U.S. patent application number 11/141459 was filed with the patent office on 2006-09-14 for drilling normally to sub-normally pressured formations.
Invention is credited to Christopher A. Pratt, Douglas P. Seams.
Application Number | 20060201715 11/141459 |
Document ID | / |
Family ID | 46322058 |
Filed Date | 2006-09-14 |
United States Patent
Application |
20060201715 |
Kind Code |
A1 |
Seams; Douglas P. ; et
al. |
September 14, 2006 |
Drilling normally to sub-normally pressured formations
Abstract
A system and method for drilling a substantially horizontal well
bore in a normally to sub-normally pressured formation. The
normally to sub-normally pressured formation is an unconventional
reservoir. The well bore is drilled over-balanced with a drilling
fluid including a fluid loss agent. The fluid loss agent is
operable to form a filter cake on the well bore during
drilling.
Inventors: |
Seams; Douglas P.; (Calgary,
CA) ; Pratt; Christopher A.; (Cochrane, CA) |
Correspondence
Address: |
FISH & RICHARDSON P.C.
P.O. BOX 1022
MINNEAPOLIS
MN
55440-1022
US
|
Family ID: |
46322058 |
Appl. No.: |
11/141459 |
Filed: |
May 31, 2005 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
11035537 |
Jan 14, 2005 |
|
|
|
11141459 |
May 31, 2005 |
|
|
|
10723322 |
Nov 26, 2003 |
|
|
|
11035537 |
Jan 14, 2005 |
|
|
|
Current U.S.
Class: |
175/65 |
Current CPC
Class: |
E21B 43/006 20130101;
E21B 43/121 20130101; E21B 43/25 20130101; E21B 21/085 20200501;
E21B 43/40 20130101 |
Class at
Publication: |
175/065 |
International
Class: |
E21B 7/00 20060101
E21B007/00; E21B 21/00 20060101 E21B021/00 |
Claims
1. A method for drilling a well bore, comprising: drilling a
substantially horizontal well bore in a coal seam; and drilling the
well bore over-balanced with a drilling fluid comprising at least
one of aphrons and micelles to form a filter cake on a wall of the
well bore during drilling.
2. The method of claim 1, wherein the drilling fluid comprises a
density at or greater than 9.5 pounds per gallon.
3. The method of claim 1, wherein the drilling fluid comprises a
density at or greater than 10 pounds per gallon.
4. The method of claim 1, wherein the drilling fluid comprises a
density substantially the same as that of the coal seam cuttings
produced by drilling the well bore.
5. The method of claim 1, wherein the drilling fluid comprises a
viscosity agent.
6. The method of claim 1, wherein the filter cake invasion into the
formation comprises a depth of less than 5 centimeters.
7. The method of claim 1, wherein the coal seam comprises at least
one of naturally occurring fractures and cleats.
8. The method of claim 1, wherein the drilling fluid further
comprises starch.
9. The method of claim 1, further comprising adjusting at least one
of a flow rate and a property of the drilling fluid based at least
in part on a difference between an actual amount of debris
recovered per unit time and an expected amount of cuttings recovery
per unit time.
10. A system for drilling a well bore, comprising: a drill bit
coupled by a drill string to a rig at a surface, the drill bit
operable to drill a well bore in a coal seam; and a drilling fluid
pumped through the drill string to the drill bit, the drilling
fluid comprising at least one of aphrons and micelles to form a
filter cake on the wall of the well bore during drilling.
11. The system of claim 10, wherein the drilling fluid comprises a
density at or greater than 9.5 pounds per gallon.
12. The system of claim 10, wherein the drilling fluid comprises a
density at or greater than 10 pounds per gallon.
13. The system of claim 10, wherein the drilling fluid comprises a
density substantially the same as that of the coal seam cuttings
produced by drilling the well bore.
14. The system of claim 10, wherein the drilling fluid comprises a
viscosity agent.
15. The system of claim 10, wherein the filter cake invasion into
the formation comprises a depth of less than 5 centimeters.
16. The system of claim 10, wherein the coal seam comprises at
least one of naturally occurring fractures and cleats.
17. The system of claim 10, wherein the drilling fluid further
comprises starch.
18. The system of claim 10, wherein the drilling fluid comprises
FLC 2000.
19. The method of claim 1, wherein the drilling fluid comprises FLC
2000.
Description
RELATED APPLICATIONS
[0001] This application is a continuation-in-part of, and therefore
claims priority from, U.S. patent application Ser. No. 11/035,537
filed on Jan. 14, 2005, which is a continuation-in-part of, and
therefore claims priority from, U.S. patent application Ser. No.
10/723,322, filed on Nov. 26, 2003. This application incorporates
by reference the two applications noted above, as well as the
application entitled Well Bore Cleaning filed May 31, 2005.
TECHNICAL FIELD
[0002] This disclosure relates generally to the field of recovery
of subterranean resources, and more particularly to a system and
method for drilling normally to sub-normally pressured
formations.
BACKGROUND
[0003] Reservoirs are subterranean formations of rock containing
oil, gas, and/or water. Unconventional reservoirs include coal
formations, shale formations and low permeability formations
containing gas and, in some cases, water. A coal bed, for example,
may contain natural gas and water.
[0004] Coal bed methane (CBM) is often produced using vertical
wells drilled from the surface into a coal bed. Vertical wells
drain a very small radius of methane gas in low permeability
formations. As a result, after gas in the vicinity of the vertical
well has been produced, further production from the coal seam
through the vertical well is limited.
[0005] To enhance production through vertical wells, the wells have
been fractured using conventional and/or other stimulation
techniques. Horizontal patterns have also been formed in coal seams
to increase and/or accelerate gas production.
SUMMARY
[0006] The invention encompasses a system and method for drilling
normally to sub-normally pressured formations. In one embodiment,
the method includes drilling a substantially horizontal well bore
in a normally to sub-normally pressured formation. The normally to
sub-normally pressured formation is an unconventional reservoir.
The well bore is drilled over-balanced with a drilling fluid
including a fluid loss agent. The fluid loss agent is operable to
form a filter cake on the well bore during drilling.
[0007] More specifically, in accordance with a particular
embodiment, the unconventional reservoir may comprise a fractured
formation, a coal bed and/or a shale. The fluid loss agent may
comprise a non-invasive or low-invasive fluid such as micelles,
aphrons or other agent operable to form a filter cake to limit
fluid loss from the well bore to the formation. The drilling fluid
may comprise a heavy fluid having a density of 9.5 pounds per
gallon or greater, 10 pounds per gallon or greater and/or a density
substantially equal to or greater than that of the cuttings
generated during drilling of the well bore.
[0008] Technical advantages of certain embodiments include
providing a system and method for drilling a normally to
sub-normally pressured formation. In a particular embodiment, a
fluid loss agent may be used to form a filter cake around the well
bore to enhance well bore stability. For example, the filter cake
may seal the well bore and prevent fluid loss to the formation that
could destabilize the formation and lower productivity of the
formation. In addition, the filter cake may allow a positive
pressure differential to be maintained between the well bore and
the formation during drilling to stabilize the well bore.
[0009] Another technical advantage of certain embodiments may
include the use of a dense drilling fluid to enhance well bore
stability and/or improve cutting removal efficiency. In a
particular embodiment, a dense drilling fluid having a density
greater than 9.5 pounds per gallon, may be used. In other
embodiments, the density of the drilling fluid may be 10 pounds per
gallon or greater and/or have a density substantially the same or
greater than the cuttings in order to improve cuttings removal.
[0010] Other technical advantages will be readily apparent to one
skilled in the art from the following figures, description, and
claims. Moreover, while specific advantages have been enumerated
above, various embodiments may include all, some, or none of the
enumerated advantages.
DESCRIPTION OF DRAWINGS
[0011] FIG. 1 illustrates one embodiment of drilling a well of
drilling a well from the terranean surface to a subterranean
zone;
[0012] FIG. 2 illustrates one embodiment of a well bore pattern for
the well of FIG. 1;
[0013] FIG. 3 illustrates one embodiment of producing the well of
FIG. 1;
[0014] FIG. 4 is a cross sectional diagram along lines 4-4 of FIG.
3 illustrating one embodiment of the well bore of FIG. 3;
[0015] FIG. 5 is a cross-sectional diagram illustrating collapse of
the well bore of FIG. 4;
[0016] FIG. 6 is a flow chart illustrating an example method for
drilling a normally to sub-normally pressured formation;
[0017] FIG. 7 illustrates another embodiment of drilling a well
from the terranean surface to a subterranean zone; and
[0018] FIG. 8 illustrates one embodiment of producing the well of
FIG. 7.
[0019] Like reference symbols in the various drawings indicate like
elements.
DETAILED DESCRIPTION
[0020] FIG. 1 illustrates an example system 10 for drilling a well
bore 40 from the terranean surface 20 to a subterranean zone 30. As
described in more detail below, the well bore 40 may be drilled
overbalanced using a low-loss and/or dense drilling fluid. The
low-loss and/or dense drilling fluid may assist in sealing and
stabilizing the well bore 40.
[0021] In the illustrated embodiment, subterranean zone 30 is an
unconventional reservoir, such as a coal seam, tight shale or low
permeability formations. Subterranean zone 30 may be accessed to
remove and/or produce water, hydrocarbons, and other fluids, to
sequester carbon dioxide or other pollutants, and/or for other
operations. Subterranean zone 30 may, in one embodiment, be
naturally fractured.
[0022] For ease of reference and purposes of example, subterranean
zone 30 will be referred to as coal seam 30. The coal seam 30 may
be a normally to sub-normally pressured formation. For a normally
pressured formation, the pressure in the formation is equal or
substantially equal to that of the water gradient at the depth of
the formation. For a sub-normally pressured formation, the pressure
in the formation is less than that of the water gradient at the
depth of the formation. For example, a sub-normally pressured coal
seam 30 may have a pressure that is 5 or more percent less than
that of the water gradient at the depth of the coal seam 30.
[0023] The well bore 40 can define a first portion 42 that extends
from the surface 20, a second portion 44 at least partially
coinciding with the coal seam 30 and a curved or radiused portion
46 interconnecting the portions 42 and 44. In one instance, the
first portion 42 may be drilled to extend past the curved portion
46 to define a sump and/or to provide access to additional coal
seams 30, for example, by drilling additional curved portions 46
and second portions 44. Additionally, although the first portion 42
is illustrated as being substantially vertical, the first portion
42 may be formed at any angle relative to the surface. For example,
the first portion 42 may be slanted to reduce the radius of the
curved portion 46, to accommodate surface 20 geometric
characteristics or other concerns such as nearby well bores. For
example, the first portion 42 may be angled to accommodate an
adjacent well bore 40 drilled from the same surface area or same
drilling pad. The first portion 42 of well bore 40 may be lined
with a suitable casing 48. The casing 48 may also extend into or
through the curved section 46, and in some instances, into the
second portion 44.
[0024] The second portion 44 may be substantially horizontal and/or
in the seam of coal seam 30, may track the depth of the coal seam
30, may undulate in the coal seam 30 or be otherwise suitably
disposed in or about the coal seam 30. The second portion 44 of the
well bore 40 may include a well bore pattern with a plurality of
lateral or other horizontal well bores, as it discussed in more
detail with respect to FIG. 2. In another embodiment, the well bore
40 may be a single bore without laterals.
[0025] Although FIG. 1 illustrates a single articulated well bore
40 that deviates to horizontal, system 10 may be implemented, as
described in connection with FIG. 7, as dual or multi-well systems
or any other suitable types of wells or well systems. Well bore 40
may be drilled to intersect more natural passages and other
fractures, such as "cleats" of a coal seam 30, that allow the flow
of fluids from seam into well bore 40, thereby increasing the
productivity of the well.
[0026] Articulated well bore 40 is drilled using drill string 50
that includes a suitable down-hole motor and drill bit 52. The
drill string 50 may be driven by a rotary rig, top drive rig and/or
coiled tubing rig. Accordingly, the drill string 50 may be coiled
tubing, sectioned drill pipe or other suitable tubing. Other down
hole drill and/or steering systems may be used. During the process
of drilling well bore 40, drilling fluid or mud is pumped down
drill string 50, as illustrated by arrows 60, and circulated out of
drill string 50 in the vicinity of drill bit 52, as illustrated by
arrows 62. The drilling fluid flows into the annulus between drill
string 50 and well bore walls 49 where the drilling fluid is used
to remove formation cuttings and coal fines. The cuttings and coal
fines (hereinafter referred to as "debris") are entrained in the
drilling fluid, which circulates up through the annulus between the
drill string 40 and the well bore walls 49, as illustrated by
arrows 63, until it reaches surface 20, where the debris is removed
from the drilling fluid and the fluid is re-circulated through well
bore 40.
[0027] In certain embodiments, the drilling fluid may comprise
water and one or more weighting agents, fluid loss agents, and/or
viscosity agents. The weighting agents may be used to increase the
density of the drilling fluid and thus the hydrostatic fluid
pressure exerted on the coal seam 30 during drilling of the well
bore 40. The drilling operation produces a column of drilling fluid
in the well bore 40 having a vertical height equal to the depth of
the well bore 40 and produces a hydrostatic pressure on well bore
40 relating to the density of the drilling fluid and the vertical
height of the column of fluid. In one embodiment, the well bore 40
is drilled over-balanced with the hydrostatic fluid pressure in
well bore 40 exceeding the pressure in the coal seam 30. For
normally and sub-normally pressured coal seams 30, the well bore 40
may be drilled with a drilling fluid having a density selected to
be approximately equal to or greater than the density of the
formation cuttings. In one instance, the well bore 40 may be
drilled with a drilling fluid having a density of 9.5 pounds per
gallon or higher, 10 pounds per gallon or higher, or a density
close to or matching that of the coal cuttings, which may be 11.2
pounds per gallon. In this embodiment, the coal cuttings may be
buoyant or nearly buoyant in the drilling fluid and efficiently
removed from the well bore 40. This would allow for extremely high
rates of drilling and high hole cleaning efficiency, greater than
could be achieved with drilling fluid having a lower density than
the cuttings.
[0028] In one embodiment, a salt such as sodium chloride or calcium
chloride may be used as a weighting agent. In particular, sodium
chloride may provide a brine having a density of up to 9.9 pounds
per gallon. Calcium chloride may provide a brine having a density
up to 11.7 pounds per gallon. In other embodiments, potassium
formate may be used as a weighting agent. Potassium formate may
provide a drilling fluid having a density up to 14 pounds per
gallon. Other suitable weighting agents may be used.
[0029] The density, or specific gravity, of the drilling fluid may
be determined based on bore hole stability needs, fracture gradient
of the coal seam 30, and/or cutting removal needs. In this and
other embodiments, bore hole stability needs may be initially
determined based on the formation stress, formation pressure,
and/or formation strength of the coal seam 30. For example,
drilling fluid density may be increased when the coal seam 30 has
less rock stability, while the density of the drilling fluid may be
reduced when the coal seam 30 has a greater rock stability. Other
suitable criteria may be used in initially or otherwise determining
the density of the drilling fluid.
[0030] The fluid loss agent may form a filter cake 100 along the
walls of the well bore 40. Filter cake 100 may prevent or
significantly restrict drilling fluids from flowing into coal seam
30 from the well bore 40. The filter cake 100 may also provide a
pressure boundary or seal between coal seam 30 and well bore 40
which may allow hydrostatic pressure in the well bore 40 to be used
to control stability of the well bore 40 to prevent collapse during
drilling. For example, during drilling, the filter cake 100 may aid
well bore stability by allowing the hydrostatic pressure to act
against the walls of the well bore 40 and/or by preventing drilling
fluid from entering the coal seam 30 and destabilizing the seam
around the well bore 40.
[0031] The depth of the filter cake 100 may be dependent upon many
factors including the composition of the drilling fluid, the fluid
loss agent, and/or the properties of the formation. The fluid loss
agent may be selected or otherwise designed in connection with the
drilling fluid based on rock mechanics, pressure and other
characteristics of the coal seam 30 to form a filter cake that
reduces or minimizes fluid loss during drilling and/or reduces or
minimizes skin damage to the well bore 40.
[0032] The filter cake 100 may be formed with low-loss, ultra
low-loss, non-invasive, low-invasive or other suitable drilling
fluids. In one embodiment, fluid loss agent may comprise solid
micelles that form microscopic spheres, rods, and/or plates in
solutions. The micelles may comprise polymers with a range of water
and oil solubilities. The micelles form a low permeability seal
over pore throats of the coal seam 30 to greatly limit further
fluid invasion or otherwise seal the coal seam boundary. In a
particular embodiment, the fluid loss agent may comprise FLC 2000
available from IMPACT SOLUTIONS GROUP which may create a shallow
filter cake 100 having a depth of invasion into the formation
approximately two to four centimeters with a structural integrity
operable to seal the well bore 40. In some instances, the fluid
invasion rate of FLC 2000 may be 0.17 cubic meters of fluid lost to
the formation per square meter of exposed formation in a day
(m.sup.3/m.sup.2day), as compared to 0.6 m.sup.3/m.sup.2day for
other conventional drilling fluids. FLC 2000 may provide a high
return permeability after drilling during production. Starch and/or
other fluid loss agents may be used in connection with the FLC
2000. In a particular embodiment, starch may be used to increase
the sealing effect of the filter cake 100 formed by the FLC 2000.
In another embodiment, aphrons, for example may be used as the
fluid loss agent.
[0033] The viscosity agents may increase lifting capacity of the
drilling fluid. In a particular embodiment, the viscosity agents
may comprise carboxyl methyl cellulose (CMC), hydroxyl ethyl
cellulose (HEC), polyanionic cellulose (PAC), and/or xanthan gum
(XG polymer). Other suitable viscosity agents may be used. In
addition, the viscosity agents may be omitted when not needed.
[0034] During drilling, the first portion 42 of the well bore 40
may be drilled overbalanced with a dense drilling fluid, but
without the fluid loss and viscosity agents. The density of the
drilling fluid may initially be between 8.3 and 9.0 pounds per
gallon. After casing the first portion 42 of the well bore 40, and,
in one embodiment, prior to entering the coal seam 30, the fluid
loss and viscosity agents may be added to the drilling fluid. In
the embodiment in which FLC 2000 is used as the fluid loss agent,
FLC 2000 may initially be added to the drilling fluid in
concentrations of up to 6-10 kilograms per cubic meter. If
additional stability is needed, the concentration of FLC 2000 may
be increased up to about 15 kilograms per cubic meter. Similarly,
the density of the drilling fluid may be increased up to, for
example, 9.5 pounds per gallon or greater to control bore hole 40
stability and/or assist in cuttings removal. For example, the
density of the drilling fluid may be increased up to the density of
the coal to suspend the cuttings in the drilling fluid and increase
hole cleaning efficiency. However, the density of the drilling
fluid may be limited due to the fracture gradient of the coal seam
30. In this case, additional viscofiers may be used. Additionally,
the velocity and/or pump rate of the drilling fluid may be
increased in the bore hole 40 to assist with cutting cleanout and
removal
[0035] FIG. 2 illustrates an example of horizontal well bore
pattern 65 for use in connection with well bore 40. In this
embodiment, the pattern 65 may include a main horizontal well bore
67 extending diagonally across the coverage area 66. A plurality of
lateral or other horizontal well bores 68 may extend from the main
bore 67. The lateral bore 68 may mirror each other on opposite
sides of the main bore 67 or may be offset from each other along
the main bore 67. Each of the laterals 68 may be drilled at a
radius off the main bore 67. The horizontal pattern 65 may be
otherwise formed, may otherwise include a plurality of horizontal
bores or may be omitted. For example, the pattern 65 may comprise a
pinnate pattern having a main horizontal bore extending diagonally
across the coverage area 66 and two, three four or more laterals
extending from and on each side of the main horizontal bore 67 to
the periphery of the coverage area 66. The horizontal bores may be
bores that are fully or substantially in the coal seam 30, or
horizontal and/or substantially horizontal.
[0036] FIG. 3 illustrates production from well bore 40. Drill
string 50 has been removed and a fluid extraction system 70
inserted into well bore 40. Fluid extraction system 70 may include
any appropriate components capable of circulating and/or removing
fluid from well bore 40 and lowering the pressure within well bore
40. For example, fluid extraction system 70 may comprise a tubing
string 72 coupled to an artificial lift apparatus 74. Artificial
lift apparatus 74 may comprise any appropriate device for
circulating and/or removing fluid from well bore 40, such as a pump
or a fluid injector. Although artificial lift apparatus 74 is
illustrated as being located on surface 20, in certain embodiments,
artificial lift apparatus 74 may be located within well bore 40,
such as would be the case if artificial lift apparatus 74 comprised
a down-hole pump. The fluid may be a liquid and/or a gas.
Artificial lift apparatus 74 may be omitted where, for example,
water produced is limited and/or gas pressure in the coal seam is
high enough to lift produced water to the surface 20.
[0037] In certain embodiments, artificial lift apparatus 74 may
comprise a pump coupled to tubing string 72 that is operable to
draw fluid from well bore 40 through tubing string 72 to surface 20
and reduce the pressure within well bore 40. In the illustrated
embodiment, artificial lift apparatus 74 comprises a fluid
injector, which may inject gas, liquid, or foam into well bore 40.
Any suitable type of injection fluid may be used in conjunction
with system 70. Examples of injection fluid may include, for
example: (1) production gas, such as natural gas, (2) water, (3)
air, and (4) any combination of production gas, water, air and/or
treating foam. In particular embodiments, production gas, water,
air, or any combination of these may be provided from a source
outside of well bore 40. In other embodiments, gas recovered from
well bore 40 may be used as the injection fluid by re-circulating
the gas back into well bore 40. Rod, positive displacement and
other pumps may be used. In these and other embodiments, as
illustrated in FIG. 8, a cavity may be formed in the well bore 40
with the pump inlet positioned in the cavity. The cavity may form a
junction with a vertical or other well in which the pump and/or
pump inlet is disposed.
[0038] The fluid extraction system 70 may also include a liner 75.
The liner 75 may have a plurality of apertures and may be loose in
the well bore or otherwise uncemented. The apertures may be holes,
slots, or openings of any other suitable size and shape. The
apertures may allow water and gas to enter into the liner 75 from
the coal seal 30 for production to the surface. The liner 75 may
have apertures when installed or may be perforated after
installation. For example, the liner 75 may comprise a drill or
other string perforated after another use in well bore 40.
[0039] The size and/or shape of apertures in the liner 75 may in
one embodiment be determined based on rock mechanics of the coal
seam. In this embodiment, for example, a representative formation
sample may be taken and tested in a tri-axial cell with pressures
on all sides. During testing, pressure may be adjusted to simulate
pressure in down-hole conditions. For example, pressure may be
changed to simulate drilling conditions by increasing hydrostatic
pressure on one side of the sample. Pressure may also be adjusted
to simulate production conditions. During testing, water may be
flowed through the formation sample to determine changes in
permeability of the coal at the well bore in different conditions.
The tests may provide permeability, solids flow and solids bridging
information which may be used in sizing the apertures, determining
the periodicity of the apertures, and determining the shape of the
apertures. Based on testing, if the coal fails in blocks without
generating a large number of fines that can flow into the well
bore, large perforations and/or high clearance liners with a loose
fit may be used. High clearance liners may comprise liners one or
more casing sizes smaller than a conventional liner for the hole
size. The apertures may, in a particular embodiment, for example,
be holes that are 1/2 inch in size.
[0040] In operation of the illustrated embodiment, fluid injector
74 injects a fluid, such as water or natural gas, into tubing
string 72, as illustrated by arrows 76. The injection fluid travels
through tubing string 72 and is injected into the liner 75 in the
well bore 40, as illustrated by arrows 78. As the injection fluid
flows through the liner 75 and annulus between liner 75 and tubing
string 72, the injection fluid mixes with water, debris, and
resources, such as natural gas, in well bore 40. Thus, the flow of
injection fluid removes water and coal fines in conjunction with
the resources. The mixture 80 of injection fluid, water, debris,
and resources is collected at a separator (not illustrated) that
separates the resource from the injection fluid carrying the
resource. Tubing string 72 and fuel injector 74 may be omitted in
some embodiments. For example, if coal fines or other debris are
not produced from the coal seam 30 into the liner 75, fluid
injection may be omitted.
[0041] In certain embodiments, the separated fluid is re-circulated
into well bore 40. In a particular embodiment, liquid, such as
water, may be injected into well bore 40. Because liquid has a
higher viscosity than air, liquid may pick up any potential
obstructive material, such as debris in well bore 40, and remove
such obstructive material from well bore 40. In another particular
embodiment, gas may be injected into well bore 40. Although certain
types of injection fluids are described, any combination of air,
water, and/or gas that are provided from an outside source and/or
re-circulated from the separator may be injected back into well
bore 40.
[0042] Also in certain embodiments, after drilling is completed,
the drilling fluid may be left in well bore 40 while drill string
50 is removed and tubing string 72 and liner 75 are inserted. The
drilling fluid, and possibly other fluids flowing from the coal
seam 30, may be pumped or gas lifted (for example, using a fluid
injector) to surface 20 to reduce, or "draw down," the pressure
within well bore 40. As pressure is drawn down below reservoir
pressure, fluid from the coal seam 30 may begin to flow into the
well bore 40. This flow may wash out the filter cake 100 when
non-invasive or other suitable drilling fluids are used. In other
embodiments, the filter cake 100 or a portion thereof may remain.
In response to the initial reduction in pressure and/or friction
reduction in pressure, the well bore 40 may collapse, as described
below.
[0043] Collapse may, in certain embodiments, improve the efficiency
of gas production from coal seam 30 by, for example, increasing the
localized permeability of the coal seam 30. The localized
permeability is a permeability of all or part of an area around,
otherwise about, or local to the well bore 40. The localized
permeability may be enhanced, in one embodiment, by spalling or
cleaving the subterranean zone 30 around the well bore and/or
otherwise collapsing the well bore 40. Cleaving refers to splitting
or separating portions of the subterranean zone 30. Spalling refers
to breaking portions of the subterranean zone 30 into fragments and
may be localized collapsed, fracturing, splitting and/or shearing.
The increased localized permeability provides more drainage surface
area without hydraulically fracturing the coal seam 30. Hydraulic
fracturing comprises pumping a fracturing fluid down-hole under
high pressure, for example, 1000 psi, 5000 psi, 10,000 psi or
more.
[0044] Collapse may occur before or after production begins.
Collapse may be beneficial in situations where coal seam 30 has low
permeability, such as below 3 millidarcies. However, coal seams 30
having other levels of permeability may also benefit from collapse.
In certain embodiments, the drilling fluid may be removed before
the pressure drop in well bore 40. In other embodiments, the
pressure within well bore 40 may be reduced by removing the
drilling fluid.
[0045] FIG. 4 is a cross sectional diagram along lines 4-4 of FIG.
3 illustrating well bore 40 in the subterranean zone 30. Filter
cake 100 is formed along walls 49 of the well bore 40. As discussed
above, filter cake 100 may occur in over-balanced drilling
conditions where the drilling fluid pressure is greater that of the
coal seam 30. Filter cake 100 may be otherwise suitably generated
and may comprise any partial or full blockage of pores, cleats 102
or fractures in order to seal the well bore 40 by substantially
limiting or reducing fluid flow between the coal seam 30 and well
bore 40.
[0046] As previously described, use of a fluid loss agent, or
non-invasive fluid, may create a relatively shallow invasion filter
cake 100, resulting in a relatively low amount of drilling fluid
lost into the cleats 102 of the coal seam 30. In certain
embodiments, a filter cake 100 may have an invasion depth 110
between two and four centimeters thick. A thin filter cake 100 may
be advantageous when it will not cause a permanent blockage but is
strong enough to form a seal between coal seam 30 and well bore 40
to facilitate stability of the well bore 40 during drilling.
[0047] FIG. 5 is a cross-sectional diagram illustrating collapse of
the well bore 40. Collapse may be initiated in response to the
pressure reduction in the well bore 40. As used herein, in response
to means in response to at least the identified event. Thus, one or
more events may intervene, be needed, or also be present. In one
embodiment, the well bore 40 may collapse when the mechanical
strength of the coal cannot support the overburden at the
hydrostatic pressure in the well bore 40. The well bore 40 may
collapse, for example, when fluid pressure is reduced in the well
bore 40.
[0048] During collapse, a shear plane 120 may be formed along the
sides of the well bore 40. The shear planes 120 may extend into the
coal seam 30 and form high permeability pathways connected to
cleats 102. In some embodiments, multiple shear planes 120 may be
formed during spalling. Each shear plane 120 may extend about the
well bore 40.
[0049] Collapse may generate an area of high permeability within
and around the pre-existing walls 49 of the well bore 40. This
enhancement and localized permeability may permit a substantially
improved flow of gas or other resources from the coal seam 30 into
liner 75 than would have occurred without collapse. In an
embodiment where the well bore 40 includes a multi-lateral pattern,
the main horizontal bore and lateral bores may each be lined with
liner 75 and collapsed by reducing hydrostatic pressure in the well
bores.
[0050] FIG. 6 is a flow chart illustrating an example method for
drilling normally and sub-normally pressured coal seams 30. In this
embodiment, well bore 40 comprises an articulated well bore in
which the first portion 42 is vertical, the second portion 44 is
horizontal and the curved portion 46 deviates from vertical to
horizontal. As previously described, the well bore 40 may be
otherwise suitably configured.
[0051] Referring to FIG. 6, the method begins at step 202, in which
formation properties are determined. For the coal seam 30,
formation stress, formation pressure and/or formation strength may
be determined from core samples, reference databases, other well
wells and/or other resources. At step 204, drilling fluid density
is selected based on well bore 40 stability and/or other formation
properties. For over-balanced drilling, the drilling fluid density
is selected such that the hydrostatic pressure of the drilling
fluid at the depth of the coal seam 30 is greater than the pressure
of the coal seam 30. As previously described, sodium chloride,
calcium chloride, potassium formate and/or other weighting agents
may be used to raise the density of the drilling fluid to the
desired density.
[0052] Proceeding to step 206, the vertical portion 42 of the well
bore 40 is drilled and cased. At step 208, and, in one embodiment,
prior to drilling into the coal seam 30, one or more fluid loss
agents are added to the drilling fluid. In one embodiment, the
fluid loss agents include at least one of aphrons and micelles. As
previously described, the fluid loss agents may form a filter cake
100 on the walls 49 of the well bore 40. The filter cake 100 may
stabilize the well bore 40 during drilling and may, in one
embodiment, reduce differential sticking and provide lubrication to
reduce friction of the drill string 50 in the well bore 40. The
fluid loss agents may, for example, comprise FLC 2000, other
micelle, and/or aphrons.
[0053] At step 210, one or more viscosity agents may be added to
the drilling fluid. As previously described, the viscosity agents
may comprise, for example, CMC, HEC, PAC and/or XG polymer. The
viscosity agents may increase the viscosity of the drilling fluid
and may thereby enhance cutting removal from the well bore 40.
[0054] Proceeding to step 212, the radiused portion 46 and
horizontal portion 44 of the well bore 40 are drilled over-balance
using the drilling fluid with the fluid loss agents and/or
viscosity agents. Step 212 leads to decisional step 214 where
during ongoing drilling operations, the No branch leads to
decisional step 216. At decisional step 216, well bore 40 stability
is determined. Well bore 40 stability may be determined based on,
for example, the size and/or amount of cuttings being returned to
the surface 20 during drilling. Large and/or a large number of
cuttings may indicate instability of the well bore 40.
[0055] If the well bore is not stable, the No branch of decisional
step 216 leads to step 218. At step 218, density of the drilling
fluid may be increased to increase pressure on the walls 49 of the
well bore 40 and stabilize the well bore 40. In one embodiment,
care may be taken to avoid increasing drilling fluid density up to
or beyond the fracture gradient of the coal seam 30. Also, at step
220, additional fluid loss agents may be added to the drilling
fluid to enhance the filter cake 100 and reduce loss of drilling
fluid into the coal seam 30. In a particular embodiment, starch may
be added to enhance the sealability of the filter cake 100. In
another embodiment, the additional amounts of fluid loss agents
(aphrons, micelles, or other fluid loss agents) may be added to
enhance the filter cake 100. Also, at step 221, the flow rate of
the drilling fluid can be adjusted.
[0056] Step 221 leads to decisional step 222. The Yes branch of
decisional step 216 also leads to step 222. At decisional step 222,
it is determined if cuttings are building up in the well bore 40.
Cutting buildup may be determined by the volume of cuttings
recovered at the surface from the drilling fluid. For example, a
low volume of cuttings may indicate buildup in the well bore 40. If
cuttings are building up in the well bore 40, the Yes branch of
decisional step 222 leads to step 224. At step 224, the density of
the drilling fluid may be increased to enhance the ability of the
drilling fluid to remove cuttings from the well bore 40. The
density of the drilling fluid may be increased to a specific
gravity toward, up to, at, near or above that of the coal cuttings
in order to increase buoyancy of cuttings in the drilling fluid and
increase cutting removal. As previously described, in one
embodiment, care may be taken to avoid reaching the fracture
gradient of the coal seam 30 and causing fractures in the seam.
Next, at step 226, additional viscosity agents may be added to
enhance cutting removal. At step 227, the flow of drilling fluid
may be adjusted. In one instance, the flow can be increased to
increase cuttings removal.
[0057] Step 227 returns to step 212. The No branch of decisional
step 222 also returns to step 212. At step 212, drilling of the
radiused and/or horizontal portions 46 and 44 of the well bore 40
is continued with adjustments for fluid density, fluid loss, and/or
viscosity made as need for well bore stability and cuttings removal
of the well bore 40. Upon completion of the well bore 40, the Yes
branch of decisional step 214 leads to the end of the process.
[0058] FIG. 7 illustrates another example system 300 of drilling a
well bore 40 from the terranean surface 20 to a subterranean zone
(coal seam 30). The example system 300 is similar to the example
system 10 described above with respect to FIGS. 1-6 above, but
further includes a surface bore 310 coupled to the terranean
surface 20 and a cavity 312. The surface bore 310 extends from the
surface 20, directly, through an entry bore (not shown), or from a
location about the surface to at least partially coincide with the
coal seam 30. In some instances, the surface bore 310 may extend
through and/or below the coal seam 30 to define a sump 314. A
casing 316 may be provided through all or part of the surface bore
310, and in one instance terminates above the cavity 312.
[0059] The surface bore 310 may be horizontally offset from the
first portion 42 of the well bore 40 proximate the coal seam 30 a
sufficient distance to permit the curved portion 46 and any desired
length of second portion 44 to be drilled before intersecting the
cavity 312. The amount of the offset can be selected so the radius
of the curved portion 46 can be large. A large radius of curvature
reduces friction in the well bore 40 during drilling operations,
and as a result, increases the reach of the drill string (as
limited by friction) over well bores drilled with tighter
radiuses.
[0060] FIG. 7 depicts the surface bore 310 extending substantially
vertically; however, the surface bore 310 may be formed at any
angle relative to the surface 20. For example, the surface bore 310
may be slanted or include a slanted portion. By slanting the
surface bore 310, the location of the surface bore 310 at the
surface 20 can be positioned closer to the location of the first
portion 42, and in some instances can be drilled from the same
drilling location, drilling pad, or both bores (bore 310, bore 42)
can be drilled through a common entry bore. The surface bore 310
may also, or alternatively, be slanted to accommodate surface 20
geometric characteristics or other concerns such as nearby well
bores.
[0061] Cavity 312 is formed proximate the coal seam 30. As used
herein, proximate is intended to encompass the case where the
cavity 312 is partly or wholly within the coal seam 30. The cavity
312 can be formed though the surface bore 310, for example, with an
under reamer device, by hydrojetting, or other cavity forming
device. Many cavity forming devices will form a cavity 312 with a
substantially cylindrical portion, whereas natural occurring cracks
or crevices are not cylindrical. The cavity 312 can be an enlarged
cavity having a transverse dimension greater than the transverse
dimension of the surface bore 310. Alternately the cavity 312 can
have a transverse dimension equal to or smaller than the transverse
dimension of the surface bore 310. The vertical dimension of the
cavity 312, may be smaller than the vertical thickness of the coal
seam 30, approximately the same as the vertical thickness of the
coal seam 30, or may be larger than the vertical thickness of the
coal seam 30.
[0062] The well bore 40 is drilled similarly to that described
above, but the surface bore 310 and the cavity 312 are typically
(although not necessarily) formed first. Also, the drilling of well
bore 40 is controlled so that the bore intersects the cavity 312.
In certain embodiments, the cavity 312 provides an enlarged target
for intersection, and reduces the precision to which drilling well
bore 40 must be controlled. After the cavity 312 has been
successfully intersected, drilling may continue through the cavity
312 and into the coal seam 30. As discussed above, drilling fluid
or mud is circulated down through the interior of drilling string
50 and up the annulus between drilling string 50 and well bore
walls 49 where the drilling fluid is used to remove debris. While
drilling the well bore 40, additional fluids, for example
additional drilling fluid with the same or different
characteristics and/or amounts and types of weighting agents, fluid
loss agents, and/or viscosity agents as that pumped down the
drilling string 50, or other suitable fluids, can be pumped down
the surface bore 310 into the annulus between the drilling string
50 and the well bore walls 49. The additional fluids can be flowed
to increase the flow rate in the annulus and aid in removing debris
that may otherwise traversing the curved portion 42 and traveling
up the first portion 42 to the surface 20.
[0063] As above, the well bore 40 may be a single bore without
laterals, or may include a well bore pattern with a plurality of
lateral or other horizontal well bores. If desired, all or part of
the well bore pattern can be lined. For example, liners may be
provided in the lateral or other horizontal well bores and tied
back to casing or liners in the well bore 40. Where the well bore
40 includes a well bore pattern, the cavity 312 can act as a
junction for multiple lined bores. If two or more of the liners
communicate with the cavity 312, production from the bores can
centrally collected in the cavity 312 and withdrawn.
[0064] FIG. 8 illustrates producing the well bore 40 of the system
300. In certain embodiments, the cavity 312 can be filled with
gravel 318 (i.e. gravel packed). The gravel 318 helps support the
cavity 312 and also acts to filter coal fragments out of fluid
before it enters the surface bore 310. In some embodiments, gravel
that is coarse may be used because, for example, coal fragments
breaking off from the coal seam tend to be larger than sands, silts
and clays that are typically produced in other formations. In one
example, gravel with a mean diameter of between about 20 and about
30 mm is used. Coarse gravel is different from finer gravel (i.e.
gravel with a smaller mean diameter) used when producing from a
sandy formation. The gravel 318, typically contained in a slurry,
may be introduced through the surface bore 310, for example,
through the interior of a tubing extending into the cavity or in an
annulus between a tubing and the wall of the surface bore 310.
[0065] In certain embodiments, the cavity 312 can be provided with
a apertured liner 320 positioned to communicate with the surface
bore 310. The apertured liner 320 can be provided in the cavity 312
prior to gravel packing. Alternatively, the cavity 312 can be
gravel packed and the apertured liner 320 provided with a conical
or other suitable tip 322 and subsequently driven through the
gravel 318 into position in the cavity 312.
[0066] In this embodiment, the inlet 324 of a pump, such as a
sucker rod pump, electric submersible pump, or other type of pump,
is installed in the surface bore 310 to withdraw fluids collected
in the cavity 312 to the surface 20 through a pump string 326. The
pump inlet 324 can be positioned within the surface bore 310 or
within the apertured liner 320 in the cavity 312. Other artificial
lift techniques or the natural flow from the formation can be used
in combination with or as an alternative to a pump.
[0067] In operation of the illustrative embodiment, water, debris,
and resources, such as gas from the coal seam 30, flow along the
well bore 40. The water and debris collect and the cavity 312, and,
if provided, also in the sump 314. The water is removed from the
cavity 312 to the surface 20 by the inlet 324 of the pump, or by
other artificial lift or natural flow from the formation. Gas may
flow through the well bore 40 to the surface 20, through the
surface bore 310 (in the annulus between the pump string 326 and
the wall of the surface bore 310) to the surface 20, or through
both.
[0068] Although the present disclosure has been described with
several embodiments, various changes and modifications may be
suggested to one skilled in the art. It is intended that the
present invention encompasses such changes and modifications as
fall within the scope of the appended claims.
* * * * *