Note: Descriptions are shown in the official language in which they were submitted.
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
METHOD AND SYSTEM FOR DRILLING WELL BORES
REFERENCE TO RELATED APPLICATIONS
The present application claims the benefit of U.S. Patent Application No.
11/141,458 filed on May 31, 2005, entitled "Well Bore Cleaning" which is
application is a continuation-in-part of U.S. Patent Application Serial No.
11/035,537
filed on January 14, 2005,which is a continuation-in-part of U.S. Patent
Application
Serial No. 10/723,322, filed on November 26, 2003.
The present application also claims the benefit of U.S. Patent Application No.
11/141,459 filed on May 31, 2005, entitled "Drilling Normally to Sub-Normally
1o Pressured Formations", which is application is a continuation-in-part of
U.S. Patent
Application Serial No. 11/035,537 filed on January 14, 2005, which is a
continuation-
in-part of U.S. Patent Application Serial No. 10/723,322, filed on November
26,
2003.
TECHNICAL FIELD
This disclosure relates generally to the field of recovery of subterranean
resources, and more particularly to a system and method for well bore
cleaning.
BACKGROUND
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.
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.
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.
1
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
SUMMARY
The invention encompasses a system and method for well bore cleaning. 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.
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.
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.
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
3o removal. The invention encompasses a system and method for drilling
normally to
sub-normally pressured formations. In one embodiment, the method includes
drilling
2
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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 conlprise 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
1o 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.
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.
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.
Other technical advantages will be readily apparent to one skilled in the art
from the following figures, description, and claims. Moreover, while specific
3
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
advantages have been enumerated above, various embodiments may include all,
some, or none of the eiiumerated advantages.
DESCRIPTION OF DRAWINGS
FIG. 1 illustrates one embodiment of drilling a well of drilling a well from
the
terranean surface to a subterranean zone;
FIG. 2 illustrates one embodiment of a well bore pattern for the well of FIG
1;
FIG. 3 illustrates one embodiment of producing the well of FIG 1;
FIG. 4 is a cross sectional diagram along lines 4-4 of FIG. 3 illustrating one
embodiment of the well bore of FIG 3;
FIG. 5 is a cross-sectional diagram illustrating collapse of the well bore of
FIG.
4;
FIG. 6 is a flow chart illustrating an example method for drilling a normally
to
sub-normally pressured formation;
FIG. 7 illustrates another embodiment of drilling a well from the terranean
surface to a subterranean zone; and
FIG. 8 illustrates one embodiment of producing the well of FIG 7.
Like reference symbols in the various drawings indicate like elements.
DETAILED DESCRIPTION
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.
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.
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
4
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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
1 o 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.
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
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
25 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.
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
3o bore 40 may be drilled to intersect more natural passages and other
fractures, such as
5
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
"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.
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
1 o 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.
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
2o 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
6
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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
1 o fluid having a density up to 14 pounds per gallon. Other suitable
weighting agents
may be used.
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.
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.
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
7
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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 (m3 /m2 =
day), as
compared to 0.6 m3 /mz = day 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.
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.
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
8
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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
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.
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
9
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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.
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.
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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.
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.
11
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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
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
15 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.
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
20 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
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
25 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.
Collapse may occur before or after production begins. Collapse may be
30 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
12
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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.
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 pernlanent 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.
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.
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.
13
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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
1 o 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.
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.
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.
14
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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.
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.
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
3o 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
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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.
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.
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.
16
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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.
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,
3o 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
17
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
As above, the well bore 40 may be a single bore without laterals, or may
1 o 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.
FIG. 8 illustrates producing the well bore 40 of the system 300. In certain
embodiments, the cavity 312 can be filled with grave1318 (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.
In certain embodiments, the cavity 312 can be provided with a apertured liner
3o 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
18
CA 02610622 2007-11-29
WO 2006/130649 PCT/US2006/021046
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.
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.
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.
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.
19
