US20080202764A1 - Consumable downhole tools - Google Patents

Abstract

A method of removing a downhole tool from a wellbore comprising contacting the tool with a heat source wherein the tool comprises at least one load-bearing component comprising a thermally degradable material. A method of reducing the structural integrity of a downhole tool comprising fabricating the load-bearing components of the tool from a thermally degradable material. A method of removing a downhole tool comprising mechanically milling and/or drilling the tool from a wellbore wherein the tool comprises at least one load bearing component comprising a phenolic resin wherein the phenolic resin comprises a rosole, a novalac or combinations thereof.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS
• This application is related to commonly owned U.S. patent application Ser. No. 11/423,079 entitled “Consumable Downhole Tools” and U.S. patent application Ser. No. 11/423,081 entitled “Methods for Removing Consumable Downhole Tools,” both filed on the Jun. 8, 2006 and incorporated by reference herein.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
• Not applicable.
REFERENCE TO A MICROFICHE APPENDIX
• Not applicable.
FIELD OF THE INVENTION
• The present invention relates to consumable downhole tools and methods of removing such tools from well bores. More particularly, the present invention relates to downhole tools comprising materials that are burned and/or consumed when exposed to heat and/or an oxygen source and methods and systems for consuming such downhole tools in situ.
BACKGROUND
• A wide variety of downhole tools may be used within a well bore in connection with producing hydrocarbons or reworking a well that extends into a hydrocarbon formation. Downhole tools such as frac plugs, bridge plugs, and packers, for example, may be used to seal a component against casing along the well bore wall or to isolate one pressure zone of the formation from another. Such downhole tools are well known in the art.
• After the production or reworking operation is complete, these downhole tools must be removed from the well bore. Tool removal has conventionally been accomplished by complex retrieval operations, or by milling or drilling the tool out of the well bore mechanically. Thus, downhole tools are either retrievable or disposable. Disposable downhole tools have traditionally been formed of drillable metal materials such as cast iron, brass and aluminum. To reduce the milling or drilling time, the next generation of downhole tools comprises composites and other non-metallic materials, such as engineering grade plastics. Nevertheless, milling and drilling continues to be a time consuming and expensive operation. To eliminate the need for milling and drilling, other methods of removing disposable downhole tools have been developed, such as using explosives downhole to fragment the tool, and allowing the debris to fall down into the bottom of the well bore. This method, however, sometimes yields inconsistent results. Therefore, a need exists for disposable downhole tools that are reliably removable without being milled or drilled out, and for methods of removing such disposable downhole tools without tripping a significant quantity of equipment into the well bore.
SUMMARY OF THE INVENTION
• Disclosed herein is a method of removing a downhole tool from a wellbore comprising contacting the tool with a heat source wherein the tool comprises at least one load-bearing component comprising a thermally degradable material.
• Also disclosed herein is a method of reducing the structural integrity of a downhole tool comprising fabricating the load-bearing components of the tool from a thermally degradable material.
• Further disclosed herein is a method of removing a downhole tool comprising mechanically milling and/or drilling the tool from a wellbore wherein the tool comprises at least one load bearing component comprising a phenolic resin wherein the phenolic resin comprises a rosole, a novalac or combinations thereof.
BRIEF DESCRIPTION OF THE DRAWINGS
• FIG. 1 is a schematic, cross-sectional view of an exemplary operating environment depicting a consumable downhole tool being lowered into a well bore extending into a subterranean hydrocarbon formation;
• FIG. 2 is an enlarged cross-sectional side view of one embodiment of a consumable downhole tool comprising a frac plug being lowered into a well bore;
• FIG. 3 is an enlarged cross-sectional side view of a well bore with a representative consumable downhole tool with an internal firing mechanism sealed therein; and
• FIG. 4 is an enlarged cross-sectional side view of a well bore with a consumable downhole tool sealed therein, and with a line lowering an alternate firing mechanism towards the tool.
NOTATION AND NOMENCLATURE
• Certain terms are used throughout the following description and claims to refer to particular assembly components. This document does not intend to distinguish between components that differ in name but not function. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”.
• Reference to up or down will be made for purposes of description with “up”, “upper”, “upwardly” or “upstream” meaning toward the surface of the well and with “down”, “lower”, “downwardly” or “downstream” meaning toward the lower end of the well, regardless of the well bore orientation. Reference to a body or a structural component refers to components that provide rigidity, load bearing ability and/or structural integrity to a device or tool.
DETAILED DESCRIPTION
• FIG. 1 schematically depicts an exemplary operating environment for aconsumable downhole tool100. As depicted, adrilling rig110 is positioned on the earth'ssurface105 and extends over and around a well bore120 that penetrates a subterranean formation F for the purpose of recovering hydrocarbons. At least the upper portion of thewell bore120 may be lined withcasing125 that is cemented127 into position against the formation F in a conventional manner. Thedrilling rig110 includes aderrick112 with arig floor114 through which awork string118, such as a cable, wireline, E-line, Z-line, jointed pipe, or coiled tubing, for example, extends downwardly from thedrilling rig110 into thewell bore120. Thework string118 suspends a representativeconsumable downhole tool100, which may comprise a frac plug, a bridge plug, a packer, or another type of well bore zonal isolation device, for example, as it is being lowered to a predetermined depth within the well bore120 to perform a specific operation. Thedrilling rig110 is conventional and therefore includes a motor driven winch and other associated equipment for extending thework string118 into the well bore120 to position theconsumable downhole tool100 at the desired depth.
• While the exemplary operating environment depicted inFIG. 1 refers to astationary drilling rig110 for lowering and setting theconsumable downhole tool100 within a land-based well bore120, one of ordinary skill in the art will readily appreciate that mobile workover rigs, well servicing units, such as slick lines and e-lines, and the like, could also be used to lower thetool100 into the well bore120. It should be understood that theconsumable downhole tool100 may also be used in other operational environments, such as within an offshore well bore.
• Theconsumable downhole tool100 may take a variety of different forms. In an embodiment, thetool100 comprises a plug that is used in a well stimulation/fracturing operation, commonly known as a “frac plug.”FIG. 2 depicts an exemplary consumable frac plug, generally designated as200, as it is being lowered into awell bore120 on a work string118 (not shown). Thefrac plug200 comprises an elongatedtubular body member210 with anaxial flowbore205 extending therethrough. Aball225 acts as a one-way check valve. Theball225, when seated on anupper surface207 of theflowbore205, acts to seal off theflowbore205 and prevent flow downwardly therethrough, but permits flow upwardly through theflowbore205. In some embodiments, an optional cage, although not included inFIG. 2, may be formed at the upper end of thetubular body member210 to retainball225. Apacker element assembly230 extends around thetubular body member210. One ormore slips240 are mounted around thebody member210, above and below thepacker assembly230. Theslips240 are guided bymechanical slip bodies245. Acylindrical torch257 is shown inserted into theaxial flowbore205 at the lower end of thebody member210 in thefrac plug200. Thetorch257 comprises afuel load251, afiring mechanism253, and atorch body252 with a plurality ofnozzles255 distributed along the length of thetorch body252. Thenozzles255 are angled to direct flow exiting thenozzles255 towards theinner surface211 of thetubular body member210. Thefiring mechanism253 is attached near the base of thetorch body252. Anannulus254 is provided between thetorch body252 and theinner surface211 of thetubular body member210, and theannulus254 is enclosed by theball225 above and by thefuel load251 below.
• At least some of the components comprising thefrac plug200 may be formed from consumable materials that burn away and/or lose structural integrity when exposed to heat. Such consumable components may be formed of any consumable material that is suitable for service in a downhole environment and that provides adequate strength to enable proper operation of thefrac plug200. In embodiments, the consumable materials comprise thermally degradable materials such as magnesium metal, a thermoplastic material, composite material, a phenolic material or combinations thereof.
• In an embodiment, the consumable materials comprise a thermoplastic material. Herein a thermoplastic material is a material that is plastic or deformable, melts to a liquid when heated and freezes to a brittle, glassy state when cooled sufficiently. Thermoplastic materials are known to one of ordinary skill in the art and include for example and without limitation polyalphaolefins, polyaryletherketones, polybutenes, nylons or polyamides, polycarbonates, thermoplastic polyesters such as those comprising polybutylene terephthalate and polyethylene terephthalate; polyphenylene sulphide; polyvinyl chloride; styrenic copolymers such as acrylonitrile butadiene styrene, styrene acrylonitrile and acrylonitrile styrene acrylate; polypropylene; thermoplastic elastomers; aromatic polyamides; cellulosics; ethylene vinyl acetate; fluoroplastics; polyacetals; polyethylenes such as high-density polyethylene, low-density polyethylene and linear low-density polyethylene; polymethylpentene; polyphenylene oxide, polystyrene such as general purpose polystyrene and high impact polystyrene; or combinations thereof.
• In an embodiment, the consumable materials comprise a phenolic resin. Herein a phenolic resin refers to a category of thermosetting resins obtained by the reaction of phenols with simple aldehydes such as for example formaldehyde. The component comprising a phenolic resin may have the ability to withstand high temperature, along with mechanical load with minimal deformation or creep thus provides the rigidity necessary to maintain structural integrity and dimensional stability even under downhole conditions. In some embodiments, the phenolic resin is a single stage resin. Such phenolic resins are produced using an alkaline catalyst under reaction conditions having an excess of aldehyde to phenol and are commonly referred to as resoles. In some embodiments, the phenolic resin is a two stage resin. Such phenolic resins are produced using an acid catalyst under reaction conditions having a substochiometric amount of aldehyde to phenol and are commonly referred to as novalacs. Examples of phenolic resins suitable for use in this disclosure include without limitation MILEX and DUREZ 23570 black phenolic which are phenolic resins commercially available from Mitsui Company and Durez Corporation respectively. In an embodiment, a phenolic resin suitable for use in this disclosure (e.g., DUREZ 23570) has about the physical properties set forth in Table 1.

• 	TABLE 1*
  	Compression Grade	Injection Grade

  	International Units	US Units	International Units	US units	ASTM Method

  Typical Physical Properties

  Specific Gravity	1.77	1.77	1.77	1.77	D792
  Molding Shrinkage	0.0030 m/m	0.0030 in/in	0.0030 m/m	0.0030 in/in	D6289
  Tensile Strength	90 MPa	13,000 psi	103 MPa	15,000 psi	D638
  Flexural Strength	124 MPa	18,000 psi	172 MPa	25,000 psi	D790
  Compressive	248 MPa	36,000 psi	262 MPa	38,000 psi	D695
  Tensile Modulus	17.2 GPa	2.5 × 106psi	17.2 GPa	2.5 × 106psi	D638
  Izod Impact	26.7 J/m	0.50 ft lb/in	26.7 J/m	0.50 ft lb/in	D256
  Deflection	204° C.	400° F.	204° C.	400° F.	D648
  Water Absorption	0.05%	0.05%	0.05%	0.05%	D570

  Typical Electrical Properties

  Dielectric Strength	16.7 MV/m	425 V/mil	17.7 MV/m	450 V/mil	D149
  Short time	16.7 MV/m	425 V/mil	17.7 MV/m	450 V/mil	D149
  Step by Step	14.7 MV/M	375 V/mil	14.7 MV/m	375 V/mil
  Dissipation Factor					D150
  @ 60 Hz	0.04	0.04	0.04	0.04
  @ 1 kHz	0.03	0.03	0.03	0.03
  @ 1 MHz	0.01	0.01	0.01	0.01
  Dielectric Constant					D150
  @ 60 Hz	5.7	5.7	5.7	5.7
  @ 1 KHz	5.4	5.4	5.4	5.4
  @ 1 MHz	5.5	5.5	5.5	5.5
  Volume Resistivity	1 × 1010m	1 × 1012cm	1 × 1010m	1 × 1012cm	D257
  *Properties determined with test specimens molded at 340–350° F.

• In an embodiment, the consumable material comprises a composite material. Herein a composite material refers to engineered materials made from two or more constituent materials with significantly different physical or chemical properties and which remain separate and distinct within the finished structure. Composite materials are well known to one of ordinary skill in the art and may include for example and without limitation a reinforcement material such as fiberglass, quartz, kevlar, Dyneema or carbon fiber combined with a matrix resin such as polyester, vinyl ester, epoxy, polyimides, polyamides, thermoplastics, phenolics, or combinations thereof. In an embodiment, the composite is a fiber reinforced polymer.
• Frac plugs are often contacted with wellbore servicing fluids comprising caustic or corrosive materials. For example, fracturing fluids often comprise an acid such as for example, hydrochloric acid. In an embodiment, the consumable materials for use in this disclosure may be further characterized by a resistance to corrosive materials such as for example acids.
• In operation, these consumable components may be exposed to heat via flow exiting thenozzles255 of thetorch body252. As such, consumable components nearest thesenozzles255 will burn first, and then the burning extends outwardly to other consumable components.
• Any number or combination offrac plug200 components may be made of consumable materials. In an embodiment, at least one of the load-bearing components offrac plug200 comprises a consumable material. In an alternative embodiment, the load bearing components of thefrac plug200, including thetubular body member210, theslips240, themechanical slip bodies245, or a combination thereof, may comprise consumable material. Theseload bearing components210,240,245 hold thefrac plug200 in place during well stimulation/fracturing operations. If thesecomponents210,240,245 are burned and/or consumed due to exposure to heat, they will lose structural integrity and crumble under the weight of the remainingplug200 components, or when subjected to other well bore forces, thereby causing thefrac plug200 to fall away (or circulate back to the surface) into thewell bore120. In another embodiment, only thetubular body member210 is made of consumable material, and consumption of thatbody member210 sufficiently compromises the structural integrity of thefrac plug200 to cause it to fall away into the well bore120 when thefrac plug200 is exposed to heat or a combustion source in combination with oxygen.
• Thefuel load251 of thetorch257 may be formed from materials that, when ignited and burned, produce heat and an oxygen source, which in turn may act as the catalysts for initiating burning of the consumable components of thefrac plug200. By way of example only, one material that produces heat and oxygen when burned is thermite, which comprises iron oxide, or rust (Fe₂O₃), and aluminum metal power (Al). When ignited and burned, thermite reacts to produce aluminum oxide (Al₂O₃) and liquid iron (Fe), which is a molten plasma-like substance. The chemical reaction is:
• 
  Fe₂O₃+2Al(s)→Al₂O₃(s)+2Fe(l)
• Thenozzles255 located along thetorch body252 are constructed of carbon and are therefore capable of withstanding the high temperatures of the molten plasma substance without melting. However, when the consumable components of thefrac plug200 are exposed to heat such as via molten plasma, the consumable components may melt, deform, ignite, combust, or be otherwise compromised, resulting in the lose of structural integrity and causing the frac plug to fall away in the wellbore. Furthermore, application of a slight load, such as a pressure fluctuation or pressure pulse, for example, may cause a compromised component made of the consumable material to crumble or otherwise lose structural integrity. In an embodiment, such loads are applied to the well bore and controlled in such a manner so as to cause structural failure of thefrac plug200.
• In one embodiment, thetorch257 may comprise the “Radial Cutting Torch”, developed and sold by MCR Oil Tools Corporation. The Radial Cutting Torch includes afuel load251 constructed of thermite and classified as a flammable, nonexplosive solid. Using a nonexplosive material like thermite provides several advantages. Numerous federal regulations regarding the safety, handling and transportation of explosives add complexity when conveying explosives to an operational job site. In contrast, thennite is nonexplosive and thus does not fall under these federal constraints.Torches257 constructed of thermite, including the Radial Cutting Torch, may be transported easily, even by commercial aircraft.
• In order to ignite thefuel load251, afiring mechanism253 is employed that may be activated in a variety of ways. In one embodiment, a timer, such as an electronic timer, a mechanical timer, or a spring-wound timer, a volume timer, or a measured flow timer, for example, may be used to activate a heating source within thefiring mechanism253. In one embodiment, an electronic timer may activate a heating source when pre-defined conditions, such as time, pressure and/or temperature are met. In another embodiment, the electronic timer may activate the heat source purely as a function of time, such as after several hours or days. In still another embodiment, the electronic timer may activate when pre-defined temperature and pressure conditions are met, and after a specified time period has elapsed. In an alternate embodiment, thefiring mechanism253 may not employ time at all. Instead, a pressure actuated firing head that is actuated by differential pressure or by a pressure pulse may be used. It is contemplated that other types of devices may also be used. Regardless of the means for activating thefiring mechanism253, once activated, thefiring mechanism253 generates enough heat to ignite thefuel load251 of thetorch257. In one embodiment, thefiring mechanism253 comprises the “Thermal Generator”, developed and sold by MCR Oil Tools Corporation, which utilizes an electronic timer. When the electronic timer senses that pre-defined conditions have been met, such as a specified time has elapsed since setting the timer, a single AA battery activates a heating filament capable of generating enough heat to ignite thefuel load251, causing it to burn. To accelerate consumption of thefrac plug200, a liquid or powder-based accelerant may be provided inside theannulus254. In various embodiments, the accelerant may be liquid manganese acetate, nitromethane, or a combination thereof.
• In an embodiment, contacting of the load-bearing components of thefrac plug200 with heat may not result in complete structural failure of thefrac plug200. In such embodiments, removal of thefrac plug200 from the wellbore may require mechanical milling or drilling of the frac plug out of the wellbore. Afrac plug200 having load-bearing components comprising the consumable materials of this disclosure may be more readily removed by mechanical methods such as milling or drilling when compared to a frac plug having load bearing components comprising metallic materials.
• In operation, thefrac plug200 ofFIG. 2 may be used in a well stimulation/fracturing operation to isolate the zone of the formation F below theplug200. Referring now toFIG. 3, thefrac plug200 ofFIG. 2 is shown disposed between producing zone A and producing zone B in the formation F. As depicted, thefrac plug200 comprises atorch257 with afuel load251 and afiring mechanism253, and at least one consumable material component such as thetubular body member210. Theslips240 and themechanical slip bodies245 may also be made of consumable material, such as magnesium metal. In a conventional well stimulation/fracturing operation, before setting thefrac plug200 to isolate zone A from zone B, a plurality ofperforations300 are made by a perforating tool (not shown) through thecasing125 andcement127 to extend into producing zone A. Then a well stimulation fluid is introduced into the well bore120, such as by lowering a tool (not shown) into the well bore120 for discharging the fluid at a relatively high pressure or by pumping the fluid directly from thesurface105 into thewell bore120. The well stimulation fluid passes through theperforations300 into producing zone A of the formation F for stimulating the recovery of fluids in the form of oil and gas containing hydrocarbons. These production fluids pass from zone A, through theperforations300, and up the well bore120 for recovery at thesurface105.
• Prior to running thefrac plug200 downhole, thefiring mechanism253 is set to activate a heating filament when predefined conditions are met. In various embodiments, such predefined conditions may include a predetermined period of time elapsing, a specific temperature, a specific pressure, or any combination thereof. The amount of time set may depend on the length of time required to perform the well stimulation/fracturing operation. For example, if the operation is estimated to be performed in12 hours, then a timer may be set to activate the heating filament after12 hours have elapsed. Once thefiring mechanism253 is set, thefrac plug200 is then lowered by thework string118 to the desired depth within the well bore120, and thepacker element assembly230 is set against thecasing125 in a conventional manner, thereby isolating zone A as depicted inFIG. 3. Due to the design of thefrac plug200, theball225 will unseal theflowbore205, such as by unseating from thesurface207 of theflowbore205, for example, to allow fluid from isolated zone A to flow upwardly through thefrac plug200. However, theball225 will seal off theflowbore205, such as by seating against thesurface207 of theflowbore205, for example, to prevent flow downwardly into the isolated zone A. Accordingly, the production fluids from zone A continue to pass through theperforations300, into the well bore120, and upwardly through theflowbore205 of thefrac plug200, before flowing into the well bore120 above thefrac plug200 for recovery at thesurface105.
• After thefrac plug200 is set into position as shown inFIG. 3, a second set ofperforations310 may then be formed through thecasing125 andcement127 adjacent intermediate producing zone B of the formation F. Zone B is then treated with well stimulation fluid, causing the recovered fluids from zone B to pass through theperforations310 into thewell bore120. In this area of the well bore120 above thefrac plug200, the recovered fluids from zone B will mix with the recovered fluids from zone A before flowing upwardly within the well bore120 for recovery at thesurface105.
• If additional well stimulation/fracturing operations will be performed, such as recovering hydrocarbons from zone C, additional frac plugs200 may be installed within the well bore120 to isolate each zone of the formation F. Eachfrac plug200 allows fluid to flow upwardly therethrough from the lowermost zone A to the uppermost zone C of the formation F, but pressurized fluid cannot flow downwardly through thefrac plug200.
• After the fluid recovery operations are complete, thefrac plug200 must be removed from the well bore120. In this context, as stated above, at least some of the components of thefrac plug200 are consumable when exposed to heat and an oxygen source, thereby eliminating the need to mill or drill thefrac plug200 from the well bore120. Thus, by exposing thefrac plug200 to heat and an oxygen source, at least some of its components will be consumed, causing thefrac plug200 to release from thecasing125, and the unconsumed components of theplug200 to fall to the bottom of thewell bore120.
• In order to expose the consumable components of thefrac plug200 to heat and an oxygen source, the fuel load351 of thetorch257 may be ignited to burn. Ignition of thefuel load251 occurs when thefiring mechanism253 powers the heating filament. The heating filament, in turn, produces enough heat to ignite thefuel load251. Once ignited, thefuel load251 burns, producing high-pressure molten plasma that is emitted from thenozzles255 and directed at theinner surface211 of thetubular body member210. Through contact of the molten plasma with theinner surface211, thetubular body member210 is burned and/or consumed. In an embodiment, thebody member210 comprises magnesium metal that is converted to magnesium oxide through contact with the molten plasma. Any other consumable components, such as theslips240 and themechanical slip bodies245, may be consumed in a similar fashion. Once the structural integrity of thefrac plug200 is compromised due to consumption of its load carrying components, thefrac plug200 falls away into the well bore120, and in some embodiments, thefrac plug200 may further be pumped out of the well bore120, if desired.
• In the method described above, removal of thefrac plug200 was accomplished without surface intervention. However, surface intervention may occur should thefrac plug200 fail to disengage and, under its own weight, fall away into the well bore120 after exposure to the molten plasma produced by the burningtorch257. In that event, another tool, such aswork string118, may be run downhole to push against thefrac plug200 until it disengages and falls away into thewell bore120. Alternatively, a load may be applied to thefrac plug200 by pumping fluid or by pumping another tool into the well bore120, thereby dislodging thefrac plug200 and/or aiding the structural failure thereof.
• Surface intervention may also occur in the event that thefiring mechanism253 fails to activate the heat source. Referring now toFIG. 4, in that scenario, analternate firing mechanism510 may be tripped into thewell bore120. Aslick line500 or other type of work string may be employed to lower thealternate firing mechanism510 near thefrac plug200. In an embodiment, using its own internal timer, thisalternate firing mechanism510 may activate to ignite thetorch257 contained within thefrac plug200. In another embodiment, thefrac plug200 may include a fuse running from the upper end of thetubular body member210, for example, down to thefuel load251, and thealternate firing mechanism510 may ignite the fuse, which in turn ignites thetorch257.
• In still other embodiments, thetorch257 may be unnecessary. As an alternative, a thermite load may be positioned on top of thefrac plug200 and ignited using afiring mechanism253. Molten plasma produced by the burning thermite may then burn down through thefrac plug200 until the structural integrity of theplug200 is compromised and theplug200 falls away downhole.
• Removing a consumabledownhole tool100, such as thefrac plug200 described above, from the well bore120 is expected to be more cost effective and less time consuming than removing conventional downhole tools, which requires making one or more trips into the well bore120 with a mill or drill to gradually grind or cut the tool away. The foregoing descriptions of specific embodiments of the consumabledownhole tool100, and the systems and methods for removing the consumabledownhole tool100 from the well bore120 have been presented for purposes of illustration and description and are not intended to be exhaustive or to limit the invention to the precise forms disclosed. Obviously many other modifications and variations are possible. In particular, the type of consumabledownhole tool100, or the particular components that make up thedownhole tool100 could be varied. For example, instead of afrac plug200, the consumabledownhole tool100 could comprise a bridge plug, which is designed to seal the well bore120 and isolate the zones above and below the bridge plug, allowing no fluid communication in either direction. Alternatively, the consumabledownhole tool100 could comprise a packer that includes a shiftable valve such that the packer may perform like a bridge plug to isolate two formation zones, or the shiftable valve may be opened to enable fluid communication therethrough.
• While various embodiments of the invention have been shown and described herein, modifications may be made by one skilled in the art without departing from the spirit and the teachings of the invention. The embodiments described here are exemplary only, and are not intended to be limiting. Many variations, combinations, and modifications of the invention disclosed herein are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited by the description set out above, but is defined by the claims which follow, that scope including all equivalents of the subject matter of the claims.

Claims (20)

1. A method of removing a downhole tool from a wellbore comprising contacting the tool with a heat source wherein the tool comprises at least one load-bearing component comprising a thermally degradable material.

2. The method ofclaim 1 wherein the thermally degradable material comprises a thermoplastic material, a phenolic material, a composite material, or combinations thereof.

3. The method ofclaim 2 wherein the thermoplastic material comprises polyalphaolefins, polyaryletherketones, polybutenes, nylons or polyamides, polycarbonates, thermoplastic polyesters, styrenic copolymers, thermoplastic elastomers, aromatic polyamides, cellulosics, ethylene vinyl acetate, fluoroplastics, polyacetals, polyethylenes, polypropylenes, polymethylpentene, polyphenylene oxide, polystyrene or combinations thereof.

4. The method ofclaim 1 wherein the load-bearing components are acid-resistant.

5. The method ofclaim 1 wherein the heat source comprises a torch with a fuel load that produces heat and oxygen when burned.

6. The method ofclaim 5 wherein the torch further comprises a torch body with a plurality of nozzles distributed along its length.

7. The method ofclaim 5 wherein the fuel load comprises a flammable, non-explosive solid.

8. The method ofclaim 5 wherein the fuel load comprises thermite.

9. The method ofclaim 5 wherein the torch further comprises a firing mechanism with a heat source to ignite the fuel load.

10. The method ofclaim 9 wherein the firing mechanism further comprises a device to activate the heat source.

11. The method ofclaim 9 wherein the firing mechanism is an electronic igniter.

12. The method ofclaim 1 wherein the tool is a frac plug,

13. The method ofclaim 1 wherein the tool is a bridge plug.

14. The method ofclaim 1 wherein the tool is a packer.

15. A method of reducing the structural integrity of a downhole tool comprising fabricating the load-bearing components of the tool from a thermally degradable material.

16. The method ofclaim 15 wherein the thermally degradable material comprises a thermoplastic material, a phenolic material, a composite material, or combinations thereof.

17. The method ofclaim 15 wherein the thermoplastic material comprises polyalphaolefins, polyaryletherketones, polybutenes, nylons or polyamides, polycarbonates, thermoplastic polyesters, styrenic copolymers, thermoplastic elastomers, aromatic polyamides, cellulosics, ethylene vinyl acetate, fluoroplastics, polyacetals, polyethylenes, polypropylenes, polymethylpentene, polyphenylene oxide, polystyrene or combinations thereof.

18. The method ofclaim 15 further comprising contacting the load bearing components with a heat source.

19. The method ofclaim 15 wherein the tool comprises a frac plug, a bridge plug or a packer.

20. A method of removing a downhole tool comprising mechanically milling and/or drilling the tool from a wellbore wherein the tool comprises at least one load bearing component comprising a phenolic resin wherein the phenolic resin comprises a rosole, a novalac or combinations thereof.

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