METHODS AND SYSTEMS FOR DRILLING FROM UNDERGROUND ACCESS TUNNELS TO DEVELOP SUBTERRANEAN HYDROCARBON RESERVOIRS

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

Embodiments described herein relate generally to systems and methods for accessing and producing subsurface hydrocarbons. More particularly, Embodiments described herein relate to systems and methods for exploiting hydrocarbons from underground access tunnels.

In drilling a borehole (or wellbore) into an earthen formation, such as for the recovery of hydrocarbons or minerals from a subsurface reservoir, it is conventional to erect an oil rig at the ground surface, connect a drill bit onto the lower end of a “drill string,” and then rotate and lower the drill bit to drill a wellbore along a predetermined path toward a subsurface reservoir. The bit may be rotated by means of either a “rotary table” or a “top drive” associated with a drilling rig and/or a downhole motor incorporated into the drillstring immediately above the bit. During the drilling process, a drilling fluid (commonly referred to as “drilling mud” or simply “mud”) is pumped under pressure downward from the surface through the drill string, out the drill bit into the wellbore, and then upward back to the surface through the annular space (“wellbore annulus”) between the drill string and the wellbore. The drilling fluid carries borehole cuttings to the surface, cools the drill bit, and forms a protective cake on the borehole wall (to stabilize and seal the borehole wall), as well as other beneficial functions. At surface, the drilling fluid is treated by removing borehole cuttings, amongst other possible treatments, then re-circulated by pumping it downhole under pressure through the drill string.

Heavy oil deposits in remote locations provide relatively new and untapped sources of hydrocarbons. However, the harsh conditions as well as the environmental sensitivity of many such locations present challenges to conventional surface drilling and production operations. For example, extreme temperatures over extended periods of time can be hard on surface equipment and personnel. In addition, because the relatively large surface footprint of conventional drilling rigs and associated equipment, as well as noise generated by such rigs and equipment, may have negative impacts on sensitive environments, obtaining governmental approval and drilling permits in many locations can be difficult. Such governmental approval and permitting issues are further exasperated by the fact that the recovery of heavy oil deposits typically requires a relatively high well density, and many state laws require removal of an existing drilling pad before a new drilling pad may be put in place. A potential solution to these challenges is to place a drilling rig below ground. However, conventional drilling rigs are simply too large to be placed within an underground or subterranean tunnel while maintaining realistic costs.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by a method for accessing a hydrocarbon reservoir in a subterranean formation from a subterranean tunnel system including an upper tunnel and a lower tunnel. In an embodiment, the method comprises (a) drilling a first bore between the upper tunnel and the lower tunnel. In addition, the method comprises (b) drilling a second bore downward from the lower tunnel.

These and other needs in the art are addressed in another embodiment by a method for accessing a hydrocarbon reservoir in a subterranean formation from a subterranean tunnel system including an upper tunnel and a lower tunnel. In an embodiment, the method comprises (a) drilling a plurality of vertical first bores from the lower tunnel to the upper tunnel with a first drilling rig disposed in the lower tunnel. In addition, the method comprises (b) drilling a plurality of second bores downward from the lower tunnel with the first drilling rig. Further, the method comprises (c) drilling a plurality of third bores with a second drilling rig disposed in the upper tunnel. Each third bore extends downward from one of the second bores. Still further, the method comprises (d) installing casing in each of the first bores with the first drilling rig. Moreover, the method comprises (e) installing casing in each of the second bores with the first drilling rig. The method also comprises (f) installing casing in each of the third bores with the second drilling rig.

These and other needs in the art are addressed in another embodiment by a system for accessing a hydrocarbon reservoir in a subterranean formation. In an embodiment, the system comprises an upper tunnel extending through the formation. In addition, the system comprises a lower tunnel extending through the formation below a portion of the upper tunnel. Further, the system comprises a first drilling rig disposed in the lower tunnel and configured to drill a first bore from the lower tunnel to the upper tunnel and drill a second bore downward from the lower tunnel. Still further, the system comprises a second drilling rig disposed in the upper tunnel and configured to drill a third bore downward from the second bore.

Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic cross-sectional side view of an embodiment of a system for accessing hydrocarbons from subterranean tunnels in accordance with the principles described herein;

FIG. 2 is a graphical illustration of an embodiment of a method for drilling from the subterranean tunnels of FIG. 1 in accordance with principles disclosed herein;

FIG. 3 is a schematic, partial cross-sectional side view of the a first rig performing the first stage of the method of FIG. 2 in the subterranean tunnels of FIG. 1;

FIG. 4 is a schematic, partial cross-sectional side view of the a second rig performing the second stage of the method of FIG. 2 in the subterranean tunnels of FIG. 1;

FIG. 4A is a perspective view of the second rig of FIG. 4;

FIG. 4B is an enlarged perspective view of the pipe handling assembly of FIG. 4A;

FIG. 5 is a schematic, partial cross-sectional side view of the a third rig performing the third stage of the method of FIG. 2 in the subterranean tunnels of FIG. 1;

FIG. 6 is a schematic, partial cross-sectional side view of the a fourth rig performing the fourth stage of the method of FIG. 2 in the subterranean tunnels of FIG. 1;

FIG. 6A is an enlarged side view of the fourth rig of FIG. 6;

FIG. 7 is a schematic, partial cross-sectional side view of the a fifth rig performing the fifth stage of the method of FIG. 2 in the subterranean tunnels of FIG. 1;

FIG. 7A is an enlarged side view of the fifth rig of FIG. 7; and

FIG. 8 is a schematic view of a closed loop mud circulation system to circulate drilling fluid to the drill sites of FIG. 1.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following description is exemplary of embodiments of the disclosure. These embodiments are not to be interpreted or otherwise used as limiting the scope of the disclosure, including the claims. One skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and is not intended to suggest in any way that the scope of the disclosure, including the claims, is limited to that embodiment.

The drawing figures are not necessarily to scale. Certain features and components disclosed herein 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. In some of the figures, one or more components or aspects of a component may be not displayed or may not have reference numerals identifying the features or components that are identified elsewhere in order to improve clarity and conciseness of the figure.

The terms “including” and “comprising” are used herein, including in the claims, in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first component couples or is coupled to a second component, the connection between the components may be through a direct engagement of the two components, or through an indirect connection that is accomplished via other intermediate components, devices and/or connections. In addition, if the connection transfers electrical power or signals, whether analog or digital, the coupling may comprise wires or a mode of wireless electromagnetic transmission, for example, radio frequency, microwave, optical, or another mode. So too, the coupling may comprise a magnetic coupling or any other mode of transfer known in the art, or the coupling may comprise a combination of any of these modes. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a given axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the axis. For instance, an axial distance refers to a distance measured along or parallel to the axis, and a radial distance means a distance measured perpendicular to the axis. Any reference to up or down in the description and the claims will be made for purpose of clarification, with “up,” “upper,” “upwardly,” or “upstream” meaning toward the surface of the well and with “down,” “lower,” “downwardly,” or “downstream” meaning toward the terminal end of the well, regardless of the well bore orientation. In some applications of the technology, the orientations of the components with respect to the surroundings may be different. For example, components described as facing “up,” in another application, may face to the left, may face down, or may face in another direction. Still further, as used herein the terms “sealed” and “gas-tight” may be used to describe components, devices, and equipment that allow fluids to flow therethrough but prevent gases from escaping into the surrounding environment during normal operating conditions.

Referring now to FIG. 1, a tunnel system 10 extending through a subterranean formation 5 is schematically shown. As will be described in more detail below, tunnel system 10 is employed to access hydrocarbon reservoir 7 from below ground as opposed to above-ground, thereby protecting personnel and equipment from harsh weather conditions at the surface 9, and reducing the footprint of drilling operations at the surface.

In this embodiment, system 10 includes an upper operating tunnel 60 and a lower operating tunnel 70. Both tunnels 60, 70 are disposed below the surface 9 and above reservoir 7. Operating tunnels 60, 70 are parallel, with upper tunnel 60 disposed above lower tunnel 70. In this embodiment, tunnels 60, 70 laterally overlap, but are not laterally centered relative to each other. Thus, only a portion of upper tunnel 60 laterally overlaps with lower tunnel 70. In other embodiments, operating tunnels 60, 70 may be laterally centered such that the central axis of each lies in a common vertical plane. In general, tunnels 60, 70 can be disposed at any suitable depth, however, for most heavy oil recovery operations, upper tunnel is preferably located at a depth of between 500 and 700 feet from the surface 9 and lower tunnel 70 is preferably located at a depth of between 570 and 800 feet from the surface 9. In general, tunnels 60, 70 can have any suitable size and geometry. However, in this embodiment, upper tunnel 60 is generally cylindrical with a diameter preferably between 20 and 40 feet, and lower operating tunnel 70 is generally cylindrical with a uniform diameter preferably between 10 and 30 feet. In general, tunnels 60, 70 can be formed in any suitable manner known in the art. Examples of subterranean tunnel systems that can be used for tunnel system 10 are disclosed in U.S. patent application Ser. No. 61/784,327, which is hereby incorporated herein by example in its entirety.

Referring still to FIG. 1, a rail system 80 including a track 83 and a plurality of rail cars 85 is provided in each tunnel 60, 70. Each track 83 is disposed along the floor of the corresponding tunnel 60, 70 and extends the entire length of the corresponding tunnel 60, 70. Cars 85 are moveably disposed on tracks 83 such that they can roll along the length of tracks 83. Because rail systems 80 are generally disposed along the floors of tunnels 60, 70, systems 80 may also be referred to as a “lower” or “floor” rail systems 80. Equipment and rigs (drilling and service rigs) can be transported through tunnels 60, 70 on rail cars 85. Each rail car 85 includes mounting members 87 disposed at its ends to facilitate its movement and manipulation in tunnels 60, 70. In general, rail systems 80 may comprise any suitable track or rail car known in the art such as those conventionally used in mining operations.

Upper operating tunnel 60 also includes a rail system 90 comprising a pair of laterally-spaced tracks 93 (note: only one track 93 is visible in FIG. 1). Tracks 93 are disposed proximate the ceiling of tunnel 60 and extending along the length of tunnel 60. Because rail system 90 is generally disposed along the ceiling, system 90 may also be referred to as an “upper” or “ceiling” rail system 90. Ceiling rail system 90 supports a plurality of pipe cassettes or carriages 95 that move along tracks 93 to transfer drill pipe joints through tunnel 60. Rail systems 80, 90 are preferably automated to minimize human intervention in drilling and tripping operations. For example, rail systems 80, 90 can be electrically powered, and monitored and controlled in tunnels 60, 70 from a remote location such as a control station or cabin 1000 disposed at the surface 9.

Referring now to FIGS. 1 and 2, a method 100 for drilling and/or producing hydrocarbons (e.g., conventional oil, gas, heavy oil, bitumen) from tunnel system 10 is shown. Starting in block 110, a vertical bore 13a is drilled upward from lower tunnel 70 to upper tunnel 60 and is lined with tubular conductor casing 15a. Consequently, bore 13a and associated casing 15a define a passage or conduit connecting tunnels 60, 70. Moving now to block 150, a bore 13b is drilled downward from lower tunnel 70 into formation 5 and is lined with tubular conductor casing 15b. Bore 13b is coaxially aligned with bore 13a extending between tunnels 60, 70. Following the installation of casing 15b, a blowout preventer (BOP) 11 (FIGS. 4, 5, 6, and 7) is disposed in lower tunnel 70 and coupled to the upper end of casing 15b to provide pressure control during subsequent operations in blocks 200, 300, 400, 500 of method 100.

Next, in block 200, a bore 23 extending from the lower end of bore 13b is formed by drilling from upper tunnel 60 through bores 13a, 13b, conductor casing 15a, 15b, BOP 11, and formation 5 generally towards the hydrocarbon reservoir 7. Bore 23 is lined with tubular safety casing 25. In block 300, a bore 33 extending from the lower end of bore 23 is formed by drilling from upper tunnel 60 through bores 13a, 13b, 23, casing 15a, 15b, 25, BOP 11, and formation 5 generally towards hydrocarbon reservoir 7. Bore 33 is lined with tubular production casing 35. Moving now to block 400, a bore 43 extending from the lower end of bore 33 is formed by drilling from upper tunnel 60 through bores 13a, 13b, 23, 33, casing 15a, 15b, 25, 35, BOP 11, and formation 5 into hydrocarbon reservoir 7. Bore 43 is lined with a slotted liner 45. Moving now to block 500, coiled tubing 55 is inserted from upper tunnel 60 through bores 13a, 13b, 23, 33, 43, casing 15a, 15b, 25, 35, BOP 11, and liner 45 into hydrocarbon reservoir 7 to facilitate service operations.

Referring still to FIGS. 1 and 2, in this embodiment of method 100, blocks 110, 150, 200, 300, 400, 500 are performed sequentially. Thus, bores 13a, 13b, 23, 33, 43 are drilled and lined one at a time in sequence. As will be described in more detail below, bores 13a, 13b are drilled and lined with a first rig 111 (FIG. 3), bore 23 is drilled and lined with a second rig 201 (FIG. 4), bore 33 is drilled and lined with a third rig 301 (FIG. 5), bore 43 is drilled and lined with a fourth rig 401 (FIG. 6), and coiled tubing 55 is inserted into reservoir 7 with a fifth rig 501 (FIG. 7). To form a relatively high density of wells, which is especially preferred for the recovery of heavy oil, a series of adjacent wells are formed from tunnel system 10 according to method 100 as shown in FIG. 1. The different rigs 111, 201, 301, 401 essentially follow one another through tunnels 60, 70 to form bores 13a, 13b, 23, 33, 43 and install casing 15a, 15b, 25, 35 and liner 45, respectively, in sequence, and then rig 501 follows behind rig 401 to insert coiled tubing 55 through casing 15a, 15b, 25, 35, and liner 45 into reservoir 7. In this embodiment, rig 111 moves through lower tunnel 70, forms a plurality of bores 13a, 13b, and installs casings 15a, 15b in bores 13a, 13b; rig 201 follows rig 111, but moves through upper tunnel 60, forms a plurality of adjacent bores 23 (each bore 23 extending from one bore 13b), and installs casings 25 in bores 23; rig 301 follows rig 201 through upper tunnel 60 and forms a plurality of adjacent bores 33 (each bore 33 extending from one bore 23), and installs casings 35 in bores 33; rig 401 follows rig 301 through upper tunnel 60, forms a plurality of adjacent bores 43 (each bore 43 extending from one bore 33), and installs liners 45 in bores 43; and rig 501 follows rig 401 through upper tunnel 60 and inserts coiled tubing 55 through casings 15b, 25, 35 and liners 45 into reservoir 7. This process is schematically shown in FIG. 1 moving from right to left through tunnels 60, 70. Because blocks 110, 150 are performed with one rig 111, block 200 is performed with one rig 201, block 300 is performed with one rig 301, block 400 is performed with one rig 401, and block 500 is performed with one rig 501, blocks 110, 150 may be referred to as a “first stage” of method 100, block 200 referred to as a “second stage” of method 100, block 300 referred to as a “third stage” of method 100, block 400 referred to as a “fourth stage” of method 100, and block 500 referred to as a “fifth stage” of method 100.

Referring now to FIG. 3, drilling rig 111 is shown in lower tunnel 70 forming bores 13a, 13b according to blocks 110, 150 (i.e., stage one) of method 100. As previously described, rig 111 drills two coaxially aligned bores—vertical bore 13a connecting tunnels 60, 70 and bore 13b extending downward from lower tunnel 70 into formation 5. First rig 111 also installs conductor casing 15a, 15b in bores 13a, 13b, respectively, above and below lower tunnel 70. Accordingly, drilling rig 111 may also be described as a “conductor casing rig.” Following the formation of aligned bores 13a, 13b and installation of casing 15a, 15b, respectively, rig 111 moves through lower tunnel 70 and repeats this process at an adjacent location along tunnel 70. Conductor casing rig 111 is mounted on a rail car 85 to facilitate its movement through lower tunnel 70.

In this embodiment, conductor casing rig 111 is an in-the-hole (ITH) drill that uses ITH hammers powered by high air pressure to form bores 13a, 13b. In general, rig 111 can be any standard ITH drill known in the art such as the Orion ITH drill available from Cubex® of Winnipeg, Canada. Conductor casing rig 111 includes a carousel 112 that supports a plurality of tubular joints 113 for installation into bores 13a, 13b to form casing 15a, 15b. In particular, conductor casing rig 111 and carousel 112 are sized and configured to handle large diameter joints 113 (e.g., up to 24 inches). In addition, conductor casing rig 111 is configured to cement casing 15a, 15b in place within bores 13a, 13b.

Referring still to FIG. 3, conductor casing rig 111 is positioned at the desired drilling location in lower tunnel 70 using rail car 85, and then the rail car 85 is locked in place to prevent movement during drilling operations. Next, conductor casing rig 111 drills bore 13a upward along a vertical axis 17a until reaching upper tunnel 60, and then drills bore 13b in the opposite direction downward into the formation 5 along axis 17b. Bore 13a preferably has a diameter between 1.0 and 2.0 ft., and more preferably about 20 in. Bore 13b is drilled to a depth from lower tunnel 70 of about 40 ft., and preferably has a diameter between 1.0 and 2.0 ft., and more preferably about 17.0 in. Because the remaining drilling rigs 201, 301, 401, 501 are deployed in upper tunnel 60 and operate through bores 13a, 13b, central axes 17a, 17b are coaxially aligned. For the purpose of further explanation, central axes 17a, 17b of bores 13a, 13b, respectively, are collectively referred to as axis 17 because they are coincident.

Conductor casing rig 111 inserts tubular joints 113 into bores 13a, 13b from lower tunnel 70, connects joints 113 together end-to-end, and cements joints 113 therein to form casings 15a, 15b, respectively. Casing 15a preferably has a diameter between 11.0 and 23.0 inches, and more preferably 16 inches. Casing 15b has a diameter between 11.0 and 20.0 inches, and more preferably 13⅜ in.

Referring now to FIGS. 2 and 4, drilling rig 201 is shown in upper tunnel 60 forming bore 23 according to block 200 (i.e., stage two) of method 100. As previously described, rig 201 drills through aligned bores 13a, 13b and corresponding casings 15a, 15b into formation 5 to form bore 23. Rig 201 also installs safety casing 25 in bore 23. Accordingly, drilling rig 201 may also be described as a “safety casing rig.”

A drill string 25a having a drill bit at its lower end is suspended from rig 201 through casings 15a, 15b. Drill string 25a is formed from a plurality of drill pipe joints 25b threadably connected together end-to-end. Rig 201 rotates drill string 25a and applies weight-on-bit (WOB) to drill bore 23 from the lower end of bore 13b. Bore 23 is preferably drilled to a depth between 600 and 1300 feet, and more preferably about 900 feet. However, it should be appreciated that the actual depth can be influenced by local regulation and exposure to risk from the lithology expected, and thus, varies based on the specific conditions at the drill site. In general, depth measurements are relative to the casing bowl elevation, typically referred to as “0 depth.” In addition, bore 23 preferably has a diameter between 10.0 and 16.0 in., and more preferably 12.0 in.

In this embodiment, safety casing rig 201 employs casing while drilling techniques, and thus, once bore 23 is drilled to the desired depth, drill string 25a is cemented in place, thereby forming casing 25. Bore 23 is preferably cased along its entire length. In addition, casing 25 preferably has a diameter between 9.0 and 15.0 in., and more preferably 9⅝ in. Following the formation of bore 23 and installation of casing 25, rig 201 moves through upper tunnel 60 and repeats this process at an adjacent location along tunnel 60. As will be described in more detail below, safety casing rig 201 is mounted on a rail car 85 to facilitate its movement through upper tunnel 60.

Referring now to FIGS. 4, 4A, and 4B, in this embodiment, safety casing rig 201 has a central axis 205 and includes a base assembly 210, a drilling assembly 220, a top frame assembly 230, and a pipe handling assembly 240. Base assembly 210 includes the primary components of a rail car 85 including rollers 218 to engage track 83 along the floor of upper tunnel 60 as well as mounting members 87 disposed at each end of base assembly 210 to connect to other rail cars 85 or for engagement during the maneuvering of rig 201. Base assembly 210 also includes a drilling deck or floor 212, which has a hole or aperture 213 to allow sections of drill pipe to pass therethrough during drilling operations. Aperture 213 has a central axis 214 concentric with central axis 205 of rig 201. Base assembly 210 interacts with rail system 80 and supports drilling assembly 220.

Drilling assembly 220 is positioned above the base assembly 210 and below top frame assembly 230. Drilling assembly 220 includes a plurality of substantially vertical support members 222, a plurality of diagonal support members 223, and a pair of linear actuators 224, all of which are disposed between and coupled to base assembly floor 212 and top frame assembly 230. Drilling assembly 220 further includes a top drive assembly 225, which is coupled to linear actuators 224 and translates along axis 205, 214 between the top frame assembly 230 and the base assembly floor 212.

As best shown in FIGS. 4 and 4A, top frame assembly 230 includes a plate 231, a track assembly 232 and a support hood 238 coupled to the plate 231. Vertical support members 222 and linear actuators 224 previously described are coupled to top frame assembly 230. Track assembly 232 includes a rail or track 233 and a rail selector or bypass mechanism 235 coupled to rail 233. Rail bypass mechanism 235 allows a carriage or cassette 95 carrying pipe joints 25b to either bypass or roll past rig 201 along the side of tunnel 60 via track 93 or be diverted to rig 201 via rail 233. Support hood 238 is braced against the ceiling of upper tunnel 60, which provides support to overcome reactive forces experienced by the drill bit during drilling operations.

As best shown in FIGS. 4 and 4B, pipe handling assembly 240 includes a pipe handling arm 242 disposed in a housing 241 with a curved finger 244 and rollers 245 driven by a rotary actuator 246 at one end configured to engage the surface of a tubular 25 in cassette 95. Pipe handling assembly 240 further includes an actuator 243 that extends and retracts the pipe handling arm 242 laterally from housing 241 to the cassette 95 and on to the central axis 205 of aperture 213 in the rig floor 212. Pipe handling assembly 240 also includes an axially oriented threaded rod 247 disposed axially below housing 241, and threadably engaged within a support post 249, which is further mounted to the rig floor 212. An actuator or driver 248 is disposed above housing 241 and configured to rotate rod 247 to impart motion to pipe handling assembly 240 along vertical support members 222. As rod 247 rotates about axes 205, 214, rod 247 and housing 241 can move up and down. Additional details of drilling rig 201 are disclosed in U.S. patent application No. 61/784,199, which is hereby incorporated herein by reference in its entirety for all purposes.

To drill bore 23 and install casing 25, rig 201 is maneuvered via its rail car 85 to the desired drilling location in upper tunnel 60. Because safety casing rig 201 drills into formation 5 from upper tunnel 60, safety casing rig 201 is precisely positioned over the desired bores 13a, 13b such that axes 17, 205 are aligned. Rail car 85 is then locked in place and support hood 238 is braced against the top of upper tunnel 60. Bypass mechanism 235 of top frame assembly 230 is adjusted to divert a cassette 95 carrying pipe joints 25b onto track assembly 232. Pipe handling arm 242 is extended toward a pipe joint 25b housed in cassette 95, and curved finger 244 rotates and engages outer cylindrical surface of the pipe joint 25b. Handling arm 242 is then raised to remove the pipe joint 25b from cassette 95, and extended to align the pipe joint 25b with aperture 213, central axis 17, and the upper end of drill string 25a. Next, pipe handling arm 242 is lowered while rollers 245 rotate the pipe joint 25b about axis 205 to makeup a threaded connection between the lower end of the pipe joint 25b and the upper end of drill string 25a, thereby incorporating the pipe joint 25b into drill string 25a. Drill string 25a is then rotated with top drive assembly 225 as linear actuator 224 apply WOB to enable the drill bit disposed at the lower end of drill string 25a to lengthen borehole 23. Safety casing rig 201 repeats the process of removing pipe joints 25b from cassette 95, aligning and mating the pipe joints 25b with drill string 25a, and drilling bore 23 with drill string 25a until bore 23 is drilled to the desired depth. Once a given cassette 95 is depleted of pipe joints 25b, it is transferred back to rail 93, and another cassette 95 carrying pipe joints 25b is diverted from rail 93 via bypass mechanism 235 onto track assembly 232 to continue drilling operations. As previously described, once bore 23 is drilled to the desired depth, drill string 25a is cemented in place to form casing 25.

Referring now to FIGS. 2 and 5, drilling rig 301 is shown in upper tunnel 60 forming bore 33 according to block 300 (i.e, stage three) of method 100. As previously described, rig 301 drills through aligned bores 13a, 13b, 23 and corresponding casings 15a, 15b, 25 into formation 5 to form bore 33. Rig 301 also installs production casing 35 in bore 33. Accordingly, drilling rig 301 may also be described as a “production casing rig.”

A drill string 35a having a drill bit at its lower end is suspended from rig 301 through casings 15a, 15b, 25. Drill string 35a is formed from a plurality of drill pipe joints 35b threadably connected together end-to-end. Rig 301 rotates drill string 35a and applies WOB to drill bore 33 from the lower end of bore 23. Bore 33 is preferably drilled to the top of hydrocarbon reservoir 7 (see FIG. 1). In many applications, this will result in bore 33 being drilled to a depth between 900 and 3800 ft. measured from the 0 depth. In addition, bore 33 preferably has a diameter between 6.0 and 12.0 in., and more preferably 8.5 in.

In this embodiment, production casing rig 301 employs casing while drilling techniques, and thus, once bore 33 is drilled to the desired depth, drill string 35a is cemented in place, thereby forming casing 35. Bore 33 is preferably cased along its entire length. In addition, casing 35 preferably has a diameter between 5.0 and 11.0 in., and more preferably 7.0 in. Following the formation of bore 33 and installation of casing 35, rig 301 moves through upper tunnel 60 and repeats this process at an adjacent location along tunnel 60. As will be described in more detail below, production casing rig 301 is mounted on a rail car 85 to facilitate its movement through upper tunnel 60.

In this embodiment, production casing rig 301 is substantially the same as safety casing rig 201 previously described except that it is sized and configured to drill bore 33 having a different diameter than bore 23 and handle pipe joints 35b having different diameters than pipe joints 25b. In particular, the outer diameter of each pipe joint 35b is less than the outer diameter of each pipe joint 25b.

Referring now to FIGS. 4A and 5, production casing rig 301 is maneuvered via its rail car 85 to the desired drilling location in upper tunnel 60. Because rig 301 drills into formation 5 from upper tunnel 60, rig 301 is precisely positioned over the desired bores 13a, 13b such that axes 17, 205 are aligned. Rail car 85 is then locked in place and support hood 238 is braced against the top of upper tunnel 60. Bypass mechanism 235 of top frame assembly 230 is adjusted to divert a cassette 95 carrying pipe joints 35b onto track assembly 232. Pipe handling arm 242 is extended toward a pipe joint 35b housed in cassette 95, and curved finger 244 rotates and engages outer cylindrical surface of the pipe joint 35b. Handling arm 242 is then raised to remove the pipe joint 35b from cassette 95, and extended to align the pipe joint 35b with aperture 213, central axis 17, and the upper end of drill string 35a. Next, pipe handling arm 242 is lowered while rollers 245 rotate the pipe joint 35b about axis 205 to makeup a threaded connection between the lower end of the pipe joint 35b and the upper end of drill string 35a, thereby incorporating the pipe joint 35b into drill string 35a. Drill string 35a is then rotated with top drive assembly 225 as linear actuator 224 apply WOB to enable the drill bit disposed at the lower end of drill string 35a to lengthen borehole 33. Production casing rig 301 repeats the process of removing pipe joints 35b from cassette 95, aligning and mating the pipe joints 35b with drill string 35a, and drilling bore 33 with drill string 35a until bore 33 is drilled to the desired depth. Once a given cassette 95 is depleted of pipe joints 35b, it is transferred back to rail 93, and another cassette 95 carrying pipe joints 35b is diverted from rail 93 via bypass mechanism 235 onto track assembly 232 to continue drilling operations. As previously described, once bore 33 is drilled to the desired depth, drill string 35a is cemented in place to form casing 35.

Referring now to FIGS. 2 and 6, drilling rig 401 is shown in upper tunnel 60 forming bore 43 according to block 400 (i.e, stage four) of method 100. As previously described, rig 401 drills through aligned bores 13a, 13b, 23, 33, corresponding casings 15a, 15b, 25, 35, and formation 5 into hydrocarbon reservoir 7 to form bore 43. Rig 401 also installs liner 45 in bore 43. Accordingly, drilling rig 301 may also be described as a “liner rig.”

In this embodiment, rig 401 drills through casings 15a, 15b, 25, 35 with coiled tubing 45a as opposed to a drill string formed from pipe joints. In particular, a bottom hole assembly (BHA) including a downhole motor and a drill bit is disposed at the lower end of tubing 45a. The downhole motor rotates the drill bit with WOB applied as rig 401 advances coiled tubing 45a through casings 15a, 15b, 25, 35 to form bore 43. Bore 43 is preferably drilled from bore 33 into hydrocarbon reservoir 7. In addition, bore 43 preferably has a diameter between 4.0 and 10.0 in., and more preferably 6⅛ in. Once bore 43 is drilled to the desired depth, coiled tubing 45a is pulled, slotted liner 45 is positioned in lower tunnel 70 and coupled to coiled tubing (e.g., coiled tubing 45a) extending from rig 401 in upper tunnel 60, run into bore 43 with rig 401, and installed in bore 43. Bore 43 is preferably lined along its entire length. In addition, liner 45 preferably has a diameter between 3.0 and 9.0 in., and more preferably 4.5 in.

In general, rig 401 can be any coiled tubing drill rig known in the art such as those manufactured by Surefire Industries of Calgary, Alberta, Canada. As best shown in FIG. 6A, in this embodiment, rig 401 includes an injector head 410 having a central axis 405, a gooseneck 420 coupled to head 410, and a coiled tubing reel 430 supporting a spool of coiled tubing 45a.

Referring still to FIGS. 6 and 6A, rig 401 is mounted on a pair of rail cars 85 coupled via mounting members 87 for facilitating its movement through upper tunnel 60. In particular, rig 401 is maneuvered via its rail cars 85 to the desired drilling location in upper tunnel 60. Because rig 401 drills into formation 5 from upper tunnel 60, rig 401 is precisely positioned over the desired bores 13a, 13b such that axes 17, 405 are aligned. Rail cars 85 are then locked in place to prevent movement during drilling. Rig 401 then drills bore 43 downward from bore 33 into the hydrocarbon reservoir 7 until the desired depth is reached. As previously described, once bore 43 is drilled to the desired depth, coiled tubing 45a is pulled and slotted liner 45 is run into bore 43 and cemented in place.

Referring now to FIGS. 2, 7 and 7A, rig 501 is shown in upper tunnel 60 inserting coiled tubing 55 according to block 500 (stage five) of method 100. Rig 501 performs well servicing operations including the installation and replacement of artificial lift systems, well clean out, and well conversion activities. Accordingly, rig 501 may also be described as a “service rig.”

In this embodiment, rig 501 is a coiled tubing workover unit that advances coiled tubing 55 through casings 15a, 15b, 25, 35, and liner 45 into hydrocarbon reservoir 7. Typically, a downhole tool or device is coupled to the lower end of coiled tubing 55 for performing the particular service operation(s). Coiled tubing 55 preferably has a diameter between 1.0 and 5.0 in., and more preferably 2.5 in.

In general, rig 501 can be any coiled tubing workover unit known in the art such as those manufactured by Surefire Industries of Calgary, Alberta, Canada. As best shown in FIG. 7A, in this embodiment, rig 501 includes an injector head 510 having a central axis 505, a gooseneck 520 coupled to head 510, and a coiled tubing reel 530 supporting a reel of coiled tubing 55. Rig 501 is mounted on a pair of rail cars 85 coupled via mounting members 87 for facilitating its movement through upper tunnel 60.

Referring still to FIGS. 7 and 7A, service rig 501 is maneuvered via its rail cars 85 to the desired location in upper tunnel 60. Because rig 501 injects coiled tubing 55 through casings 15a, 15b, 25, 35, and liner 45 from upper tunnel 60, rig 501 is precisely positioned over the desired bore 13a such that axes 17, 505 are aligned. Rail cars 85 are then locked in place to prevent movement during service operations. Rig 501 then advances coiled tubing 55 through casings 15a, 15b, 25, 35, and liner 45 until the desired depth for performing the desired service operation(s).

In the manner described, rigs 111, 201, 301, 401, 501 perform different stages of method 100 shown in FIG. 2. Each stage of method 100 requires a certain amount of time to complete and may vary significantly from stage to stage. Because rigs 111, 201, 301, 401 drill successive bores 13a, 13b, 23, 33, 43, respectively, and rig 501 injects coiled tubing 55 after the formation and lining of bores 13a, 13b, 23, 33, 43, the stages of method 10 are performed in sequential order at each particular drill site along system 10. Bottlenecks may occur at certain points along method 100, thereby delaying the start of the next stage. To prevent such bottlenecks, drilling may be completed in batches. For example, first rig 111 can drill and case a plurality of adjacent bores 13a, 13b along tunnels 60, 70 prior to the deployment of rig 201. Then, rig 111 can be moved to another section of lower tunnel 70 to begin drilling and lining another set of bores 13a, 13b. Rig 201 can then be positioned in upper tunnel 60 over one of the bores 13a previously drilled by rig 111, and employed to drill and line bores 23. Rig 301 can similarly follow suit behind rig 201, rig 401 can follow suit behind rig 301, and rig 501 can follow suit behind rig 401. Another exemplary means to prevent bottlenecks is to employ a plurality of one or more rigs 111, 201, 301, 401, 501 that perform stages that take longer than other stages. By deploying a higher quantity of rigs with longer operating times and lower quantity of stage rigs with shorter operating times, the differences in operating times can be balanced. For example, one rig 111 may be used, while three rigs 201, five rigs 301, two rigs 401, and one service rig 501 are used because rigs 201, 301 perform more time intensive stages of method 100.

Referring again to FIG. 1, the various steps performed in method 100 (e.g., drilling operations, casing and lining operations, service operations, etc.) are preferably performed with minimal human intervention within tunnels 60, 70 to enhance overall safety. In this embodiment, the various steps in method 100 are controlled remotely from control station 1000 disposed at the surface 9. Consequently, in this embodiment, many of the traditional interfaces in the drilling processes are automated. Moving control of the drilling operations out of tunnels 60, 70 reduces the personnel needed in the tunnels 60, 70. The communications and control commands to and from control cabin 1000 can be transmitted using any means standard in the art.

In embodiments described herein, a closed loop drilling fluids circulation and management system is preferably employed during drilling operations. An exemplary embodiment of a closed loop drilling system 1100 is shown in FIG. 8. System 1100 generally circulates drilling fluid between a local drilling mud circulation system 1110 disposed in lower tunnel 70 and a central drilling fluid processing facility 1120 located at the surface 9. Central processing facility 1120 includes a variety of components for processing used drilling fluid and converting it into clean drilling fluid. For example, central processing facility can include equipment including, without limitation, a degasser for removing gases from the drilling fluid, solids separation equipment for removing solids from drilling fluid, and a drilling fluid transfer pump for facilitating the flow of drilling fluid through facility 1120.

Central processing facility 1120 supplies clean, processed drilling fluid to local mud circulation system 1110 via a primary supply system 1130. Local drilling mud circulation system 1110 pumps the clean, processed drilling fluid to each drilling rig 111, 201, 301, 401 during their respective drilling operations. The clean, processed drilling fluid is pumped down the corresponding drill string or coiled tubing, through the face of the drill bit, and returns to BOP 11 via the annulus between the drillstring and the sidewall of corresponding bore. While being circulated through the bore, solids (e.g., formation cuttings), liquids (e.g., hydrocarbons, water, etc.), gases (e.g., hydrogen sulfide, natural gas, etc.), or combinations thereof become entrained in the drilling fluid, thereby transitioning clean drilling fluid into used drilling fluid. The dirty, used drilling fluid from the annulus is supplied back to local mud circulation system 1110 via a rotating head on BOP 11. The returned drilling fluid is partially processed by local mud circulation system 1110 to remove large solids, and then pumped back to central processing facility 1120 via a primary return system 1131 for further processing and conditioning. Examples of closed loop drilling fluid circulation and management systems that can be used with system 10 are described in U.S. patent application Ser. No. 61/783,979, which is hereby incorporated herein by reference in its entirety.

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

METHODS AND SYSTEMS FOR DRILLING FROM UNDERGROUND ACCESS TUNNELS TO DEVELOP SUBTERRANEAN HYDROCARBON RESERVOIRS

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