US20060201715A1 - Drilling normally to sub-normally pressured formations - Google Patents

Abstract

A system and method for drilling a substantially horizontal well bore in a normally to sub-normally pressured formation. The normally to sub-normally pressured formation is an unconventional reservoir. The well bore is drilled over-balanced with a drilling fluid including a fluid loss agent. The fluid loss agent is operable to form a filter cake on the well bore during drilling.

Description

RELATED APPLICATIONS
• This application is a continuation-in-part of, and therefore claims priority from, U.S. patent application Ser. No. 11/035,537 filed on Jan. 14, 2005, which is a continuation-in-part of, and therefore claims priority from, U.S. patent application Ser. No. 10/723,322, filed on Nov. 26, 2003. This application incorporates by reference the two applications noted above, as well as the application entitled Well Bore Cleaning filed May 31, 2005.
TECHNICAL FIELD
• This disclosure relates generally to the field of recovery of subterranean resources, and more particularly to a system and method for drilling normally to sub-normally pressured formations.
BACKGROUND
• Reservoirs are subterranean formations of rock containing oil, gas, and/or water. Unconventional reservoirs include coal formations, shale formations and low permeability formations containing gas and, in some cases, water. A coal bed, for example, may contain natural gas and water.
• Coal bed methane (CBM) is often produced using vertical wells drilled from the surface into a coal bed. Vertical wells drain a very small radius of methane gas in low permeability formations. As a result, after gas in the vicinity of the vertical well has been produced, further production from the coal seam through the vertical well is limited.
• To enhance production through vertical wells, the wells have been fractured using conventional and/or other stimulation techniques. Horizontal patterns have also been formed in coal seams to increase and/or accelerate gas production.
SUMMARY
• The invention encompasses a system and method for drilling normally to sub-normally pressured formations. In one embodiment, the method includes drilling a substantially horizontal well bore in a normally to sub-normally pressured formation. The normally to sub-normally pressured formation is an unconventional reservoir. The well bore is drilled over-balanced with a drilling fluid including a fluid loss agent. The fluid loss agent is operable to form a filter cake on the well bore during drilling.
• More specifically, in accordance with a particular embodiment, the unconventional reservoir may comprise a fractured formation, a coal bed and/or a shale. The fluid loss agent may comprise a non-invasive or low-invasive fluid such as micelles, aphrons or other agent operable to form a filter cake to limit fluid loss from the well bore to the formation. The drilling fluid may comprise a heavy fluid having a density of 9.5 pounds per gallon or greater, 10 pounds per gallon or greater and/or a density substantially equal to or greater than that of the cuttings generated during drilling of the well bore.
• Technical advantages of certain embodiments include providing a system and method for drilling a normally to sub-normally pressured formation. In a particular embodiment, a fluid loss agent may be used to form a filter cake around the well bore to enhance well bore stability. For example, the filter cake may seal the well bore and prevent fluid loss to the formation that could destabilize the formation and lower productivity of the formation. In addition, the filter cake may allow a positive pressure differential to be maintained between the well bore and the formation during drilling to stabilize the well bore.
• Another technical advantage of certain embodiments may include the use of a dense drilling fluid to enhance well bore stability and/or improve cutting removal efficiency. In a particular embodiment, a dense drilling fluid having a density greater than 9.5 pounds per gallon, may be used. In other embodiments, the density of the drilling fluid may be 10 pounds per gallon or greater and/or have a density substantially the same or greater than the cuttings in order to improve cuttings removal.
• Other technical advantages will be readily apparent to one skilled in the art from the following figures, description, and claims. Moreover, while specific advantages have been enumerated above, various embodiments may include all, some, or none of the enumerated advantages.
DESCRIPTION OF DRAWINGS
• FIG. 1 illustrates one embodiment of drilling a well of drilling a well from the terranean surface to a subterranean zone;
• FIG. 2 illustrates one embodiment of a well bore pattern for the well ofFIG. 1;
• FIG. 3 illustrates one embodiment of producing the well ofFIG. 1;
• FIG. 4 is a cross sectional diagram along lines4-4 ofFIG. 3 illustrating one embodiment of the well bore ofFIG. 3;
• FIG. 5 is a cross-sectional diagram illustrating collapse of the well bore ofFIG. 4;
• FIG. 6 is a flow chart illustrating an example method for drilling a normally to sub-normally pressured formation;
• FIG. 7 illustrates another embodiment of drilling a well from the terranean surface to a subterranean zone; and
• FIG. 8 illustrates one embodiment of producing the well ofFIG. 7.
• Like reference symbols in the various drawings indicate like elements.
DETAILED DESCRIPTION
• FIG. 1 illustrates anexample system10 for drilling awell bore40 from theterranean surface20 to asubterranean zone30. As described in more detail below, the well bore40 may be drilled overbalanced using a low-loss and/or dense drilling fluid. The low-loss and/or dense drilling fluid may assist in sealing and stabilizing thewell bore40.
• In the illustrated embodiment,subterranean zone30 is an unconventional reservoir, such as a coal seam, tight shale or low permeability formations.Subterranean zone30 may be accessed to remove and/or produce water, hydrocarbons, and other fluids, to sequester carbon dioxide or other pollutants, and/or for other operations.Subterranean zone30 may, in one embodiment, be naturally fractured.
• For ease of reference and purposes of example,subterranean zone30 will be referred to ascoal seam30. Thecoal seam30 may be a normally to sub-normally pressured formation. For a normally pressured formation, the pressure in the formation is equal or substantially equal to that of the water gradient at the depth of the formation. For a sub-normally pressured formation, the pressure in the formation is less than that of the water gradient at the depth of the formation. For example, a sub-normally pressuredcoal seam30 may have a pressure that is 5 or more percent less than that of the water gradient at the depth of thecoal seam30.
• Thewell bore40 can define afirst portion42 that extends from thesurface20, asecond portion44 at least partially coinciding with thecoal seam30 and a curved or radiusedportion46 interconnecting theportions42 and44. In one instance, thefirst portion42 may be drilled to extend past thecurved portion46 to define a sump and/or to provide access toadditional coal seams30, for example, by drilling additionalcurved portions46 andsecond portions44. Additionally, although thefirst portion42 is illustrated as being substantially vertical, thefirst portion42 may be formed at any angle relative to the surface. For example, thefirst portion42 may be slanted to reduce the radius of thecurved portion46, to accommodatesurface20 geometric characteristics or other concerns such as nearby well bores. For example, thefirst portion42 may be angled to accommodate anadjacent well bore40 drilled from the same surface area or same drilling pad. Thefirst portion42 of well bore40 may be lined with asuitable casing48. Thecasing48 may also extend into or through thecurved section46, and in some instances, into thesecond portion44.
• Thesecond portion44 may be substantially horizontal and/or in the seam ofcoal seam30, may track the depth of thecoal seam30, may undulate in thecoal seam30 or be otherwise suitably disposed in or about thecoal seam30. Thesecond portion44 of thewell bore40 may include a well bore pattern with a plurality of lateral or other horizontal well bores, as it discussed in more detail with respect toFIG. 2. In another embodiment, the well bore40 may be a single bore without laterals.
• AlthoughFIG. 1 illustrates a single articulated well bore40 that deviates to horizontal,system10 may be implemented, as described in connection withFIG. 7, as dual or multi-well systems or any other suitable types of wells or well systems. Well bore40 may be drilled to intersect more natural passages and other fractures, such as “cleats” of acoal seam30, that allow the flow of fluids from seam into well bore40, thereby increasing the productivity of the well.
• Articulated well bore40 is drilled usingdrill string50 that includes a suitable down-hole motor anddrill bit52. Thedrill string50 may be driven by a rotary rig, top drive rig and/or coiled tubing rig. Accordingly, thedrill string50 may be coiled tubing, sectioned drill pipe or other suitable tubing. Other down hole drill and/or steering systems may be used. During the process of drilling well bore40, drilling fluid or mud is pumped downdrill string50, as illustrated byarrows60, and circulated out ofdrill string50 in the vicinity ofdrill bit52, as illustrated byarrows62. The drilling fluid flows into the annulus betweendrill string50 and well borewalls49 where the drilling fluid is used to remove formation cuttings and coal fines. The cuttings and coal fines (hereinafter referred to as “debris”) are entrained in the drilling fluid, which circulates up through the annulus between thedrill string40 and the well borewalls49, as illustrated byarrows63, until it reachessurface20, where the debris is removed from the drilling fluid and the fluid is re-circulated through well bore40.
• In certain embodiments, the drilling fluid may comprise water and one or more weighting agents, fluid loss agents, and/or viscosity agents. The weighting agents may be used to increase the density of the drilling fluid and thus the hydrostatic fluid pressure exerted on thecoal seam30 during drilling of the well bore40. The drilling operation produces a column of drilling fluid in the well bore40 having a vertical height equal to the depth of the well bore40 and produces a hydrostatic pressure on well bore40 relating to the density of the drilling fluid and the vertical height of the column of fluid. In one embodiment, the well bore40 is drilled over-balanced with the hydrostatic fluid pressure in well bore40 exceeding the pressure in thecoal seam30. For normally and sub-normallypressured coal seams30, the well bore40 may be drilled with a drilling fluid having a density selected to be approximately equal to or greater than the density of the formation cuttings. In one instance, the well bore40 may be drilled with a drilling fluid having a density of 9.5 pounds per gallon or higher, 10 pounds per gallon or higher, or a density close to or matching that of the coal cuttings, which may be 11.2 pounds per gallon. In this embodiment, the coal cuttings may be buoyant or nearly buoyant in the drilling fluid and efficiently removed from the well bore40. This would allow for extremely high rates of drilling and high hole cleaning efficiency, greater than could be achieved with drilling fluid having a lower density than the cuttings.
• In one embodiment, a salt such as sodium chloride or calcium chloride may be used as a weighting agent. In particular, sodium chloride may provide a brine having a density of up to 9.9 pounds per gallon. Calcium chloride may provide a brine having a density up to 11.7 pounds per gallon. In other embodiments, potassium formate may be used as a weighting agent. Potassium formate may provide a drilling fluid having a density up to 14 pounds per gallon. Other suitable weighting agents may be used.
• The density, or specific gravity, of the drilling fluid may be determined based on bore hole stability needs, fracture gradient of thecoal seam30, and/or cutting removal needs. In this and other embodiments, bore hole stability needs may be initially determined based on the formation stress, formation pressure, and/or formation strength of thecoal seam30. For example, drilling fluid density may be increased when thecoal seam30 has less rock stability, while the density of the drilling fluid may be reduced when thecoal seam30 has a greater rock stability. Other suitable criteria may be used in initially or otherwise determining the density of the drilling fluid.
• The fluid loss agent may form afilter cake100 along the walls of the well bore40.Filter cake100 may prevent or significantly restrict drilling fluids from flowing intocoal seam30 from the well bore40. Thefilter cake100 may also provide a pressure boundary or seal betweencoal seam30 and well bore40 which may allow hydrostatic pressure in the well bore40 to be used to control stability of the well bore40 to prevent collapse during drilling. For example, during drilling, thefilter cake100 may aid well bore stability by allowing the hydrostatic pressure to act against the walls of the well bore40 and/or by preventing drilling fluid from entering thecoal seam30 and destabilizing the seam around the well bore40.
• The depth of thefilter cake100 may be dependent upon many factors including the composition of the drilling fluid, the fluid loss agent, and/or the properties of the formation. The fluid loss agent may be selected or otherwise designed in connection with the drilling fluid based on rock mechanics, pressure and other characteristics of thecoal seam30 to form a filter cake that reduces or minimizes fluid loss during drilling and/or reduces or minimizes skin damage to the well bore40.
• Thefilter cake100 may be formed with low-loss, ultra low-loss, non-invasive, low-invasive or other suitable drilling fluids. In one embodiment, fluid loss agent may comprise solid micelles that form microscopic spheres, rods, and/or plates in solutions. The micelles may comprise polymers with a range of water and oil solubilities. The micelles form a low permeability seal over pore throats of thecoal seam30 to greatly limit further fluid invasion or otherwise seal the coal seam boundary. In a particular embodiment, the fluid loss agent may comprise FLC 2000 available from IMPACT SOLUTIONS GROUP which may create ashallow filter cake100 having a depth of invasion into the formation approximately two to four centimeters with a structural integrity operable to seal the well bore40. In some instances, the fluid invasion rate of FLC 2000 may be 0.17 cubic meters of fluid lost to the formation per square meter of exposed formation in a day (m³/m²·day), as compared to 0.6 m³/m²·day for other conventional drilling fluids. FLC 2000 may provide a high return permeability after drilling during production. Starch and/or other fluid loss agents may be used in connection with the FLC 2000. In a particular embodiment, starch may be used to increase the sealing effect of thefilter cake100 formed by the FLC 2000. In another embodiment, aphrons, for example may be used as the fluid loss agent.
• The viscosity agents may increase lifting capacity of the drilling fluid. In a particular embodiment, the viscosity agents may comprise carboxyl methyl cellulose (CMC), hydroxyl ethyl cellulose (HEC), polyanionic cellulose (PAC), and/or xanthan gum (XG polymer). Other suitable viscosity agents may be used. In addition, the viscosity agents may be omitted when not needed.
• During drilling, thefirst portion42 of the well bore40 may be drilled overbalanced with a dense drilling fluid, but without the fluid loss and viscosity agents. The density of the drilling fluid may initially be between 8.3 and 9.0 pounds per gallon. After casing thefirst portion42 of the well bore40, and, in one embodiment, prior to entering thecoal seam30, the fluid loss and viscosity agents may be added to the drilling fluid. In the embodiment in which FLC 2000 is used as the fluid loss agent, FLC 2000 may initially be added to the drilling fluid in concentrations of up to 6-10 kilograms per cubic meter. If additional stability is needed, the concentration of FLC 2000 may be increased up to about 15 kilograms per cubic meter. Similarly, the density of the drilling fluid may be increased up to, for example, 9.5 pounds per gallon or greater to controlbore hole40 stability and/or assist in cuttings removal. For example, the density of the drilling fluid may be increased up to the density of the coal to suspend the cuttings in the drilling fluid and increase hole cleaning efficiency. However, the density of the drilling fluid may be limited due to the fracture gradient of thecoal seam30. In this case, additional viscofiers may be used. Additionally, the velocity and/or pump rate of the drilling fluid may be increased in thebore hole40 to assist with cutting cleanout and removal
• FIG. 2 illustrates an example of horizontalwell bore pattern65 for use in connection withwell bore40. In this embodiment, thepattern65 may include a main horizontal well bore67 extending diagonally across thecoverage area66. A plurality of lateral or other horizontal well bores68 may extend from themain bore67. The lateral bore68 may mirror each other on opposite sides of themain bore67 or may be offset from each other along themain bore67. Each of thelaterals68 may be drilled at a radius off themain bore67. Thehorizontal pattern65 may be otherwise formed, may otherwise include a plurality of horizontal bores or may be omitted. For example, thepattern65 may comprise a pinnate pattern having a main horizontal bore extending diagonally across thecoverage area66 and two, three four or more laterals extending from and on each side of the main horizontal bore67 to the periphery of thecoverage area66. The horizontal bores may be bores that are fully or substantially in thecoal seam30, or horizontal and/or substantially horizontal.
• FIG. 3 illustrates production from well bore40.Drill string50 has been removed and afluid extraction system70 inserted into well bore40.Fluid extraction system70 may include any appropriate components capable of circulating and/or removing fluid from well bore40 and lowering the pressure within well bore40. For example,fluid extraction system70 may comprise atubing string72 coupled to anartificial lift apparatus74.Artificial lift apparatus74 may comprise any appropriate device for circulating and/or removing fluid from well bore40, such as a pump or a fluid injector. Althoughartificial lift apparatus74 is illustrated as being located onsurface20, in certain embodiments,artificial lift apparatus74 may be located within well bore40, such as would be the case ifartificial lift apparatus74 comprised a down-hole pump. The fluid may be a liquid and/or a gas.Artificial lift apparatus74 may be omitted where, for example, water produced is limited and/or gas pressure in the coal seam is high enough to lift produced water to thesurface20.
• In certain embodiments,artificial lift apparatus74 may comprise a pump coupled totubing string72 that is operable to draw fluid from well bore40 throughtubing string72 to surface20 and reduce the pressure within well bore40. In the illustrated embodiment,artificial lift apparatus74 comprises a fluid injector, which may inject gas, liquid, or foam into well bore40. Any suitable type of injection fluid may be used in conjunction withsystem70. Examples of injection fluid may include, for example: (1) production gas, such as natural gas, (2) water, (3) air, and (4) any combination of production gas, water, air and/or treating foam. In particular embodiments, production gas, water, air, or any combination of these may be provided from a source outside of well bore40. In other embodiments, gas recovered from well bore40 may be used as the injection fluid by re-circulating the gas back into well bore40. Rod, positive displacement and other pumps may be used. In these and other embodiments, as illustrated inFIG. 8, a cavity may be formed in the well bore40 with the pump inlet positioned in the cavity. The cavity may form a junction with a vertical or other well in which the pump and/or pump inlet is disposed.
• Thefluid extraction system70 may also include aliner75. Theliner75 may have a plurality of apertures and may be loose in the well bore or otherwise uncemented. The apertures may be holes, slots, or openings of any other suitable size and shape. The apertures may allow water and gas to enter into theliner75 from thecoal seal30 for production to the surface. Theliner75 may have apertures when installed or may be perforated after installation. For example, theliner75 may comprise a drill or other string perforated after another use in well bore40.
• The size and/or shape of apertures in theliner75 may in one embodiment be determined based on rock mechanics of the coal seam. In this embodiment, for example, a representative formation sample may be taken and tested in a tri-axial cell with pressures on all sides. During testing, pressure may be adjusted to simulate pressure in down-hole conditions. For example, pressure may be changed to simulate drilling conditions by increasing hydrostatic pressure on one side of the sample. Pressure may also be adjusted to simulate production conditions. During testing, water may be flowed through the formation sample to determine changes in permeability of the coal at the well bore in different conditions. The tests may provide permeability, solids flow and solids bridging information which may be used in sizing the apertures, determining the periodicity of the apertures, and determining the shape of the apertures. Based on testing, if the coal fails in blocks without generating a large number of fines that can flow into the well bore, large perforations and/or high clearance liners with a loose fit may be used. High clearance liners may comprise liners one or more casing sizes smaller than a conventional liner for the hole size. The apertures may, in a particular embodiment, for example, be holes that are ½ inch in size.
• In operation of the illustrated embodiment,fluid injector74 injects a fluid, such as water or natural gas, intotubing string72, as illustrated byarrows76. The injection fluid travels throughtubing string72 and is injected into theliner75 in the well bore40, as illustrated byarrows78. As the injection fluid flows through theliner75 and annulus betweenliner75 andtubing string72, the injection fluid mixes with water, debris, and resources, such as natural gas, in well bore40. Thus, the flow of injection fluid removes water and coal fines in conjunction with the resources. Themixture80 of injection fluid, water, debris, and resources is collected at a separator (not illustrated) that separates the resource from the injection fluid carrying the resource.Tubing string72 andfuel injector74 may be omitted in some embodiments. For example, if coal fines or other debris are not produced from thecoal seam30 into theliner75, fluid injection may be omitted.
• In certain embodiments, the separated fluid is re-circulated into well bore40. In a particular embodiment, liquid, such as water, may be injected into well bore40. Because liquid has a higher viscosity than air, liquid may pick up any potential obstructive material, such as debris in well bore40, and remove such obstructive material from well bore40. In another particular embodiment, gas may be injected into well bore40. Although certain types of injection fluids are described, any combination of air, water, and/or gas that are provided from an outside source and/or re-circulated from the separator may be injected back into well bore40.
• Also in certain embodiments, after drilling is completed, the drilling fluid may be left in well bore40 whiledrill string50 is removed andtubing string72 andliner75 are inserted. The drilling fluid, and possibly other fluids flowing from thecoal seam30, may be pumped or gas lifted (for example, using a fluid injector) to surface20 to reduce, or “draw down,” the pressure within well bore40. As pressure is drawn down below reservoir pressure, fluid from thecoal seam30 may begin to flow into the well bore40. This flow may wash out thefilter cake100 when non-invasive or other suitable drilling fluids are used. In other embodiments, thefilter cake100 or a portion thereof may remain. In response to the initial reduction in pressure and/or friction reduction in pressure, the well bore40 may collapse, as described below.
• Collapse may, in certain embodiments, improve the efficiency of gas production fromcoal seam30 by, for example, increasing the localized permeability of thecoal seam30. The localized permeability is a permeability of all or part of an area around, otherwise about, or local to the well bore40. The localized permeability may be enhanced, in one embodiment, by spalling or cleaving thesubterranean zone30 around the well bore and/or otherwise collapsing the well bore40. Cleaving refers to splitting or separating portions of thesubterranean zone30. Spalling refers to breaking portions of thesubterranean zone30 into fragments and may be localized collapsed, fracturing, splitting and/or shearing. The increased localized permeability provides more drainage surface area without hydraulically fracturing thecoal seam30. Hydraulic fracturing comprises pumping a fracturing fluid down-hole under high pressure, for example, 1000 psi, 5000 psi, 10,000 psi or more.
• Collapse may occur before or after production begins. Collapse may be beneficial in situations wherecoal seam30 has low permeability, such as below 3 millidarcies. However, coal seams30 having other levels of permeability may also benefit from collapse. In certain embodiments, the drilling fluid may be removed before the pressure drop in well bore40. In other embodiments, the pressure within well bore40 may be reduced by removing the drilling fluid.
• FIG. 4 is a cross sectional diagram along lines4-4 ofFIG. 3 illustrating well bore40 in thesubterranean zone30.Filter cake100 is formed alongwalls49 of the well bore40. As discussed above,filter cake100 may occur in over-balanced drilling conditions where the drilling fluid pressure is greater that of thecoal seam30.Filter cake100 may be otherwise suitably generated and may comprise any partial or full blockage of pores,cleats102 or fractures in order to seal the well bore40 by substantially limiting or reducing fluid flow between thecoal seam30 and well bore40.
• As previously described, use of a fluid loss agent, or non-invasive fluid, may create a relatively shallowinvasion filter cake100, resulting in a relatively low amount of drilling fluid lost into thecleats102 of thecoal seam30. In certain embodiments, afilter cake100 may have aninvasion depth110 between two and four centimeters thick. Athin filter cake100 may be advantageous when it will not cause a permanent blockage but is strong enough to form a seal betweencoal seam30 and well bore40 to facilitate stability of the well bore40 during drilling.
• FIG. 5 is a cross-sectional diagram illustrating collapse of the well bore40. Collapse may be initiated in response to the pressure reduction in the well bore40. As used herein, in response to means in response to at least the identified event. Thus, one or more events may intervene, be needed, or also be present. In one embodiment, the well bore40 may collapse when the mechanical strength of the coal cannot support the overburden at the hydrostatic pressure in the well bore40. The well bore40 may collapse, for example, when fluid pressure is reduced in the well bore40.
• During collapse, ashear plane120 may be formed along the sides of the well bore40. The shear planes120 may extend into thecoal seam30 and form high permeability pathways connected to cleats102. In some embodiments,multiple shear planes120 may be formed during spalling. Eachshear plane120 may extend about the well bore40.
• Collapse may generate an area of high permeability within and around thepre-existing walls49 of the well bore40. This enhancement and localized permeability may permit a substantially improved flow of gas or other resources from thecoal seam30 intoliner75 than would have occurred without collapse. In an embodiment where the well bore40 includes a multi-lateral pattern, the main horizontal bore and lateral bores may each be lined withliner75 and collapsed by reducing hydrostatic pressure in the well bores.
• FIG. 6 is a flow chart illustrating an example method for drilling normally and sub-normally pressured coal seams30. In this embodiment, well bore40 comprises an articulated well bore in which thefirst portion42 is vertical, thesecond portion44 is horizontal and thecurved portion46 deviates from vertical to horizontal. As previously described, the well bore40 may be otherwise suitably configured.
• Referring toFIG. 6, the method begins atstep202, in which formation properties are determined. For thecoal seam30, formation stress, formation pressure and/or formation strength may be determined from core samples, reference databases, other well wells and/or other resources. Atstep204, drilling fluid density is selected based on well bore40 stability and/or other formation properties. For over-balanced drilling, the drilling fluid density is selected such that the hydrostatic pressure of the drilling fluid at the depth of thecoal seam30 is greater than the pressure of thecoal seam30. As previously described, sodium chloride, calcium chloride, potassium formate and/or other weighting agents may be used to raise the density of the drilling fluid to the desired density.
• Proceeding to step206, thevertical portion42 of the well bore40 is drilled and cased. Atstep208, and, in one embodiment, prior to drilling into thecoal seam30, one or more fluid loss agents are added to the drilling fluid. In one embodiment, the fluid loss agents include at least one of aphrons and micelles. As previously described, the fluid loss agents may form afilter cake100 on thewalls49 of the well bore40. Thefilter cake100 may stabilize the well bore40 during drilling and may, in one embodiment, reduce differential sticking and provide lubrication to reduce friction of thedrill string50 in the well bore40. The fluid loss agents may, for example, comprise FLC 2000, other micelle, and/or aphrons.
• Atstep210, one or more viscosity agents may be added to the drilling fluid. As previously described, the viscosity agents may comprise, for example, CMC, HEC, PAC and/or XG polymer. The viscosity agents may increase the viscosity of the drilling fluid and may thereby enhance cutting removal from the well bore40.
• Proceeding to step212, the radiusedportion46 andhorizontal portion44 of the well bore40 are drilled over-balance using the drilling fluid with the fluid loss agents and/or viscosity agents. Step212 leads todecisional step214 where during ongoing drilling operations, the No branch leads todecisional step216. Atdecisional step216, well bore40 stability is determined. Well bore40 stability may be determined based on, for example, the size and/or amount of cuttings being returned to thesurface20 during drilling. Large and/or a large number of cuttings may indicate instability of the well bore40.
• If the well bore is not stable, the No branch ofdecisional step216 leads to step218. Atstep218, density of the drilling fluid may be increased to increase pressure on thewalls49 of the well bore40 and stabilize the well bore40. In one embodiment, care may be taken to avoid increasing drilling fluid density up to or beyond the fracture gradient of thecoal seam30. Also, atstep220, additional fluid loss agents may be added to the drilling fluid to enhance thefilter cake100 and reduce loss of drilling fluid into thecoal seam30. In a particular embodiment, starch may be added to enhance the sealability of thefilter cake100. In another embodiment, the additional amounts of fluid loss agents (aphrons, micelles, or other fluid loss agents) may be added to enhance thefilter cake100. Also, at step221, the flow rate of the drilling fluid can be adjusted.
• Step221 leads to decisional step222. The Yes branch ofdecisional step216 also leads to step222. At decisional step222, it is determined if cuttings are building up in the well bore40. Cutting buildup may be determined by the volume of cuttings recovered at the surface from the drilling fluid. For example, a low volume of cuttings may indicate buildup in the well bore40. If cuttings are building up in the well bore40, the Yes branch of decisional step222 leads to step224. Atstep224, the density of the drilling fluid may be increased to enhance the ability of the drilling fluid to remove cuttings from the well bore40. The density of the drilling fluid may be increased to a specific gravity toward, up to, at, near or above that of the coal cuttings in order to increase buoyancy of cuttings in the drilling fluid and increase cutting removal. As previously described, in one embodiment, care may be taken to avoid reaching the fracture gradient of thecoal seam30 and causing fractures in the seam. Next, atstep226, additional viscosity agents may be added to enhance cutting removal. At step227, the flow of drilling fluid may be adjusted. In one instance, the flow can be increased to increase cuttings removal.
• Step227 returns to step212. The No branch of decisional step222 also returns to step212. Atstep212, drilling of the radiused and/orhorizontal portions46 and44 of the well bore40 is continued with adjustments for fluid density, fluid loss, and/or viscosity made as need for well bore stability and cuttings removal of the well bore40. Upon completion of the well bore40, the Yes branch ofdecisional step214 leads to the end of the process.
• FIG. 7 illustrates anotherexample system300 of drilling a well bore40 from theterranean surface20 to a subterranean zone (coal seam30). Theexample system300 is similar to theexample system10 described above with respect toFIGS. 1-6 above, but further includes asurface bore310 coupled to theterranean surface20 and acavity312. The surface bore310 extends from thesurface20, directly, through an entry bore (not shown), or from a location about the surface to at least partially coincide with thecoal seam30. In some instances, the surface bore310 may extend through and/or below thecoal seam30 to define asump314. Acasing316 may be provided through all or part of the surface bore310, and in one instance terminates above thecavity312.
• The surface bore310 may be horizontally offset from thefirst portion42 of the well bore40 proximate the coal seam30 a sufficient distance to permit thecurved portion46 and any desired length ofsecond portion44 to be drilled before intersecting thecavity312. The amount of the offset can be selected so the radius of thecurved portion46 can be large. A large radius of curvature reduces friction in the well bore40 during drilling operations, and as a result, increases the reach of the drill string (as limited by friction) over well bores drilled with tighter radiuses.
• FIG. 7 depicts the surface bore310 extending substantially vertically; however, the surface bore310 may be formed at any angle relative to thesurface20. For example, the surface bore310 may be slanted or include a slanted portion. By slanting the surface bore310, the location of the surface bore310 at thesurface20 can be positioned closer to the location of thefirst portion42, and in some instances can be drilled from the same drilling location, drilling pad, or both bores (bore310, bore42) can be drilled through a common entry bore. The surface bore310 may also, or alternatively, be slanted to accommodatesurface20 geometric characteristics or other concerns such as nearby well bores.
• Cavity312 is formed proximate thecoal seam30. As used herein, proximate is intended to encompass the case where thecavity312 is partly or wholly within thecoal seam30. Thecavity312 can be formed though the surface bore310, for example, with an under reamer device, by hydrojetting, or other cavity forming device. Many cavity forming devices will form acavity312 with a substantially cylindrical portion, whereas natural occurring cracks or crevices are not cylindrical. Thecavity312 can be an enlarged cavity having a transverse dimension greater than the transverse dimension of the surface bore310. Alternately thecavity312 can have a transverse dimension equal to or smaller than the transverse dimension of the surface bore310. The vertical dimension of thecavity312, may be smaller than the vertical thickness of thecoal seam30, approximately the same as the vertical thickness of thecoal seam30, or may be larger than the vertical thickness of thecoal seam30.
• The well bore40 is drilled similarly to that described above, but the surface bore310 and thecavity312 are typically (although not necessarily) formed first. Also, the drilling of well bore40 is controlled so that the bore intersects thecavity312. In certain embodiments, thecavity312 provides an enlarged target for intersection, and reduces the precision to which drilling well bore40 must be controlled. After thecavity312 has been successfully intersected, drilling may continue through thecavity312 and into thecoal seam30. As discussed above, drilling fluid or mud is circulated down through the interior ofdrilling string50 and up the annulus betweendrilling string50 and well borewalls49 where the drilling fluid is used to remove debris. While drilling the well bore40, additional fluids, for example additional drilling fluid with the same or different characteristics and/or amounts and types of weighting agents, fluid loss agents, and/or viscosity agents as that pumped down thedrilling string50, or other suitable fluids, can be pumped down the surface bore310 into the annulus between thedrilling string50 and the well borewalls49. The additional fluids can be flowed to increase the flow rate in the annulus and aid in removing debris that may otherwise traversing thecurved portion42 and traveling up thefirst portion42 to thesurface20.
• As above, the well bore40 may be a single bore without laterals, or may include a well bore pattern with a plurality of lateral or other horizontal well bores. If desired, all or part of the well bore pattern can be lined. For example, liners may be provided in the lateral or other horizontal well bores and tied back to casing or liners in the well bore40. Where the well bore40 includes a well bore pattern, thecavity312 can act as a junction for multiple lined bores. If two or more of the liners communicate with thecavity312, production from the bores can centrally collected in thecavity312 and withdrawn.
• FIG. 8 illustrates producing the well bore40 of thesystem300. In certain embodiments, thecavity312 can be filled with gravel318 (i.e. gravel packed). The gravel318 helps support thecavity312 and also acts to filter coal fragments out of fluid before it enters the surface bore310. In some embodiments, gravel that is coarse may be used because, for example, coal fragments breaking off from the coal seam tend to be larger than sands, silts and clays that are typically produced in other formations. In one example, gravel with a mean diameter of between about 20 and about 30 mm is used. Coarse gravel is different from finer gravel (i.e. gravel with a smaller mean diameter) used when producing from a sandy formation. The gravel318, typically contained in a slurry, may be introduced through the surface bore310, for example, through the interior of a tubing extending into the cavity or in an annulus between a tubing and the wall of the surface bore310.
• In certain embodiments, thecavity312 can be provided with aapertured liner320 positioned to communicate with the surface bore310. Theapertured liner320 can be provided in thecavity312 prior to gravel packing. Alternatively, thecavity312 can be gravel packed and theapertured liner320 provided with a conical or othersuitable tip322 and subsequently driven through the gravel318 into position in thecavity312.
• In this embodiment, theinlet324 of a pump, such as a sucker rod pump, electric submersible pump, or other type of pump, is installed in the surface bore310 to withdraw fluids collected in thecavity312 to thesurface20 through a pump string326. Thepump inlet324 can be positioned within the surface bore310 or within theapertured liner320 in thecavity312. Other artificial lift techniques or the natural flow from the formation can be used in combination with or as an alternative to a pump.
• In operation of the illustrative embodiment, water, debris, and resources, such as gas from thecoal seam30, flow along the well bore40. The water and debris collect and thecavity312, and, if provided, also in thesump314. The water is removed from thecavity312 to thesurface20 by theinlet324 of the pump, or by other artificial lift or natural flow from the formation. Gas may flow through the well bore40 to thesurface20, through the surface bore310 (in the annulus between the pump string326 and the wall of the surface bore310) to thesurface20, or through both.
• Although the present disclosure has been described with several embodiments, various changes and modifications may be suggested to one skilled in the art. It is intended that the present invention encompasses such changes and modifications as fall within the scope of the appended claims.

Claims (19)

1. A method for drilling a well bore, comprising:

drilling a substantially horizontal well bore in a coal seam; and

drilling the well bore over-balanced with a drilling fluid comprising at least one of aphrons and micelles to form a filter cake on a wall of the well bore during drilling.

2. The method ofclaim 1, wherein the drilling fluid comprises a density at or greater than 9.5 pounds per gallon.

3. The method ofclaim 1, wherein the drilling fluid comprises a density at or greater than 10 pounds per gallon.

4. The method ofclaim 1, wherein the drilling fluid comprises a density substantially the same as that of the coal seam cuttings produced by drilling the well bore.

5. The method ofclaim 1, wherein the drilling fluid comprises a viscosity agent.

6. The method ofclaim 1, wherein the filter cake invasion into the formation comprises a depth of less than 5 centimeters.

7. The method ofclaim 1, wherein the coal seam comprises at least one of naturally occurring fractures and cleats.

8. The method ofclaim 1, wherein the drilling fluid further comprises starch.

9. The method ofclaim 1, further comprising adjusting at least one of a flow rate and a property of the drilling fluid based at least in part on a difference between an actual amount of debris recovered per unit time and an expected amount of cuttings recovery per unit time.

10. A system for drilling a well bore, comprising:

a drill bit coupled by a drill string to a rig at a surface, the drill bit operable to drill a well bore in a coal seam; and

a drilling fluid pumped through the drill string to the drill bit, the drilling fluid comprising at least one of aphrons and micelles to form a filter cake on the wall of the well bore during drilling.

11. The system ofclaim 10, wherein the drilling fluid comprises a density at or greater than 9.5 pounds per gallon.

12. The system ofclaim 10, wherein the drilling fluid comprises a density at or greater than 10 pounds per gallon.

13. The system ofclaim 10, wherein the drilling fluid comprises a density substantially the same as that of the coal seam cuttings produced by drilling the well bore.

14. The system ofclaim 10, wherein the drilling fluid comprises a viscosity agent.

15. The system ofclaim 10, wherein the filter cake invasion into the formation comprises a depth of less than 5 centimeters.

16. The system ofclaim 10, wherein the coal seam comprises at least one of naturally occurring fractures and cleats.

17. The system ofclaim 10, wherein the drilling fluid further comprises starch.

18. The system ofclaim 10, wherein the drilling fluid comprises FLC 2000.

19. The method ofclaim 1, wherein the drilling fluid comprises FLC 2000.

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