. In an exemplary embodiment, thefluid passage 2802 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The first
inner sealing mandrel 2720 is coupled to thesealing sleeve 2715 and the firstlower sealing head 2730. The firstinner sealing mandrel 2720 preferably comprises a substantially hollow tubular member or members. The firstinner sealing mandrel 2720 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the firstinner sealing mandrel 2720 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The first
inner sealing mandrel 2720 may be coupled to thesealing sleeve 2715 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, the firstinner sealing mandrel 2720 is removably coupled to thesealing sleeve 2715 by a standard threaded connection. The firstinner sealing mandrel 2720 may be coupled to the firstlower sealing head 2730 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, the firstinner sealing mandrel 2720 is removably coupled to the firstlower sealing head 2730 by a standard threaded connection. - The first
inner sealing mandrel 2720 preferably includes afluid passage 2805 that is adapted to convey fluidic materials from thefluid passage 2802 into thefluid passage 2810. In an exemplary embodiment, thefluid passage 2805 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The first
upper sealing head 2725 is coupled to the firstouter sealing mandrel 2735, the secondupper sealing head 2745, the secondouter sealing mandrel 2755, and theexpansion cone 2765. The firstupper sealing head 2725 is also movably coupled to the outer surface of the firstinner sealing mandrel 2720 and the inner surface of thecasing 2790. In this manner, the firstupper sealing head 2725 reciprocates in the axial direction. The radial clearance between the inner cylindrical surface of the firstupper sealing head 2725 and the outer surface of the firstinner sealing mandrel 2720 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of the firstupper sealing head 2725 and the outer surface of the firstinner sealing mandrel 2720 ranges from about 0.005 to 0.125 inches in order to optimally provide minimal radial clearance. The radial clearance between the outer cylindrical surface of the firstupper sealing head 2725 and the inner surface of thecasing 2790 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of the firstupper sealing head 2725 and the inner surface of thecasing 2790 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 2765 during the expansion process. - The first
upper sealing head 2725 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The firstupper sealing head 2725 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the firstupper sealing head 2725 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance and low friction surfaces. The inner surface of the firstupper sealing head 2725 preferably includes one or moreannular sealing members 2835 for sealing the interface between the firstupper sealing head 2725 and the firstinner sealing mandrel 2720. The sealingmembers 2835 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2835 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - In an exemplary embodiment, the first
upper sealing head 2725 includes ashoulder 2840 for supporting the firstupper sealing head 2725 on the firstlower sealing head 2730. - The first
upper sealing head 2725 may be coupled to the firstouter sealing mandrel 2735 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding or a standard threaded connection. In an exemplary embodiment, the firstupper sealing head 2725 is removably coupled to the firstouter sealing mandrel 2735 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the firstupper sealing head 2725 and the firstouter sealing mandrel 2735 includes one ormore sealing members 2845 for fluidicly sealing the interface between the firstupper sealing head 2725 and the firstouter sealing mandrel 2735. The sealingmembers 2845 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2845 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - The first
lower sealing head 2730 is coupled to the firstinner sealing mandrel 2720 and the secondinner sealing mandrel 2740. The firstlower sealing head 2730 is also movably coupled to the inner surface of the firstouter sealing mandrel 2735. In this manner, the firstupper sealing head 2725 and firstouter sealing mandrel 2735 reciprocate in the axial direction. The radial clearance between the outer surface of the firstlower sealing head 2730 and the inner surface of the firstouter sealing mandrel 2735 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the outer surface of the firstlower sealing head 2730 and the inner surface of the firstouter sealing mandrel 2735 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. - The first
lower sealing head 2730 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The firstlower sealing head 2730 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the firstlower sealing head 2730 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The outer surface of the firstlower sealing head 2730 preferably includes one or moreannular sealing members 2850 for sealing the interface between the firstlower sealing head 2730 and the firstouter sealing mandrel 2735. The sealingmembers 2850 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2850 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - The first
lower sealing head 2730 may be coupled to the firstinner sealing mandrel 2720 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty threaded connections, welding, amorphous bonding, or standard threaded connection, in an exemplary embodiment, the firstlower sealing head 2730 is removably coupled to the firstinner sealing mandrel 2720 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the firstlower sealing head 2730 and the firstinner sealing mandrel 2720 includes one ormore sealing members 2855 for fluidicly sealing the interface between the firstlower sealing head 2730 and the firstinner sealing mandrel 2720. The sealingmembers 2855 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2855 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - The first
lower sealing head 2730 may be coupled to the secondinner sealing mandrel 2740 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specially threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, thelower sealing head 2730 is removably coupled to the secondinner sealing mandrel 2740 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the firstlower sealing head 2730 and the secondinner sealing mandrel 2740 includes one ormore sealing members 2860 for fluidicly sealing the interface between the firstlower sealing head 2730 and the secondinner sealing mandrel 2740. The sealingmembers 2860 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2860 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - The first
outer sealing mandrel 2735 is coupled to the firstupper sealing head 2725, the secondupper sealing head 2745, the secondouter sealing mandrel 2755, and theexpansion cone 2765. The firstouter sealing mandrel 2735 is also movably coupled to the inner surface of thecasing 2790 and the outer surface of the firstlower sealing head 2730. In this manner, the firstupper sealing head 2725, firstouter sealing mandrel 2735, secondupper sealing head 2745, secondouter sealing mandrel 2755, and theexpansion cone 2765 reciprocate in the axial direction. The radial clearance between the outer surface of the firstouter sealing mandrel 2735 and the inner surface of thecasing 2790 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer surface of the firstouter sealing mandrel 2735 and the inner surface of thecasing 2790 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 2765 during the expansion process. The radial clearance between the inner surface of the firstouter sealing mandrel 2735 and the outer surface of the firstlower sealing head 2730 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner surface of the firstouter sealing mandrel 2735 and the outer surface of the firstlower sealing head 2730 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. - The
outer sealing mandrel 1935 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The firstouter sealing mandrel 2735 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the firstouter sealing mandrel 2735 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The first
outer sealing mandrel 2735 may be coupled to the firstupper sealing head 2725 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods, welding, amorphous bonding, or a standard threaded connection, in an exemplary embodiment, the firstouter sealing mandrel 2735 is removably coupled to the firstupper sealing head 2725 by a standard threaded connection. The firstouter sealing mandrel 2735 may be coupled to the secondupper sealing head 2745 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, the firstouter sealing mandrel 2735 is removably coupled to the secondupper sealing head 2745 by a standard threaded connection. - The second
inner sealing mandrel 2740 is coupled to the firstlower sealing head 2730 and the second lower sealing head2750. The secondinner sealing mandrel 2740 preferably comprises a substantially hollow tubular member or members. The secondinner sealing mandrel 2740 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the secondinner sealing mandrel 2740 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The second
inner sealing mandrel 2740 may be coupled to the firstlower sealing head 2730 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, the secondinner sealing mandrel 2740 is removably coupled to the first lower sealinghead 2740 by a standard threaded connection. The mechanical coupling between the secondinner sealing mandrel 2740 and the firstlower sealing head 2730 preferably includes sealingmembers 2860. - The second
inner sealing mandrel 2740 may be coupled to the secondlower sealing head 2750 using any number of conventional commercially available mechanical couplings such as, for example, oilfield country tubular goods specialty threaded connection, welding, amorphous bonding, or a standard threaded connection. In an exemplary embodiment, the secondinner sealing mandrel 2720 is removably coupled to the second lower sealinghead 2750 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the secondinner sealing mandrel 2740 and the secondlower sealing head 2750 includes one or more sealingmembers 2865. The sealingmembers 2865 may comprise any number of conventional commercially available seals such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2865 comprise polypak seals available from Parker Seals. - The second
inner sealing mandrel 2740 preferably includes afluid passage 2810 that is adapted to convey fluidic materials from thefluid passage 2805 into thefluid passage 2815. In an exemplary embodiment, thefluid passage 2810 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The second upper sealing
head 2745 is coupled to the first upper sealinghead 2725, the firstouter sealing mandrel 2735, the secondouter sealing mandrel 2755, and theexpansion cone 2765. The second upper sealinghead 2745 is also movably coupled to the outer surface of the secondinner sealing mandrel 2740 and the inner surface of thecasing 2790. In this manner, the second upper sealinghead 2745 reciprocates in the axial direction. The radial clearance between the inner cylindrical surface of the second upper sealinghead 2745 and the outer surface of the secondinner sealing mandrel 2740 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of the second upper sealinghead 2745 and the outer surface of the secondinner sealing mandrel 2740 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. The radial clearance between the outer cylindrical surface of the second upper sealinghead 2745 and the inner surface of thecasing 2790 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of the secondupper sealing head 2745 and the inner surface of thecasing 2790 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 2765 during the expansion process. - The second upper sealing
head 2745 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The second upper sealinghead 2745 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the second upper sealinghead 2745 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The inner surface of the second upper sealinghead 2745 preferably includes one or moreannular sealing members 2870 for sealing the interface between the second upper sealinghead 2745 and the secondinner sealing mandrel 2740. The sealingmembers 2870 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals, in an exemplary embodiment, the sealingmembers 2870 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - In an exemplary embodiment, the second upper sealing
head 2745 includes ashoulder 2875 for supporting the second upper sealinghead 2745 on the secondlower sealing head 2750. - The second upper sealing
head 2745 may be coupled to the firstouter sealing mandrel 2735 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, the second upper sealinghead 2745 is removably coupled to the firstouter sealing mandrel 2735 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the second upper sealinghead 2745 and the firstouter sealing mandrel 2735 includes one or more sealingmembers 2880 for fluidicly sealing the interface between the second upper sealinghead 2745 and the firstouter sealing mandrel 2735. The sealingmembers 2880 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2880 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The second upper sealing
head 2745 may be coupled to the secondouter sealing mandrel 2755 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, the second upper sealinghead 2745 is removably coupled to the secondouter sealing mandrel 2755 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the second upper sealinghead 2745 and the secondouter sealing mandrel 2755 includes one or more sealingmembers 2885 for fiuldicly sealing the interface between the secondupper sealing head 2745 and the secondouter sealing mandrel 2755. The sealingmembers 2885 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2885 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - The second
lower sealing head 2750 is coupled to the secondinner sealing mandrel 2740 and theload mandrel 2760. The secondlower sealing head 2750 is also movably coupled to the inner surface of the secondouter sealing mandrel 2755. In this manner, the first upper sealinghead 2725, the firstouter sealing mandrel 2735, second upper sealinghead 2745, secondouter sealing mandrel 2755, and theexpansion cone 2765 reciprocate in the axial direction. The radial clearance between the outer surface of the secondlower sealing head 2750 and the inner surface of the secondouter sealing mandrel 2755 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the outer surface of the secondlower sealing head 2750 and the inner surface of the secondouter sealing mandrel 2755 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. - The second
lower sealing head 2750 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The secondlower sealing head 2750 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the secondlower sealing head 2750 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The outer surface of the secondlower sealing head 2750 preferably includes one or moreannular sealing members 2890 for sealing the interface between the secondlower sealing head 2750 and the secondouter sealing mandrel 2755. The sealingmembers 2890 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2890 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - The second
lower sealing head 2750 may be coupled to the secondinner sealing mandrel 2740 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, the secondlower sealing head 2750 is removably coupled to the secondinner sealing mandrel 2740 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the secondlower sealing head 2750 and the secondinner sealing mandrel 2740 includes one or more sealingmembers 2895 for fluidicly sealing the interface between the second sealinghead 2750 and thesecond sealing mandrel 2740. The sealingmembers 2895 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2895 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The second
lower sealing head 2750 may be coupled to theload mandrel 2760 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield tubular goods specialty threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, the secondlower sealing head 2750 is removably coupled to theload mandrel 2760 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the secondlower sealing head 2750 and theload mandrel 2760 includes one or more sealingmembers 2900 for fluidicly sealing the interface between the secondlower sealing head 2750 and theload mandrel 2760. The sealingmembers 2900 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 2900 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - In an exemplary embodiment, the second
lower sealing bead 2750 includes athroat passage 2905 fiuldicly coupled between thefluid passages throat passage 2905 is preferably of reduced size and is adapted to receive and engage with aplug 2910, or other similar device. In this manner, thefluid passage 2810 is fiuldicly isolated from thefluid passage 2815. In this manner, thepressure chambers 2915 and2920 are pressurized. The use of a plurality of pressure chambers in theapparatus 2700 permits the effective driving force to be multiplied. While illustrated using a pair of pressure chambers,2915 and2920, theapparatus 2700 may be further modified to employ additional pressure chambers. - The second
outer sealing mandrel 2755 is coupled to the first upper sealinghead 2725, the firstouter sealing mandrel 2735, the second upper sealinghead 2745, and theexpansion cone 2765. The secondouter sealing mandrel 2755 is also movably coupled to the inner surface of thecasing 2790 and the outer surface of the secondlower sealing head 2750. In this manner, the firstupper sealing head 2725, firstouter sealing mandrel 2735, secondupper sealing head 2745, secondouter sealing mandrel 2755, and theexpansion cone 2765 reciprocate in the axial direction. - The radial clearance between the outer surface of the second
outer sealing mandrel 2755 and the inner surface of thecasing 2790 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer surface of the secondouter sealing mandrel 2755 and the inner surface of thecasing 2790 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 2765 during the expansion process. The radial clearance between the inner surface of the secondouter sealing mandrel 2755 and the outer surface of the secondlower sealing head 2750 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner surface of the secondouter sealing mandrel 2755 and the outer surface of the secondlower sealing head 2750 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. - The second
outer sealing mandrel 2755 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The secondouter sealing mandrel 2755 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the secondouter sealing mandrel 2755 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The second
outer sealing mandrel 2755 may be coupled to the secondupper sealing head 2745 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, the secondouter sealing mandrel 2755 is removably coupled to the secondupper sealing head 2745 by a standard threaded connection. The secondouter sealing mandrel 2755 may be coupled to theexpansion cone 2755 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, the secondouter sealing mandrel 2755 is removably coupled to theexpansion cone 2765 by a standard threaded connection. - The
load mandrel 2760 is coupled to the secondlower sealing head 2750 and themechanical slip body 2755. Theload mandrel 2760 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theload mandrel 2760 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theload mandrel 2760 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
load mandrel 2760 may be coupled to the secondlower sealing head 2750 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, theload mandrel 2760 is removably coupled to the secondlower sealing head 2750 by a standard threaded connection. Theload mandrel 2760 may be coupled to themechanical slip body 2775 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, theload mandrel 2760 is removably coupled to themechanical slip body 2775 by a standard threaded connection. - The
load mandrel 2760 preferably includes afluid passage 2815 that is adapted to convey fluidic materials from thefluid passage 2810 to thefluid passage 2820. In an exemplary embodiment, thefluid passage 2815 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
expansion cone 2765 is coupled to the secondouter sealing mandrel 2755. Theexpansion cone 2765 is also movably coupled to the inner surface of thecasing 2790. In this manner, the firstupper sealing head 2725, firstouter sealing mandrel 2735, secondupper sealing head 2745, secondouter sealing mandrel 2755, and theexpansion cone 2765 reciprocate in the axial direction. The reciprocation of theexpansion cone 2765 causes thecasing 2790 to expand in the radial direction. - The
expansion cone 2765 preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces. The outside radius of the outside conical surface may range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 inches in order to optimally provide expansion cone dimensions that accommodate the typical range of casings. The axial length of theexpansion cone 2765 may range, for example, from about 2 to 8 times the largest outer diameter of theexpansion cone 2765. In an exemplary embodiment, the axial length of theexpansion cone 2765 ranges from about 3 to 5 times the largest outer diameter of theexpansion cone 2765 in order to optimally provide stabilization and centralization of theexpansion cone 2765. In an exemplary embodiment, the angle of attack of theexpansion cone 2765 ranges from about 5 to 30 degrees in order to optimally balance frictional forces and radial expansion forces. - The
expansion cone 2765 may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramics or other similar high strength materials. In an exemplary embodiment, theexpansion cone 2765 is fabricated from D2 machine tool steel in order to optimally provide high strength and resistance to corrosion and galling. In an exemplary embodiment, the outside surface of theexpansion cone 2765 has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide high strength and resistance to wear and galling. - The
expansion cone 2765 may be coupled to the secondoutside sealing mandrel 2765 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, theexpansion cone 2765 is coupled to the secondoutside sealing mandrel 2765 using a standard threaded connection in order to optimally provide high strength and easy replacement of theexpansion cone 2765. - The
mandrel launcher 2770 is coupled to thecasing 2790. Themandrel launcher 2770 comprises a tubular section of casing having a reduced wall thickness compared to thecasing 2790. In an exemplary embodiment, the wall thickness of themandrel launcher 2770 is about 50 to 100% of the wall thickness of thecasing 2790. The wall thickness of themandrel launcher 2770 may range, for example, from about 0.15 to 1.5 inches. In an exemplary embodiment, the wall thickness of themandrel launcher 2770 ranges from about 0.25 to 0.75 inches. In this manner, the initiation of the radial expansion of thecasing 2790 is facilitated, the placement of theapparatus 2700 within a wellbore casing and wellbore is facilitated, and themandrel launcher 2770 has a burst strength approximately equal to that of thecasing 2790. - The
mandrel launcher 2770 may be coupled to thecasing 2790 using any number of conventional mechanical couplings such as, for example, a standard threaded connection. Themandrel launcher 2770 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength materials, in an exemplary embodiment, themandrel launcher 2770 is fabricated from oilfield country tubular goods of higher strength than that of thecasing 2790 but with a reduced wall thickness in order to optimally provide a small compact tubular container having a burst strength approximately equal to that of thecasing 2790. - The
mechanical slip body 2775 is coupled to theload mandrel 2760, themechanical slips 2780, and the drag blocks2785. Themechanical slip body 2775 preferably comprises a tubular member having aninner passage 2820 fluidicly coupled to thepassage 2815. In this manner, fluidic materials may be conveyed from thepassage 2820 to a region outside of theapparatus 2700. - The
mechanical slip body 2775 may be coupled to theload mandrel 2760 using any number of conventional mechanical couplings. In an exemplary embodiment, themechanical slip body 2775 is removably coupled to theload mandrel 2760 using a standard threaded connection in order to optimally provide high strength and easy disassembly. Themechanical slip body 2775 may be coupled to themechanical slips 2780 using any number of conventional mechanical couplings. In an exemplary embodiment, themechanical slip body 2755 is removably coupled to themechanical slips 2780 using threaded connections and sliding steel retainer rings in order to optimally provide a high strength attachment. Themechanical slip body 2755 may be coupled to the drag blocks2785 using any number of conventional mechanical couplings. In an exemplary embodiment, themechanical slip body 2775 is removably coupled to the drag blocks2785 using threaded connections and sliding steel retainer rings in order to optimally provide a high strength attachment. - The
mechanical slip body 2775 preferably includes afluid passage 2820 that is adapted to convey fluidic materials from thefluid passage 2815 to the region outside of theapparatus 2700. In an exemplary embodiment, thefluid passage 2820 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
mechanical slips 2780 are coupled to the outside surface of themechanical slip body 2775. During operation of theapparatus 2700, themechanical slips 2780 prevent upward movement of thecasing 2790 andmandrel launcher 2770. In this manner, during the axial reciprocation of theexpansion cone 2765, thecasing 2790 andmandrel launcher 2770 are maintained in a substantially stationary position. In this manner, themandrel launcher 2765 andcasing 2790 andmandrel launcher 2770 are expanded in the radial direction by the axial movement of theexpansion cone 2765. - The
mechanical slips 2780 may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In an exemplary embodiment, themechanical slips 2780 comprise RTTS packer tungsten carbide mechanical slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of thecasing 2790 andmandrel launcher 2770 during the expansion process. - The drag blocks2785 are coupled to the outside surface of the
mechanical slip body 2775. During operation of theapparatus 2700, the drag blocks2785 prevent upward movement of thecasing 2790 andmandrel launcher 2770. In this manner, during the axial reciprocation of theexpansion cone 2765, thecasing 2790 andmandrel launcher 2770 are maintained in a substantially stationary position. In this manner, themandrel launcher 2770 andcasing 2790 are expanded in the radial direction by the axial movement of theexpansion cone 2765. - The drag blocks2785 may comprise any number of conventional commercially available mechanical slips such as, for example, RTTS packer mechanical drag blocks or Model 3L retrievable bridge plug drag blocks. In an exemplary embodiment, the drag blocks2785 comprise RTTS packer mechanical drag blocks available from Halliburton Energy Services in order to optimally provide resistance to axial movement of the
casing 2790 andmandrel launcher 2770 during the expansion process. - The
casing 2790 is coupled to themandrel launcher 2770. Thecasing 2790 is further removably coupled to themechanical slips 2780 and drag blocks2785. Thecasing 2790 preferably comprises a tubular member. Thecasing 2790 may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thecasing 2790 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength using standardized materials. In an exemplary embodiment, the upper end of thecasing 2790 includes one or more sealing members positioned about the exterior of thecasing 2790. - During operation, the
apparatus 2700 is positioned in a wellbore with the upper end of thecasing 2790 positioned in an overlapping relationship within an existing wellbore casing. In order minimize surge pressures within the borehole during placement of theapparatus 2700, thefluid passage 2795 is preferably provided with one or more pressure relief passages. During the placement of theapparatus 2700 in the wellbore, thecasing 2790 is supported by theexpansion cone 2765. - After positioning of the
apparatus 2700 within the bore hole in an overlapping relationship with an existing section of wellbore casing, a first fluidic material is pumped into thefluid passage 2795 from a surface location. The first fluidic material is conveyed from thefluid passage 2795 to thefluid passages apparatus 2700 and fill the annular region between the outside of theapparatus 2700 and the interior walls of the bore hole. - The first fluidic material may comprise any number of conventional commercially available materials such as, for example, epoxy, drilling mud, slag mix, water or cement. In an exemplary embodiment, the first fluidic material comprises a hardenable fluidic sealing material such as, for example, slag mix, epoxy, or cement. In this manner, a wellbore casing having an outer annular layer of a hardenable material may be formed.
- The first fluidic material may be pumped into the
apparatus 2700 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 3,000 gallons/minute. In an exemplary embodiment, the first fluidic material is pumped into theapparatus 2700 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency. - At a predetermined point in the injection of the first fluidic material such as, for example, after the annular region outside of the
apparatus 2700 has been filled to a predetermined level, aplug 2910, dart, or other similar device is introduced into the first fluidic material. Theplug 2910 lodges in thethroat passage 2905 thereby fiuldicly isolating thefluid passage 2810 from thefluid passage 2815. - After placement of the
plug 2910 in thethroat passage 2905, a second fluidic material is pumped into thefluid passage 2795 in order to pressurize thepressure chambers 2915 and2920. The second fluidic material may comprise any number of conventional commercially available materials such as, for example, water, drilling gases, drilling mud or lubricants. In an exemplary embodiment, the second fluidic material comprises a non-hardenable fluidic material such as, for example, water, drilling mud or lubricant. The use of lubricant optimally provides lubrication of the moving parts of theapparatus 2700. - The second fluidic material may be pumped into the
apparatus 2700 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute. In an exemplary embodiment, the second fluidic material is pumped into theapparatus 2700 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency. - The pressurization of the
pressure chambers 2915 and2920 cause the upper sealing heads,2725 and2745, outer sealing mandrels,2735 and2755, andexpansion cone 2765 to move in an axial direction. As theexpansion cone 2765 moves in the axial direction, theexpansion cone 2765 pulls themandrel launcher 2770,casing 2790, anddrag blocks 2785 along, which sets themechanical slips 2780 and stops further axial movement of themandrel launcher 2770 andcasing 2790. In this manner, the axial movement of theexpansion cone 2765 radially expands themandrel launcher 2770 andcasing 2790. - Once the upper sealing heads,2725 and2745, outer sealing mandrels,2735 and2755, and
expansion cone 2765 complete an axial stroke, the operating pressure of the second fluidic material is reduced and thedrill string 2705 is raised. This causes the inner sealing mandrels,2720 and2740, lower sealing heads,2730 and2750,load mandrel 2760, andmechanical slip body 2755 to move upward. This unsets themechanical slips 2780 and permits themechanical slips 2780 anddrag blocks 2785 to be moved upward within themandrel launcher 2770 andcasing 2790. When the lower sealing heads,2730 and2750, contact the upper sealing heads,2725 and2745, the second fluidic material is again pressurized and the radial expansion process continues. In this manner, themandrel launcher 2770 andcasing 2790 are radially expanded through repeated axial strokes of the upper sealing heads,2725 and2745, outer sealing mandrels,2735 and2755, andexpansion cone 2765. Throughout the radial expansion process, the upper end of thecasing 2790 is preferably maintained in an overlapping relation with an existing section of wellbore casing. - At the end of the radial expansion process, the upper end of the
casing 2790 is expanded into intimate contact with the inside surface of the lower end of the existing wellbore casing. In an exemplary embodiment, the sealing members provided at the upper end of thecasing 2790 provide a fluidic seal between the outside surface of the upper end of thecasing 2790 and the inside surface of the lower end of the existing wellbore casing. In an exemplary embodiment, the contact pressure between thecasing 2790 and the existing section of wellbore casing ranges from about 400 to 10,000 in order to optimally provide contact pressure for activating the sealing members, provide optimal resistance to axial movement of the expanded casing, and optimally resist typical tensile and compressive loads on the expanded casing. - In an exemplary embodiment, as the
expansion cone 2765 nears the end of thecasing 2790, the operating pressure of the second fluidic material is reduced in order to minimize shock to theapparatus 2700. In an alternative embodiment, theapparatus 2700 includes a shock absorber for absorbing the shock created by the completion of the radial expansion of thecasing 2790. - In an exemplary embodiment, the reduced operating pressure of the second fluidic material ranges from about 100 to 1,000 psi as the
expansion cone 2765 nears the end of thecasing 2790 in order to optimally provide reduced axial movement and velocity of theexpansion cone 2765. In an exemplary embodiment, the operating pressure of the second fluidic material is reduced during the return stroke of theapparatus 2700 to the range of about 0 to 500 psi in order minimize the resistance to the movement of theexpansion cone 2765 during the return stroke. In an exemplary embodiment, the stroke length of theapparatus 2700 ranges from about 10 to 45 feet in order to optimally provide equipment that can be easily handled by typical oil well rigging equipment and minimize the frequency at which theapparatus 2700 must be re-stroked during an expansion operation. - In an alternative embodiment, at least a portion of the upper sealing heads,2725 and2745, include expansion cones for radially expanding the
mandrel launcher 2770 andcasing 2790 during operation of theapparatus 2700 in order to increase the surface area of thecasing 2790 acted upon during the radial expansion process. In this manner, the operating pressures can be reduced. - In an alternative embodiment, mechanical slips are positioned in an axial location between the sealing
sleeve 2715 and the firstinner sealing mandrel 2720 in order to optimally provide a simplified assembly and operation of theapparatus 2700. - Upon the complete radial expansion of the
casing 2790, if applicable, the first fluidic material is permitted to cure within the annular region between the outside of the expandedcasing 2790 and the interior walls of the wellbore. In the case where thecasing 2790 is slotted, the cured fluidic material preferably permeates and envelops the expandedcasing 2790. In this manner, a new section of wellbore casing is formed within a wellbore. Alternatively, theapparatus 2700 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, theapparatus 2700 may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material. Alternatively, theapparatus 2700 may be used to expand a tubular support member in a hole. - During the radial expansion process, the pressurized areas of the
apparatus 2700 are limited to thefluid passages pressure chambers 2915 and2920. No fluid pressure acts directly on themandrel launcher 2770 andcasing 2790. This permits the use of operating pressures higher than themandrel launcher 2770 andcasing 2790 could normally withstand. - Referring now to
FIG. 20 , an exemplary embodiment of anapparatus 3000 for forming a mono-diameter wellbore casing will be described. Theapparatus 3000 preferably includes adrillpipe 3005, aninnerstring adapter 3010, a sealingsleeve 3015, a firstinner sealing mandrel 3020,hydraulic slips 3025, a firstupper sealing head 3030, a firstlower sealing head 3035, a firstouter sealing mandrel 3040, a secondinner sealing mandrel 3045, a secondupper sealing head 3050, a secondlower sealing head 3055, a secondouter sealing mandrel 3060,load mandrel 3065,expansion cone 3070,casing 3075, andfluid passages - The
drillpipe 3005 is coupled to theinnerstring adapter 3010. During operation of theapparatus 3000, thedrillpipe 3005 supports theapparatus 3000. Thedrillpipe 3005 preferably comprises a substantially hollow tubular member or members. Thedrillpipe 3005 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thedrillpipe 3005 is fabricated from coiled tubing in order to facilitate the placement of theapparatus 3000 in non-vertical weilbores. Thedrillpipe 3005 may be coupled to theinnerstring adapter 3010 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty threaded connection, or a standard threaded connection. In an exemplary embodiment, thedrillpipe 3005 is removably coupled to theinnerstring adapter 3010 by a drillpipe connection. - The
drillpipe 3005 preferably includes afluid passage 3080 that is adapted to convey fluidic materials from a surface location into thefluid passage 3085. In an exemplary embodiment, thefluid passage 3080 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
innerstring adapter 3010 is coupled to thedrill string 3005 and thesealing sleeve 3015. Theinnerstring adapter 3010 preferably comprises a substantially hollow tubular member or members. Theinnerstring adapter 3010 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength materials. In an exemplary embodiment, theinnerstring adapter 3010 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
innerstring adapter 3010 may be coupled to thedrill string 3005 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 3010 is removably coupled to thedrill pipe 3005 by a drillpipe connection. Theinnerstring adapter 3010 may be coupled to thesealing sleeve 3015 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, theinnerstring adapter 3010 is removably coupled to thesealing sleeve 3015 by a standard threaded connection. - The
innerstring adapter 3010 preferably includes afluid passage 3085 that is adapted to convey fluidic materials from thefluid passage 3080 into thefluid passage 3090. In an exemplary embodiment, thefluid passage 3085 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The sealing
sleeve 3015 is coupled to theinnerstring adapter 3010 and the firstinner sealing mandrel 3020. The sealingsleeve 3015 preferably comprises a substantially hollow tubular member or members. The sealingsleeve 3015 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the sealingsleeve 3015 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The sealing
sleeve 3015 may be coupled to theinnerstring adapter 3010 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type connection or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 3015 is removably coupled to theinnerstring adapter 3010 by a standard threaded connection. The sealingsleeve 3015 may be coupled to the firstinner sealing mandrel 3020 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, the sealingsleeve 3015 is removably coupled to the firstinner sealing mandrel 3020 by a standard threaded connection. - The sealing
sleeve 3015 preferably includes afluid passage 3090 that is adapted to convey fluidic materials from thefluid passage 3085 into thefluid passage 3095. In an exemplary embodiment, thefluid passage 3090 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The first
inner sealing mandrel 3020 is coupled to thesealing sleeve 3015, thehydraulic slips 3025, and the firstlower sealing head 3035. The firstinner sealing mandrel 3020 is further movably coupled to the firstupper sealing head 3030. The firstinner sealing mandrel 3020 preferably comprises a substantially hollow tubular member or members. The firstinner sealing mandrel 3020 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or similar high strength materials. In an exemplary embodiment, the firstinner sealing mandrel 3020 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The first
inner sealing mandrel 3020 may be coupled to thesealing sleeve 3015 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, the firstinner sealing mandrel 3020 is removably coupled to thesealing sleeve 3015 by a standard threaded connection. The firstinner sealing mandrel 3020 may be coupled to thehydraulic slips 3025 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, the firstinner sealing mandrel 3020 is removably coupled to thehydraulic slips 3025 by a standard threaded connection. The firstinner sealing mandrel 3020 may be coupled to the firstlower sealing head 3035 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, the firstinner sealing mandrel 3020 is removably coupled to the firstlower sealing head 3035 by a standard threaded connection. - The first
inner sealing mandrel 3020 preferably includes afluid passage 3095 that is adapted to convey fluidic materials from thefluid passage 3090 into thefluid passage 3100. In an exemplary embodiment, thefluid passage 3095 is adapted to convey fluidic materials such as, for example, water, drilling mud, cement, epoxy, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The first
inner sealing mandrel 3020 further preferably includesfluid passages 3110 that are adapted to convey fluidic materials from thefluid passage 3095 into the pressure chambers of thehydraulic slips 3025. In this manner, theslips 3025 are activated upon the pressurization of thefluid passage 3095 into contact with the inside surface of thecasing 3075. In an exemplary embodiment, thefluid passages 3110 are adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling fluids or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The first
inner sealing mandrel 3020 further preferably includesfluid passages 3115 that are adapted to convey fluidic materials from thefluid passage 3095 into thefirst pressure chamber 3175 defined by the firstupper sealing head 3030, the firstlower sealing head 3035, the firstinner sealing mandrel 3020, and the firstouter sealing mandrel 3040. During operation of theapparatus 3000, pressurization of thepressure chamber 3175 causes the firstupper sealing head 3030, the firstouter sealing mandrel 3040, the secondupper sealing head 3050, the secondouter sealing mandrel 3060, and theexpansion cone 3070 to move in an axial direction. - The
slips 3025 are coupled to the outside surface of the firstinner sealing mandrel 3020. During operation of theapparatus 3000, theslips 3025 are activated upon the pressurization of thefluid passage 3095 into contact with the inside surface of thecasing 3075. In this manner, theslips 3025 maintain thecasing 3075 in a substantially stationary position. - The
slips 3025 preferably includefluid passages 3125,pressure chambers 3130,spring bias 3135, andslip members 3140. Theslips 3025 may comprise any number of conventional commercially available hydraulic slips such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L retrievable bridge plug with hydraulic slips. In an exemplary embodiment, theslips 3025 comprise RTTS packer tungsten carbide hydraulic slips available from Halliburton Energy Services in order to optimally provide resistance to axial movement of thecasing 3075 during the expansion process. - The first
upper sealing head 3030 is coupled to the firstouter sealing mandrel 3040, the secondupper sealing head 3050, the secondouter sealing mandrel 3060, and theexpansion cone 3070. The firstupper sealing head 3030 is also movably coupled to the outer surface of the firstinner sealing mandrel 3020 and the inner surface of thecasing 3075. In this manner, the firstupper sealing head 3030, the firstouter sealing mandrel 3040, the secondupper sealing head 3050, the secondouter sealing mandrel 3060, and theexpansion cone 3070 reciprocate in the axial direction. - The radial clearance between the inner cylindrical surface of the first
upper sealing head 3030 and the outer surface of the firstinner sealing mandrel 3020 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of the firstupper sealing head 3030 and the outer surface of the firstinner sealing mandrel 3020 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. The radial clearance between the outer cylindrical surface of the firstupper sealing head 3030 and the inner surface of thecasing 3075 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of the firstupper sealing head 3030 and the inner surface of thecasing 3075 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 3070 during the expansion process. - The first
upper sealing head 3030 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The firstupper sealing head 3030 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, or other similar high strength materials. In an exemplary embodiment, the firstupper sealing head 3030 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The inner surface of the firstupper sealing head 3030 preferably includes one or moreannular sealing members 3145 for sealing the interface between the firstupper sealing head 3030 and the firstinner sealing mandrel 3020. The sealingmembers 3145 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 3145 comprise polypak seals available from Parker seals in order to optimally provide sealing for a long axial stroke. - In an exemplary embodiment, the first
upper sealing head 3030 includes ashoulder 3150 for supporting the firstupper sealing head 3030, firstouter sealing mandrel 3040, secondupper sealing head 3050, secondouter sealing mandrel 3060, andexpansion cone 3070 on the firstlower sealing head 3035. - The first
upper sealing head 3030 may be coupled to the firstouter sealing mandrel 3040 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, the firstupper sealing head 3030 is removably coupled to the firstouter sealing mandrel 3040 by a standard threaded connection, in an exemplary embodiment, the mechanical coupling between the firstupper sealing head 3030 and the firstouter sealing mandrel 3040 includes one ormore sealing members 3155 for fluidicly sealing the interface between the firstupper sealing head 3030 and the firstouter sealing mandrel 3040. The sealingmembers 3155 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 3155 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The first
lower sealing head 3035 is coupled to the firstinner sealing mandrel 3020 and the secondinner sealing mandrel 3045. The firstlower sealing head 3035 is also movably coupled to the inner surface of the firstouter sealing mandrel 3040. In this manner, the firstupper sealing head 3030, firstouter sealing mandrel 3040, secondupper sealing head 3050, secondouter sealing mandrel 3060, andexpansion cone 3070 reciprocate in the axial direction. The radial clearance between the outer surface of the firstlower sealing head 3035 and the inner surface of the firstouter sealing mandrel 3040 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the outer surface of the firstlower sealing head 3035 and the inner surface of theouter sealing mandrel 3040 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. - The first
lower sealing head 3035 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The firstlower sealing head 3035 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the firstlower sealing head 3035 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The outer surface of the firstlower sealing head 3035 preferably includes one or moreannular sealing members 3160 for sealing the interface between the firstlower sealing head 3035 and the firstouter sealing mandrel 3040. The sealingmembers 3160 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals, in an exemplary embodiment, the sealingmembers 3160 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The first
lower sealing head 3035 may be coupled to the firstinner sealing mandrel 3020 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, the firstlower sealing head 3035 is removably coupled to the firstinner sealing mandrel 3020 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the firstlower sealing head 3035 and the firstinner sealing mandrel 3020 includes one ormore sealing members 3165 for fluidicly sealing the interface between the firstlower sealing head 3035 and the firstinner sealing mandrel 3020. The sealingmembers 3165 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 3165 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke length. - The first
lower sealing head 3035 may be coupled to the secondinner sealing mandrel 3045 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, the firstlower sealing head 3035 is removably coupled to the secondinner sealing mandrel 3045 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the firstlower sealing head 3035 and the secondinner sealing mandrel 3045 includes one ormore sealing members 3170 for fluidicly sealing the interface between the firstlower sealing head 3035 and the secondinner sealing mandrel 3045. The sealingmembers 3170 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 3170 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The first
outer sealing mandrel 3040 is coupled to the firstupper sealing head 3030 and the secondupper sealing head 3050. The firstouter sealing mandrel 3040 is also movably coupled to the inner surface of thecasing 3075 and the outer surface of the firstlower sealing head 3035. In this manner, the firstupper sealing head 3030, firstouter sealing mandrel 3040, secondupper sealing head 3050, secondouter sealing mandrel 3060, and theexpansion cone 3070 reciprocate in the axial direction. The radial clearance between the outer surface of the firstouter sealing mandrel 3040 and the inner surface of thecasing 3075 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer surface of the firstouter sealing mandrel 3040 and the inner surface of thecasing 3075 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 3070 during the expansion process. The radial clearance between the inner surface of the firstouter sealing mandrel 3040 and the outer surface of the firstlower sealing head 3035 may range, for example, from about 0.005 to 0.125 inches. In an exemplary embodiment, the radial clearance between the inner surface of the firstouter sealing mandrel 3040 and the outer surface of the firstlower sealing head 3035 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. - The first
outer sealing mandrel 3040 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The firstouter sealing mandrel 3040 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the firstouter sealing mandrel 3040 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The first
outer sealing mandrel 3040 may be coupled to the firstupper sealing head 3030 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, the firstouter sealing mandrel 3040 is removably coupled to the firstupper sealing head 3030 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the firstouter sealing mandrel 3040 and the firstupper sealing head 3030 includes one ormore sealing members 3180 for sealing the interface between the firstouter sealing mandrel 3040 and the firstupper sealing head 3030. The sealingmembers 3180 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 3180 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The first
outer sealing mandrel 3040 may be coupled to the secondupper sealing head 3050 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, the firstouter sealing mandrel 3040 is removably coupled to the secondupper sealing head 3050 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the firstouter sealing mandrel 3040 and the secondupper sealing head 3050 includes one ormore sealing members 3185 for sealing the interface between the firstouter sealing mandrel 3040 and the secondupper sealing head 3050. The sealingmembers 3185 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 3185 compose polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - The second
inner sealing mandrel 3045 is coupled to the firstlower sealing head 3035 and the secondlower sealing head 3055. The secondinner sealing mandrel 3045 preferably comprises a substantially hollow tubular member or members. The secondinner sealing mandrel 3045 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the secondinner sealing mandrel 3045 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The second
inner sealing mandrel 3045 may be coupled to the firstlower sealing head 3035 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection or a standard threaded connection. In an exemplary embodiment, the secondinner sealing mandrel 3045 is removably coupled to the firstlower sealing head 3035 by a standard threaded connection. The secondinner sealing mandrel 3045 may be coupled to the secondlower sealing head 3055 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type connection, or a standard threaded connection. In an exemplary embodiment, the secondinner sealing mandrel 3045 is removably coupled to the secondlower sealing head 3055 by a standard threaded connection. - The second
inner sealing mandrel 3045 preferably includes afluid passage 3100 that is adapted to convey fluidic materials from thefluid passage 3095 into thefluid passage 3105. In an exemplary embodiment, thefluid passage 3100 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The second
inner sealing mandrel 3045 further preferably includesfluid passages 3120 that are adapted to convey fluidic materials from thefluid passage 3100 into thesecond pressure chamber 3190 defined by the secondupper sealing head 3050, the secondlower sealing head 3055, the secondinner sealing mandrel 3045, and the secondouter sealing mandrel 3060. During operation of theapparatus 3000, pressurization of thesecond pressure chamber 3190 causes the firstupper sealing head 3030, the firstouter sealing mandrel 3040, the secondupper sealing head 3050, the secondouter sealing mandrel 3060, and theexpansion cone 3070 to move in an axial direction. - The second
upper sealing head 3050 is coupled to the firstouter sealing mandrel 3040 and the secondouter sealing mandrel 3060. The secondupper sealing head 3050 is also movably coupled to the outer surface of the secondinner sealing mandrel 3045 and the inner surface of thecasing 3075. In this manner, the secondupper sealing head 3050 reciprocates in the axial direction. The radial clearance between the inner cylindrical surface of the secondupper sealing head 3050 and the outer surface of the secondinner sealing mandrel 3045 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner cylindrical surface of the secondupper sealing head 3050 and the outer surface of the secondinner sealing mandrel 3045 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. The radial clearance between the outer cylindrical surface of the secondupper sealing head 3050 and the inner surface of thecasing 3075 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer cylindrical surface of the secondupper sealing head 3050 and the inner surface of thecasing 3075 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 3070 during the expansion process. - The second
upper sealing head 3050 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The secondupper sealing head 3050 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the secondupper sealing head 3050 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The inner surface of the secondupper sealing head 3050 preferably includes one or more annular sealing members3195 for sealing the interface between the secondupper sealing head 3050 and the secondinner sealing mandrel 3045. The sealing members3195 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealing members3195 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - In an exemplary embodiment, the second
upper sealing head 3050 includes ashoulder 3200 for supporting the firstupper sealing head 3030, firstouter sealing mandrel 3040, secondupper sealing head 3050, secondouter sealing mandrel 3060, andexpansion cone 3070 on the secondlower sealing head 3055. - The second
upper sealing head 3050 may be coupled to the firstouter sealing mandrel 3040 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, the secondupper sealing head 3050 is removably coupled to the firstouter sealing mandrel 3040 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the secondupper sealing head 3050 and the firstouter sealing mandrel 3040 includes one ormore sealing members 3185 for fluidicly sealing the interface between the secondupper sealing head 3050 and the firstouter sealing mandrel 3040. The secondupper sealing head 3050 may be coupled to the secondouter sealing mandrel 3060 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type threaded connection, or a standard threaded connection. In an exemplary embodiment, the secondupper sealing head 3050 is removably coupled to the secondouter sealing mandrel 3060 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the secondupper sealing head 3050 and the secondouter sealing mandrel 3060 includes one ormore sealing members 3205 for fiuldicly sealing the interface between the secondupper sealing head 3050 and the secondouter sealing mandrel 3060. - The second
lower sealing head 3055 is coupled to the secondinner sealing mandrel 3045 and theload mandrel 3065. The secondlower sealing head 3055 is also movably coupled to the inner surface of the secondouter sealing mandrel 3060. In this manner, the firstupper sealing head 3030, firstouter sealing mandrel 3040, secondupper sealing mandrel 3050, secondouter sealing mandrel 3060, andexpansion cone 3070 reciprocate in the axial direction. The radial clearance between the outer surface of the secondlower sealing head 3055 and the inner surface of the secondouter sealing mandrel 3060 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the outer surface of the secondlower sealing head 3055 and the inner surface of the secondouter sealing mandrel 3060 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. - The second
lower sealing head 3055 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The secondlower sealing head 3055 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength materials. In an exemplary embodiment, the secondlower sealing head 3055 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. The outer surface of the secondlower sealing head 3055 preferably includes one or moreannular sealing members 3210 for sealing the interface between the secondlower sealing head 3055 and the secondouter sealing mandrel 3060. The sealingmembers 3210 may comprise any number of conventional commercially available annular sealing members such as, for example, o-rings, polypak seals, or metal spring energized seals. In an exemplary embodiment, the sealingmembers 3210 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - The second
lower sealing head 3055 may be coupled to the secondinner sealing mandrel 3045 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, the secondlower sealing head 3055 is removably coupled to the secondinner sealing mandrel 3045 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between thelower sealing head 3055 and the secondinner sealing mandrel 3045 includes one ormore sealing members 3215 for fluidicly sealing the interface between the secondlower sealing head 3055 and the secondinner sealing mandrel 3045. The sealingmembers 3215 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 3215 comprise polypak seals available from Parker Seals in order to optimally provide sealing for long axial strokes. - The second
lower sealing head 3055 may be coupled to theload mandrel 3065 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, the secondlower sealing head 3055 is removably coupled to theload mandrel 3065 by a standard threaded connection. In an exemplary embodiment, the mechanical coupling between the secondlower sealing head 3055 and theload mandrel 3065 includes one ormore sealing members 3220 for fluidicly sealing the interface between the secondlower sealing head 3055 and theload mandrel 3065. The sealingmembers 3220 may comprise any number of conventional commercially available sealing members such as, for example, o-rings, polypak seals or metal spring energized seals. In an exemplary embodiment, the sealingmembers 3220 comprise polypak seals available from Parker Seals in order to optimally provide sealing for a long axial stroke. - In an exemplary embodiment, the second
lower sealing head 3055 includes athroat passage 3225 fluidicly coupled between thefluid passages throat passage 3225 is preferably of reduced size and is adapted to receive and engage with aplug 3230, or other similar device. In this manner, thefluid passage 3100 is fluidicly isolated from thefluid passage 3105. In this manner, thepressure chambers plug 3230 in thethroat passage 3225 also pressurizes thepressure chambers 3130 of thehydraulic slips 3025. - The second
outer sealing mandrel 3060 is coupled to the secondupper sealing head 3050 and theexpansion cone 3070. The secondouter sealing mandrel 3060 is also movably coupled to the inner surface of thecasing 3075 and the outer surface of the secondlower sealing head 3055. In this manner, the firstupper sealing head 3030, firstouter sealing mandrel 3040, secondupper sealing head 3050, secondouter sealing mandrel 3060, and theexpansion cone 3070 reciprocate in the axial direction. The radial clearance between the outer surface of the secondouter sealing mandrel 3060 and the inner surface of thecasing 3075 may range, for example, from about 0.025 to 0.375 inches. In an exemplary embodiment, the radial clearance between the outer surface of the secondouter sealing mandrel 3060 and the inner surface of thecasing 3075 ranges from about 0.025 to 0.125 inches in order to optimally provide stabilization for theexpansion cone 3070 during the expansion process. The radial clearance between the inner surface of the secondouter sealing mandrel 3060 and the outer surface of the secondlower sealing head 3055 may range, for example, from about 0.0025 to 0.05 inches. In an exemplary embodiment, the radial clearance between the inner surface of the secondouter sealing mandrel 3060 and the outer surface of the secondlower sealing head 3055 ranges from about 0.005 to 0.01 inches in order to optimally provide minimal radial clearance. - The second
outer sealing mandrel 3060 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. The secondouter sealing mandrel 3060 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, the secondouter sealing mandrel 3060 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The second
outer sealing mandrel 3060 may be coupled to the secondupper sealing head 3050 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, theouter sealing mandrel 3060 is removably coupled to the secondupper sealing head 3050 by a standard threaded connection. The secondouter sealing mandrel 3060 may be coupled to theexpansion cone 3070 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, or a standard threaded connection. In an exemplary embodiment, the secondouter sealing mandrel 3060 is removably coupled to theexpansion cone 3070 by a standard threaded connection. - The first
upper sealing head 3030, the firstlower sealing head 3035, the firstinner sealing mandrel 3020, and the firstouter sealing mandrel 3040 together define thefirst pressure chamber 3175. The secondupper sealing head 3050, the secondlower sealing head 3055, the secondinner sealing mandrel 3045, and the secondouter sealing mandrel 3060 together define thesecond pressure chamber 3190. The first and second pressure chambers,3175 and3190, are fluidicly coupled to the passages,3095 and3100, via one or more passages,3115 and3120. During operation of theapparatus 3000, theplug 3230 engages with thethroat passage 3225 to fluidicly isolate thefluid passage 3100 from thefluid passage 3105. The pressure chambers,3175 and3190, are then pressurized which in turn causes the firstupper sealing head 3030, the firstouter sealing mandrel 3040, the secondupper sealing head 3050, the secondouter sealing mandrel 3060, andexpansion cone 3070 to reciprocate in the axial direction. The axial motion of theexpansion cone 3070 in turn expands thecasing 3075 in the radial direction. The use of a plurality of pressure chambers,3175 and3190, effectively multiplies the available driving force for theexpansion cone 3070. - The
load mandrel 3065 is coupled to the secondlower sealing head 3055. Theload mandrel 3065 preferably comprises an annular member having substantially cylindrical inner and outer surfaces. Theload mandrel 3065 may be fabricated from any number of conventional commercially available materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In an exemplary embodiment, theload mandrel 3065 is fabricated from stainless steel in order to optimally provide high strength, corrosion resistance, and low friction surfaces. - The
load mandrel 3065 may be coupled to thelower sealing head 3055 using any number of conventional commercially available mechanical couplings such as, for example, epoxy, cement, water, drilling mud, or lubricants. In an exemplary embodiment, theload mandrel 3065 is removably coupled to thelower sealing head 3055 by a standard threaded connection. - The
load mandrel 3065 preferably includes afluid passage 3105 that is adapted to convey fluidic materials from thefluid passage 3100 to the region outside of theapparatus 3000. In an exemplary embodiment, thefluid passage 3105 is adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute. - The
expansion cone 3070 is coupled to the secondouter sealing mandrel 3060. Theexpansion cone 3070 is also movably coupled to the inner surface of thecasing 3075. In this manner, the firstupper sealing head 3030, firstouter sealing mandrel 3040, secondupper sealing head 3050, secondouter sealing mandrel 3060, and theexpansion cone 3070 reciprocate in the axial direction. The reciprocation of theexpansion cone 3070 causes thecasing 3075 to expand in the radial direction. - The
expansion cone 3070 preferably comprises an annular member having substantially cylindrical inner and conical outer surfaces. The outside radius of the outside conical surface may range, for example, from about 2 to 34 inches. In an exemplary embodiment, the outside radius of the outside conical surface ranges from about 3 to 28 inches in order to optimally provide anexpansion cone 3070 for expanding typical casings. The axial length of theexpansion cone 3070 may range, for example, from about 2 to 8 times the maximum outer diameter of theexpansion cone 3070. In an exemplary embodiment, the axial length of theexpansion cone 3070 ranges from about 3 to 5 times the maximum outer diameter of theexpansion cone 3070 in order to optimally provide stabilization and centralization of theexpansion cone 3070 during the expansion process. In an exemplary embodiment, the maximum outside diameter of theexpansion cone 3070 is between about 95 to 99% of the inside diameter of the existing wellbore that thecasing 3075 will be joined with. In an exemplary embodiment, the angle of attack of theexpansion cone 3070 ranges from about 5 to 30 degrees in order to optimally balance the frictional forces with the radial expansion forces. - The
expansion cone 3070 may be fabricated from any number of conventional commercially available materials such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramics, or other similar high strength materials. In an exemplary embodiment, theexpansion cone 3070 is fabricated from D2 machine tool steel in order to optimally provide high strength and resistance to wear and galling. In an exemplary embodiment, the outside surface of theexpansion cone 3070 has a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide high strength and resistance to wear and galling. - The
expansion cone 3070 may be coupled to the secondoutside sealing mandrel 3060 using any number of conventional commercially available mechanical couplings such as, for example, drillpipe connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch type connection or a standard threaded connection. In an exemplary embodiment, theexpansion cone 3070 is coupled to the secondoutside sealing mandrel 3060 using a standard threaded connection in order to optimally provide high strength and easy disassembly. - The
casing 3075 is removably coupled to theslips 3025 and theexpansion cone 3070. Thecasing 3075 preferably comprises a tubular member. Thecasing 3075 may be fabricated from any number of conventional commercially available materials such as, for example, slotted tubulars, oilfield country tubular goods, carbon steel, low alloy steel, stainless steel or other similar high strength materials. In an exemplary embodiment, thecasing 3075 is fabricated from oilfield country tubular goods available from various foreign and domestic steel mills in order to optimally provide high strength. - In an exemplary embodiment, the
upper end 3235 of thecasing 3075 includes athin wall section 3240 and an outerannular sealing member 3245. In an exemplary embodiment, the wall thickness of thethin wall section 3240 is about 50 to 100% of the regular wall thickness of thecasing 3075. In this manner, theupper end 3235 of thecasing 3075 may be easily radially expanded and deformed into intimate contact with the lower end of an existing section of wellbore casing. In an exemplary embodiment, the lower end of the existing section of casing also includes a thin wall section. In this manner, the radial expansion of the thinwalled section 3240 ofcasing 3075 into the thin walled section of the existing wellbore casing results in a wellbore casing having a substantially constant inside diameter. - The
annular sealing member 3245 may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal or plastic. In an exemplary embodiment, theannular sealing member 3245 is fabricated from StrataLock epoxy in order to optimally provide compressibility and wear resistance. The outside diameter of theannular sealing member 3245 preferably ranges from about 70 to 95% of the inside diameter of the lower section of the wellbore casing that thecasing 3075 is joined to. In this manner, after radial expansion, theannular sealing member 3245 optimally provides a fluidic seal and also preferably optimally provides sufficient frictional force with the inside surface of the existing section of wellbore casing during the radial expansion of thecasing 3075 to support thecasing 3075. - In an exemplary embodiment, the
lower end 3250 of thecasing 3075 includes athin wall section 3255 and an outerannular sealing member 3260. In an exemplary embodiment, the wall thickness of thethin wall section 3255 is about 50 to 100% of the regular wall thickness of thecasing 3075. In this manner, thelower end 3250 of thecasing 3075 may be easily expanded and deformed. Furthermore, in this manner, an other section of casing may be easily joined with thelower end 3250 of thecasing 3075 using a radial expansion process. In an exemplary embodiment, the upper end of the other section of casing also includes a thin wall section. In this manner, the radial expansion of the thin walled section of the upper end of the other casing into the thinwalled section 3255 of thelower end 3250 of thecasing 3075 results in a wellbore casing having a substantially constant inside diameter. - The upper
annular sealing member 3245 may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal or plastic. In an exemplary embodiment, the upperannular sealing member 3245 is fabricated from Stratalock epoxy in order to optimally provide compressibility and resistance to wear. The outside diameter of the upperannular sealing member 3245 preferably ranges from about 70 to 95% of the inside diameter of the lower section of the existing wellbore casing that thecasing 3075 is joined to. In this manner, after radial expansion, the upperannular sealing member 3245 preferably provides a fluidic seal and also preferably provides sufficient frictional force with the inside wall of the wellbore during the radial expansion of thecasing 3075 to support thecasing 3075. - The lower
annular sealing member 3260 may be fabricated from any number of conventional commercially available sealing materials such as, for example, epoxy, rubber, metal or plastic. In an exemplary embodiment, the lowerannular sealing member 3260 is fabricated from StrataLock epoxy in order to optimally provide compressibility and resistance to wear. The outside diameter of the lowerannular sealing member 3260 preferably ranges from about 70 to 95% of the inside diameter of the lower section of the existing wellbore casing that thecasing 3075 is joined to. In this manner, the lowerannular sealing member 3260 preferably provides a fluidic seal and also preferably provides sufficient frictional force with the inside wall of the wellbore during the radial expansion of thecasing 3075 to support thecasing 3075. - During operation, the
apparatus 3000 is preferably positioned in a wellbore with theupper end 3235 of thecasing 3075 positioned in an overlapping relationship with the lower end of an existing wellbore casing. In an exemplary embodiment, thethin wall section 3240 of thecasing 3075 is positioned in opposing overlapping relation with the thin wall section and outer annular sealing member of the lower end of the existing section of wellbore casing. In this manner, the radial expansion of thecasing 3075 will compress the thin wall sections and annular compressible members of theupper end 3235 of thecasing 3075 and the lower end of the existing wellbore casing into intimate contact. During the positioning of theapparatus 3000 in the wellbore, thecasing 3000 is preferably supported by theexpansion cone 3070. - After positioning the
apparatus 3000, a first fluidic material is then pumped into thefluid passage 3080. The first fluidic material may comprise any number of conventional commercially available materials such as, for example, drilling mud, water, epoxy, cement, slag mix or lubricants. In an exemplary embodiment the first fluidic material comprises a hardenable fluidic sealing material such as, for example, cement, epoxy, or slag mix in order to optimally provide a hardenable outer annular body around the expandedcasing 3075. - The first fluidic material may be pumped into the
fluid passage 3080 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute. In an exemplary embodiment, the first fluidic material is pumped into thefluid passage 3080 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operating efficiency. - The first fluidic material pumped into the
fluid passage 3080 passes through thefluid passages apparatus 3000. The first fluidic material then preferably fills the annular region between the outside of theapparatus 3000 and the interior walls of the wellbore. - The
plug 3230 is then introduced into thefluid passage 3080. Theplug 3230 lodges in thethroat passage 3225 and fluidicly isolates and blocks off thefluid passage 3100. In an exemplary embodiment, a couple of volumes of a non-hardenable fluidic material are then pumped into thefluid passage 3080 in order to remove any hardenable fluidic material contained within and to ensure that none of the fluid passages are blocked. - A second fluidic material is then pumped into the
fluid passage 3080. The second fluidic material may comprise any number of conventional commercially available materials such as, for example, water, drilling gases, drilling mud or lubricant. In an exemplary embodiment, the second fluidic material comprises a non-hardenable fluidic material such as, for example, water, drilling mud, drilling gases, or lubricant in order to optimally provide pressurization of thepressure chambers - The second fluidic material may be pumped into the
fluid passage 3080 at operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500 gallons/minute. In an exemplary embodiment, the second fluidic material is pumped into thefluid passage 3080 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order to optimally provide operational efficiency. - The second fluidic material pumped into the
fluid passage 3080 passes through thefluid passages pressure chambers 3130 of theslips 3025, and into thepressure chambers pressure chambers - The pressurization of the
pressure chambers 3130 causes thehydraulic slip members 3140 to expand in the radial direction and grip the interior surface of thecasing 3075. Thecasing 3075 is then preferably maintained in a substantially stationary position. - The pressurization of the
pressure chambers upper sealing head 3030, firstouter sealing mandrel 3040, secondupper sealing head 3050, secondouter sealing mandrel 3060, andexpansion cone 3070 to move in an axial direction relative to thecasing 3075. In this manner, theexpansion cone 3070 will cause thecasing 3075 to expand in the radial direction, beginning with thelower end 3250 of thecasing 3075. - During the radial expansion process, the
casing 3075 is prevented from moving in an upward direction by theslips 3025. A length of thecasing 3075 is then expanded in the radial direction through the pressurization of thepressure chambers casing 3075 that is expanded during the expansion process will be proportional to the stroke length of the firstupper sealing head 3030, firstouter sealing mandrel 3040, secondupper sealing head 3050, andexpansion cone 3070. - Upon the completion of a stroke, the operating pressure of the second fluidic material is reduced and the first
upper sealing head 3030, firstouter sealing mandrel 3040, secondupper sealing head 3050, secondouter sealing mandrel 3060, andexpansion cone 3070 drop to their rest positions with thecasing 3075 supported by theexpansion cone 3070. The reduction in the operating pressure of the second fluidic material also causes thespring bias 3135 of theslips 3025 to pull theslip members 3140 away from the inside walls of thecasing 3075. - The position of the
drillpipe 3005 is preferably adjusted throughout the radial expansion process in order to maintain the overlapping relationship between the thin walled sections of the lower end of the existing wellbore casing and the upper end of thecasing 3235. In an exemplary embodiment, the stroking of theexpansion cone 3070 is then repeated, as necessary, until the thinwalled section 3240 of theupper end 3235 of thecasing 3075 is expanded into the thin walled section of the lower end of the existing wellbore casing. In this manner, a wellbore casing is formed including two adjacent sections of casing having a substantially constant inside diameter. This process may then be repeated for the entirety of the wellbore to provide a wellbore casing thousands of feet in length having a substantially constant inside diameter. - In an exemplary embodiment, during the final stroke of the
expansion cone 3070, theslips 3025 are positioned as close as possible to the thinwalled section 3240 of theupper end 3235 of thecasing 3075 in order minimize slippage between thecasing 3075 and the existing wellbore casing at the end of the radial expansion process. Alternatively, or in addition, the outside diameter of the upperannular sealing member 3245 is selected to ensure sufficient interference fit with the inside diameter of the lower end of the existing casing to prevent axial displacement of thecasing 3075 during the final stroke. Alternatively, or in addition, the outside diameter of the lowerannular sealing member 3260 is selected to provide an interference fit with the inside walls of the wellbore at an earlier point in the radial expansion process so as to prevent further axial displacement of thecasing 3075. In this final alternative, the interference fit is preferably selected to permit expansion of thecasing 3075 by pulling theexpansion cone 3070 out of the wellbore, without having to pressurize thepressure chambers - During the radial expansion process, the pressurized areas of the
apparatus 3000 are preferably limited to thefluid passages pressure chambers 3130 within theslips 3025, and thepressure chambers casing 3075. This permits the use of operating pressures higher than thecasing 3075 could normally withstand. - Once the
casing 3075 has been completely expanded off of theexpansion cone 3070, the remaining portions of theapparatus 3000 are removed from the wellbore. In an exemplary embodiment, the contact pressure between the deformed thin wall sections and compressible annular members of the lower end of the existing casing and theupper end 3235 of thecasing 3075 ranges from about 400 to 10,000 psi in order to optimally support thecasing 3075 using the existing wellbore casing. - In this manner, the
casing 3075 is radially expanded into contact with an existing section of casing by pressurizing theinterior fluid passages pressure chambers 3130 of theslips 3025 and thepressure chambers apparatus 3000. - In an exemplary embodiment, as required, the annular body of hardenable fluidic material is then allowed to cure to form a rigid outer annular body about the expanded
casing 3075. In the case where thecasing 3075 is slotted, the cured fluidic material preferably permeates and envelops the expandedcasing 3075. The resulting new section of wellbore casing includes the expandedcasing 3075 and the rigid outer annular body. The overlapping joint between the pre-existing wellbore casing and the expandedcasing 3075 includes the deformed thin wall sections and the compressible outer annular bodies. The inner diameter of the resulting combined wellbore casings is substantially constant. In this manner, a mono-diameter wellbore casing is formed. This process of expanding overlapping tubular members having thin wall end portions with compressible annular bodies into contact can be repeated for the entire length of a wellbore. In this manner, a mono-diameter wellbore casing can be provided for thousands of feet in a subterranean formation. - In an exemplary embodiment, as the
expansion cone 3070 nears theupper end 3235 of thecasing 3075, the operating flow rate of the second fluidic material is reduced in order to minimize shock to theapparatus 3000. In an alternative embodiment, theapparatus 3000 includes a shock absorber for absorbing the shock created by the completion of the radial expansion of thecasing 3075. - In an exemplary embodiment, the reduced operating pressure of the second fluidic material ranges from about 100 to 1,000 psi as the
expansion cone 3070 nears the end of thecasing 3075 in order to optimally provide reduced axial movement and velocity of theexpansion cone 3070. In an exemplary embodiment, the operating pressure of the second fluidic material is reduced during the return stroke of theapparatus 3000 to the range of about 0 to 500 psi in order minimize the resistance to the movement of theexpansion cone 3070 during the return stroke. In an exemplary embodiment, the stroke length of theapparatus 3000 ranges from about 10 to 45 feet in order to optimally provide equipment that can be easily handled by typical oil well rigging equipment and also minimize the frequency at which theapparatus 3000 must be re-stroked. - In an alternative embodiment, at least a portion of one or both of the upper sealing heads,3030 and3050, includes an expansion cone for radially expanding the
casing 3075 during operation of theapparatus 3000 in order to increase the surface area of thecasing 3075 acted upon during the radial expansion process. In this manner, the operating pressures can be reduced. - Alternatively, the
apparatus 3000 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, theapparatus 3000 may be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of a hardenable material. Alternatively, theapparatus 3000 may be used to expand a tubular support member in a hole. - Referring now to
FIG. 21 , anapparatus 3330 for isolating subterranean zones will be described. Awellbore 3305 including acasing 3310 are positioned in asubterranean formation 3315. Thesubterranean formation 3315 includes a number of productive and non-productive zones, including awater zone 3320 and a targetedoil sand zone 3325. During exploration of thesubterranean formation 3315, thewellbore 3305 may be extended in a well known manner to traverse the various productive and non-productive zones, including thewater zone 3320 and the targetedoil sand zone 3325. - In an exemplary embodiment, in order to fluidicly isolate the
water zone 3320 from the targetedoil sand zone 3325, anapparatus 3330 is provided that includes one or more sections ofsolid casing 3335, one or moreexternal seals 3340, one or more sections of slottedcasing 3345, one or more intermediate sections ofsolid casing 3350, and asolid shoe 3355. - The
solid casing 3335 may provide a fluid conduit that transmits fluids and other materials from one end of thesolid casing 3335 to the other end of thesolid casing 3335. Thesolid casing 3335 may comprise any number of conventional commercially available sections of solid tubular casing such as, for example, oilfield tubulars fabricated from chromium steel or fiberglass. In an exemplary embodiment, thesolid casing 3335 comprises oilfield tubulars available from various foreign and domestic steel mills. - The
solid casing 3335 is preferably coupled to thecasing 3310. Thesolid casing 3335 may be coupled to thecasing 3310 using any number of conventional commercially available processes such as, for example, welding, slotted and expandable connectors, or expandable solid connectors. In an exemplary embodiment, thesolid casing 3335 is coupled to thecasing 3310 by using expandable solid connectors. Thesolid casing 3335 may comprise a plurality of suchsolid casings 3335. - The
solid casing 3335 is preferably coupled to one more of the slottedcasings 3345. Thesolid casing 3335 may be coupled to the slottedcasing 3345 using any number of conventional commercially available processes such as, for example, welding, or slotted and expandable connectors. In an exemplary embodiment, thesolid casing 3335 is coupled to the slottedcasing 3345 by expandable solid connectors. - In an exemplary embodiment, the
casing 3335 includes onemore valve members 3360 for controlling the flow of fluids and other materials within the interior region of thecasing 3335. In an alternative embodiment, during the production mode of operation, an internal tubular string with various arrangements of packers, perforated tubing, sliding sleeves, and valves may be employed within the apparatus to provide various options for commingling and isolating subterranean zones from each other while providing a fluid path to the surface. - In an exemplary embodiment, the
casing 3335 is placed into thewellbore 3305 by expanding thecasing 3335 in the radial direction into intimate contact with the interior walls of thewellbore 3305. Thecasing 3335 may be expanded in the radial direction using any number of conventional commercially available methods. In an exemplary embodiment, thecasing 3335 is expanded in the radial direction using one or more of the processes and apparatus described within the present disclosure. - The
seals 3340 prevent the passage of fluids and other materials within theannular region 3365 between thesolid casings wellbore 3305. Theseals 3340 may comprise any number of conventional commercially available sealing materials suitable for sealing a casing in a wellbore such as, for example, lead, rubber or epoxy. In an exemplary embodiment, theseals 3340 comprise Stratalok epoxy material available from Halliburton Energy Services. - The slotted
casing 3345 permits fluids and other materials to pass into and out of the interior of the slotted easing3345 from and to theannular region 3365. In this manner, oil and gas may be produced from a producing subterranean zone within a subterranean formation. The slottedcasing 3345 may comprise any number of conventional commercially available sections of slotted tubular casing. In an exemplary embodiment, the slottedcasing 3345 comprises expandable slotted tubular casing available from Petroline in Abeerdeen, Scotland. In an exemplary embodiment, the slotted casing145 comprises expandable slotted sandscreen tubular casing available from Petroline in Abeerdeen, Scotland. - The slotted
casing 3345 is preferably coupled to one or moresolid casing 3335. The slottedcasing 3345 may be coupled to thesolid casing 3335 using any number of conventional commercially available processes such as, for example, welding, or slotted or solid expandable connectors. In an exemplary embodiment, the slottedcasing 3345 is coupled to thesolid casing 3335 by expandable solid connectors. - The slotted
casing 3345 is preferably coupled to one or more intermediatesolid casings 3350. The slottedcasing 3345 may be coupled to the intermediatesolid casing 3350 using any number of conventional commercially available processes such as, for example, welding or expandable solid or slotted connectors. In an exemplary embodiment, the slottedcasing 3345 is coupled to the intermediatesolid casing 3350 by expandable solid connectors. - The last section of slotted
casing 3345 is preferably coupled to theshoe 3355. The last slottedcasing 3345 may be coupled to theshoe 3355 using any number of conventional commercially available processes such as, for example, welding or expandable solid or slotted connectors. In an exemplary embodiment, the last slottedcasing 3345 is coupled to theshoe 3355 by an expandable solid connector. - In an alternative embodiment, the
shoe 3355 is coupled directly to the last one of the intermediatesolid casings 3350. - In an exemplary embodiment, the slotted
casings 3345 are positioned within thewellbore 3305 by expanding the slottedcasings 3345 in a radial direction into intimate contact with the interior walls of thewellbore 3305. The slottedcasings 3345 may be expanded in a radial direction using any number of conventional commercially available processes. In an exemplary embodiment, the slottedcasings 3345 are expanded in the radial direction using one or more of the processes and apparatus disclosed in the present disclosure with reference toFIGS. 14 a-20. - The intermediate
solid casing 3350 permits fluids and other materials to pass between adjacent slottedcasings 3345. The intermediatesolid casing 3350 may comprise any number of conventional commercially available sections of solid tubular casing such as, for example, oilfield tubulars fabricated from chromium steel or fiberglass. In an exemplary embodiment, the intermediatesolid casing 3350 comprises oilfield tubulars available from foreign and domestic steel mills. - The intermediate
solid casing 3350 is preferably coupled to one or more sections of the slottedcasing 3345. The intermediatesolid casing 3350 may be coupled to the slottedcasing 3345 using any number of conventional commercially available processes such as, for example, welding, or solid or slotted expandable connectors. In an exemplary embodiment, the intermediatesolid casing 3350 is coupled to the slottedcasing 3345 by expandable solid connectors. The intermediatesolid easing 3350 may comprise a plurality of such intermediatesolid casing 3350. - In an exemplary embodiment, each intermediate
solid casing 3350 includes onemore valve members 3370 for controlling the flow of fluids and other materials within the interior region of theintermediate casing 3350. In an alternative embodiment, as will be recognized by persons having ordinary skill in the art and the benefit of the present disclosure, during the production mode of operation, an internal tubular string with various arrangements of packers, perforated tubing, sliding sleeves, and valves may be employed within the apparatus to provide various options for commingling and isolating subterranean zones from each other while providing a fluid path to the surface. - In an exemplary embodiment, the
intermediate casing 3350 is placed into thewellbore 3305 by expanding theintermediate casing 3350 in the radial direction into intimate contact with the interior walls of thewellbore 3305. Theintermediate casing 3350 may be expanded in the radial direction using any number of conventional commercially available methods. - In an alternative embodiment, one or more of the intermediate
solid casings 3350 may be omitted. In an exemplary embodiment, one or more of the slottedcasings 3345 are provided with one ormore seals 3340. - The
shoe 3355 provides a support member for theapparatus 3330. In this manner, various production and exploration tools may be supported by theshow 3350. Theshoe 3350 may comprise any number of conventional commercially available shoes suitable for use in a wellbore such as, for example, cement filled shoe, or an aluminum or composite shoe. In an exemplary embodiment, theshoe 3350 comprises an aluminum shoe available from Halliburton. In an exemplary embodiment, theshoe 3355 is selected to provide sufficient strength in compression and tension to permit the use of high capacity production and exploration tools. - In an exemplary embodiment the
apparatus 3330 includes a plurality ofsolid casings 3335, a plurality ofseals 3340, a plurality of slottedcasings 3345, a plurality of intermediatesolid casings 3350, and ashoe 3355. More generally, theapparatus 3330 may comprise one or moresolid casings 3335, each with one ormore valve members 3360, n slottedcasings 3345, n-1 intermediatesolid casings 3350, each with one ormore valve members 3370, and ashoe 3355. - During operation of the
apparatus 3330, oil and gas may be controllably produced from the targetedoil sand zone 3325 using the slottedcasings 3345. The oil and gas may then be transported to a surface location using thesolid casing 3335. The use of intermediatesolid casings 3350 withvalve members 3370 permits isolated sections of thezone 3325 to be selectively isolated for production. Theseals 3340 permit thezone 3325 to be fiuldicly isolated from thezone 3320. Theseals 3340 further permits isolated sections of thezone 3325 to be fiuldicly isolated from each other. In this manner, theapparatus 3330 permits unwanted and/or non-productive subterranean zones to be fluidicly isolated. - In an alternative embodiment, as will be recognized by persons having ordinary skill in the art and also having the benefit of the present disclosure, during the production mode of operation, an internal tubular string with various arrangements of packers, perforated tubing, sliding sleeves, and valves may be employed within the apparatus to provide various options for commingling and isolating subterranean zones from each other while providing a fluid path to the surface.
- A method of creating a casing in a borehole located in a subterranean formation has been described that includes installing a tubular liner and a mandrel in the borehole. A body of fluidic material is then injected into the borehole. The tubular liner is then radially expanded by extruding the liner off of the mandrel. The injecting preferably includes injecting a hardenable fluidic sealing material into an annular region located between the borehole and the exterior of the tubular liner; and a non hardenable fluidic material into an interior region of the tubular liner below the mandrel. The method preferably includes fluidicly isolating the annular region from the interior region before injecting the second quantity of the non hardenable sealing material into the interior region. The injecting the hardenable fluidic sealing material is preferably provided at operating pressures and flow rates ranging from about 0 to 5000 psi and 0 to 1,500 gallons/min. The injecting of the non hardenable fluidic material is preferably provided at operating pressures and flow rates ranging from about 500 to 9000 psi and 40 to 3,000 gallons/min. The injecting of the non hardenable fluidic material is preferably provided at reduced operating pressures and flow rates during an end portion of the extruding. The non hardenable fluidic material is preferably injected below the mandrel. The method preferably includes pressurizing a region of the tubular liner below the mandrel. The region of the tubular liner below the mandrel is preferably pressurized to pressures ranging from about 500 to 9,000 psi. The method preferably includes fluidicly isolating an interior region of the tubular liner from an exterior region of the tubular liner. The method further preferably includes curing the hardenable sealing material, and removing at least a portion of the cured sealing material located within the tubular liner. The method further preferably includes overlapping the tubular liner with an existing wellbore casing. The method further preferably includes sealing the overlap between the tubular liner and the existing wellbore casing. The method further preferably includes supporting the extruded tubular liner using the overlap with the existing wellbore casing. The method further preferably includes testing the integrity of the seal in the overlap between the tubular liner and the existing wellbore casing. The method further preferably includes removing at least a portion of the hardenable fluidic sealing material within the tubular liner before curing. The method further preferably includes lubricating the surface of the mandrel. The method further preferably includes absorbing shock. The method further preferably includes catching the mandrel upon the completion of the extruding.
- An apparatus for creating a casing in a borehole located in a subterranean formation has been described that includes a support, member, a mandrel, a tubular member, and a shoe. The support member includes a first fluid passage. The mandrel is coupled to the support member and includes a second fluid passage. The tubular member is coupled to the mandrel. The shoe is coupled to the tubular liner and includes a third fluid passage. The first, second and third fluid passages are operably coupled. The support member preferably further includes a pressure relief passage, and a flow control valve coupled to the first fluid passage and the pressure relief passage. The support member further preferably includes a shock absorber. The support member preferably includes one or more sealing members adapted to prevent foreign material from entering an interior region of the tubular member. The mandrel is preferably expandable. The tubular member is preferably fabricated from materials selected from the group consisting of Oilfield Country Tubular Goods, 13 chromium steel tubing/casing, and plastic casing. The tubular member preferably has inner and outer diameters ranging from about 3 to 15.5 inches and 3.5 to 16 inches, respectively. The tubular member preferably has a plastic yield point ranging from about 40,000 to 135,000 psi. The tubular member preferably includes one or more sealing members at an end portion. The tubular member preferably includes one or more pressure relief holes at an end portion. The tubular member preferably includes a catching member at an end portion for slowing down the mandrel. The shoe preferably includes an inlet port coupled to the third fluid passage, the inlet port adapted to receive a plug for blocking the inlet port. The shoe preferably is drillable.
- A method of joining a second tubular member to a first tubular member, the first tubular member having an inner diameter greater than an outer diameter of the second tubular member, has been described that includes positioning a mandrel within an interior region of the second tubular member, positioning the first and second tubular members in an overlapping relationship, pressurizing a portion of the interior region of the second tubular member; and extruding the second tubular member off of the mandrel into engagement with the first tubular member. The pressurizing of the portion of the interior region of the second tubular member is preferably provided at operating pressures ranging from about 500 to 9,000 psi. The pressurizing of the portion of the interior region of the second tubular member is preferably provided at reduced operating pressures during a latter portion of the extruding. The method further preferably includes sealing the overlap between the first and second tubular members. The method further preferably includes supporting the extruded first tubular member using the overlap with the second tubular member. The method further preferably includes lubricating the surface of the mandrel. The method further preferably includes absorbing shock.
- A liner for use in creating a new section of wellbore casing in a subterranean formation adjacent to an already existing section of wellbore casing has been described that includes an annular member. The annular member includes one or more sealing members at an end portion of the annular member, and one or more pressure relief passages at an end portion of the annular member.
- A wellbore casing has been described that includes a tubular liner and an annular body of a cured fluidic sealing material. The tubular liner is formed by the process of extruding the tubular liner off of a mandrel. The tubular liner is preferably formed by the process of placing the tubular liner and mandrel within the wellbore, and pressurizing an interior portion of the tubular liner. The annular body of the cured fluidic sealing material is preferably formed by the process of injecting a body of hardenable fluidic sealing material into an annular region external of the tubular liner. During the pressurizing, the interior portion of the tubular liner is preferably fluidicly isolated from an exterior portion of the tubular liner. The interior portion of the tubular liner is preferably pressurized to pressures ranging from about 500 to 9,000 psi. The tubular liner preferably overlaps with an existing wellbore casing. The wellbore casing preferably further includes a seal positioned in the overlap between the tubular liner and the existing wellbore casing. Tubular liner is preferably supported the overlap with the existing wellbore casing.
- A method of repairing an existing section of a wellbore casing within a borehole has been described that includes installing a tubular liner and a mandrel within the wellbore casing, injecting a body of a fluidic material into the borehole, pressurizing a portion of an interior region of the tubular liner, and radially expanding the liner in the borehole by extruding the liner off of the mandrel. In an exemplary embodiment, the fluidic material is selected from the group consisting of slag mix, cement, drilling mud, and epoxy. In an exemplary embodiment, the method further includes fluidicly isolating an interior region of the tubular liner from an exterior region of the tubular liner. In an exemplary embodiment, the injecting of the body of fluidic material is provided at operating pressures and flow rates ranging from about 500 to 9,000 psi and 40 to 3,000 gallons/min. In an exemplary embodiment, the injecting of the body of fluidic material is provided at reduced operating pressures and flow rates during an end portion of the extruding. In an exemplary embodiment, the fluidic material is injected below the mandrel. In an exemplary embodiment, a region of the tubular liner below the mandrel is pressurized. In an exemplary embodiment, the region of the tubular liner below the mandrel is pressurized to pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the method further includes overlapping the tubular liner with the existing wellbore casing. In an exemplary embodiment, the method further includes sealing the interface between the tubular liner and the existing wellbore casing. In an exemplary embodiment, the method further includes supporting the extruded tubular liner using the existing wellbore casing. In an exemplary embodiment, the method further includes testing the integrity of the seal in the interface between the tubular liner and the existing wellbore casing. In an exemplary embodiment, method further includes lubricating the surface of the mandrel. In an exemplary embodiment, the method further includes absorbing shock. In an exemplary embodiment, the method further includes catching the mandrel upon the completion of the extruding. In an exemplary embodiment, the method further includes expanding the mandrel in a radial direction.
- A tie-back liner for lining an existing wellbore casing has been described that includes a tubular liner and an annular body of a cured fluidic sealing material. The tubular liner is formed by the process of extruding the tubular liner off of a mandrel. The annular body of a cured fluidic sealing material is coupled to the tubular liner. In an exemplary embodiment, the tubular liner is formed by the process of placing the tubular liner and mandrel within the wellbore, and pressurizing an interior portion of the tubular liner. In an exemplary embodiment, during the pressurizing, the interior portion of the tubular liner is fluidicly isolated from an exterior portion of the tubular liner. In an exemplary embodiment, the interior portion of the tubular liner is pressurized at pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the annular body of a cured fluidic sealing material is formed by the process of injecting a body of hardenable fluidic sealing material into an annular region between the existing wellbore casing and the tubular liner. In an exemplary embodiment, the tubular liner overlaps with another existing wellbore casing. In an exemplary embodiment, the tie-back liner further includes a seal positioned in the overlap between the tubular liner and the other existing wellbore casing. In an exemplary embodiment, tubular liner is supported by the overlap with the other existing wellbore casing.
- An apparatus for expanding a tubular member has been described that includes a support member, a mandrel, a tubular member, and a shoe. The support member includes a first fluid passage. The mandrel is coupled to the support member. The mandrel includes a second fluid passage operably coupled to the first fluid passage, an interior portion, and an exterior portion. The interior portion of the mandrel is drillable. The tubular member is coupled to the mandrel. The shoe is coupled to the tubular member. The shoe includes a third fluid passage operably coupled to the second fluid passage, an interior portion, and an exterior portion. The interior portion of the shoe is drillable. Preferably, the interior portion of the mandrel includes a tubular member and a load bearing member. Preferably, the load bearing member comprises a drillable body. Preferably, the interior portion of the shoe includes a tubular member, and a load bearing member. Preferably, the load bearing member comprises a drillable body. Preferably, the exterior portion of the mandrel comprises an expansion cone. Preferably, the expansion cone is fabricated from materials selected from the group consisting of tool steel, titanium, and ceramic. Preferably, the expansion cone has a surface hardness ranging from about 58 to 62 Rockwell C. Preferably at least a portion of the apparatus is drillable.
- A wellhead has also been described that includes an outer casing and a plurality of substantially concentric and overlapping inner casings coupled to the outer casing. Each inner casing is supported by contact pressure between an outer surface of the inner casing and an inner surface of the outer casing. In an exemplary embodiment, the outer casing has a yield strength ranging from about 40,000 to 135,000 psi. In an exemplary embodiment, the outer casing has a burst strength ranging from about 5,000 to 20,000 psi. In an exemplary embodiment, the contact pressure between the inner casings and the outer casing ranges from about 500 to 10,000 psi. In an exemplary embodiment, one or more of the inner casings include one or more sealing members that contact with an inner surface of the outer casing. In an exemplary embodiment, the sealing members are selected from the group consisting of lead, rubber, Teflon, epoxy, and plastic. In an exemplary embodiment, a Christmas tree is coupled to the outer casing. In an exemplary embodiment, a drilling spool is coupled to the outer casing. In an exemplary embodiment, at least one of the inner casings is a production casing.
- A wellhead has also been described that includes an outer casing at least partially positioned within a wellbore and a plurality of substantially concentric inner casings coupled to the interior surface of the outer casing by the process of expanding one or more of the inner casings into contact with at least a portion of the interior surface of the outer casing. In an exemplary embodiment, the inner casings are expanded by extruding the inner casings off of a mandrel. In an exemplary embodiment, the inner casings are expanded by the process of placing the inner casing and a mandrel within the wellbore; and pressurizing an interior portion of the inner casing. In an exemplary embodiment, during the pressurizing, the interior portion of the inner casing is fluidicly isolated from an exterior portion of the inner casing. In an exemplary embodiment, the interior portion of the inner casing is pressurized at pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, one or more seals are positioned in the interface between the inner casings and the outer casing. In an exemplary embodiment, the inner casings are supported by their contact with the outer casing.
- A method of forming a wellhead has also been described that includes drilling a wellbore. An outer casing is positioned at least partially within an upper portion of the wellbore. A first tubular member is positioned within the outer casing. At least a portion of the first tubular member is expanded into contact with an interior surface of the outer casing. A second tubular member is positioned within the outer casing and the first tubular member. At least a portion of the second tubular member is expanded into contact with an interior portion of the outer casing. In an exemplary embodiment, at least a portion of the interior of the first tubular member is pressurized. In an exemplary embodiment, at least a portion of the interior of the second tubular member is pressurized. In an exemplary embodiment, at least a portion of the interiors of the first and second tubular members are pressurized. In an exemplary embodiment, the pressurizing of the portion of the interior region of the first tubular member is provided at operating pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the pressurizing of the portion of the interior region of the second tubular member is provided at operating pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the pressurizing of the portion of the interior region of the first and second tubular members is provided at operating pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the pressurizing of the portion of the interior region of the first tubular member is provided at reduced operating pressures during a latter portion of the expansion. In an exemplary embodiment, the pressurizing of the portion of the interior region of the second tubular member is provided at reduced operating pressures during a latter portion of the expansion. In an exemplary embodiment, the pressurizing of the portion of the interior region of the first and second tubular members is provided at reduced operating pressures during a latter portion of the expansions. In an exemplary embodiment, the contact between the first tubular member and the outer casing is sealed. In an exemplary embodiment, the contact between the second tubular member and the outer casing is sealed. In an exemplary embodiment, the contact between the first and second tubular members and the outer casing is sealed. In an exemplary embodiment, the expanded first tubular member is supported using the contact with the outer casing. In an exemplary embodiment, the expanded second tubular member is supported using the contact with the outer casing. In an exemplary embodiment, the expanded first and second tubular members are supported using their contacts with the outer casing. In an exemplary embodiment, the first and second tubular members are extruded off of a mandrel. In an exemplary embodiment, the surface of the mandrel is lubricated. In an exemplary embodiment, shock is absorbed. In an exemplary embodiment, the mandrel is expanded in a radial direction. In an exemplary embodiment, the first and second tubular members are positioned in an overlapping relationship. In an exemplary embodiment, an interior region of the first tubular member is fluidicly isolated from an exterior region of the first tubular member. In an exemplary embodiment, an interior region of the second tubular member is fluidicly isolated from an exterior region of the second tubular member. In an exemplary embodiment, the interior region of the first tubular member is fluidicly isolated from the region exterior to the first tubular member by injecting one or more plugs into the interior of the first tubular member. In an exemplary embodiment, the interior region of the second tubular member is fluidicly isolated from the region exterior to the second tubular member by injecting one or more plugs into the interior of the second tubular member. In an exemplary embodiment, the pressurizing of the portion of the interior region of the first tubular member is provided by injecting a fluidic material at operating pressures and flow rates ranging from about 500 to 9,000 psi and 40 to 3,000 gallons/minute. In an exemplary embodiment, the pressurizing of the portion of the interior region of the second tubular member is provided by injecting a fluidic material at operating pressures and flow rates ranging from about 500 to 9,000 psi and 40 to 3,000 gallons/minute. In an exemplary embodiment, fluidic material is injected beyond the mandrel. In an exemplary embodiment, a region of the tubular members beyond the mandrel is pressurized. In an exemplary embodiment, the region of the tubular members beyond the mandrel is pressurized to pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the first tubular member comprises a production casing. In an exemplary embodiment, the contact between the first tubular member and the outer casing is sealed. In an exemplary embodiment, the contact between the second tubular member and the outer casing is sealed. In an exemplary embodiment, the expanded first tubular member is supported using the outer casing. In an exemplary embodiment, the expanded second tubular member is supported using the outer casing. In an exemplary embodiment the integrity of the seal in the contact between the first tubular member and the outer casing is tested. In an exemplary embodiment, the integrity of the seal in the contact between the second tubular member and the outer casing is tested. In an exemplary embodiment, the mandrel is caught upon the completion of the extruding. In an exemplary embodiment, the mandrel is drilled out. In an exemplary embodiment, the mandrel is supported with coiled tubing. In an exemplary embodiment, the mandrel is coupled to a drillable shoe.
- An apparatus has also been described that includes an outer tubular member, and a plurality of substantially concentric and overlapping inner tubular members coupled to the outer tubular member. Each inner tubular member is supported by contact pressure between an outer surface of the inner casing and an inner surface of the outer inner tubular member. In an exemplary embodiment, the outer tubular member has a yield strength ranging from about 40,000 to 135,000 psi. In an exemplary embodiment, the outer tubular member has a burst strength ranging from about 5,000 to 20,000 psi. In an exemplary embodiment, the contact pressure between the inner tubular members and the outer tubular member ranges from about 500 to 10,000 psi. In an exemplary embodiment, one or more of the inner tubular members include one or more sealing members that contact with an inner surface of the outer tubular member. In an exemplary embodiment, the sealing members are selected from the group consisting of rubber, lead, plastic, and epoxy.
- An apparatus has also been described that includes an outer tubular member, and a plurality of substantially concentric inner tubular members coupled to the interior surface of the outer tubular member by the process of expanding one or more of the inner tubular members into contact with at least a portion of the interior surface of the outer tubular member. In an exemplary embodiment, the inner tubular members are expanded by extruding the inner tubular members off of a mandrel. In an exemplary embodiment, the inner tubular members are expanded by the process of: placing the inner tubular members and a mandrel within the outer tubular member; and pressurizing an interior portion of the inner casing. In an exemplary embodiment, during the pressurizing, the interior portion of the inner tubular member is fluidicly isolated from an exterior portion of the inner tubular member. In an exemplary embodiment, the interior portion of the inner tubular member is pressurized at pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the apparatus further includes one or more seals positioned in the interface between the inner tubular members and the outer tubular member. In an exemplary embodiment, the inner tubular members are supported by their contact with the outer tubular member.
- A wellbore casing has also been described that includes a first tubular member, and a second tubular member coupled to the first tubular member in an overlapping relationship. The inner diameter of the first tubular member is substantially equal to the inner diameter of the second tubular member. In an exemplary embodiment, the first tubular member includes a first thin wall section, wherein the second tubular member includes a second thin wall section, and wherein the first thin wall section is coupled to the second thin wall section. In an exemplary embodiment, first and second thin wall sections are deformed. In an exemplary embodiment, the first tubular member includes a first compressible member coupled to the first thin wall section, and wherein the second tubular member includes a second compressible member coupled to the second thin wall section. In an exemplary embodiment, the first thin wall section and the first compressible member are coupled to the second thin wall section and the second compressible member. In an exemplary embodiment, the first and second thin wall sections and the first and second compressible members are deformed.
- A wellbore casing has also been described. In an exemplary embodiment, the wellbore casing includes a tubular member including at least one thin wall section and a thick wall section, and a compressible annular member coupled to each thin wall section.
- In an exemplary embodiment, the compressible annular member is fabricated from materials selected from the group consisting of rubber, plastic, metal and epoxy. In an exemplary embodiment, the wall thickness of the thin wall section ranges from about 50 to 100% of the wall thickness of the thick wall section. In an exemplary embodiment, the length of the thin wall section ranges from about 120 to 2400 inches. In an exemplary embodiment, the compressible annular member is positioned along the thin wall section. In an exemplary embodiment, the compressible annular member is positioned along the thin and thick wall sections. In an exemplary embodiment, the tubular member is fabricated from materials selected from the group consisting of oilfield country tubular goods, stainless steel, low alloy steel, carbon steel, automotive grade steel, plastics, fiberglass, high strength and/or deformable materials. In an exemplary embodiment, the wellbore casing includes a first thin wall at a first end of the casing, and a second thin wall at a second end of the casing.
- A method of creating a casing in a borehole located in a subterranean formation has also been described that includes supporting a tubular liner and a mandrel in the borehole using a support member, injecting fluidic material into the borehole, pressurizing an interior region of the mandrel, displacing a portion of the mandrel relative to the support member, and radially expanding the tubular liner. In an exemplary embodiment, the injecting includes injecting hardenable fluidic sealing material into an annular region located between the borehole and the exterior of the tubular liner, and injecting non hardenable fluidic material into an interior region of the mandrel. In an exemplary embodiment, the method further includes fiuldicly isolating the annular region from the interior region before injecting the non hardenable fluidic material into the interior region of the mandrel. In an exemplary embodiment, the injecting of the hardenable fluidic sealing material is provided at operating pressures and flow rates ranging from about 0 to 5,000 psi and 0 to 1,500 gallons/min. In an exemplary embodiment, the injecting of the non hardenable fluidic material is provided at operating pressures and flow rates ranging from about 500 to 9,000 psi and 40 to 3,000 gallons/min. In an exemplary embodiment, the injecting of the non hardenable fluidic material is provided at reduced operating pressures and flow rates during an end portion of the radial expansion. In an exemplary embodiment, the fluidic material is injected into one or more pressure chambers. In an exemplary embodiment, the one or more pressure chambers are pressurized. In an exemplary embodiment, the pressure chambers are pressurized to pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the method further includes fluidicly isolating an interior region of the mandrel from an exterior region of the mandrel. In an exemplary embodiment, the interior region of the mandrel is isolated from the region exterior to the mandrel by inserting one or more plugs into the injected fluidic material. In an exemplary embodiment, the method further includes curing at least a portion of the fluidic material, and removing at least a portion of the cured fluidic material located within the tubular liner. In an exemplary embodiment, the method further includes overlapping the tubular liner with an existing wellbore casing. In an exemplary embodiment, the method further includes sealing the overlap between the tubular liner and the existing wellbore casing. In an exemplary embodiment, the method further includes supporting the extruded tubular liner using the overlap with the existing wellbore easing. In an exemplary embodiment, the method further includes testing the integrity of the seal in the overlap between the tubular liner and the existing wellbore casing. In an exemplary embodiment, the method further includes removing at least a portion of the hardenable fluidic sealing material within the tubular liner before curing. In an exemplary embodiment, the method further includes lubricating the surface of the mandrel. In an exemplary embodiment, the method further includes absorbing shock. In an exemplary embodiment, the method further includes catching the mandrel upon the completion of the extruding. In an exemplary embodiment, the method further includes drilling out the mandrel. In an exemplary embodiment, the method further includes supporting the mandrel with coiled tubing. In an exemplary embodiment, the mandrel reciprocates. In an exemplary embodiment, the mandrel is displaced in a first direction during the pressurization of the interior region of the mandrel, and the mandrel is displaced in a second direction during a de-pressurization of the interior region of the mandrel. In an exemplary embodiment, the tubular liner is maintained in a substantially stationary position during the pressurization of the interior region of the mandrel. In an exemplary embodiment, the tubular liner is supported by the mandrel during a de-pressurization of the interior region of the mandrel.
- A wellbore casing has also been described that includes a first tubular member having a first inside diameter, and a second tubular member having a second inside diameter substantially equal to the first inside diameter coupled to the first tubular member in an overlapping relationship. The first and second tubular members are coupled by the process of deforming a portion of the second tubular member into contact with a portion of the first tubular member. In an exemplary embodiment, the second tubular member is deformed by the process of placing the first and second tubular members in an overlapping relation ship, radially expanding at least a portion of the first tubular member, and radially expanding the second tubular member. In an exemplary embodiment, the second tubular member is radially expanded by the process of supporting the second tubular member and a mandrel within the wellbore using a support member, injecting a fluidic material into the wellbore, pressurizing an interior region of the mandrel, and displacing a portion of the mandrel relative to the support member. In an exemplary embodiment, the injecting includes injecting hardenable fluidic sealing material into an annular region located between the borehole and the exterior of the second liner, and injecting non hardenable fluidic material into an interior region of the mandrel. In an exemplary embodiment, the wellbore casing further includes fluidicly isolating the annular region from the interior region of the mandrel before injecting the non hardenable fluidic material into the interior region of the mandrel. In an exemplary embodiment, the injecting of the hardenable fluidic sealing material is provided at operating pressures and flow rates ranging from about 0 to 5,000 psi and 0 to 1,500 gallons/min. In an exemplary embodiment, the injecting of the non hardenable fluidic material is provided at operating pressures and flow rates ranging from about 500 to 9,000 psi and 40 to 3,000 gallons/min. In an exemplary embodiment, the injecting of the non hardenable fluidic material is provided at reduced operating pressures and flow rates during an end portion of the radial expansion. In an exemplary embodiment, the fluidic material is injected into one or more pressure chambers. In an exemplary embodiment, one or more pressure chambers are pressurized. In an exemplary embodiment, the pressure chambers are pressurized to pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the wellbore casing further includes fiuldicly isolating an interior region of the mandrel from an exterior region of the mandrel. In an exemplary embodiment, the interior region of the mandrel is isolated from the region exterior to the mandrel by inserting one or more plugs into the injected fluidic material. In an exemplary embodiment, the wellbore casing further includes curing at least a portion of the fluidic material, and removing at least a portion of the cured fluidic material located within the second tubular liner. In an exemplary embodiment, the wellbore casing further includes sealing the overlap between the first and second tubular liners. In an exemplary embodiment, the wellbore casing further includes supporting the second tubular liner using the overlap with the first tubular liner. In an exemplary embodiment, the wellbore casing further includes testing the integrity of the seal in the overlap between the first and second tubular liners. In an exemplary embodiment, the wellbore casing further includes removing at least a portion of the hardenable fluidic sealing material within the second tubular liner before curing. In an exemplary embodiment, the wellbore casing further includes lubricating the surface of the mandrel. In an exemplary embodiment, the wellbore casing further includes absorbing shock. In an exemplary embodiment, the wellbore casing further includes catching the mandrel upon the completion of the radial expansion. In an exemplary embodiment, the wellbore casing further includes drilling out the mandrel. In an exemplary embodiment, the wellbore casing further include supporting the mandrel with coiled tubing. In an exemplary embodiment, the mandrel reciprocates. In an exemplary embodiment, the mandrel is displaced in a first direction during the pressurization of the interior region of the mandrel; and wherein the mandrel is displaced in a second direction during a de-pressurization of the interior region of the mandrel. In an exemplary embodiment, the second tubular liner is maintained in a substantially stationary position during the pressurization of the interior region of the mandrel. In an exemplary embodiment, the second tubular liner is supported by the mandrel during a de-pressurization of the interior region of the mandrel.
- An apparatus for expanding a tubular member has also been described that includes a support member including a fluid passage, a mandrel movably coupled to the support member including an expansion cone, at least one pressure chamber defined by and positioned between the support member and mandrel fluidicly coupled to the first fluid passage, and one or more releasable supports coupled to the support member adapted to support the tubular member. In an exemplary embodiment, the fluid passage includes a throat passage having a reduced inner diameter. In an exemplary embodiment, the mandrel includes one or more annular pistons. In an exemplary embodiment, the apparatus includes a plurality of pressure chambers. In an exemplary embodiment, the pressure chambers are at least partially defined by annular pistons. In an exemplary embodiment, the releasable supports are positioned below the mandrel. In an exemplary embodiment, the releasable supports are positioned above the mandrel. In an exemplary embodiment, the releasable supports comprise hydraulic slips. In an exemplary embodiment, the releasable supports comprise mechanical slips. In an exemplary embodiment, the releasable supports comprise drag blocks. In an exemplary embodiment, the mandrel includes one or more annular pistons, and an expansion cone coupled to the annular pistons. In an exemplary embodiment, one or more of the annular pistons include an expansion cone. In an exemplary embodiment, the pressure chambers comprise annular pressure chambers.
- An apparatus has also been described that includes one or more solid tubular members, each solid tubular member including one or more external seals, one or more slotted tubular members coupled to the solid tubular members, and a shoe coupled to one of the slotted tubular members. In an exemplary embodiment, the apparatus further includes one or more intermediate solid tubular members coupled to and interleaved among the slotted tubular members, each intermediate solid tubular member including one or more external seals. In an exemplary embodiment, the apparatus further includes one or more valve members. In an exemplary embodiment, one or more of the intermediate solid tubular members include one or more valve members.
- A method of joining a second tubular member to a first tubular member, the first tubular member having an inner diameter greater than an outer diameter of the second tubular member, has also been described that includes positioning a mandrel within an interior region of the second tubular member, pressurizing a portion of the interior region of the mandrel, displacing the mandrel relative to the second tubular member, and extruding at least a portion of the second tubular member off of the mandrel into engagement with the first tubular member. In an exemplary embodiment, the pressurizing of the portion of the interior region of the mandrel is provided at operating pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the pressurizing of the portion of the interior region of the mandrel is provided at reduced operating pressures during a fatter portion of the extruding. In an exemplary embodiment, the method further includes sealing the interface between the first and second tubular members. In an exemplary embodiment, the method further includes supporting the extruded second tubular member using the interface with the first tubular member. In an exemplary embodiment, the method further includes lubricating the surface of the mandrel. In an exemplary embodiment, the method further includes absorbing shock. In an exemplary embodiment, the method further includes positioning the first and second tubular members in an overlapping relationship. In an exemplary embodiment, the method further includes fluidicly isolating an interior region of the mandrel an exterior region of the mandrel. In an exemplary embodiment, the interior region of the mandrel is fluidicly isolated from the region exterior to the mandrel by injecting one or more plugs into the interior of the mandrel. In an exemplary embodiment, the pressurizing of the portion of the interior region of the mandrel is provided by injecting a fluidic material at operating pressures and flow rates ranging from about 500 to 9,000 psi and 40 to 3,000 gallons/minute. In an exemplary embodiment, the method further includes injecting fluidic material beyond the mandrel. In an exemplary embodiment, one or more pressure chambers defined by the mandrel are pressurized. In an exemplary embodiment, the pressure chambers are pressurized to pressures ranging from about 500 to 9,000 psi. In an exemplary embodiment, the first tubular member comprises an existing section of a wellbore. In an exemplary embodiment, the method further includes sealing the interface between the first and second tubular members. In an exemplary embodiment, the method further includes supporting the extruded second tubular member using the first tubular member. In an exemplary embodiment, the method further includes testing the integrity of the seal in the interface between the first tubular member and the second tubular member. In an exemplary embodiment, the method further includes catching the mandrel upon the completion of the extruding. In an exemplary embodiment, the method further includes drilling out the mandrel. In an exemplary embodiment, the method further include supporting the mandrel with coiled tubing. In an exemplary embodiment, the method further includes coupling the mandrel to a drillable shoe. In an exemplary embodiment, the mandrel is displaced in the longitudinal direction. In an exemplary embodiment, the mandrel is displaced in a first direction during the pressurization and in a second direction during a de-pressurization.
- An apparatus has also been described that includes one or more primary solid tubulars, each primary solid tubular including one or more external annular seals, n slotted tubulars coupled to the primary solid tubulars, n-1 intermediate solid tubulars coupled to and interleaved among the slotted tubulars, each intermediate solid tubular including one or more external annular seals, and a shoe coupled to one of the slotted tubulars.
- A method of isolating a first subterranean zone from a second subterranean zone in a wellbore has also been described that includes positioning one or more primary solid tubulars within the wellbore, the primary solid tubulars traversing the first subterranean zone, positioning one or more slotted tubulars within the wellbore, the slotted tubulars traversing the second subterranean zone, fluidicly coupling the slotted tubulars and the solid tubulars, and preventing the passage of fluids from the first subterranean zone to the second subterranean zone within the wellbore external to the solid and slotted tubulars.
- A method of extracting materials from a producing subterranean zone in a wellbore, at least a portion of the wellbore including a casing, has also been described that includes positioning one or more primary solid tubulars within the wellbore, fluidicly coupling the primary solid tubulars with the casing, positioning one or more slotted tubulars within the wellbore, the slotted tubulars traversing the producing subterranean zone, fluidicly coupling the slotted tubulars with the solid tubulars, fluidicly isolating the producing subterranean zone from at least one other subterranean zone within the wellbore, and fluidicly coupling at least one of the slotted tubulars from the producing subterranean zone. In an exemplary embodiment, the method further includes controllably fiuldicly decoupling at least one of the slotted tubulars from at least one other of the slotted tubulars.
- Although illustrative embodiments of the invention have been shown and described, a wide range of modification, changes and substitution is contemplated in the foregoing disclosure, in some instances, some features of the present invention may be employed without a corresponding use of the other features. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the invention.
Claims (16)
1. An apparatus for expanding a tubular member, comprising:
a support member comprising a fluid passage.
an expansion device movably coupled to the support member comprising an expansion cone and a tubular piston operably coupled to the expansion cone;
at least one pressure chamber defined by and positioned between the support member and the expansion device fluidicly coupled to the first fluid passage; and
one or more releasable supports coupled to the support member adapted to support the tubular member;
wherein the releasable supports are positioned above the expansion device.
2. The apparatus ofclaim 1 , wherein the at least one releasable support comprises at least one releasable locking member for locking the tubular member to the support member.
3. An apparatus for radially expanding and plastically deforming an expandable tubular member, comprising:
an expansion device for radially expanding and plastically deforming the expandable tubular member;
a support member;
an actuator coupled to the expansion device and the support member for displacing the expansion device in the longitudinal direction relative to the tubular member; and
a locking device for the position of the expandable tubular member relative to the support member; wherein the locking device is positioned above the expansion device; and wherein the actuator comprises one of more tubular pistons.
4. The apparatus ofclaim 3 , wherein the actuator comprises an expandable pressure chamber.
5. The apparatus ofclaim 3 , wherein the locking device comprises one or more of the following:
hydraulic slips;
mechanical slips; or
drag blocks.
6. The apparatus ofclaim 3 , wherein the locking device is one of a plurality of locking devices, and wherein at least one of the plurality of locking devices engages a radially nonexpanded portion of the tubular member.
7. The apparatus ofclaim 3 , wherein the expansion device comprises:
an adjustable expansion device; and
a non-adjustable expansion device.
8. The apparatus ofclaim 3 , wherein the expansion device comprises a tapered outer expansion surface having an angle of attack ranging from about 5 to 30 degrees; wherein the tapered outer expansion surface of the expansion device comprises a D2 steel; and wherein the tapered outer expansion surface of the expansion device comprises a surface hardness ranging from about 58 to 62 Rockwell C.
9. An apparatus for radially expanding and plastically deforming an expandable tubular member, comprising:
an expansion device for radially expanding and plastically deforming the expandable tubular member;
a support member;
an actuator coupled to the expansion device and the support member for displacing the expansion device in the longitudinal direction relative to the tubular member; and
a locking device for preventing movement of the expandable tubular member in at least a single direction;
wherein the locking device is positioned above the expansion device.
10. The apparatus ofclaim 9 , wherein the actuator comprises an expandable pressure chamber.
11. The apparatus ofclaim 9 , wherein the locking device is one of a plurality of locking devices, and wherein at least one of the plurality of locking devices engages a radially nonexpanded portion of the tubular member.
12. The apparatus ofclaim 9 , wherein the expansion device comprises:
an adjustable expansion device; and
a non-adjustable expansion device.
13. An apparatus for radially expanding and plastically deforming an expandable tubular member, comprising:
an expansion device for radially expanding and plastically deforming the expandable tubular member:
a support member;
an actuator coupled to the expansion device and the support member for displacing the expansion device in the longitudinal direction relative to the tubular member; and
a device for preventing movement of the expandable tubular member;
wherein the device is positioned above the expansion device.
14. The apparatus ofclaim 13 , wherein the actuator comprises an expandable pressure chamber.
15. The apparatus ofclaim 13 , wherein the device is one of a plurality of devices, and wherein at least one of the plurality of devices engages a radially nonexpanded portion of the tubular member.
16. The apparatus ofclaim 13 , wherein the expansion device comprises:
an adjustable expansion device;
a non-adjustable expansion device.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US11/831,466US20080156480A1 (en) | 1998-12-07 | 2007-07-31 | Apparatus for expanding a tubular member |
Applications Claiming Priority (9)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US11129398P | 1998-12-07 | 1998-12-07 | |
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| US09/510,913US7357188B1 (en) | 1998-12-07 | 2000-02-23 | Mono-diameter wellbore casing |
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| US09/962,469Expired - LifetimeUS6892819B2 (en) | 1998-12-07 | 2001-09-25 | Forming a wellbore casing while simultaneously drilling a wellbore |
| US10/767,953Expired - LifetimeUS7077211B2 (en) | 1998-12-07 | 2004-01-29 | Method of creating a casing in a borehole |
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| US10/767,953Expired - LifetimeUS7077211B2 (en) | 1998-12-07 | 2004-01-29 | Method of creating a casing in a borehole |
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| US11/142,756Expired - Fee RelatedUS7121337B2 (en) | 1998-12-07 | 2005-06-01 | Apparatus for expanding a tubular member |
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- 2005
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- 2005-06-02USUS11/143,393patent/US7198100B2/ennot_activeExpired - Fee Related
- 2007
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Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
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| US20080097248A1 (en)* | 2006-08-16 | 2008-04-24 | Boston Scientific Scimed, Inc. | Mechanical honing of metallic tubing for soldering in a medical device construction |
| US8021311B2 (en)* | 2006-08-16 | 2011-09-20 | Boston Scientific Scimed, Inc. | Mechanical honing of metallic tubing for soldering in a medical device construction |
| CN109681142A (en)* | 2018-12-13 | 2019-04-26 | 大港油田集团有限责任公司 | A kind of naked eye expansion device and application method |
Also Published As
| Publication number | Publication date |
|---|---|
| US7198100B2 (en) | 2007-04-03 |
| US6892819B2 (en) | 2005-05-17 |
| US20040182569A1 (en) | 2004-09-23 |
| US20050230104A1 (en) | 2005-10-20 |
| US7240729B2 (en) | 2007-07-10 |
| US7665532B2 (en) | 2010-02-23 |
| US7121337B2 (en) | 2006-10-17 |
| US20050205253A1 (en) | 2005-09-22 |
| US20020060078A1 (en) | 2002-05-23 |
| US20040188099A1 (en) | 2004-09-30 |
| US7077211B2 (en) | 2006-07-18 |
| US20050230103A1 (en) | 2005-10-20 |
| US7195061B2 (en) | 2007-03-27 |
| US7434618B2 (en) | 2008-10-14 |
| US20080087418A1 (en) | 2008-04-17 |
| US7216701B2 (en) | 2007-05-15 |
| US7357188B1 (en) | 2008-04-15 |
| US20050224225A1 (en) | 2005-10-13 |
| US20050230102A1 (en) | 2005-10-20 |
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| AS | Assignment | Owner name:SHELL OIL COMPANY, TEXAS Free format text:ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:COOK, ROBERT LANCE;BRISCO, DAVID PAUL;STEWART, R. BRUCE;AND OTHERS;REEL/FRAME:020653/0933;SIGNING DATES FROM 20070107 TO 20080217 | |
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