U.S. patent application number 14/207963 was filed with the patent office on 2014-09-18 for methods and systems for drilling from underground access tunnels to develop subterranean hydrocarbon reservoirs.
The applicant listed for this patent is Richard Beddoes, Ulric Fournier, Allan Peats, Robert Roulston. Invention is credited to Richard Beddoes, Ulric Fournier, Allan Peats, Robert Roulston.
Application Number | 20140262340 14/207963 |
Document ID | / |
Family ID | 50442703 |
Filed Date | 2014-09-18 |
United States Patent
Application |
20140262340 |
Kind Code |
A1 |
Beddoes; Richard ; et
al. |
September 18, 2014 |
METHODS AND SYSTEMS FOR DRILLING FROM UNDERGROUND ACCESS TUNNELS TO
DEVELOP SUBTERRANEAN HYDROCARBON RESERVOIRS
Abstract
A method for accessing a hydrocarbon reservoir in a subterranean
formation from a subterranean tunnel system includes (a) drilling a
first bore between an upper tunnel and a lower tunnel. In addition,
the method includes (b) drilling a second bore downward from the
lower tunnel.
Inventors: |
Beddoes; Richard; (White
Rock, CA) ; Fournier; Ulric; (Sussex, CA) ;
Peats; Allan; (Okotoks, CA) ; Roulston; Robert;
(Victoria, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Beddoes; Richard
Fournier; Ulric
Peats; Allan
Roulston; Robert |
White Rock
Sussex
Okotoks
Victoria |
|
CA
CA
CA
CA |
|
|
Family ID: |
50442703 |
Appl. No.: |
14/207963 |
Filed: |
March 13, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61784442 |
Mar 14, 2013 |
|
|
|
Current U.S.
Class: |
166/381 ;
166/77.2; 175/57 |
Current CPC
Class: |
E21B 19/146 20130101;
E21B 7/02 20130101; E21C 41/24 20130101; E21D 9/14 20130101; E21B
7/208 20130101; E21B 43/30 20130101 |
Class at
Publication: |
166/381 ; 175/57;
166/77.2 |
International
Class: |
E21B 7/20 20060101
E21B007/20 |
Claims
1. A method for accessing a hydrocarbon reservoir in a subterranean
formation from a subterranean tunnel system including an upper
tunnel and a lower tunnel, the method comprising: (a) drilling a
first bore between the upper tunnel and the lower tunnel; and (b)
drilling a second bore downward from the lower tunnel.
2. The method of claim 1, further comprising: (c) drilling a third
bore downward from the second bore.
3. The method of claim 2, further comprising: performing (a) and
(b) at a first location in the lower tunnel with a first drilling
rig; and performing (c) at a first location in the upper tunnel
with a second drilling rig.
4. The method of claim 3, wherein the first drilling rig is
disposed in the lower tunnel and the second drilling rig is
disposed in the upper tunnel.
5. The method of claim 4, wherein (c) comprises: lowering a drill
string from the second rig through the first bore and the second
bore.
6. The method of claim 5, further comprising: installing casing in
the first bore with the first drilling rig; installing casing in
the second bore with the first drilling rig; and installing casing
in the third bore with the second drilling rig.
7. The method of claim 6, wherein the drill string forms the casing
in the third bore.
8. The method of claim 2, further comprising: lowering a first
segment of coiled tubing from a coiled tubing drilling rig in the
upper tunnel through the first bore, the second bore, and the third
bore.
9. The method of claim 8, further comprising drilling with the
first segment of coiled tubing to the hydrocarbon reservoir.
10. The method of claim 8, further comprising lowering a second
segment of coiled tubing from a service rig in the upper tunnel
through the first bore, the second bore, the third bore, and the
first segment of coiled tubing.
11. The method of claim 3, further comprising: moving the first
drilling rig to a second location in the lower tunnel; performing
(a) and (b) at the second location in the lower tunnel with the
first drilling rig; moving the second drilling rig to a second
location in the upper tunnel; performing (c) at the second location
in the upper tunnel with the second drilling rig.
12. A method for accessing a hydrocarbon reservoir in a
subterranean formation from a subterranean tunnel system including
an upper tunnel and a lower tunnel, the method comprising: (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; (b) drilling a plurality of second bores downward from the
lower tunnel with the first drilling rig; (c) drilling a plurality
of third bores with a second drilling rig disposed in the upper
tunnel, wherein each third bore extends downward from one of the
second bores; (d) installing casing in each of the first bores with
the first drilling rig; (e) installing casing in each of the second
bores with the first drilling rig; and (f) installing casing in
each of the third bores with the second drilling rig.
13. The method of claim 12, further comprising: drilling a
plurality of fourth bores with a third drilling rig disposed in the
upper tunnel, wherein each fourth bore extends downward from one of
the third bores; installing casing in each of the fourth bores with
the third drilling rig.
14. The method of claim 13, further comprising: drilling a
plurality of fifth bores with a fourth drilling rig disposed in the
upper tunnel, wherein each of the fifth bores extends downward from
one of the fourth bores; installing a liner in each of the fifth
bores with the fourth drilling rig.
15. The method of claim 14, wherein the fourth drilling rig is a
coiled tubing drilling unit.
16. The method of claim 14, wherein the liner extends into the
hydrocarbon reservoir.
17. The method of claim 14, further comprising: injecting coiled
tubing from the upper tunnel through one of the first bores, one of
the second bores, one of the third bores, and one of the fourth
bores.
18. A system for accessing a hydrocarbon reservoir in a
subterranean formation, the system comprising: an upper tunnel
extending through the formation; a lower tunnel extending through
the formation below a portion of the upper tunnel; 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; and a second drilling rig
disposed in the upper tunnel and configured to drill a third bore
downward from the second bore.
19. The system of claim 18, wherein the first drilling rig is
configured to install tubular casing in the first bore and the
second bore; and wherein the second drilling rig is configured to
install tubular casing in the third bore.
20. The system of claim 19, further comprising a control system at
the surface, wherein the control system is configured to remotely
operate the first drilling rig or the second drilling rig.
21. The system of claim 20, wherein first drilling rig is disposed
on a rail car moveably coupled to a track in the lower tunnel; and
wherein the second drilling rig is disposed on a rail car moveably
coupled to a track in the upper tunnel.
22. The system of claim 18, further comprising: a third drilling
rig disposed in the upper tunnel and configured to drill through
the second bore and the third bore with coiled tubing.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims benefit of U.S. provisional patent
application Ser. No. 61/784,442, filed Mar. 14, 2013, and entitled
"Methods and Systems for Drilling from Underground Access Tunnels
to Develop Subterranean Hydrocarbon Reservoirs," which is hereby
incorporated by reference in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND
[0003] 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.
[0004] 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.
[0005] 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
[0006] 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.
[0007] 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.
[0008] 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.
[0009] 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
[0010] For a detailed description of the preferred embodiments of
the invention, reference will now be made to the accompanying
drawings in which:
[0011] 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;
[0012] 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;
[0013] 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;
[0014] 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;
[0015] FIG. 4A is a perspective view of the second rig of FIG.
4;
[0016] FIG. 4B is an enlarged perspective view of the pipe handling
assembly of FIG. 4A;
[0017] 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;
[0018] 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;
[0019] FIG. 6A is an enlarged side view of the fourth rig of FIG.
6;
[0020] 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;
[0021] FIG. 7A is an enlarged side view of the fifth rig of FIG. 7;
and
[0022] 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
[0023] 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.
[0024] 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.
[0025] 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.
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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.
[0030] 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.
[0031] 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.
[0032] 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.
[0033] 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.
[0034] 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.RTM. 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.
[0035] 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.
[0036] 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 133/8
in.
[0037] 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."
[0038] 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.
[0039] 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 95/8 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.
[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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.
[0045] 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."
[0046] 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.
[0047] 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.
[0048] 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.
[0049] 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.
[0050] 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."
[0051] 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 61/8 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.
[0052] 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.
[0053] 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.
[0054] 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."
[0055] 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.
[0056] 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.
[0057] 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).
[0058] 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.
[0059] 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.
[0060] 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.
[0061] 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.
[0062] 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.
* * * * *