Title:
Slow Drilling Assembly and Method
Kind Code:
A1


Abstract:
A wellbore tubular-conveyed drill assembly comprising a wellbore tubular, an electrical drilling mechanism coupled to an outside surface of the wellbore tubular, wherein the electrical drilling mechanism has a refracted position and an extended position, wherein the electrical drilling mechanism drills one or more openings in a subterranean formation when in the extended position, and a power source coupled to the electrical drilling mechanism. A method comprising extending an electrical drilling mechanism in a direction away from a wellbore tubular, wherein the electrical drilling mechanism is coupled to an outside surface of the wellbore tubular, and drilling one or more openings in a subterranean formation with the electrical drilling mechanism.



Inventors:
Vick Jr., James Dan (Dallas, TX, US)
Scott, Bruce Edward (McKinney, TX, US)
Grieco, Joseph Steven (McKinney, TX, US)
Application Number:
14/431719
Publication Date:
10/22/2015
Filing Date:
08/20/2012
Assignee:
HALLIBURTON ENERGY SERVICES, INC.
Primary Class:
Other Classes:
175/61, 175/78, 166/308.1
International Classes:
E21B7/04; E21B3/00; E21B4/04; E21B7/06; E21B17/20; E21B43/116; E21B43/26
View Patent Images:
Related US Applications:
20060169450Degradable particulate generation and associated methodsAugust, 2006Mang et al.
20150159442High Annular Area Low Friction Stabilizer DesignJune, 2015Tomczak et al.
20080135236Method and Apparatus for Characterizing Gas ProductionJune, 2008Schoell
20170044896Real-Time Calculation of Maximum Safe Rate of Penetration While DrillingFebruary, 2017Salminen
20100012377System And Apparatus For Locating And Avoiding An Underground ObstacleJanuary, 2010Sharp et al.
20030132030Horizontal boring pipe connecting and disconnecting deviceJuly, 2003Tompkins
20150014061HYDRAULIC ACTUATION OF A DOWNHOLE TOOL ASSEMBLYJanuary, 2015Wu et al.
20140182946ENGINEERED MATERIALS FOR DRILL ROD APPLICATIONSJuly, 2014Drenth et al.
20110168443Bitless Drilling SystemJuly, 2011Smolka
20160032715RIG TELEMETRY SYSTEMFebruary, 2016Mueller et al.
20030007835Pavement corer and methodJanuary, 2003Jurshak



Other References:
Knisley US Patent no 4512422
Goodhart US Patent no 4605076
Zupanick U.S Publication no 20080066903
King US Publication no 20090006058
Primary Examiner:
QUAIM, LAMIA
Attorney, Agent or Firm:
HAYNES AND BOONE, LLP (Dallas, TX, US)
Claims:
1. A wellbore tubular-conveyed drill assembly comprising: a wellbore tubular; an electrical drilling mechanism coupled to an outside surface of the wellbore tubular, wherein the electrical drilling mechanism has a retracted position and an extended position, wherein the electrical drilling mechanism drills one or more openings in a subterranean formation when in the extended position; and a power source coupled to the electrical drilling mechanism.

2. The assembly of claim 1, wherein the electrical drilling mechanism comprises a flexible rod and a drill bit coupled to the flexible rod, wherein the electrical drilling mechanism is configured to extend the flexible rod to engage the drill bit with the subterranean formation.

3. The assembly of claim 1, wherein the electrical drilling mechanism comprises: a drill bit; and a propulsion mechanism configured to drive the drill bit in a direction away from the wellbore tubular into the subterranean formation.

4. The assembly of claim 1, wherein the electrical drilling mechanism comprises: a spool carried aboard the electrical drilling mechanism, wherein the spool provides a length of cable as the electrical drilling mechanism moves away from the retracted position.

5. The assembly of claim 3, wherein the propulsion mechanism comprises: a plurality of wheels for burrowing the electrical drilling mechanism through the subterranean formation.

6. The assembly of claim 3, wherein the propulsion mechanism further comprises: a track wrapped around the plurality of wheels for providing traction for the electrical drilling mechanism in an opening formed in the subterranean formation.

7. The assembly of claim 3, wherein the electrical drilling mechanism further comprises a telescoping body associated with the propulsion mechanism, wherein the propulsion mechanism comprises: at least two slips associated with the telescoping body.

8. The assembly of claim 1, wherein the electrical drilling mechanism comprises a rotating drill rod configured to rotate and engage the subterranean formation, wherein the rotating drill rod comprises a cutting surface along at least a portion of a length thereof.

9. The assembly of claim 1, wherein the electrical drilling mechanism pivots at one end so as to engage the subterranean formation with an opposite end.

10. The assembly of claim 1, wherein the electrical drilling mechanism comprises one or more perforating charges.

11. The assembly of claim 1, further comprising a housing coupled to the outside surface of the wellbore tubular, wherein the electrical drilling mechanism is at least partially contained in the housing when in the retracted position.

12. The assembly of claim 11, wherein the housing is configured to pivot relative to the wellbore tubular.

13. The assembly of claim 1, further comprising a deflector configured to direct the drilling mechanism in a direction away from the wellbore tubular.

14. A method comprising: extending an electrical drilling mechanism in a direction away from a wellbore tubular, wherein the electrical drilling mechanism is coupled to an outside surface of the wellbore tubular; and drilling one or more openings in a subterranean formation with the electrical drilling mechanism.

15. The method of claim 14, further comprising: drilling a wellbore; and inserting a production string comprising the wellbore tubular into the wellbore.

16. The method of claim 14, wherein the one or more openings increase a producing area of the wellbore.

17. The method of claim 14, further comprising: producing a fluid through at least one of the one or more openings.

18. The method of claim 14, further comprising: producing a fluid from a subterranean formation.

19. The method of claim 17, wherein drilling the one or more openings occurs during producing the fluid, the method further comprising: removing a cutting from the wellbore with the fluid produced from the subterranean formation.

20. The method of claim 14, further comprising: delaying drilling the one or more openings until production of the fluid subsides.

21. The method of claim 14, wherein drilling one or more openings occurs intermittently, continuously, or combinations thereof.

22. The method of claim 14, wherein drilling one or more openings occurs over a period of time greater than one year.

23. The method of claim 14, wherein extending the electrical drilling mechanism comprises: pivoting the electrical drilling mechanism.

24. The method of claim 14, further comprising: pivoting a housing in a direction away from the wellbore tubular, wherein extending the electrical drilling mechanism comprises extending the electrical drilling mechanism from within the housing.

25. The method of claim 14, wherein extending the electrical drilling mechanism comprises: driving the electrical drilling mechanism in a direction away from the wellbore tubular into the subterranean formation.

26. The method of claim 14, wherein extending the electrical drilling mechanism comprises: guiding the electrical drilling mechanism in the direction away from the wellbore tubular.

27. The method of claim 14, further comprising: creating a perforation in a liner or a wall of the wellbore, wherein the electrical drilling mechanism extends through the perforation.

28. The method of claim 14, further comprising: detonating an explosive charge within the one or more openings.

29. The method of claim 14, further comprising: fracturing the subterranean formation via the one or more openings.

30. The method of claim 14, further comprising: operating the electrical drilling mechanism until failure.

31. A method comprising: providing a wellbore tubular-conveyed drill assembly coupled to an outside surface of a wellbore tubular, wherein the wellbore tubular-conveyed drill assembly has a continuous hollow channel extending therethrough; coupling the continuous hollow channel to an interior of the wellbore tubular; pressurizing the interior of the wellbore tubular with a drilling fluid; directing the drilling fluid through the continuous hollow channel; and drilling one or more openings in a subterranean formation with the wellbore tubular-conveyed drill assembly.

32. The method of claim 31, further comprising: extending the wellbore tubular-conveyed drill assembly in a direction away from the wellbore tubular.

33. The method of claim 31, further comprising: providing a production string comprising the wellbore tubular; and plugging the production string below the wellbore tubular-conveyed drill assembly.

Description:

CROSS-REFERENCE TO RELATED APPLICATIONS

None.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

BACKGROUND

Wellbores are sometimes drilled into subterranean formations that contain hydrocarbons to allow recovery of the hydrocarbons. After completion of drilling, some or all of a wellbore may be lined, for example, with casing. A production string may be placed in a wellbore for production of fluids from the wellbore. In some wellbores, downhole power is available and can operate various production equipment, such as valves, chokes, sensors, etc. It is possible that excess downhole power can be available, creating an opportunity for operation of additional equipment downhole.

SUMMARY

Disclosed herein is a wellbore tubular-conveyed drill assembly comprising a wellbore tubular, an electrical drilling mechanism coupled to an outside surface of the wellbore tubular, wherein the electrical drilling mechanism has a retracted position and an extended position, wherein the electrical drilling mechanism drills one or more openings in a subterranean formation when in the extended position, and a power source coupled to the electrical drilling mechanism.

Also disclosed herein is a method comprising extending an electrical drilling mechanism in a direction away from a wellbore tubular, wherein the electrical drilling mechanism is coupled to an outside surface of the wellbore tubular, and drilling one or more openings in a subterranean formation with the electrical drilling mechanism.

Further disclosed herein is a method comprising providing a wellbore tubular-conveyed drill assembly coupled to an outside surface of a wellbore tubular, wherein the wellbore tubular-conveyed drill assembly has a continuous hollow channel extending therethrough, coupling the continuous hollow channel to an interior of the wellbore tubular, pressurizing the interior of the wellbore tubular with a drilling fluid, directing the drilling fluid through the continuous hollow channel, and drilling one or more openings in a subterranean formation with the wellbore tubular-conveyed drill assembly.

These and other features will be more clearly understood from the following detailed description taken in conjunction with the accompanying drawings and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and the advantages thereof, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description:

FIG. 1A is a cut-away side view of an embodiment of a wellbore tubular-conveyed drill assembly in a wellbore operating environment;

FIG. 1B is a cut-away side view of an embodiment of the wellbore tubular-conveyed drill assembly, shown in a retracted position;

FIG. 1C is a cut-away side view of the embodiment of the wellbore tubular-conveyed drill assembly of FIG. 1B, shown in an extended position;

FIG. 2A is cut-away side view of another embodiment of a wellbore tubular-conveyed drill assembly in a refracted position;

FIG. 2B is a cut-away side view of the embodiment of the wellbore tubular-conveyed drill assembly of FIG. 2A, shown in an extended position;

FIG. 3A is a cut-away side view of yet another embodiment a wellbore tubular-conveyed drill assembly, shown in a refracted position;

FIG. 3B is a cut-away side view of the embodiments of the wellbore tubular-conveyed drill assembly of FIG. 3A, shown in an extended position;

FIG. 4A is a side view of an embodiment of an electrical drilling mechanism;

FIG. 4B is a side view of another embodiment of an electrical drilling mechanism;

FIG. 4C is a side view of yet another embodiment of an electrical drilling mechanism;

FIG. 5 is a cut-away side view of an embodiment of the wellbore tubular-conveyed drill assembly comprising an embodiment of a deflector; and

FIG. 6 is a cut-away side view of an embodiment of the wellbore tubular-conveyed drill assembly comprising another embodiment of a deflector.

DETAILED DESCRIPTION OF THE EMBODIMENTS

In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of principles, and is not intended to limit the claims to the embodiments illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed infra may be employed separately or in any suitable combination to produce desired results.

Unless otherwise specified, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. 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,” “upward,” or “upstream” meaning toward the surface of the wellbore and with “down,” “lower,” “downward,” or “downstream” meaning toward the terminal end of the well, regardless of the wellbore orientation. Reference to in or out will be made for purposes of description with “in,” “inner,” or “inward” meaning toward the center or central axis of the wellbore, and with “out,” “outer,” or “outward” meaning toward the wellbore tubular and/or wall of the wellbore. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art with the aid of this disclosure upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.

Disclosed herein are wellbore tubular-conveyed assemblies and methods related to drilling of openings in a subterranean formation. In embodiments, the assemblies and methods may utilize available downhole power to increase long term production of a subterranean formation. Embodiments of the assemblies and methods contemplate drilling techniques which may occur over relatively long periods of time so as to provide a novel “slow” drilling technique. The slow drilling assemblies and methods disclosed herein may provide production from relatively small openings drilled in a subterranean formation, which may increase the overall recovery from the subterranean formation above production amounts conventionally provided in a wellbore. Using the embodiments disclosed herein, production may be increased by increasing the producing area of the wellbore; as such, the disclosed assemblies and methods may increase revenue from increased production. Many different embodiments of the disclosed assemblies and methods may be used in the same wellbore.

Referring to FIG. 1A, an example of a wellbore operating environment is shown. As depicted, the operating environment comprises a drilling rig 111 positioned on the earth's surface 107 which extends over and around a wellbore 102 that penetrates a subterranean formation 101 for the purpose of producing hydrocarbons. The disclosed methods may include drilling a wellbore 102, and the wellbore 102 may be drilled into the subterranean formation 101 using any suitable drilling technique. The wellbore 102 may extend substantially vertically away from the earth's surface 107. In alternative operating environments, all or a portion of the wellbore 102 may be vertical, deviated at any suitable angle, horizontal, and/or curved. The wellbore 102 may comprise a new wellbore, an existing wellbore, a straight wellbore, an extended reach wellbore, a sidetracked wellbore, a multi-lateral wellbore, other types of wellbores for drilling and completing one or more production zones, or combinations thereof. Further, the wellbore 102 may be used for any suitable purpose, e.g., hydrocarbon production, water production, injection, etc. In an embodiment, all or a portion of the wellbore 102 may be used for purposes other than or in addition to hydrocarbon production, such as uses related to geothermal energy.

The drilling rig 111 may comprise a derrick 108 with a rig floor 109 through which the wellbore tubular 110 extends downward from the drilling rig 111 into the wellbore 102. The drilling rig 111 may comprise a motor-driven winch and other associated equipment for extending the wellbore tubular 110 into the wellbore 102 to position the wellbore tubular-conveyed drill assembly 120 at a selected depth. While the operating environment depicted in FIG. 1 refers to a stationary drilling rig 111 for lowering and setting the wellbore tubular 110 and wellbore tubular-conveyed drill assembly 120 coupled thereto within a land-based wellbore 102, in alternative embodiments, mobile workover rigs, wellbore servicing units (such as coiled tubing units), and the like may be used to lower the wellbore tubular 110 and wellbore tubular-conveyed drill assembly 120 coupled thereto into the wellbore 102. It should be understood that a wellbore tubular 110 and wellbore tubular-conveyed drill assembly 120 coupled thereto may alternatively be used in other operational environments, such as within an offshore wellbore operational environment.

A production string 115 comprising the wellbore tubular 110 may be inserted and lowered into the wellbore 102 for production of one or more fluids from subterranean formation 101. While the disclosed assemblies and methods are described in the context of hydrocarbon production, it should be understood the assemblies and methods may be utilized in conjunction with other tubular strings which may be lowered into the wellbore 102 for various other purposes, e.g., water production, workover procedures, treatment procedures, or combinations thereof. Further, it should be understood that the wellbore tubular 110 is equally applicable to any type of wellbore tubular being inserted into a wellbore, including as non-limiting examples, drill pipe, production tubing, rod strings, coiled tubing, or combinations thereof.

The embodiment shown in FIG. 1A illustrates the wellbore tubular 110 as part of a production string 115 which has been lowered into the wellbore 102 formed in the subterranean formation 101. The wellbore tubular 110 and wellbore tubular-conveyed drill assembly 120 coupled thereto may be conveyed into the wellbore 102 in any conventional manner, and the wellbore tubular-conveyed drill assembly 120 may be conveyed into the wellbore 102 by wellbore tubular 110. The wellbore tubular-conveyed drill assembly 120 may be configured to minimize a footprint in the annulus around the wellbore tubular 110 so as to minimize obstruction of fluid(s) produced from the subterranean formation 101. In an embodiment, the wellbore tubular-conveyed drill assembly 120 may be located in a pocket (e.g., a side pocket mandrel) of the wellbore tubular 110.

Embodiments of the disclosed assemblies and methods may be used in lined wellbores, unlined wellbores, and wellbores having both lined and unlined portions. As seen in FIG. 1A, the wellbore 102 may be lined with a liner 104, e.g., casing. In alternative operating environments, a vertical portion, a deviated portion, a horizontal portion, or combinations thereof of the wellbore 102 may be cased and cemented, said portions of the wellbore 102 may be uncased, or combinations thereof. In embodiments, the liner 104 may be perforated, unperforated, or combinations thereof. In an embodiment where a wellbore 102 has a non-perforated liner 104, the wellbore tubular-conveyed drill assembly 120 may comprise a perforating charge to perforate the liner 104. To extend the assembly 120 into the subterranean formation 101, the assembly 120 may drill through the liner 104 (e.g., casing and any associated sealant such as an annular cement sheath) of lined wellbore 102, the assembly 120 may use a perforation charge to create a perforation in the liner 104 of the wellbore 102, or combinations thereof. Likewise, to extend the assembly 120 into the subterranean formation 101, the assembly 120 may drill through the wall 105 of the wellbore 102, use a perforation charge to create a perforation in the wall 105 of the wellbore 102, or combinations thereof.

In an embodiment, the wellbore tubular-conveyed drill assembly 120 may be coupled to the outside surface 112 of the wellbore tubular 110. In alternative or additional embodiments, part or all of the wellbore tubular-conveyed drill assembly 120 may be interiorly located in the production tubing of a wellbore tubular 110. Although one wellbore tubular-conveyed drill assembly 120 is shown in FIG. 1A, it should be understood that more than one wellbore tubular-conveyed drill assembly 120 may be coupled to the outside surface of wellbore tubular 110 and/or other wellbore tubulars in the production string 115. The wellbore tubular-conveyed drill assembly 120 may be placed anywhere on the circumference of the wellbore tubular 110, and in embodiments, multiple wellbore tubular-conveyed drill assemblies may be placed along the circumference of a given length of the wellbore tubular 110. Regardless of the type of operational environment the wellbore tubular-conveyed drill assembly 120 is used, it should be understood that the wellbore tubular-conveyed drill assembly 120 may serve to form one or more side boreholes and increase production of fluids from the subterranean formation 101 through the wellbore 102.

Referring to FIG. 1B, an embodiment of the wellbore tubular-conveyed drill assembly 120 may be seen placed in wellbore 102. The wellbore tubular-conveyed drill assembly 120 may comprise the wellbore tubular 110, an electrical drilling mechanism 150 coupled to the outside surface 112 of the wellbore tubular 110, and a power source 140 coupled to the electrical drilling mechanism 150. The electrical drilling mechanism 150 may have a retracted position and an extended position, and the electrical drilling mechanism 150 may drill one or more openings in the subterranean formation 101 when in the extended position. The electrical drilling mechanism 150 is shown in FIG. 1B in the retracted position. In the embodiment of FIG. 1B, the electrical drilling mechanism 150 may comprise a flexible rod 157 and a drill bit 180 coupled to the flexible rod 157, and the electrical drilling mechanism 150 may be configured to extend the flexible rod 157 so as to engage the drill bit 180 with the liner 104, wellbore wall 105, and/or subterranean formation 101. In embodiments, the electrical drilling mechanism 150 may comprise one or more perforating charges 192 to perforate a liner 104 of the wellbore 102, a wall 105 of the wellbore 102, the subterranean formation 101, or combinations thereof. The wellbore tubular-conveyed drill assembly 120 may optionally comprise a housing 130 coupled to the outside surface 112 of the wellbore tubular 110, and the electrical drilling mechanism 150 may be at least partially contained in the housing 130 when in the refracted position. The drill bit 180 may be coupled to and rotated by motor 156. The electrical drilling mechanism 150 may include a propulsion mechanism 160 (e.g., coupled to the flexible body 157 in the embodiment of FIG. 1B) to extend the electrical drilling assembly 150 in a direction away from the wellbore tubular 110. For example, the propulsion mechanism 160 may drive the drill bit 180 in a direction away from the wellbore tubular 110 (e.g., in a radial direction) and into the subterranean formation 101.

“A direction away” as used herein may refer to a general movement away from the wellbore tubular 110 (e.g., away from a central longitudinal axis defined by the wellbore tubular 110) without limitation as to the angle between the direction of movement and the longitudinal axis of the wellbore tubular 110, and without limitation to any intermittent or transient movements toward the wellbore tubular 110 when the overall or net movement is away from the wellbore tubular 110. For example, the electrical drilling mechanism 150 may follow a path which requires moving upward within the wellbore 102, moving outward to the liner 104 or wall 105 of wellbore 102, moving backward toward the wellbore tubular 110, or combinations thereof in any sequence, and such movements may be considered “a direction away” for purposes of the disclosure. In another example, repeated (e.g., piston-like) movements of the electrical drilling mechanism 150 toward the liner 104 or wall 105 of the wellbore 102 may be considered “a direction away” for purposes of the disclosure. The term “a direction away” may also refer to the movements of the electrical drilling mechanism 150 in the embodiments described herein. In an embodiment, “a direction away” means any net amount of movement beyond the wellbore wall 105 and into the surrounding subterranean formation 101 in any direction relative to an initial starting point.

Referring to FIG. 1C, the embodiment of the wellbore tubular-conveyed drill assembly 120 of FIG. 1B may be seen in the extended position. Motor 166 of the propulsion mechanism 160 has extended the flexible rod 157 from the housing 130 of the wellbore tubular-conveyed drill assembly 120. The flexible rod 157 of the electrical drilling mechanism 150 has extended toward the wall 105 of the wellbore 102 so as to move the drill bit 180 in a direction away from the wellbore tubular 110 and engage the drill bit 180 with the subterranean formation 101. The perforation charge (reference numeral 192 in FIG. 1B) has created perforation 103 in liner 104 (additionally or alternatively, the wall 105) of the wellbore 102. In alternative or additional embodiments having a lined wellbore 102, the drill bit 180 may drill through the liner 104 of the wellbore 102. In FIG. 1C, the electrical drilling mechanism 150 has drilled through any portion of the liner 104 which was not perforated to an appropriate size by the perforation charge and extended through the perforation 103. Further, the electrical drilling mechanism 150 has drilled through the wall 105 of the wellbore 102, and into the subterranean formation 101. The drill bit 180 has drilled an opening 106 in the subterranean surface 101.

Motor 166 of the propulsion mechanism 160 may be coupled to the power source 140 via cable 155. In embodiments, motor 156 may likewise be coupled to power source 140, for example, through a connection to the propulsion mechanism 160, directly to the power source 140, or combinations thereof. In alternative or additional embodiments, the propulsion mechanism 160 and/or motor 156 may be coupled to a battery with or without need for cables, such as cable 155. In alternative or additional embodiments, the propulsion mechanism 160 and/or motor 156 may be coupled to a power source external to the wellbore tubular-conveyed drill assembly 120. Examples of external power sources may include sources in downhole tools and/or components, sources in a side pocket mandrel, sources at the surface, the like, or combinations thereof. In alternative or additional embodiments, the motor 166 of the propulsion mechanism 160 may be coupled to a battery, which is coupled to a power source. In alternative or additional embodiments, the motor 156 may be coupled to a battery, which is coupled to a power source.

The power source 140 may comprise any device capable of being electrically coupled and/or providing power to the assembly 120. In an embodiment, the power source 140 may be an on-board DC battery coupled to the motor 166, motor 156, or another battery within assembly 120, for example. Alternatively, the power source 140 may be located on the rig surface. Current may be delivered to the assembly 120 through wireless power transmission or a power wireline connected to the assembly 120, such as cable 155. For example, the power source 140 may comprise a downhole generator, such as a fluid turbine, that may be used to convert fluid flow into power to the assembly 120.

In embodiments, motor 166 may move with the flexible rod 157, or may associate with moving parts which move the flexible rod 157, while the motor 166 remains stationary. The cable 155 may be of suitable length for extending and retracting the electrical drilling mechanism 150. The housing 130 may have a shape suitable for containing the electrical drilling mechanism 150 therein. In the embodiment of FIG. 1C, the flexible rod 157 may have a cylindrical shape, and housing 130 may correspondingly have a cylindrical shape. Length of extension, drilling time, drilling rate, and useful life for the disclosed assemblies are described hereinbelow.

In embodiments, one or more openings (e.g., opening 106) may be drilled in the subterranean formation 101 with one or more electrical drilling mechanisms, e.g., electrical drilling mechanism 150. As the electrical drilling mechanism 150 drills, cuttings are formed. Because of the relatively small size of the disclosed assemblies (discussed hereinbelow), cuttings may also be relatively small compared to cuttings formed in conventional drilling. In an embodiment where one or more openings are drilled during production of fluid(s) in the wellbore 102 from the subterranean formation 101, the fluid(s) may remove the cuttings. In an alternative embodiment, the cuttings may be removed with fluid (e.g., production fluid, formation fluid, drilling or treatment fluid, combinations thereof, etc.) flowing through the disclosed assembly 120. For example, the flexible rod 157 and the drill bit 180 of the wellbore tubular-conveyed drill assembly 120 may be hollow and have a continuous channel extending therethrough (e.g., longitudinally). The channel may be coupled to the interior of the wellbore tubular 110, and fluid may be directed into the hollow channel formed in the flexible rod 157 and the drill bit 180 of the wellbore tubular-conveyed drill assembly 120 (e.g., concurrent with drilling of the well, concurrent with producing the well, after production subsides, etc.). The fluid (e.g., a production or formation fluid) may be pressurized in the wellbore tubular 110 so as to force fluid through the hollow channel and out of the drill bit 180 of the wellbore tubular-conveyed drill assembly 120, thereby circulating fluid and the cuttings out of opening 106. In an additional or alternatively embodiment, the production string 115 (e.g., the wellbore tubular 110) may be plugged below the wellbore tubular-conveyed drilling assembly 120 to pressurize fluid through the hollow channel and out of the drill bit 180 of the wellbore tubular-conveyed drill assembly 120.

FIG. 2A shows a cut-away side view of another embodiment of a wellbore tubular-conveyed drill assembly 220 in a retracted position. In embodiments, the assembly 220 may comprise an electrical drilling mechanism 250 coupled to an outside surface 212 of a wellbore tubular 210. In alternative or additional embodiments, the electrical drilling mechanism 250 may be interiorly located in the production tubing of a wellbore tubular 210. The electrical drilling mechanism 250 may comprise a rotating drill rod 270 configured to rotate so as to engage the liner (e.g., of the type of liner 104 shown in FIGS. 1A-1C), the wellbore wall 205, and/or the subterranean formation 201. The rotating drill rod 270 may comprise one or more cutting surfaces 272 along at least a portion of a length thereof. A cutting surface 272 may comprise cutting teeth, a diamond bit, a cutting bit, an auger, or combinations thereof, for example. In alternative or additional embodiments, the cutting surface 272 may extend along the circumference of the rotating drill rod 270. In embodiments, the assembly 220 may be held in a retracted position via a holding mechanism (e.g., latch, clip, bracket, magnet, abutment, electromechanical lock, the like, or combinations thereof), an electric motor (e.g., motor 266 of propulsion mechanism 260), an adhesive (e.g., chemical or time or pressure or temperature activated release, the like, or combinations thereof), or combinations thereof.

FIG. 2B shows a cut-away side view of the embodiment of the wellbore tubular-conveyed drill assembly 220 of FIG. 2A in an extended position. Motor 266 may move the assembly 220 to the extended position so as to engage a wall 205 (alternatively or additionally, a liner) of the wellbore 202 and drill into the subterranean formation 201. In an embodiment, motor 266 may move or rotate the assembly 220 about a pivot point located on the outside surface 212 of the wellbore tubular 210. In an alternative embodiment, an adhesive holding the assembly 220 in a refracted position may release due to elapsed time, chemical environment, temperature, pressure, or combinations thereof. The release may cause the assembly 220 to pivot. In an embodiment, assembly 220 may be braced (e.g., weighted, unbalanced, spring-loaded, etc.) to pivot upon release. In the embodiment shown in FIG. 2B, the wellbore tubular-conveyed drill assembly 220 has pivoted at end 274 (extending electronic drilling mechanism 250 by pivoting) so as to engage the liner (e.g., of the type of liner 104 shown in FIGS. 1A-1C), the wellbore wall 205, and/or the subterranean formation 201 with opposite end 276. Upon pivot, the opposite end 276 of the rotating drill rod 270 may move in the direction (e.g., an arc) shown by arrow A. The opposite end 276 may engage the liner and/or the wall 205 of the wellbore 202 and then drill into the subterranean formation 201 in the direction shown by arrow A, as the motor 266 of the propulsion mechanism 260 pivots the assembly 220. Gravity may also act to pivot the assembly 220 while drilling alternatively or in addition to a pivoting force provided by the motor 266. The rotating drill rod 270 may rotate (e.g., clockwise or counterclockwise) along a longitudinal axis thereof, e.g., in the direction shown by arrow B. Motor 256 may be coupled to the rotating drill rod 270 so as to rotate the rotating drill rod 270 along the longitudinal axis thereof. As the rotating drill rod 270 of the electrical drilling mechanism 250 drills into subterranean formation 201, opening 206 is formed, and fluids may be produced from opening 206 so as to supplement the fluid(s) produced from the subterranean formation 201 in the wellbore 202. Power may be supplied to motor 266 of assembly 220 in any manner as described herein (e.g., a downhole power source such as a fluid turbine or other power source described hereinbelow).

FIG. 3A is a cut-away side view of an embodiment of wellbore tubular-conveyed drill assemblies 320, 322, 324, and 326 coupled to the outside surface 312 of wellbore tubular 310. The assemblies 320, 322, 324, and 326 are shown in the retracted position. Assembly 320 may comprise electrical drilling mechanism 350 contained in housing 330, assembly 322 may comprise electrical drilling mechanism 352 contained in housing 332, assembly 324 may comprise electrical drilling mechanism 354 contained in housing 334, and assembly 326 may comprise electrical drilling mechanism 356 contained in housing 336. The housings 330, 332, 334, and 336 may be coupled to the outside surface 312 of the wellbore tubular 310. The housings 330, 332, 334, and 336 may serve to contain and protect the electrical drilling mechanisms 350, 352, 354, and 356 as the wellbore tubular 310 is lowered into the wellbore 302, while fluids are produced from the wellbore 302, while other tools/components/assemblies operate in the wellbore 302, or combinations thereof. A perforation charge 392 may be placed on one or more of the assemblies 320, 322, 324, and 326, such as assembly 324. In the embodiment of FIG. 3A, the perforation charge 392 may be placed on the housing 334 of assembly 324. In additional or alternative embodiments, a perforation charge may be placed on an electrical drilling mechanism, or a combination of a housing and electrical drilling mechanism. The perforation charge 392 may be detonated at an appropriate time when engaged with the subterranean formation 301, either automatically or on command. In one or more embodiments, housings 330, 332, 334, and 336 may be hingedly or pivotably coupled to the outside surface 312 of the wellbore tubular 310 at points 340, 342, 344, and 346, respectively. The housings 330, 332, 334, and 336 of the assemblies 320, 322, 324, and 326 may be held in a retracted position via a holding mechanism (e.g., latch, clip, bracket, magnet, abutment, electromechanical lock, the like, or combinations thereof), an electric motor (e.g., at points 340, 342, 344, and 346), an adhesive (e.g., chemical or time or pressure or temperature activated release, the like, or combinations thereof), or combinations thereof. The housings 330, 332, 334, and 336 may have ends complementarily angled (as shown in FIG. 3A) so as to provide a desired path or trajectory for the electrical drilling mechanisms 350, 352, 354, and 356 contained therein for engaging the liner (e.g., of the type of liner 104 shown in FIGS. 1A-1C), wellbore wall 305, and/or subterranean formation 301 when the assemblies 320, 322, 324, and 326 are moved to the extended position. The angle of the ends of the housings 330, 332, 334, and 336 may be the same as or different from one another. For example, in FIG. 3A the angles of the ends of housing 330 are different than the angles of the ends of housing 332 and 334, which are different than the angles of the ends of housing 336, thereby providing differing trajectories for the electrical drilling mechanisms 350, 352, 354, and 356 to drill into the subterranean formation 301.

FIG. 3B is a cut-away side view of the embodiment of the wellbore tubular-conveyed drill assemblies 320, 322, 324, and 326 of FIG. 3A, shown in the extended position. Each of the assemblies 320, 322, 324, 326 has pivoted so that electrical drilling mechanisms 350, 352, 354, and 356 may engage and drill into the liner (e.g., of the type of liner 104 shown in FIGS. 1A-1C), wellbore wall 305, and/or subterranean formation 301. The electrical drilling mechanisms 350, 352, 354, and 356 shown in FIG. 3B may operate independently of one another. In additional or alternative embodiments, the electrical drilling mechanisms 350, 352, 354, 356 may operate independently, dependently, in coordination with other production components (e.g., other electrical drilling mechanisms), or combinations thereof. In embodiments, when two or more wellbore tubular-conveyed drill assemblies operate in coordination, the assemblies may operate concurrently, in sequence, or combinations thereof. In FIG. 3A, electrical drilling mechanism 354 has engaged the subterranean formation 301 and drilled opening 304 before other assemblies 350, 352, and 356. Electrical drilling mechanism 356 has engaged the subterranean formation 301 and drilled opening 306. Electrical drilling mechanisms 350 and 352 cooperatively remain dormant in their respective housings 330 and 332.

Cable 355 has supplied electrical drilling mechanism 354 with power from a power source (e.g., a downhole power source or any other power source as described herein), as has cable 357 for electrical drilling mechanism 356. In an embodiment, electrical drilling mechanisms 350 and 352 are without cables and may operate with batteries as a power source, and batteries may be charged via a downhole power source as described herein.

In an embodiment, extending the electrical drilling mechanism 350 may comprise pivoting a housing (e.g., one or more of housings 330, 332, 334, and 336) and extending the electrical drilling mechanism 350 from within of the housing. As can be seen in FIG. 3B, the housings 330, 332, 334, and 336 have pivoted relative to the wellbore tubular 310. The housings 330, 332, 334, and 336 may serve to guide the electrical drilling mechanisms 350, 352, 354, and 356 to engage the liner (e.g., of the type of liner 104 shown in FIGS. 1A-1C) and/or wall 305 of the subterranean formation 301 (i.e., guide in a direction away from the wellbore tubular 310); thus, housings 330, 332, 334, and 336 of the embodiments of FIGS. 3B may have a dual function of guiding the electrical drilling mechanisms 350, 352, 354, and 356 to engage the subterranean formation 301 as the mechanisms 350, 352, 354, and 356 extend from the housings 330, 332, 334, and 336, and of protecting the mechanisms 350, 352, 354, and 356 from elements in the wellbore 302. As can be seen in FIG. 3B, different angles of the ends of housings may provide different paths or trajectories for the electrical drilling mechanisms contained therein. Housings may provide an about horizontal path or trajectory for electrical drilling mechanisms, as housing 330 provides for electrical drilling mechanism 350, for example. Housings may provide an upwardly sloping path or trajectory for electrical drilling mechanisms, as housing 332 provides for electrical drilling mechanism 352 and as housing 334 provides for electrical drilling mechanism 354, for example. Housings may also provide downwardly sloping paths or trajectories, as housing 336 does for electrical drilling mechanism 356, for example.

The propulsion mechanisms of the electrical drilling mechanisms may be placed on the front, back, or combinations thereof. For example, propulsion mechanism 360 is placed on the back of electrical drilling mechanism 350. FIG. 3B shows propulsion mechanisms 362, 364, and 366 placed on the front of the electrical drilling mechanisms 352, 354, and 356, respectively. Propulsion mechanism 364 of electrical drilling mechanism 354 has provided traction in the opening 304 to pull the electrical drilling mechanism 354 further against subterranean formation 301 as the electrical drilling mechanism 354 drills. Likewise, propulsion mechanism 366 of the electrical drilling mechanism 356 has provided traction in the opening 306 to pull the electrical drilling mechanism 356 further against subterranean formation 301. Because electrical drilling mechanism 354 has an upward path or trajectory while electrical drilling mechanism 356 has a downward path or trajectory, the propulsion mechanism 364 may use more power than propulsion mechanism 366. In embodiments, after being guided by housings 330, 332, 334, and 336, the electrical drilling mechanisms 350, 352, 354, and 356 may travel in a known path or trajectory, preplanned path or trajectory, unknown path or trajectory, random path or trajectory, or combinations thereof. It should be understood the embodiments disclosed herein are without limitation as to path or trajectory.

FIG. 4A shows a side view of an embodiment of an electrical drilling mechanism 450, for example, of the type that may be used in the embodiments of FIG. 3. The electrical drilling mechanism 450 may be coupled to a power source (e.g., a downhole power source of the type described herein) via a cable 455. The electrical drilling mechanism 450 may comprise a spool 453 carried aboard the electrical drilling mechanism 450. The spool 453 may provide a length of cable as the electrical drilling mechanism 450 moves away from the retracted position. The length of the cable 455 may be made available by spool 453 so that the electrical drilling mechanism 450 unwinds the spool 453 as the electrical drilling mechanism 450 drills into a subterranean formation. In embodiments, the spool 453 may have a reel configuration, an end-feed configuration (which may feed lengths of cable 455 from the interior or outside of the spooled cable 455), or combinations thereof. In embodiments, the spool 453 may have a conical shape, a cylindrical shape, or combinations thereof. In embodiments with a spool 453, the cable 455 may be carried aboard electrical drilling mechanism 450 and lengthened when the electrical drilling mechanism 450 drills further into the subterranean formation; thus, the electrical drilling mechanism 450 does not have to drag or pull lengths of cable in order to extend further into the subterranean formation. Moreover, risks of catching or tangling the cable 455 are minimized because the electrical drilling mechanism 450 may carry the cable 455 and release lengths of cable 455 as needed. The cable 455 may have an end attached to a housing of the disclosed assemblies, for example. In an alternative or additional embodiment, the cable 455 may enable communication with and/or control of the electronic drilling mechanism 450.

The electrical drilling mechanism 450 may comprise a body 451, and the body 451 may comprise the cable 455 and associated spool 453, a propulsion mechanism 460, and a motor 456 for operating the drill bit 480. The drill bit 480 may be operably coupled to the motor 456. The propulsion mechanism 460 may comprise a motor 466 and wheels 462 coupled to the motor 466. In FIG. 4A the propulsion mechanism 460 has six wheels 462 associated with motor 466; however, it should be understood any number of wheels may be used which would be suitable for burrowing the electrical drilling mechanism 450 through subterranean formations as the drill bit 480 drills therein. In the embodiment of FIG. 4A, the drill bit 480 comprises a single drill head 482. The drill bit 480 may have a diameter of suitable size so as to allow wheels 462 into an opening in the subterranean formation. The diameter of the drill bit 480 may be, for example, two inches or less. The drill bit 480 may be of any configuration known in the art for engaging subterranean formations. For example, the drill bit 480 may comprise a fixed blade bit, a roller cone bit, a reamer-type bit, or any other type of bit. In FIG. 4A, the wheels 462 are positioned on the body 451 of the electrical drilling mechanism 450 adjacent the drill bit 480 (e.g., adjacent the front), however, in alternative or additional embodiments (e.g., assembly 350 in FIG. 3B), the wheels 462 may be positioned adjacent the end of the electrical drilling mechanism 450 opposite the drill bit 480 (e.g., adjacent the back). The motors 456 and 466 may be coupled to the cable 455 (and thus a power source) via connections known to those skilled in the art; alternatively, the motors 456 and 466 may include a battery (e.g., a battery pack) as a power source; alternatively, the motors 456 and 466 may include a battery which may be charged by a power source coupled to the battery.

In an embodiment, the electrical drilling mechanism 450 of the wellbore tubular-conveyed assembly may include an explosive charge 490. In an embodiment, the explosive charge 490 may detonate (e.g., manually or automatically) upon reaching a terminal or predetermined distance in the openings in the subterranean formation formed by the electrical drilling mechanism 450 (e.g., upon reaching the end of cable 455 on spool 453.). The detonation of explosives may aid in fracturing the subterranean formation to increase production of fluid(s) therefrom. Explosives and detonation techniques may be of any suitable type known to those skilled in the art with the aid of this disclosure.

FIG. 4B shows a side view of another embodiment of the electrical drilling mechanism 452. The configuration of the electrical drilling mechanism 452 shares a common configuration with the electrical drilling mechanism 450 of FIG. 4A. The electrical drilling mechanism 452 may have a propulsion mechanism 460 comprising a motor 466, wheels 462 coupled to the motor 466, and a track 464 wrapped around the wheels 462. The track 464 may be of any suitable configuration for providing traction for the electrical drilling mechanism 452 in an opening formed in a subterranean formation. The drill bit 481 of the electrical drilling mechanism 452 may have multiple heads 483, 485, and 487. The diameter of drill bit 481 may be of a suitable size so that track 464 may fit into an opening in a subterranean formation drilled by the drill bit 481. The drill bit 481 may be of any configuration known in the art for engaging subterranean formations, including fixed blade bits, roller cone bits, reamer-type bits, etc. In an embodiment, drill bit 481 may contain an explosive charge 490, and the drill bit 481 may be configured such that explosive charge 490 is effective as a shaped charge.

FIG. 4C shows a side view of yet another embodiment of an electrical drilling mechanism 454. The configuration of the electrical drilling mechanism 454 shares a common configuration with the electrical drilling mechanism 450 of FIG. 4A. The electrical drilling mechanism 454 may further comprise a telescoping body having telescoping members 457, 458, and 459. The telescoping body may be associated with the propulsion mechanism 460. The propulsion mechanism 460 may comprise slips 461 and 463 associated with the telescoping body. In embodiments, the slips 461 and 463 may be hydraulically actuated, electrically actuated, or a combination thereof. In an embodiment, the slips 461 and 463 may comprise pistons. The slips 461 and 463 may enable the electrical drilling mechanism 454 to advance to an extended position by extension and contraction of the slips 461 and 463. Slips 461 and 463 may each comprise an engaging surface for engaging, for example, an opening in a subterranean formation formed by drill bit 480. Slips 461 and 463 may be of the type known by those skilled in the art, such as those commonly used with packers. While drill bit 480 drills an opening into a subterranean formation, slip 461 may contract radially inward and slip 463 may expand radially outward from the electrical drilling mechanism 454 so an engaging surface thereof contacts the subterranean formation. The telescoping members 457, 458, and 459 of the body of the electrical drilling mechanism 454 then expand longitudinally so as to drive the drill bit 480 into the subterranean formation. When the telescoping members 457, 458, and 459 of the telescoping body are expanded, slip 461 may expand radially outward from the electrical drilling mechanism 454 so an engaging surface thereof contacts the subterranean formation. Slip 463 may then contract and the telescoping members 457, 458, and 459 of the body may then contract longitudinally. The process of expansion and contraction of the slips 461 and 463 and telescoping members 457, 458, and 459 of the telescoping body may repeat as the electronic drilling mechanism 454 drills into the subterranean formation.

FIG. 5 shows a cut-away side view of an embodiment of a wellbore tubular-conveyed drill assembly 520 comprising an embodiment of a deflector 532. The wellbore tubular-conveyed drill assembly 520 is in the retracted position. The deflector 532 may direct the electrical drilling mechanism 550 in a direction away from wellbore tubular 510 so as to engage the liner (e.g., of the type of liner 104 shown in FIGS. 1A-1C) and/or the wall 505 of the wellbore 502 and the subterranean formation 501. In embodiments such as the one shown in FIG. 5, the deflector 532 may be located adjacent an end of the housing 530, for example, above the housing 530. The deflector 532 may have an end 535 adjacent to the housing 530 so that electrical drilling mechanism 550 may extend from within of the housing 530, through the deflector 532, and urged toward the liner (e.g., of the type of liner 104 shown in FIGS. 1A-1C) and/or the wall 505 of the wellbore 502. In alternative embodiments, the deflector 532 is not utilized in conjunction with a housing and still serves to direct the electrical drilling mechanism 550. As seen in FIG. 5, the deflector 532 may have an end 534 having a curved taper or other directional shape. The end 534 may have an opening 533 facing the liner (e.g., of the type of liner 104 shown in FIGS. 1A-1C) and/or wall 505 of the wellbore 502. The end 534 may have a curved or other contour which may guide the electrical drilling mechanism 550 through the opening 533 in a direction away from the wellbore tubular 510. In an embodiment, the deflector 532 may be extendable and retractable from and to the housing 530. In other embodiments, the deflector 532 may be integrally formed with the housing 530. In an alternative embodiment, the deflector 532 may be located below the housing 530.

FIG. 6 shows a cut-away side view of an embodiment of a wellbore tubular-conveyed drill assembly 620 comprising another embodiment of a deflector 632. The wellbore tubular-conveyed drill assembly 620 is in the retracted position. The deflector 632 may direct the electrical drilling mechanism 650 in a direction away from wellbore tubular 610 so as to engage the liner (e.g., of the type of liner 104 shown in FIGS. 1A-1C) and/or the wall 605 of the wellbore 602. In embodiments such as the one shown in FIG. 6, the deflector 632 may be located adjacent an end of the housing 630, for example, below the housing 630. The deflector 632 may have an end 633 adjacent to the housing 630 so that electrical drilling mechanism 650 may extend from within of the housing 630, through the deflector 632, and guided toward the liner (e.g., of the type of liner 104 shown in FIGS. 1A-1C) and/or wall 605 of the wellbore 602. In alternative embodiments, the deflector 632 is not utilized in conjunction with a housing and still serve to direct the electrical drilling mechanism 650. The deflector 632 may have a curvature which allows electrical drilling mechanism 650 to pass therethrough to engage with the wall 605 of the wellbore 602 and thus, the subterranean formation 601. In an embodiment, the deflector 632 may be extendable and retractable from and to the housing 630. In other embodiments, the deflector 632 may be integrally formed with the housing 630. In an alternative embodiment, the deflector 632 may be located above the housing 630.

The slow drilling techniques embodied by the disclosed assemblies and methods may use available downhole power to increase production in a wellbore. In such an embodiment, the power source may supply power for the purpose of operating the assemblies described herein. The power source may be carried with, attached, incorporated within or otherwise suitably coupled to an assembly. In embodiments, the power source may comprise a power generation device, a battery, bursts of electromagnetic radiation from downhole components, or combinations thereof, for example. In embodiments, the power source may further comprise one or more wirelines (e.g., a cable as described herein) coupled to a battery, one or more other power sources, an assembly described herein, or combinations thereof. In embodiments, the power source may be located at the surface, within the wellbore, or both.

In embodiments, the power generation device may comprise a generator. The generator may comprise a turbo-generator configured to convert fluid movement into electrical power, a thermoelectric generator configured to convert differences in temperature into electrical power, a conventional fuel-operated generator, a galvanic cell, or combinations thereof, for example. Suitable power generation devices are disclosed in U.S. application Ser. No. 13/031,513 to Roddy, et al., which is incorporated herein by reference in its entirety. In an embodiment, the power source and/or power generation device may be sufficient to power assemblies, for example, in the range of from about 0.5 to about 10 watts, alternatively, from about 0.5 to about 1.0 watts.

In embodiments, a battery may comprise an internal battery, an external battery, or combinations thereof. In an embodiment, the battery may comprise a lithium ion battery. A battery may be charged prior to and/or after placement of the assemblies into a wellbore. A battery may be rechargeable or otherwise powered and/or recharged by other downhole power sources such as heat capture/transfer and/or fluid flow. In an embodiment, a battery may be inductively rechargeable by a recharging unit lowered into the wellbore via a wireline. For example, a battery charger (e.g., an inductive charger) may be lowered into the wellbore periodically to charge one or more batteries associated with one or more assemblies.

In the one or more of the various embodiments described herein, a motor may comprise any electrically-powered motor known to those skilled in the art which is suitable for rotating a drill bit so as to drill into subterranean formation and/or for extending the electrical drilling mechanism. For example, a motor may comprise a gear box. Alternatively or additionally, a motor may comprise a hydraulic motor known to those skilled in the art which may be coupled to an electrically-powered pump. In embodiments, a motor may utilize or drive tracks, channels, wheels, cogs, or combinations thereof to extend the electrical drilling mechanism.

In one or more embodiments, the disclosed assemblies and methods may be utilized during production of fluids in the wellbore, such as before or after maximum production is achieved. In an embodiment, the slow drilling techniques embodied in the disclosed assemblies and methods may be utilized in the first few days of production of a wellbore so as to boost initial production levels. In additional or alternative embodiments, the slow drilling techniques embodied in the disclosed assemblies and methods is implemented over the life of a well so as to offset production subsidence due to depletion, plugging, sanding, or combinations thereof, for example. In alternative embodiments, the slow drilling techniques embodied in the disclosed assemblies and methods may be delayed until production of fluid from the subterranean formation in the wellbore subsides. For example, drilling the one or more openings may be delayed until production subsides. In embodiments where the disclosed assemblies and methods are utilized with drill strings, it may be possible for a well to begin production of fluids through the openings before drilling of the wellbore is complete. In alternative or additional embodiments, it may be possible to begin production of the wellbore while drilling (i.e., before completion of the wellbore) because of the openings formed in the walls of the wellbore (i.e., into the subterranean formation) by the disclosed assemblies and methods.

Embodiments of the assemblies and methods contemplate drilling techniques which may occur continuously, intermittently, or combinations thereof over relatively long periods of time so as to provide a novel “slow” drilling technique. In an embodiment, drilling one or more openings may operate continuously. Drilling may commence and operate continuously until an event happens, such as depletion of a battery, disconnection of a power source, failure of an assembly, failure of an electrical drilling mechanism, or combinations thereof. In an embodiment, drilling one or more openings may operate intermittently. Drilling may start and stop—by control with constant power availability, by usage of battery than needs recharging after power depletion, or combinations thereof. For example, the power source may charge the battery (e.g., battery pack) to full capacity, and the wellbore tubular-conveyed drill assembly operates until the battery drains of power. The battery may then be charged by a power source, and the wellbore tubular-conveyed drill assembly operates in this cycle until failure. Alternatively, drilling may occur intermittently subject to available excess or non-utilized downhole power being intermittently available. In this way, excess or non-utilized downhole power is used to further enhance production. In an embodiment, drilling one or more openings may operate both continuously and intermittently. For example, one assembly in accordance with the disclosed embodiments may operate continuously as described above while another operates intermittently as described above.

The slow drilling techniques disclosed herein may be further characterized by the useful life, drilling rate, extension length, and drilling time. The disclosed assemblies may drill openings in a wall of a wellbore and into a subterranean formation over a time of years by drilling and extending a distance of inches per month. In embodiments, the useful life of the disclosed assemblies and methods may comprise about 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, or 20 years, for example. In embodiments, the drill rate of the disclosed assemblies and methods may be about 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 24, 36, 48, or 60 or greater inches per month, for example. In one or more embodiments, the disclosed assemblies may operate until failure, i.e. the useful life may be the time it takes for the assembly to fail. Many electrical drilling mechanisms may be coupled to the outside surface of a wellbore tubular, and when one or more fails (i.e., reaches a useful life due to, for example, manufacturing flaws, unexpected downhole forces, etc.) others may continue to drill over time as power becomes available. In embodiments, the electrical drilling mechanisms may extend from about 1 ft to about 50 ft or more over the useful life; alternatively, from about 5 ft to about 20 ft; alternatively, from about 10 ft to about 15 ft. In embodiments, an electrical drilling mechanism may drill for any amount of time when power is available. Such amounts of time may include, for example, a few hours, minutes, or days per month; a few weeks or months a year; a few years per lifetime of the well.

Embodiments of the electrical drilling mechanism may operate without control, with control, or combinations thereof. When operating without control, the electrical drilling mechanism may operate when power is available from power source and be inoperable when power is not available. In other embodiments, an amount of programming may be embedded in an assembly so an electrical drilling mechanism drills only after extension from a housing, for example. When operating with control, control may be automated with an electronic controller (e.g., a PID controller, a fuzzy logic controller, etc.). In other embodiments, control may be manual (e.g., by an operator input or programming at the surface).

The propulsion mechanisms disclosed herein may operate to direct the electrical drilling mechanisms in a direction away from the wellbore tubular and into the opening formed in the subterranean formation. The propulsion mechanisms may have various techniques for driving the electrical drilling mechanism in a direction away from the wellbore tubular into the subterranean formation, including pushing, pivoting, pulling, or combinations thereof. For example, FIGS. 1B and 1C show a propulsion mechanism 160 which operates to push the electrical drilling mechanism 150 in the opening 106 formed in the subterranean formation 101. FIGS. 2A and 2B show a propulsion mechanism 260 which operates to pivot the electrical drilling mechanism 250 to create opening 206 in the subterranean formation. FIG. 3B shows propulsion mechanisms 362, 364, and 366 which operates to pull electrical drilling mechanisms 352, 354, and 356, respectively, while propulsion mechanism 360 operates to push electrical drilling mechanism 350. FIG. 4C shows a propulsion mechanism 460 which utilizes both pulling and pushing to drive the electrical drilling mechanism 454 in a direction away from a wellbore tubular.

The assemblies and methods disclosed herein may operate to drill openings through the wall of a wellbore and into a subterranean formation. Although a direction of the openings is not limited, the openings may generally comprise side boreholes, for example. The openings drilled according to the disclosure may produce fluid(s) from the subterranean formation. Additionally, the assemblies and methods may be used to fracture the subterranean formation to increase production of fluid(s) therefrom. As discussed above, fracturing may occur by detonating an explosive charge in one or more openings. Fracturing may also occur by flowing fracturing fluid into an opening under fracturing conditions (e.g., hydraulic fracturing one or more boreholes produced by slow drilling as described herein).

ADDITIONAL DISCLOSURE

The following are nonlimiting, specific embodiments in accordance with the present disclosure:

A first embodiment, which is a wellbore tubular-conveyed drill assembly comprising:

a wellbore tubular;

an electrical drilling mechanism coupled to an outside surface of the wellbore tubular, wherein the electrical drilling mechanism has a retracted position and an extended position, wherein the electrical drilling mechanism drills one or more openings in a subterranean formation when in the extended position; and

a power source coupled to the electrical drilling mechanism.

A second embodiment, which is the assembly of the first embodiment, wherein the electrical drilling mechanism comprises a flexible rod and a drill bit coupled to the flexible rod, wherein the electrical drilling mechanism is configured to extend the flexible rod to engage the drill bit with the subterranean formation.

A third embodiment, which is the assembly of any of the first to second embodiments, wherein the electrical drilling mechanism comprises:

a drill bit; and

a propulsion mechanism configured to drive the drill bit in a direction away from the wellbore tubular into the subterranean formation.

A fourth embodiment, which is the assembly of any of the first to third embodiments, wherein the electrical drilling mechanism comprises:

a spool carried aboard the electrical drilling mechanism, wherein the spool provides a length of cable as the electrical drilling mechanism moves away from the retracted position.

A fifth embodiment, which is the assembly of any of the third to fourth embodiments, wherein the propulsion mechanism comprises:

a plurality of wheels for burrowing the electrical drilling mechanism through the subterranean formation.

A sixth embodiment, which is the assembly of any of the third to fifth embodiments, wherein the propulsion mechanism further comprises:

a track wrapped around the plurality of wheels for providing traction for the electrical drilling mechanism in an opening formed in the subterranean formation.

A seventh embodiment, which is the assembly of any of the third to sixth embodiments, wherein the electrical drilling mechanism further comprises a telescoping body associated with the propulsion mechanism, wherein the propulsion mechanism comprises:

at least two slips associated with the telescoping body.

An eighth embodiment, which is the assembly of any of the first to seventh embodiments, wherein the electrical drilling mechanism comprises a rotating drill rod configured to rotate and engage the subterranean formation, wherein the rotating drill rod comprises a cutting surface along at least a portion of a length thereof.

A ninth embodiment, which is the assembly of any of the first to eighth embodiments, wherein the electrical drilling mechanism pivots at one end so as to engage the subterranean formation with an opposite end.

A tenth embodiment, which is the assembly of any of the first to ninth embodiments, wherein the electrical drilling mechanism comprises one or more perforating charges.

An eleventh embodiment, which is the assembly of any of the first to tenth embodiments, further comprising a housing coupled to the outside surface of the wellbore tubular, wherein the electrical drilling mechanism is at least partially contained in the housing when in the refracted position.

A twelfth embodiment, which is the assembly of the eleventh embodiment, wherein the housing is configured to pivot relative to the wellbore tubular.

A thirteenth embodiment, which is the assembly of any of the first to twelfth embodiments, further comprising a deflector configured to direct the drilling mechanism in a direction away from the wellbore tubular.

A fourteenth embodiment, which is a method comprising:

extending an electrical drilling mechanism in a direction away from a wellbore tubular, wherein the electrical drilling mechanism is coupled to an outside surface of the wellbore tubular; and

drilling one or more openings in a subterranean formation with the electrical drilling mechanism.

A fifteenth embodiment, which is the method of the fourteenth embodiment, further comprising:

drilling a wellbore; and

inserting a production string comprising the wellbore tubular into the wellbore.

A sixteenth embodiment, which is the method of any of the fourteenth to fifteenth embodiments, wherein the one or more openings increase a producing area of the wellbore.

A seventeenth embodiment, which is the method of any of the fourteenth to sixteenth embodiments, further comprising:

producing a fluid through at least one of the one or more openings.

An eighteenth embodiment, which is the method of any of the fourteenth to seventeenth embodiments, further comprising:

producing a fluid from a subterranean formation.

A nineteenth embodiment, which is the method of any of the seventeenth to eighteenth embodiments, wherein drilling the one or more openings occurs during producing the fluid, the method further comprising:

removing a cutting from the wellbore with the fluid produced from the subterranean formation.

A twentieth embodiment, which is the method of any of the fourteenth to nineteenth embodiments, further comprising:

delaying drilling the one or more openings until production of the fluid subsides.

A twenty-first embodiment, which is the method of any of the fourteenth to twentieth embodiments, wherein drilling one or more openings occurs intermittently, continuously, or combinations thereof.

A twenty-second embodiment, which is the method of any of the fourteenth to twenty-first embodiments, wherein drilling one or more openings occurs over a period of time greater than one year.

A twenty-third embodiment, which is the method of any of the fourteenth to twenty-second embodiments, wherein extending the electrical drilling mechanism comprises:

pivoting the electrical drilling mechanism.

A twenty-fourth embodiment, which is the method of any of the fourteenth to twenty-third embodiments, further comprising:

pivoting a housing in a direction away from the wellbore tubular, wherein extending the electrical drilling mechanism comprises extending the electrical drilling mechanism from within the housing.

A twenty-fifth embodiment, which is the method of any of the fourteenth to twenty-fourth embodiments, wherein extending the electrical drilling mechanism comprises:

driving the electrical drilling mechanism in a direction away from the wellbore tubular into the subterranean formation.

A twenty-sixth embodiment, which is the method of any of the fourteenth to twenty-fifth embodiments, wherein extending the electrical drilling mechanism comprises:

guiding the electrical drilling mechanism in the direction away from the wellbore tubular.

A twenty-seventh embodiment, which is the method of any of the fourteenth to twenty-sixth embodiments, further comprising:

creating a perforation in a liner or a wall of the wellbore, wherein the electrical drilling mechanism extends through the perforation.

A twenty-eighth embodiment, which is the method of any of the fourteenth to twenty-seventh embodiments, further comprising:

detonating an explosive charge within the one or more openings.

A twenty-ninth embodiment, which is the method of any of the fourteenth to twenty-eighth embodiments, further comprising:

fracturing the subterranean formation via the one or more openings.

A thirtieth embodiment, which is the method of any of the fourteenth to twenty-ninth embodiments, further comprising:

operating the electrical drilling mechanism until failure.

A thirty-first embodiment, which is a method comprising:

providing a wellbore tubular-conveyed drill assembly coupled to an outside surface of a wellbore tubular, wherein the wellbore tubular-conveyed drill assembly has a continuous hollow channel extending therethrough;

coupling the continuous hollow channel to an interior of the wellbore tubular;

pressurizing the interior of the wellbore tubular with a drilling fluid;

directing the drilling fluid through the continuous hollow channel; and

drilling one or more openings in a subterranean formation with the wellbore tubular-conveyed drill assembly.

A thirty-second embodiment, which is the method of the thirty-first embodiment, further comprising:

extending the wellbore tubular-conveyed drill assembly in a direction away from the wellbore tubular.

A thirty-third embodiment, which is the method of any of the thirty-first to thirty-second embodiments, further comprising:

providing a production string comprising the wellbore tubular; and

plugging the production string below the wellbore tubular-conveyed drill assembly.

At least one embodiment is disclosed and variations, combinations, and/or modifications of the embodiment(s) and/or features of the embodiment(s) made by a person having ordinary skill in the art are within the scope of the disclosure. Alternative embodiments that result from combining, integrating, and/or omitting features of the embodiment(s) are also within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, Rl, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=Rl+k*(Ru−R1), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . , 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim means that the element is required, or alternatively, the element is not required, both alternatives being within the scope of the claim. Use of broader terms such as comprises, includes, and having should be understood to provide support for narrower terms such as consisting of, consisting essentially of, and comprised substantially of Accordingly, the scope of protection is not limited by the description set out above but is defined by the claims that follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated as further disclosure into the specification and the claims are embodiment(s) of the disclosed subject matter.