U.S. patent application number 13/820937 was filed with the patent office on 2013-08-08 for method and system for fracture stimulation by formation displacement.
The applicant listed for this patent is Michael S. Chelf, Bruce A. Dale, Sheng-Yuan Hsu, Kevin H. Searles. Invention is credited to Michael S. Chelf, Bruce A. Dale, Sheng-Yuan Hsu, Kevin H. Searles.
Application Number | 20130199781 13/820937 |
Document ID | / |
Family ID | 45994321 |
Filed Date | 2013-08-08 |
United States Patent
Application |
20130199781 |
Kind Code |
A1 |
Dale; Bruce A. ; et
al. |
August 8, 2013 |
Method and System for Fracture Stimulation by Formation
Displacement
Abstract
The present techniques provide methods and systems for
fracturing reservoirs without directly treating them. For example,
an embodiment provides a method for fracturing a subterranean
formation. The method includes causing a volumetric increase in a
zone proximate to the subterranean formation so as to apply a
mechanical stress to the subterranean formation, creating a
fracture network in the subterranean formation to improve
permeability therein.
Inventors: |
Dale; Bruce A.; (Sugar Land,
TX) ; Searles; Kevin H.; (Kingwood, TX) ; Hsu;
Sheng-Yuan; (Sugar Land, TX) ; Chelf; Michael S.;
(Humble, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Dale; Bruce A.
Searles; Kevin H.
Hsu; Sheng-Yuan
Chelf; Michael S. |
Sugar Land
Kingwood
Sugar Land
Humble |
TX
TX
TX
TX |
US
US
US
US |
|
|
Family ID: |
45994321 |
Appl. No.: |
13/820937 |
Filed: |
October 14, 2011 |
PCT Filed: |
October 14, 2011 |
PCT NO: |
PCT/US2011/056350 |
371 Date: |
March 5, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61407249 |
Oct 27, 2010 |
|
|
|
61544766 |
Oct 7, 2011 |
|
|
|
Current U.S.
Class: |
166/268 ;
166/244.1; 166/280.1; 166/299; 166/302; 166/305.1; 166/308.1;
166/52 |
Current CPC
Class: |
E21B 43/267 20130101;
E21B 43/26 20130101; E21B 43/263 20130101 |
Class at
Publication: |
166/268 ;
166/244.1; 166/308.1; 166/280.1; 166/302; 166/305.1; 166/299;
166/52 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 43/267 20060101 E21B043/267; E21B 43/263 20060101
E21B043/263 |
Claims
1. A method for fracturing a subterranean formation, comprising
applying stress in a zone proximate to the subterranean formation
to indirectly translate a mechanical stress to the subterranean
formation and effect a permeability increase within the
subterranean formation.
2. The method of claim 1, wherein the permeability increase is
effected by creation of a fracture network in the subterranean
formation.
3. The method of claim 1, wherein the applied stress in the zone
proximate affects a volumetric increase in the within the zone
proximate.
4. The method of claim 1, wherein the stress in the zone proximate
causes at least a portion of the zone proximate to arch against at
least a portion of the subterranean formation, producing a fracture
network in the arched at least a portion of the subterranean
formation.
5. The method of claim 1, wherein the applied stress in the zone
proximate produces a stress reduction in the in-situ stress of the
zone proximate and enables the subterranean formation to arch
toward at least a portion of the zone proximate, producing a
fracture network in the arched at least a portion of the
subterranean formation.
6. The method of claim 1, wherein the effected permeability
increase results from creation of a fracture network within an
arched portion of the subterranean formation.
7. The method of claim 6, wherein at least a portion of the
fracture network results from delamination fracturing within the
arched portion of the subterranean formation.
8. The method of claim 1, wherein the zone proximate is below the
subterranean formation, with respect to the wellbore path.
9. The method of claim 1, applying the stress to a near-wellbore
portion of the zone proximate to the subterranean formation to bend
the subterranean formation and cause fractures to form in the
subterranean formation.
10. The method of claim 1, further comprising: thereafter reducing
the applied stress to reversing at least a portion of the
volumetric increase and effect rubblization within the subterranean
formation; and thereafter reapplying the applied stress to repeat
the volumetric increase to cause further rubblization within the
subterranean formation.
11. The method of claim 1, wherein the subterranean formation
comprises a hydrocarbon-bearing formation and the method further
comprises extracting at least a portion of the hydrocarbons from
the subterranean formation into a wellbore.
12. The method of claim 1, wherein the zone proximate comprises an
underburden formation layer.
13. The method of claim 1, wherein creating the volumetric increase
comprises pumping a fluid into the zone proximate.
14. The method of claim 13, wherein the pumped fluid comprises a
suspension of a proppant.
15. The method of claim 14, wherein the proppant comprises waste
product tailings.
16. The method of claim 1, wherein applying the stress in the zone
proximate comprises thermally expanding the zone proximate.
17. The method of claim 1, wherein applying the stress to the zone
proximate comprises expanding the zone proximate by a pressurized
fluid without hydraulically fracturing the zone proximate.
18. The method of claim 1, wherein applying the stress to the zone
proximate comprises expanding a cavity or tunnel in the zone
proximate by a pressurized fluid.
19. The method of claim 1, wherein applying the stress to the zone
proximate comprises expanding the zone proximate by a chemical
reaction.
20. The method of claim 1, wherein applying the stress to the zone
proximate comprises expanding the zone proximate by a pressurized
fluid.
21. The method of claim 1, wherein applying the stress to the zone
proximate comprises expanding the zone proximate with
explosives.
22. The method of claim 1, further comprising applying stress to
the zone proximate so as to cause at least a portion of the
subterranean formation to arch in a direction away from the zone
proximate.
23. The method of claim 1, further comprising applying stress to
the zone proximate by reducing the in-situ geomechanical stress in
the zone proximate so as to cause a volumetric reduction in at
least a portion of the zone proximate and effect at least a portion
of the subterranean formation to arch in a direction toward the
zone proximate.
24. A method for production of a hydrocarbon from a reservoir,
comprising: penetrating a zone proximate a hydrocarbon bearing
subterranean formation with a wellbore; applying stress to the zone
proximate to the subterranean formation to indirectly translate a
mechanical stress change to the subterranean formation to arch at
least a portion of the subterranean formation and thereby effect
enhanced permeability within the arched portion of the subterranean
formation; and extracting hydrocarbons from the enhanced
permeability subterranean formation into the wellbore.
25. The method of claim 24, further comprising penetrating both the
zone proximate and the hydrocarbon bearing subterranean formation
with the wellbore.
26. The method of claim 24, wherein the enhanced permeability
results from creation of a fracture network within the arched
portion of the subterranean formation.
27. The method of claim 26, wherein at least a portion of the
fracture network results from delamination fracturing within at
least a portion of the arched portion of the subterranean
formation.
28. The method of claim 24, wherein the hydrocarbon bearing
subterranean formation comprises a tight gas reservoir.
29. The method of claim 24, wherein the hydrocarbon bearing
subterranean formation comprises a shale gas reservoir.
30. The method of claim 24, wherein the hydrocarbon bearing
subterranean formation comprises a coal bed methane reservoir.
31. The method of claim 24, wherein the hydrocarbon bearing
subterranean formation comprises a tight oil reservoir.
32. The method of claim 30, wherein a cleat system within the coal
bed methane reservoir is opened to enhance conductivity.
33. The method of claim 24, further comprising drilling a
stimulation well to the zone proximate and applying the stress to
the zone proximate from the stimulation well; and extracting the
hydrocarbons from a wellbore other than the stimulation well.
34. The method of claim 33, comprising drilling a production well
from the stimulation well into the hydrocarbon bearing subterranean
formation.
35. The method of claim 24, further comprising applying stress to
the zone proximate so as to cause at least a portion of the
subterranean formation to arch in a direction away from the zone
proximate.
36. The method of claim 24, further comprising applying stress to
the zone proximate by reducing the in-situ stress in the zone
proximate so as to cause at least a portion of the subterranean
formation to arch in a direction toward the zone proximate.
37. The method of claim 24, further comprising drilling a
production well into the hydrocarbon bearing subterranean formation
after applying the stress to the zone proximate.
38. The method of claim 24, further comprising drilling a
production well into the hydrocarbon bearing subterranean formation
before the step of applying the stress to the zone proximate is
completed.
39. The method of claim 24, further comprising cycling applying the
stress and relieving the applies stress to cause a cycle of an
expansion of the zone proximate and a contraction of the zone
proximate to effect rubblizing a layer of material within the
hydrocarbon bearing subterranean formation.
40. The method of claim 24, further comprising: injecting waste
product tailings into the zone proximate to prop open any fractures
within the zone proximate.
41. A hydrocarbon production system, comprising: a hydrocarbon
bearing subterranean formation; a zone proximate to the hydrocarbon
bearing subterranean formation; a stimulation well drilled to the
zone proximate; and a stimulation system configured to applying
stress in the zone proximate to the subterranean formation to
indirectly affect a mechanical stress to the hydrocarbon bearing
subterranean formation and effect a volumetric increase within the
hydrocarbon bearing subterranean formation.
42. The hydrocarbon production system of claim 41, wherein the
hydrocarbon bearing subterranean formation comprises a tight gas
layer.
43. The hydrocarbon production system of claim 41, wherein the
hydrocarbon bearing subterranean formation comprises a shale gas
layer.
44. The hydrocarbon production system of claim 41, wherein the
hydrocarbon bearing subterranean formation comprises a coal bed
methane layer.
45. The hydrocarbon production system of claim 41, wherein the
hydrocarbon bearing subterranean formation comprises a tight oil
layer.
46. The hydrocarbon production system of claim 41, wherein the zone
comprises a formation layer in an underburden.
47. The hydrocarbon production system of claim 41, comprising a
production well drilled into the hydrocarbon bearing subterranean
formation.
48. The hydrocarbon production system of claim 41, comprising a
production well drilled into the hydrocarbon bearing subterranean
formation from the stimulation well.
49. The hydrocarbon production system of claim 41, further
comprising applying stress to the zone proximate so as to cause at
least a portion of the subterranean formation to arch in a
direction away from the zone proximate.
50. The hydrocarbon production system of claim 41, further
comprising applying stress to the zone proximate by reducing the
in-situ stress in the zone proximate so as to cause at least a
portion of the subterranean formation to arch in a direction toward
the zone proximate.
51. A method for fracturing a subterranean formation, comprising
causing a volumetric increase in a zone proximate to the
subterranean formation so as to apply a mechanical stress to the
subterranean formation.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application No. 61/407,249, filed Oct. 27, 2010 entitled METHOD AND
SYSTEM FOR FRACTURE STIMULATION, and also claims the benefit of
U.S. Provisional Application No. 61/544,766, filed Oct. 7, 2011
entitled METHOD AND SYSTEM FOR FRACTURE STIMULATION BY FORMATION
DISPLACEMENT. This application is related to concurrently filed
International Patent Application, Attorney Docket No. 2010EM298-A,
entitled "Method and System for Fracture Stimulation by Cyclic
Formation Settling and Displacement".
FIELD OF THE INVENTION
[0002] Exemplary embodiments of the present techniques relate to a
method and system for fracture stimulation of subterranean
formations to enhance the recovery of hydrocarbons. Specifically,
an exemplary embodiment provides for creating fractures and other
flow paths by delamination and rubblization of formations.
BACKGROUND
[0003] This section is intended to introduce various aspects of the
art that may be topically associated with exemplary embodiments of
the present techniques. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present techniques. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
[0004] As hydrocarbon reservoirs that are easily harvested, such as
reservoirs on land or reservoirs located in shallow ocean water,
are used up, other hydrocarbon sources must be used to keep up with
energy demands. Such reservoirs may include any number of
unconventional hydrocarbon sources, such as biomass, deep-water oil
reservoirs, and natural gas from other sources.
[0005] One such unconventional hydrocarbon source is natural gas
produced from rocks that form unconventional gas reservoirs,
including, for example, shale and coal seams. Because
unconventional gas reservoirs may have insufficient permeability to
allow significant fluid flow to a wellbore, many of such
unconventional gas reservoirs are currently not considered as
practical sources of natural gas. However, natural gas has been
produced for years from low permeability reservoirs having natural
fractures. Furthermore, a significant increase in shale gas
production has resulted from hydraulic fracturing, which can be
used to create extensive artificial fractures around wellbores.
When combined with horizontal drilling, which is often used with
wells in tight gas reservoirs, the hydraulic fracturing may allow
formerly unpractical reservoirs to be commercially viable.
[0006] The fracturing process is complicated and often requires
numerous hydraulic fractures in a single well and numerous wells
for an economic field development. Thus, more efficient fracturing
processes may provide a more productive reservoir. In other words,
a greater amount of the gas or other hydrocarbon, trapped in a
relatively non-porous reservoir, such as a tight gas, tight sand,
shale layer or even a coal seam may be harvested. Accordingly,
numerous researchers have explored ways to improve fracturing.
[0007] For example, U.S. Pat. No. 3,455,391, to Matthews, et al.,
discloses a process for horizontally fracturing subterranean earth
formations. The process is performed by injecting a hot fluid at
high pressure, until vertical fractures are formed and then closed
due to thermal expansion of the earth formation. A fluid is then
injected at a pressure sufficient to form horizontal fractures.
[0008] A similar process is disclosed in U.S. Pat. No. 3,613,785,
to Closman and Phocas. In this process a wellbore is extended into
the formation and a vertical fracture is generated by pressurizing
the borehole. A hot fluid is injected into the formation to heat
the formation, until thermal stressing of the formation matrix
material causes the horizontal compressive stress in the formation
to exceed the vertical compressive stress at a location selected
for a second well. Hydraulically fracturing the formation through
this second well can form a horizontal fracture extending into the
formation.
[0009] Other approaches have focused on relieving stress in the
formation, for example, by cavitation of the formation. For
example, U.S. Pat. No. 5,147,111, to Montgomery, discloses a method
for cavity induced stimulation of coal degasification wells. The
method can be used for improving the initial production of fluids,
such as methane, from a coal seam. To perform the method, a well is
drilled and completed into the seam. A tubing string is run into
the hole and liquid carbon dioxide is pumped down the tubing while
a backpressure is maintained on the well annulus. The pumping is
stopped, and the pressure is allowed to build until it reached a
desired elevated pressure, for example, 1500 to 2000 psia. The
pressure is quickly released, causing the coal to fail and fragment
into particles. The particles are removed to form a cavity in the
seam. The cavity can allow expansion of the coal, potentially
leading to opening of cleats within the coal seam.
[0010] A similar concept has been described in Ukraine Patent No.
35282, which discloses another method for coal degasification, but
through subsurface gasification of an underburden coal seam (a coal
seam that underlies the gas-containing formation). In this process,
wellbores are drilled through an underburden coal bed so that a
gasification catalyst can be applied. Once gasification occurs and
lowers the underburden pressure due to depletion, subsidence of the
overburden (e.g., the layer containing the gas) occurs due to
gravitational loading. The subsidence can potentially create
microfractures within the overburden reservoir, thereby allowing
improved gas migration to the degassing wells.
[0011] It has also been noted that vertical wells and mining
processes can lower stress points on coal seams, leading to
increases in the production of coal bed methane. For example, S.
Sang, et al., "Stress relief coalbed methane drainage by surface
vertical wells in China," International Journal of Coal Geology,
Volume 82, 196-203 (2010), presents a summary of studies on
improved coalbed methane production by stress relief. The paper
summarizes the status of engineering practice, technology, and
research related to stress relief coalbed methane (CBM) drainage
using surface wells in China during the past 10 years. Comments are
provided on the theory and technical progress of this method. In
high gas mining areas, such as the Huainan, Huaibei and Tiefa
mining areas, characterized by heavily sheared coals with
relatively low permeability, stress relief CBM surface well
drainage has been successfully implemented and has broad acceptance
as a CBM exploitation technology. The fundamental theories
underpinning stress relief CBM surface well drainage include
elements relating to: (1) formation layer deformation theory,
vertical zoning and horizontal partitioning, and the change in the
stress condition in mining stopes; (2) a theory regarding an
Abscission Circle in the development of mining horizontal
abscission fracture and vertical broken fracture in overlaying
rocks; and (3) the theory of stress relief inducing permeability
increase in protected coal seams during mining; and the gas
migration--accumulation theory of stress relief CBM surface well
drainage.
[0012] Other techniques for increasing production from coal beds,
and other reservoirs, have focused on in-situ pyrolysis of
hydrocarbons in a reservoir, followed by production of hydrocarbons
from the reservoir. All of these techniques above have focused on
the treatment of the hydrocarbon reservoir itself. Further, some
techniques have taught that relieving a stress on a reservoir may
enhance the production of hydrocarbons, for example, by allowing
cleats to open up in coal seams.
[0013] Related information may be found in S. E. Laubach, et al.,
"Characteristics and origins of coal cleat: A review,"
International Journal of Coal Geology 35 (1998), 175-207; Ian
Palmer, "Coalbed methane completions: A world view," International
Journal of Coal Geology 82 (2010), 184-195; Jack A. Pashin,
"Stratigraphy and structure of coalbed methane reservoirs in the
United States: An overview," International Journal of Coal Geology
35 (1998), 209-240; Pablo F. Sanz, et al., "Mechanical models of
fracture reactivation and slip on bedding surfaces during folding
of the asymmetric anticline at Sheep Mountain, Wyo.," Journal of
Structural Geology 30 (2008), 1177-1191; V. Palchik, "Localization
of mining-induced horizontal fractures along formation layer
interfaces in overburden: field measurements and prediction,"
Environ. Geol. 48 (2005), 68-80; and Stephen P. Laubach, et al.,
"Differential compaction of interbedded sandstone and coal," from:
Cosgrove, J. W. and Ameen, M. S. (eds.), Forced Folds and
Fractures, Geological Society of London, Special Publications, 169,
51-60 (The Geological Society of London 2000).
SUMMARY
[0014] An embodiment of the present techniques provides a method
for fracturing a hydrocarbon-bearing (HC-bearing) subterranean
formation, more particularly by directly effecting either
increasing stress and strain, or decreasing stress and strain upon
or within a formation or portion of a formation that is proximately
adjacent to a HC-bearing formation that provides the primary
hydrocarbon source for desired HC production. The directly applied
stress and strain (whether increased, decreased, or cycled through
both effects) is applied in a method that indirectly translates or
effects the stress and strain upon the targeted HC-bearing
formation, thereby effecting structural or stratagraphic
alterations, fractures, rubblization, or other desired effects that
increases effective permeability within the HC-bearing formation to
enable movement of at least a portion of the previously
flow-restricted hydrocarbons toward a wellbore. The method includes
causing a bulk volumetric increase or deformation in a zone or
formation proximate to the subterranean formation so as to apply or
affect a resultant mechanical stress and induced strain or
deformation to the proximately adjacent HC-bearing subterranean
formation. In another embodiment, the present techniques may
comprise cyclically increasing and decreasing the applied stress to
facilitate imparting in the HC-bearing formation, the desired
permeability change. Some methods may also create a formation
matrix distortion hysteresis in the HC-bearing formation structure
that yields improved effective permeability. For simplicity
purposes, all such formation changes, subductions, deformations,
distortion, cleaving, fracturing, rubblization, microfracturing, or
other formation shape or strain changes may be referred to
generally as a volumetric "decrease" or volumetric "increase" in
bulk formation volume (or volumetric "increase," as appropriate,
such as in a cyclic operation) of both the directly treated
formation and the indirectly affected HC-bearing formation, even
when an actual volumetric decrease or increase is not actually
affected, but is merely facilitated by plastic or elastic formation
displacement or compression of the treatment and/or HC-bearing
formations and/or compression or displacement of remote
compressible or incompressible strata and/or fluid.
[0015] In one aspect, the inventive methods include a method for
fracturing a subterranean formation, comprising causing a
volumetric increase in a zone proximate to the subterranean
formation so as to apply a mechanical stress to the subterranean
formation. In another aspect, the improved technology provides a
method for fracturing a subterranean formation, comprising applying
stress in a zone proximate to the subterranean formation to
indirectly translate a mechanical stress to the subterranean
formation and effect a permeability increase within the
subterranean formation. For consistency and simplicity of
explanation purposes, the zone that is initially treated, stressed
or other wise affected with the applied stress may be referred to
as the zone proximate, while the zone that contains the desired
hydrocarbons or other fluids, may be referred to as the
subterranean formation. The zone proximate and the subterranean
formation may be immediately adjacent or in contact with each
other, or may be subset of the same general formation, or may be
separated by intermediate formations, layers, or lenses of
strata.
[0016] In other aspects, the methods may include steps whereby the
permeability increase is effected by creation of a fracture network
in the subterranean formation. In some embodiments, the applied
stress in the zone proximate effects a volumetric increase in the
within the zone proximate. In some instances, the stress in the
zone proximate causes at least a portion of the zone proximate to
arch against at least a portion of the subterranean formation,
producing a fracture network in at least a portion of the arched
portion of the subterranean formation. In still other methods, the
applied stress in the zone proximate produces a stress reduction in
the in-situ stress of the zone proximate and enables the
subterranean formation to arch toward at least a portion of the
zone proximate, producing a fracture network in the arched at least
a portion of the subterranean formation. In most instances, the
effected permeability increase results from creation of a fracture
network within an arched portion of the subterranean formation,
whereby the subterranean formation may be cause to arch toward or
away from the zone proximate.
[0017] In another aspect, the inventive methods include a method
for production of a hydrocarbon from a reservoir, comprising:
penetrating a hydrocarbon bearing subterranean formation and a zone
proximate with a wellbore; applying stress to the zone proximate to
the subterranean formation to indirectly affect a mechanical stress
to the subterranean formation to arch at least a portion of the
subterranean formation and thereby effect enhanced permeability
within the arched portion of the subterranean formation; and
extracting hydrocarbons from the enhanced permeability subterranean
formation into the wellbore.
[0018] In yet another embodiment, the present methods include a
hydrocarbon production system, comprising: a hydrocarbon bearing
subterranean formation; a zone proximate to the hydrocarbon bearing
subterranean formation; a stimulation well drilled to the zone
proximate; and a stimulation system configured to applying stress
in the zone proximate to the subterranean formation to indirectly
affect a mechanical stress to the hydrocarbon bearing subterranean
formation and effect a volumetric increase within the hydrocarbon
bearing subterranean formation.
[0019] Another embodiment of the present techniques provides a
method for production of a hydrocarbon from a reservoir. The method
includes expanding a zone below a hydrocarbon reservoir to
mechanically stress the hydrocarbon reservoir and create an arch in
the hydrocarbon reservoir. A relative movement may be created
across a fracture surface to enhance conductivity.
[0020] Another embodiment provides a hydrocarbon production system
that includes a hydrocarbon bearing subterranean formation, a zone
proximate to the hydrocarbon bearing subterranean formation, a
stimulation well drilled to the zone, and a stimulation system
configured to create a volumetric increase in the zone.
BRIEF DESCRIPTION OF THE DRAWINGS
[0021] The advantages of the present techniques are better
understood by referring to the following detailed description and
the attached drawings, in which:
[0022] FIG. 1 is a diagram of a hydraulic fracturing process;
[0023] FIG. 2 is a drawing of a local stress state for an element
in a hydrocarbon bearing subterranean formation;
[0024] FIG. 3 is a drawing of a first mode of fracture formation,
commonly resulting from a standard hydraulic fracturing
process;
[0025] FIG. 4 is a schematic of a hydraulic fracturing process,
wherein a zone below a reservoir is subjected to a volumetric
increase, placing stress on an adjacent reservoir layer;
[0026] FIG. 5 is a block diagram of a method for stimulation of a
hydrocarbon bearing subterranean formation by treating a formation
outside of the reservoir;
[0027] FIG. 6 is a more detailed schematic view of a delamination
fracture stimulation;
[0028] FIG. 7 is a drawing of two modes of fracture formation that
may participate in delamination fracture stimulation as discussed
herein;
[0029] FIG. 8 is a drawing of rubblization during shearing at a
fracture boundary;
[0030] FIG. 9 is a drawing of an azimuthal rotation of fracture
planes within a formation that may occur as a result of cyclic
treatment of the formation; and
[0031] FIG. 10 is a drawing of a delamination fracturing process
illustrating the use of a separate production well and treatment
well.
DETAILED DESCRIPTION
[0032] In the following detailed description section, the specific
embodiments of the present techniques are described in connection
with exemplary embodiments. However, to the extent that the
following description is specific to a particular embodiment or a
particular use of the present techniques, this is intended to be
for exemplary purposes only and simply provides a description of
the exemplary embodiments. Accordingly, the present techniques are
not limited to the specific embodiments described below, but
rather, such techniques include all alternatives, modifications,
and equivalents falling within the true spirit and scope of the
appended claims.
[0033] At the outset, and for ease of reference, certain terms used
in this application and their meanings as used in this context are
set forth. To the extent a term used herein is not defined below,
it should be given the broadest definition persons in the pertinent
art have given that term as reflected in at least one printed
publication or issued patent. Further, the present techniques are
not limited by the usage of the terms shown below, as all
equivalents, synonyms, new developments, and terms or techniques
that serve the same or a similar purpose are considered to be
within the scope of the present claims.
[0034] "Cavitation completion" or "cavitation" is a process by
which an opening may be made in a formation. Generally, cavitation
is performed by drilling a well into a formation. The formation is
then pressurized in the vicinity of the well. The pressure is
suddenly released, causing the material in the vicinity of the well
to fragment. The fragments and debris may then be swept to the
surface through the well by circulating a fluid through the
well.
[0035] "Cleat system" is the system of naturally occurring joints
that are created as a coal seam forms over geologic time. The cleat
system allows for the production of natural gas if the provided
permeability to the coal seam is sufficient.
[0036] "Coal" is a solid hydrocarbon, including, but not limited
to, lignite, sub-bituminous, bituminous, anthracite, peat, and the
like. The coal may be of any grade or rank. This can include, but
is not limited to, low grade, high sulfur coal that is not suitable
for use in coal-fired power generators due to the production of
emissions having high sulfur content.
[0037] "Coalbed methane" (CBM) is a natural gas that is adsorbed
onto the surface of coal. CBM may be substantially comprised of
methane, but may also include ethane, propane, and other
hydrocarbons. Further, CBM may include some amount of other gases,
such as carbon dioxide (CO.sub.2) and nitrogen (N.sub.2).
[0038] A "compressor" is a machine that increases the pressure of a
gas by the application of work (compression). Accordingly, a low
pressure gas (for example, 5 psig) may be compressed into a
high-pressure gas (for example, 1000 psig) for transmission through
a pipeline, injection into a well, or other processes.
[0039] "Directional drilling" is the intentional deviation of the
wellbore from the path it would naturally take. In other words,
directional drilling is the steering of the drill string so that it
travels in a desired direction. Directional drilling can be used
for increasing the drainage of a particular well, for example, by
forming deviated branch bores from a primary borehole. Directional
drilling is also useful in the marine environment where a single
offshore production platform can reach several hydrocarbon bearing
subterranean formations or reservoirs by utilizing a plurality of
deviated wells that can extend in any direction from the drilling
platform. Directional drilling also enables horizontal drilling
through a reservoir to form a horizontal wellbore. As used herein,
"horizontal wellbore" represents the portion of a wellbore in a
subterranean zone to be completed which is substantially horizontal
or at an angle from vertical in the range of from about 15.degree.
to about 75.degree.. A horizontal wellbore may have a longer
section of the wellbore traversing the payzone of a reservoir,
thereby permitting increases in the production rate from the
well.
[0040] "Exemplary" is used exclusively herein to mean "serving as
an example, instance, or illustration." Any embodiment described
herein as exemplary is not to be construed as preferred or
advantageous over other embodiments.
[0041] A "facility" is tangible piece of physical equipment, or
group of equipment units, through which hydrocarbon fluids are
either produced from a reservoir or injected into a reservoir. In
its broadest sense, the term facility is applied to any equipment
that may be present along the flow path between a reservoir and its
delivery outlets, which are the locations at which hydrocarbon
fluids either leave the model (produced fluids) or enter the model
(injected fluids). Facilities may comprise production wells,
injection wells, well tubulars, wellhead equipment, gathering
lines, manifolds, pumps, compressors, separators, surface flow
lines, and delivery outlets. In some instances, the term "surface
facility" is used to distinguish those facilities other than
wells.
[0042] "Formation" refers to a body or section of geologic strata,
structure, formation or other subsurface solid or collected
material that is sufficiently distinctive and continuous with
respect to other geologic strata or characteristics that it can be
mapped, for example, by seismic techniques. A formation can be a
body of geologic strata of predominantly one type or a combination
of types, or a fraction of strata having substantially common set
of characteristics. A formation can contain one or more
hydrocarbon-bearing zones. Note that the terms formation,
hydrocarbon bearing subterranean formation, reservoir, and interval
may be used interchangeably, but may generally be used to denote
progressively smaller subsurface regions, zones, or volumes. More
specifically, a geologic formation may generally be the largest
subsurface region, a subterranean formation may generally be a
region within the geologic formation and may generally be a
hydrocarbon-bearing zone (a formation, reservoir, or interval
having oil, gas, heavy oil, and any combination thereof), and an
interval may generally refer to a sub-region or portion of a
reservoir. A hydrocarbon-bearing zone can be separated from other
hydrocarbon-bearing zones by zones of lower permeability such as
mudstones, shales, or shale-like (highly compacted) sands. In one
or more embodiments, a hydrocarbon-bearing zone may include heavy
oil in addition to sand, clay, or other porous solids.
[0043] A "fracture" is a crack, delamination, surface breakage,
separation, crushing, rubblization, or other destruction within a
geologic formation or fraction of formation not related to
foliation or cleavage in metamorphic formation, along which there
has been displacement or movement relative to an adjacent portion
of the formation. A fracture along which there has been lateral
displacement may be termed a fault. When walls of a fracture have
moved only normal to each other, the fracture may be termed a
joint. Fractures may enhance permeability of rocks greatly by
connecting pores together, and for that reason, joints and faults
may be induced mechanically in some reservoirs in order to increase
fluid flow.
[0044] "Fracturing" refers to the structural degradation of a
treatment interval, such as a subsurface shale formation, from
applied thermal or mechanical stress. Such structural degradation
generally enhances the permeability of the treatment interval to
fluids and increases the accessibility of the hydrocarbon component
to such fluids. Fracturing may also be performed by degrading rocks
in treatment intervals by chemical means. "Fracture network" refers
to a field or network of interconnecting fractures.
[0045] "Fracture gradient" refers to an equivalent fluid pressure
sufficient to create or enhance one or more fractures in the
subterranean formation. As used herein, the "fracture gradient" of
a layered formation also encompasses a parting fluid pressure
sufficient to separate one or more adjacent bedding planes in a
layered formation. It should be understood that a person of
ordinary skill in the art could perform a simple leak-off test on a
core sample of a formation to determine the fracture gradient of a
particular formation.
[0046] "Geomechanical stress" (including a change related thereto)
or similar phrase, refers generally to the forces external to
and/or interior to a formation acting upon or within such
formation, which may define a stress state, condition, or property
of a formation, zone, or other geologic strata, and/or any fluid
contained therein.
[0047] "Heat source" is any system for providing heat to at least a
portion of a formation substantially by conductive or radiative
heat transfer. For example, a heat source may include electric
heaters such as an insulated conductor, an elongated member, or a
conductor disposed in a conduit. Other heating systems may include
electric resistive heaters placed in wells, electrical induction
heaters placed in wells, circulation of hot fluids through wells,
resistively heated conductive propped fractures emanating from
wells, downhole burners, exothermic chemical reactions, and in situ
combustion. A heat source may also include systems that generate
heat by burning a fuel external to or in a formation. The systems
may be surface burners, downhole gas burners, flameless distributed
combustors, and natural gas distributed combustors. In some
embodiments, heat provided to or generated in one or more heat
sources may be supplied by other sources of energy. The other
sources of energy may directly heat a formation, or the energy may
be applied to a transfer medium that directly or indirectly heats
the formation. For example, an "electrofrac heater" may use
electrical conductive propped fractures to apply heat to the
formation. In an electrofrac heater, a formation is hydraulically
fractured and a graphite proppant is used to prop the fractures
open. An electric current may then be passed through the graphite
proppant causing it to generate heat, which heats the surrounding
formation.
[0048] "Hydraulic fracturing" is used to create single or branching
fractures that extend from the wellbore into reservoir formations
so as to stimulate the potential for production. A fracturing
fluid, typically a viscous fluid, is injected into the formation
with sufficient pressure to create and extend a fracture, and a
proppant is used to "prop" or hold open the created fracture after
the hydraulic pressure used to generate the fracture has been
released. When pumping of the treatment fluid is finished, the
fracture "closes." Loss of fluid to permeable formation results in
a reduction in fracture width until the proppant supports the
fracture faces. The fracture may be artificially held open by
injection of a proppant material. Hydraulic fractures may be
substantially horizontal in orientation, substantially vertical in
orientation, or oriented along any other plane. Generally, the
fractures tend to be vertical at greater depths, due to the
increased mass of the overburden. As used herein, fracturing may
take place in portions of a formation outside of a hydrocarbon
bearing subterranean formation in order to enhance hydrocarbon
production from the hydrocarbon bearing subterranean formation.
[0049] "Hydrocarbon production" refers to any activity associated
with extracting hydrocarbons from a well or other opening.
Hydrocarbon production normally refers to any activity conducted in
or on the well after the well is completed. Accordingly,
hydrocarbon production or extraction includes not only primary
hydrocarbon extraction but also secondary and tertiary production
techniques, such as injection of gas or liquid for increasing drive
pressure, mobilizing the hydrocarbon or treating by, for example
chemicals or hydraulic fracturing the wellbore to promote increased
flow, well servicing, well logging, and other well and wellbore
treatments.
[0050] "Hydrocarbons" are generally defined as molecules formed
primarily of carbon and hydrogen atoms such as oil and natural gas.
Hydrocarbons may also include other elements, such as, but not
limited to, halogens, metallic elements, nitrogen, oxygen, and/or
sulfur. Hydrocarbons may be produced from subterranean formations
through wells penetrating a hydrocarbon containing formation.
Hydrocarbons derived from a hydrocarbon bearing subterranean
formation may include, but are not limited to, kerogen, bitumen,
pyrobitumen, asphaltic or tar oil, crude oils, natural gases,
and/or combinations thereof. Hydrocarbons may be located within or
adjacent to mineral matrices within the earth. Matrices may
include, but are not limited to, sedimentary rock, sands,
silicilytes, carbonates, diatomites, and other porous media.
[0051] A "hydraulic fracture" is a fracture at least partially
propagated into a formation, wherein the fracture is created
through injection of pressurized fluids into the formation. While
the term "hydraulic fracture" is used, the techniques described
herein are not limited to use in hydraulic fractures. The
techniques may be suitable for use in any fractures created in any
manner considered suitable by one skilled in the art. Hydraulic
fractures may be substantially horizontal in orientation,
substantially vertical in orientation, or oriented along any other
plane. Generally, the fractures tend to be vertical at greater
depths, due to the increased mass of the overburden.
[0052] "Hydraulic fracturing" is a process used to create fractures
that extend from the wellbore into formations to stimulate the
potential for production. A fracturing fluid, typically viscous, is
generally injected into the formation with sufficient pressure, for
example, at a pressure greater than the lithostatic pressure of the
formation, to create and extend a fracture. A proppant may often be
used to "prop" or hold open the created fracture after the
hydraulic pressure used to generate the fracture has been released.
Parameters that may be useful for controlling the fracturing
process include the pressure of the hydraulic fluid, the viscosity
of the hydraulic fluid, the mass flow rate of the hydraulic fluid,
the amount of proppant, and the like.
[0053] "Imbibition" refers to the incorporation of a fracturing
fluid into a fracture face by capillary action. Imbibition may
result in decreases in permeation of a formation fluid across the
fracture face, and is known to be a form of formation damage. For
example, if the fracturing fluid is an aqueous fluid, imbibition
may result in lower transport of organic materials, such as
hydrocarbons, across the fracture face, resulting in decreased
recovery. The decrease in hydrocarbon transport may outweigh any
increases in fracture surface area resulting in no net increase in
recovery, or even a decrease in recovery, after fracturing.
[0054] "In-Situ" or "insitu" refers to a state, condition, or
property of a geologic formation, strata, zone, and/or fluids
therein, prior to changing or altering such state, condition, or
property by an action effecting the formation and/or fluids
therein. Changes to the insitu properties may be effected by
substantially any action upon the formation, such as producing or
removing fluids from a formation, injecting or introducing fluids
or other materials into a formation, stimulating a formation,
causing a collapse such as permitting a wellbore collapse or
dissolving supporting strata, removing adjacent formation or fluid,
heating or cooling the formation, or other action that effects
change in the state, condition or property of the formation. The
insitu state may or may not be the virgin or original state of the
formation, but is a relative term that may in fact merely reference
a state that exists prior to undertaking some action upon the
formation.
[0055] As used herein, "material properties" represents any number
of physical constants that reflect the behavior of a rock. Such
material properties may include, for example, Young's modulus (E),
Poisson's Ratio ( ), tensile strength, compressive strength, shear
strength, creep behavior, and other properties. The material
properties may be measured by any combinations of tests, including,
among others, a "Standard Test Method for Unconfined Compressive
Strength of Intact formation Core Specimens," ASTM D 2938-95; a
"Standard Test Method for Splitting Tensile Strength of Intact
formation Core Specimens [Brazilian Method]," ASTM D 3967-95a
Reapproved 1992; a "Standard Test Method for Determination of the
Point Load Strength Index of Rock," ASTM D 5731-95; "Standard
Practices for Preparing formation Core Specimens and Determining
Dimensional and Shape Tolerances," ASTM D 4435-01; "Standard Test
Method for Elastic Moduli of Intact formation Core Specimens in
Uniaxial Compression," ASTM D 3148-02; "Standard Test Method for
Triaxial Compressive Strength of Undrained formation Core Specimens
Without Pore Pressure Measurements," ASTM D 2664-04; "Standard Test
Method for Creep of Cylindrical Soft formation Specimens in
Uniaxial Compressions," ASTM D 4405-84, Reapproved 1989; "Standard
Test Method for Performing Laboratory Direct Shear Strength Tests
of formation Specimens Under Constant Normal Stress," ASTM D
5607-95; "Method of Test for Direct Shear Strength of formation
Core Specimen," U.S. Military formation Testing Handbook,
RTH-203-80, available at
"http://www.wes.army.mil/SL/MTC/handbook/RT/RTH/203-80.pdf" (last
accessed on Jun. 25, 2010); and "Standard Method of Test for
Multistage Triaxial Strength of Undrained formation Core Specimens
Without Pore Pressure Measurements," U.S. Military formation
Testing Handbook, available at
http://www.wes.army.mil/SL/MTC/handbook/RT/RTH/204-80.pdf" (last
accessed on Jun. 25, 2010). One of ordinary skill will recognize
that other methods of testing formation specimens may be used to
determine the physical constants used herein.
[0056] "Natural gas" refers to various compositions of raw or
treated hydrocarbon gases. Raw natural gas is primarily comprised
of light hydrocarbons such as methane, ethane, propane, butanes,
pentanes, hexanes and impurities like benzene, but may also contain
small amounts of non-hydrocarbon impurities, such as nitrogen,
hydrogen sulfide, carbon dioxide, and traces of helium, carbonyl
sulfide, various mercaptans, or water. Treated natural gas is
primarily comprised of methane and ethane, but may also contain
small percentages of heavier hydrocarbons, such as propane,
butanes, and pentanes, as well as small percentages of nitrogen and
carbon dioxide.
[0057] "Overburden" refers to the subsurface formation overlying
the formation containing one or more hydrocarbon-bearing zones (the
reservoirs). For example, overburden may include rock, shale,
mudstone, or wet/tight carbonate (such as an impermeable carbonate
without hydrocarbons). An overburden may include a
hydrocarbon-containing layer that is relatively impermeable. In
some cases, the overburden may be permeable.
[0058] "Overburden stress" refers to the load per unit area or
stress overlying an area or point of interest in the subsurface
from the weight of the overlying sediments and fluids. In one or
more embodiments, the "overburden stress" is the load per unit area
or stress overlying the hydrocarbon-bearing zone that is being
conditioned or produced according to the embodiments described. In
general, the magnitude of the overburden stress may primarily
depend on two factors: 1) the composition of the overlying
sediments and fluids, and 2) the depth of the subsurface area or
formation. Similarly, underburden refers to the subsurface
formation underneath the formation containing one or more
hydrocarbon-bearing zones (reservoirs).
[0059] "Permeability" is the capacity of a formation to transmit
fluids through the interconnected pore spaces of the rock.
Permeability may be measured using Darcy's Law: Q=(k .DELTA.P
A)/(.mu.L), where Q=flow rate (cm.sup.3/s), .DELTA.P=pressure drop
(atm) across a cylinder having a length L (cm) and a
cross-sectional area A (cm.sup.2), .mu.=fluid viscosity (cp), and
k=permeability (Darcy). The customary unit of measurement for
permeability is the millidarcy. The term "relatively permeable" is
defined, with respect to formations or portions thereof, as an
average permeability of 10 millidarcy or more (for example, 10 or
100 millidarcy). The term "relatively low permeability" is defined,
with respect to formations or portions thereof, as an average
permeability of less than about 10 millidarcy. An impermeable layer
generally has a permeability of less than about 0.1 millidarcy. By
these definitions, shale may be considered impermeable, for
example, ranging from about 0.1 millidarcy (100 microdarcy) to as
low as 0.00001 millidarcy (10 nanodarcy).
[0060] "Porosity" is defined as the ratio of the volume of pore
space to the total bulk volume of the material expressed in
percent. Although there often is an apparent close relationship
between porosity and permeability, because a highly porous
formation may be highly permeable, there is no real relationship
between the two; a formation with a high percentage of porosity may
be very impermeable because of a lack of communication between the
individual pores, capillary size of the pore space or the
morphology of structures constituting the pore space. For example,
the diatomite in one exemplary formation type, Belridge, has very
high porosity, at about 60%, but the permeability is very low, for
example, less than about 0.1 millidarcy.
[0061] "Pressure" refers to a force acting on a unit area. Pressure
is usually shown as pounds per square inch (psi). "Atmospheric
pressure" refers to the local pressure of the air. Local
atmospheric pressure is assumed to be 14.7 psia, the standard
atmospheric pressure at sea level. "Absolute pressure" (psia)
refers to the sum of the atmospheric pressure plus the gauge
pressure (psig). "Gauge pressure" (psig) refers to the pressure
measured by a gauge, which indicates only the pressure exceeding
the local atmospheric pressure (a gauge pressure of 0 psig
corresponds to an absolute pressure of 14.7 psia).
[0062] As previously mentioned, a "reservoir" or "hydrocarbon
reservoir" or "hydrocarbon bearing subterranean reservoir" is
defined as a pay or hydrocarbon bearing zone (for example,
hydrocarbon-producing zones) that includes sandstone, limestone,
chalk, coal, and some types of shale. Pay zones can vary in
thickness from less than one foot (0.3048 m) to hundreds of feet
(hundreds of m). The permeability of the reservoir formation
provides the potential for production.
[0063] "Reservoir properties" and "Reservoir property values" are
defined as quantities representing physical attributes of rocks
containing reservoir fluids. The term "reservoir properties" as
used in this application includes both measurable and descriptive
attributes. Examples of measurable reservoir property values
include impedance to P-waves, impedance to S-waves, porosity,
permeability, water saturation, and fracture density. Examples of
descriptive reservoir property values include facies, lithology
(for example, sandstone or carbonate), and
environment-of-deposition (EOD). Reservoir properties may be
populated into a reservoir framework of computational cells to
generate a reservoir model.
[0064] A "rock physics model" relates petrophysical and
production-related properties of a formation (or its constituents)
to the bulk elastic properties of the formation. Examples of
petrophysical and production-related properties may include, but
are not limited to, porosity, pore geometry, pore connectivity
volume of shale or clay, estimated overburden stress or related
data, pore pressure, fluid type and content, clay content,
mineralogy, temperature, and anisotropy and examples of bulk
elastic properties may include, but are not limited to, P-impedance
and S-impedance. A formation physics model may provide values that
may be used as a velocity model for a seismic survey.
[0065] "Shale" is a fine-grained elastic sedimentary formation with
a mean grain size of less than 0.0625 mm. Shale typically includes
laminated and fissile siltstones and claystones. These materials
may be formed from clays, quartz, and other minerals that are found
in fine-grained rocks. Non-limiting examples of shales include
Barnett, Fayetteville, and Woodford in North America. Shale has low
matrix permeability, so gas production in commercial quantities
requires fractures to provide permeability. Shale gas reservoirs
may be hydraulically fractured to create extensive artificial
fracture networks around wellbores. Horizontal drilling is often
used with shale gas wells.
[0066] "Stimulated Rock Volume" (SRV) describes a relatively large
formation volume that has experienced increased permeability and
associated hydrocarbon production potential through the use of
applied (volumetric increasing) or reduced (volumetric decreasing)
stress and strain adjusting techniques, such as but not limited to
hydraulic fracturing or other related reservoir stimulation or
stressing techniques. In one potential SRV scenario, a network of
hydraulic fractures could be in communication with fractures that
naturally occur in the formation so that the formation volume
outside of one specific hydraulic fracture experiences improved
reservoir properties.
[0067] "Strain" is the fractional change in dimension or volume of
the deformation induced in the material by applying stress. For
most materials, strain is directly proportional to the stress, and
depends upon the flexibility of the material. This relationship
between strain and stress is known as Hooke's law, and is presented
by the formula; =E{tilde over ( )}
[0068] "Stress" is the application of force to a material, such as
a through a hydraulic fluid used to fracture a formation. Stress
can be measured as force per unit area. Thus, applying a
longitudinal force f to a cross-sectional area S of a strength
member yields a stress which is given by f/S.
[0069] "Substantial" when used in reference to a quantity or amount
of a material, or a specific characteristic thereof, refers to an
amount that is sufficient to provide an effect that the material or
characteristic was intended to provide. The exact degree of
deviation allowable may in some cases depend on the specific
context.
[0070] The force f could be compressional, leading to
longitudinally compressing the strength member, or tensional,
leading to longitudinally extending the strength member. In the
case of a strength member in a seismic section, the force will
typically be tension.
[0071] "Thermal fractures" are fractures created in a formation
caused by expansion or contraction of a portion of the formation or
fluids within the formation. The expansion or contraction may be
caused by changing the temperature of the formation or fluids
within the formation. The change in temperature may change the
pressure of fluids within the formation, resulting in the
fracturing. Thermal fractures may propagate into or form in
neighboring regions significantly cooler than the heated zone.
[0072] "Tight oil" is used to reference formations with relatively
low matrix permeability and/or porosity where liquid hydrocarbon
production potential exists. In these formations, liquid
hydrocarbon production may also include natural gas condensate.
[0073] "Underburden" refers to the subsurface formation below or
farther downhole than the formation containing one or more
hydrocarbon-bearing zones (the reservoirs). For example,
underburden may include rock, shale, mudstone, or wet/tight
carbonate (such as an impermeable carbonate without hydrocarbons).
An underburden may include a hydrocarbon-containing layer that is
relatively impermeable. In some cases, the underburden may be
permeable. The underburden may be a formation that is distinct from
the HC-bearing formation or may be a selected fraction within a
common formation shared between the underburden portion and the
HC-bearing portion. Intermediate layers may also reside between the
underburden layer and the HC-bearing zone.
[0074] The "Young's modulus" of a formation or rock sample is the
stiffness of the formation sample, defined as the amount of axial
load (or stress) sufficient to make the formation sample undergo a
unit amount of deformation (or strain) in the direction of load
application, when deformed within its elastic limit. The higher the
Young's modulus, the harder it is to deform. It is an elastic
property of the material and is usually denoted by the English
alphabet E having units the same as that of stress.
Overview
[0075] Exemplary embodiments of the present techniques provide
techniques for fracture stimulation of reservoirs, or portions of a
reservoir, on a large scale, up to stimulating an entire reservoir
at once. The techniques may be used with any type of hydrocarbon
bearing subterranean formation, such as oil, gas, or mixed
reservoirs and may also be used to fracture other types of
formations, such as formations used for the production of
geothermal energy. In exemplary embodiments, the techniques can be
used to enhance production of natural gas from unconventional
(i.e., low permeability) gas reservoirs.
[0076] The stimulation is generally based on changes to formations
other than the target formation itself, for example, by changing a
volume of a proximate formation, which places a stress on the
target formation. The applied stress can cause delamination of
layers and other forms of non-hydraulic fracturing in the target
formation, leading to the formation of cracks over a broad area.
The cracks or fractures may result from a residual or "hysteresis"
displacement of the formation components due to the strain
displacement that remains, both while the stress is applied and
after the stress is relaxed. The hysteresis effect results from the
failure of the crack or fracture to heal completely, in the event
further fracturing happens and/or the applied stress is reduced.
Thereby, the permeability may be at least somewhat permanently
improved. Ideally, the stress (applied initially in the zone
proximate and then translated or otherwise promulgated into the
hydrocarbon containing subsurface formation) creates some residual
permeability in at least a portion of the targeted subterranean
formation. The treatment duration may range from seconds, such as
if explosives are used, to months, such as if waste tailings are
used to fracture and prop open the fractures in the zone proximate
formation. The ultimate goal is to effect fracturing within the
near, hydrocarbon-bearing subterranean formation.
[0077] At the delaminated fractures, the formation surfaces or rock
strata within the formation can be destroyed, forming a rubble
layer or interface between the surfaces, or the formation surfaces
offset from their original position, forming open apertures between
the surfaces. If the volume changes in the proximate formation are
repeated, the rubblization may be increased, forming channels
through which natural gas, other hydrocarbons, or heated water, may
be harvested. The use of an applied mechanical stress may be
considered counterintuitive; as such stress would normally tend to
close fractures or cleats, leading to lower production. However, in
exemplary embodiments, the application of stress may provide
increased permeability and production rates, due to delamination
along weak layers and rubblization within the target reservoir, as
mentioned above and discussed in further detail below.
[0078] FIG. 1 is a diagram of a hydraulic fracturing process 100.
The traditional method of fracture stimulation utilizes "hydraulic"
pressure pumping and is a proven technology that has been used
since the 1940s in more than 1 million wells in the United States
to help produce oil and natural gas. In typical oilfield
operations, the technology involves pumping a water-sand mixture
into subterranean layers where the oil or gas is trapped. The
pressure of the water creates tiny fissures or fractures in the
rock. After pumping is finished the sand props open the fractures,
allowing the oil or gas to escape from the HC-bearing formation and
flow to a wellbore.
[0079] For example, a well 102 may be drilled through an overburden
104 to a hydrocarbon bearing subterranean formation 106. Although
the well 102 may penetrate through the hydrocarbon bearing
subterranean formation 106 and into the underburden 108,
perforations 110 in the well 102 can direct fluids to and from the
hydrocarbon bearing subterranean formation 106. The hydraulic
fracturing process 100 may utilize an extensive amount of equipment
at the well site. This equipment may include fluid storage tanks
112 to hold the fracturing fluid, and blenders 114 to blend the
fracturing fluid with other materials, such as proppant 116 and
other chemical additives, forming a low pressure slurry. The low
pressure slurry 118 may be run through a treater manifold 120,
which may use pumps 122 to adjust flow rates, pressures, and the
like, creating a high pressure slurry 124, which can be pumped down
the well 102 to fracture the rocks in the hydrocarbon bearing
subterranean formation 106. A mobile command center 126 may be used
to control the fracturing process.
[0080] The goal of hydraulic fracture stimulation is to create a
highly-conductive fracture zone 128 by engineering subsurface
stress conditions to induce pressure parting of the formation in
the hydrocarbon bearing subterranean formation 106. This is
generally performed by injecting fluids with a high permeability
proppant 116, such as sand, into the hydrocarbon bearing
subterranean formation 106 to overcome "in-situ" stresses and
hydraulically-fracture the reservoir rock. The fracture zone 128
may be considered a network or "cloud" of fractures generally
radiating out from the well 102. Depending on the depth of the
hydrocarbon bearing subterranean formation 106, the fractures may
often be predominately perpendicular to the bedding planes, e.g.,
vertical within the subsurface.
[0081] After the fracturing process 100 is completed, the treating
fluids are flowed back to minimize formation damage. For example,
contact with the fracturing fluids may result in imbibement of the
fluids by pores in the hydrocarbon bearing subterranean formation
106, which may actually lower the productivity of the reservoir.
Further, a carefully controlled flowback may ensure proper fracture
closure, trapping the proppant 116 in the fractures and holding
them open. Stimulation is generally effective at near-well scale,
for example, in which the fracture dimensions are in the 100s of
feet. Treating and production are often conducted in the same
interval, e.g., the portion of the hydrocarbon bearing subterranean
formation 106 reached by the well 102. The fracturing process 100
may use significant amounts of freshwater and proppant materials.
The orientation of the fractures is controlled by the local
stresses in the hydrocarbon bearing subterranean formation 106 as
discussed further with respect to FIG. 2.
[0082] FIG. 2 is a drawing of a local stress state 200 for an
element 202 in a hydrocarbon bearing subterranean formation. The
state of stress in the earth is defined by the mass of the
overburden, the pressure in the pores of the rock, the tectonic
stresses governing boundary conditions, and the basic mechanical
properties of the rock, such as Young's modulus or stiffness. The
in-situ earth stresses determine the predominant orientation of
hydraulic fractures. The presence of natural fractures, the
configuration of the completion itself, and the characteristics of
the treating fluids may alter the earth stresses near the well and
thereby influence growth of hydraulic fractures for a relatively
short distance away from the well.
[0083] The earth stresses can be divided into three principal
stresses where .sigma..sub.z is the vertical stress in this
drawing, .sigma..sub.max is the maximum horizontal stress, while
.sigma..sub.min is the minimum horizontal stress, where
.sigma..sub.z>.sigma..sub.max>.sigma..sub.min. However,
depending on geologic conditions, the vertical stress could be the
intermediate (.sigma..sub.max) or minimum stress (.sigma..sub.min).
These stresses are normally compressive and vary in magnitude
throughout the reservoir, particularly in the vertical direction
and from layer to layer. The magnitude and direction of the
principal stresses are important because they control the pressure
required to create and propagate a fracture in the reservoir, the
shape of the fracture, the vertical extent of the fracture, the
direction of the fracture, and the stresses trying to crush or
embed the propping agent during production. Fractures in a
horizontal direction, e.g., perpendicular to a vertically drilled
well or parallel to a horizontally drilled well, may be more
effective at conducting hydrocarbons back to the well for
production. However, in deeper wells, the vertical stresses may
often force fractures to be predominately vertical, e.g.,
perpendicular to a horizontally drilled wellbores. As pressure on
the hydrocarbon bearing subterranean formation drops, for example,
during production, further fracturing may be horizontal. This is
discussed in further detail with respect to FIG. 9.
[0084] In other exemplary aspects or descriptions, the earth
stresses can be divided into three principal stresses where
.sigma..sub.v is the vertical stress, .sigma..sup.H.sub.max is the
maximum horizontal stress (similar to .sigma..sub.max in the
paragraph above) and .sigma..sup.h.sub.min is the minimum
horizontal stress. Typically, these stresses are normally
compressive and vary in magnitude throughout the reservoir,
particularly in the vertical direction and from layer to layer. The
vertical stress .sigma..sub.v, is typically the most compressive
stress, i.e.,
.sigma..sub.v>.sigma..sup.H.sub.max>.sigma..sup.H.sub.min.
However, depending on geologic conditions, the vertical stress
could be less compressive than the maximum horizontal stress,
.sigma..sup.H.sub.max, or than the minimum horizontal stress,
.sigma..sup.h.sub.min.
[0085] Fractures in a horizontal direction, e.g., perpendicular to
a vertically drilled well or parallel to a horizontally drilled
well, may be more effective at conducting hydrocarbons back to the
well for production. In deeper wells, the higher vertical stress
from the overburden may often force fractures to be predominately
vertical, e.g., perpendicular to a horizontally drilled
wellbore.
[0086] FIG. 3 is a drawing of a first mode (mode I) 300 of fracture
formation, commonly resulting from a standard hydraulic fracturing
process. Fractures generally propagate in one or more of three
primary modes as discussed with respect to FIGS. 3 and 7. While,
each mode is capable of propagating a fracture, standard hydraulic
fracture stimulation predominantly utilizes mode I 300, resulting
from "direct" fluid pressure parting of the rock. In mode I 300,
the pressure of the hydraulic fracturing fluid either creates
fractures or advances pre-existing fractures. The fractures are
propagated by tensile breaking of the formation at the crack
tip.
[0087] As noted herein, the fractures may often be nearly vertical
and approximately perpendicular to bedding planes. At shallow
depths, the fractures produced may be horizontal, in which case
they likely will be parallel to bedding planes. In standard
hydraulic fracturing, the hydraulic pressure and fluids directly
contact the formation being fractured or treated. Application of
the traditional hydraulic fracturing method to unconventional
hydrocarbon resources, such as tight gas or shale gas reservoirs,
requires both large numbers of wells and large numbers of fracture
treatments in each well. These requirements are largely driven by
the relatively small "effective" area that is created during the
hydraulic fracturing process due to inherent limitations in the
treating fluids, proppants, reservoir stratigraphy, and in-situ
stresses. In exemplary embodiments of the present techniques, a new
fracturing concept can be used to achieve massive fracture
stimulation of wells, particularly for unconventional hydrocarbon
resources. In these embodiments, a volumetric increase in a layer
adjacent to the hydrocarbon bearing subterranean formation can be
used to place a stress on the reservoir, leading to fracturing in
the reservoir.
[0088] FIG. 4 is an exemplified drawing of a well treatment system
such as a hydraulic fracturing system 400, wherein a zone 402 below
a hydrocarbon bearing subterranean formation 404 is subjected to a
volumetric expansion 406, which can place stress on the hydrocarbon
bearing subterranean formation 404 leading to fracturing. The
techniques are not limited to a hydrocarbon bearing subterranean
formation 404, but may be used in any number of situations where
fracturing a formation layer would be useful, such as in the
production of geothermal energy. In the hydraulic fracturing system
400, all like units are as discussed with respect to FIG. 1. In
this exemplary embodiment, the drilling and production wastes from
the field may be used for the hydraulic fracturing of the zone 402,
lowering the requirements for freshwater over standard hydraulic
fracturing. Further, the drilling cuttings may be used to provide a
proppant to maintain the fractures open in the zone 402. The
present techniques are not limited to hydraulic fracturing of the
zone 402. In embodiments, thermal expansion may be used to create
the volumetric expansion 406. Further, a pressurized liquid may be
used to cause the volumetric expansion 406 of the zone 402 without
fracturing. The volumetric expansion 406 may be cycled by
successive thermal heating and cooling cycles. In other
embodiments, a chemical treatment may be applied in the zone 402 to
create an area of cavitation. The present techniques are not
limited to a chemical treatment of the zone 402. In embodiments,
the volumetric contraction 406 may be provided through production
of fluids from non-hydrocarbon productive zone 402 to create
subsidence in both the non-hydrocarbon-bearing zone and in the
adjacent hydrocarbon bearing subterranean formation 404, thereby
creating a network of conductive fractures in both zones, including
any intermediate zones, such that hydrocarbon can flow from the
HC-bearing reservoir to the non-hydrocarbon bearing zone and
finally to the wellbore. In some embodiments, the network of
conductive fractures may facilitate production of the hydrocarbons
directly from the HC-bearing zone directly to the wellbore or
another wellbore that is separate from the wellbore used for the
treatment process. Further, a borehole could be drilled in the zone
402 to induce the volumetric contraction 406. The volumetric
contraction 406 may be enhanced by alternately injecting (for
example, hours, days, weeks, months, even years) and then producing
fluid in successive cycles.
[0089] In some embodiments, the formation layers of interest are
mechanically damaged or "delaminated," for example, by arching, or
bending flexure, of the hydrocarbon bearing subterranean formation
404. The method used to treat the hydrocarbon bearing subterranean
formation 404 would need to create the stress state to impose
delamination fracturing along preferred layers of interest. This
may occur from dilating, enlarging, or uplifting formations in the
zone 402 from below. The delamination fractures may be created
without pressurizing the fracture surfaces of the hydrocarbon
bearing subterranean formation 404 with treating fluids. As
stimulation fluids do not need to contact the surfaces of the
formation, the hydrocarbon bearing subterranean formation 404 may
not be damaged by imbibement of the treating fluids. The
stimulation may be effective at reservoir scale, i.e., the fracture
dimensions may be on the order of 1000s of feet. Further, the
treating and the production may be conducted in different
intervals, using the same or separate wells.
[0090] FIG. 5 is a block diagram of a method 500 for stimulation of
a hydrocarbon bearing subterranean formation by treating a
formation outside of the reservoir. The method 500 begins at block
502, with the drilling and completing of a well to the treatment
interval. The treatment interval may be a formation under the
hydrocarbon bearing subterranean formation, as generally discussed
with respect to FIG. 4. In other embodiments, the treatment
interval may be beside or above the hydrocarbon bearing
subterranean formation, for example, if the hydrocarbon bearing
subterranean formation is in a deviated formation. At block 504,
the treatment interval may be treated. For example, a chemical,
thermal, physical, biological, and/or other treatment may be
injected or introduced into the treatment interval. For further
example, fracturing fluids may be injected into the treatment
interval. The fracturing fluids may or may not include solids for
proppants, such as crushed drilling cuttings from wells. In some
embodiments, the treatment may be performed by successively
inflating and deflating the treatment interval to cause
rubblization of the hydrocarbon bearing subterranean formation. The
treatment may be performed by reducing underburden support and/or
pressure and thereafter providing an expansive force such as
pressure or a heat source into the treatment interval to cause
inflation of the treatment interval such as by thermal expansion.
Such deflation and inflation may be cyclically performed.
[0091] At block 506, a production well is completed to the
reservoir to produce hydrocarbons. The production well may be
drilled after stimulation from the treating well, thereby reducing
the potential for subsequent well integrity or reliability issues.
In embodiments, the production well may be the same as the
treatment well, for example, by creating perforations in the well
at the interval of the hydrocarbon bearing subterranean formation,
or by drilling production wells from the treatment well. At block
508, hydrocarbons may be produced from the production well. It will
be clear that the techniques described herein are not limited to
the production of hydrocarbons, but may be used in other
circumstances where a subterranean formation is fractured to aid in
the production of fluid. For example, in embodiments, the
techniques may be used to fracture a hot dry formation layer for
use in geothermal energy production. Water or other fluids may then
be circulated through the fractures, collected in a production
well, and returned to the surface for harvesting heat energy. The
wells are not limited to the conformations discussed above. In
embodiments, various treating, and producing well patterns and
operational schemes may be considered to concurrently optimize
reservoir stimulation, gas production, waste disposal, and well
operability.
[0092] FIG. 6 is a more detailed schematic view of a delamination
fracture stimulation 600 showing the physics that may lead to
delamination fracturing. A well 602 may be drilled through a
hydrocarbon bearing subterranean formation 604, and into a
treatment interval or zone 606 below the hydrocarbon bearing
subterranean formation 604. The treatment interval or zone 606 does
not have to be adjacent to the hydrocarbon bearing subterranean
formation 604, but may have one or more intervening layers 608.
These layers 608 may lower the chance that a treatment fluid, if
used, will leak into the hydrocarbon bearing subterranean formation
604. Further, if waste tailing are used as proppants, the layers
608 may assist in fixing the tailings in place, lowering the
probability that material may migrate into the hydrocarbon bearing
subterranean formation 604 or other locations, such as
aquifers.
[0093] As the treatment progresses, a volumetric expansion 610
occurs in the treatment interval or zone 606, which presses upwards
on the layers 608, forming an arch or dome 612 in the hydrocarbon
bearing subterranean formation 604. In the embodiment shown, fluids
and/or particulate solids are injected into the treatment interval
or zone 606 to dilate, uplift, "arch," and shear fracture the
hydrocarbon bearing subterranean formation 604. The distance, or
vertical distance, between the zone 606 and the hydrocarbon bearing
subterranean formation 604 may control the size of the area over
which the treatment affects the hydrocarbon bearing subterranean
formation 604. A layer that is further from the hydrocarbon bearing
subterranean formation 604 may affect a wider area, but with a
lower total movement. For example, if a treatment of a zone 606
located around 50 m under the hydrocarbon bearing subterranean
formation 604 caused a vertical motion of about 2 cm over a
distance of about 500 m, treatment of a zone 606 located about 100
m under the hydrocarbon bearing subterranean formation 606, using
the same contaction and/or expansion conditions, may cause a
vertical motion of about 1 cm over a horizontal distance of about
1000 m. In addition to separation distance, the choice of the
treatment zone 606 may be made on the basis of formation
properties, both in the zone 606 and in the hydrocarbon bearing
subterranean formation 604.
[0094] In addition to separation distance, the choice of the
treatment zone 606 may be made on the basis of formation
properties, both in the zone 606 and in the hydrocarbon bearing
subterranean formation 604. A relatively impermeable formation may
be useful for treatment using hydraulic fracturing techniques, as
the zone 606 may have lower leak-off, making the treatment more
efficient. If waste tailings are going to be used, this may be less
of an issue, as the zone 606 may be propped open and expanded, even
after pressure has leaked off. If thermal expansion is going to be
used, the zone 606 may be selected to have a higher coefficient of
thermal expansion than other surrounding zones.
[0095] In addition to the properties of the formation within the
zone 606, the properties of the material in the hydrocarbon bearing
subterranean formation 604 may also influence the choice of
expansion techniques and location. For example, if the hydrocarbon
bearing subterranean formation 604 is shale, a slow expansion may
not open sufficient cracks, as a ductile shale may have enough
plastic deformation to reseal the cracks. Thus, an explosive
deformation may cause a fast enough deformation, such as on the
order of seconds, to shatter the shale without plastic flow
resealing the cracks. In this case, the zone 606 may be selected to
have a hard rock, such as granite, that can transfer the energy of
expansion to the hydrocarbon bearing subterranean formation
604.
[0096] A hydrocarbon bearing subterranean formation 604 may often
have weaker layers 614, or even inherent fracture planes 616. The
arching can cause shear stress in the hydrocarbon bearing
subterranean formation 604, leading to sliding or breaking of the
hydrocarbon bearing subterranean formation 604 along these layers
614 and fracture planes 616, as indicated by the arrows 618,
creating delamination fractures 620. Thus, the delamination
fracture stimulation 600 can create a highly-conductive
multi-fracture/dual-porosity reservoir system by delaminating
formation layers, parting formation within layers, and rubblizing
the formation "in-situ." The injection operations may also create
relative movement or displacement between the fracture surfaces
along the layers 614 and fracture planes 616 to achieve fracture
conductivity, for example, by creating delamination fractures 620
that contain enhanced permeability formation debris. Vertical
fractures 622 may also be created during the delamination process.
The control of stresses in the formation may be used to control the
direction of the fractures, as discussed with respect to FIGS. 9
and 10.
[0097] In addition to the injection of fluids, embodiments may
induce delamination fractures in the hydrocarbon bearing
subterranean formation 604 using in-situ techniques, such as
thermal heating, explosive detonations, and the like to enlarge the
volume of the treatment interval or zone 606 and thereby increase
the stresses at the target formation intervals such that
shear-dominated fractures delaminate along, and possibly normal to,
the bedding planes.
[0098] The flow conductivity of the delamination fractures may be
enhanced by cyclically inflating and deflating the treatment
interval or zone 606 such that the delaminated formations
"rubblize" due to frictional contact and relative sliding motion
between formation surfaces, creating an in-situ propped bed of
failed formation material. This is discussed further with respect
to FIG. 8.
[0099] In contrast with the direct hydraulic fracture stimulation
of a hydrocarbon bearing subterranean formation 604, the
delamination fracture stimulation 600 minimizes direct fluid
contact with the formation fracture face, thereby reducing the
potential for formation damage and the need for flowback clean-up.
Further, fracture "conductivity" is created in-situ over the full
fracture dimensions, thereby enhancing productivity and eliminating
the need for transporting proppants. The fractures 620 may also
extend beyond geologic drainage boundaries, such as faults,
pinchouts and the like, reducing the number of wells required for
economic development. The fracture delamination may be created
using "waste disposal" products, such as drill cuttings, produced
brines, and the like, to enhance volumetric strain, reducing the
need for customized fracturing formulations and large volumes of
freshwater. The fracture delamination or other permeability
improvement also may be created with non-aqueous techniques to
enhance volumetric strain, reducing the need for customized
fracturing formulations and large volumes of freshwater.
[0100] In summary, the delamination fracture stimulation 600 is
based on three physical components, including delamination,
rubblization, and stress control. The relative importance of each
of these components is dependent on the parameters of the
particular application, for example, the depths of treatment
interval or zone 606 and hydrocarbon bearing subterranean formation
604, the thicknesses of each interval 604 and 606, the formation
properties, the pore pressures, the in-situ stress environments,
and the like. These parameters are discussed in more detail with
respect to FIGS. 7-10.
[0101] FIG. 7 is a drawing 700 of two modes of fracture formation
that may participate in delamination fracture stimulation as
discussed herein. Both of these modes are based on shearing the
rock, rather than tensile parting of the rock. An in-plane shear
mode 702 develops a fracture 704 that is aligned (i.e., in the same
two-dimensional plane) with the applied shear stress 706. The
in-plane shear mode 702, also termed mode II, may develop as an
arch or bend that distorts a reservoir. Further, the in-plane shear
mode 702 may develop horizontal fractures, for example, as some
layers 708 are placed under compressive stress, while other layers
710 are released from compressive stress. Additional mode I 300
"non-hydraulic" tensile fractures also may be incurred from stress
arching of the reservoir. Another mode of fracture formation is an
anti-plane shear mode 712, also termed mode III. Similarly, the
anti-plane shear mode 712 develops a fracture 714 that also is
aligned in the same two-dimensional plane with the applied shear
stress 716. This mode may also participate in both vertical and
horizontal fractures as adjacent layers are moved in opposite
directions. In embodiments, both mode II 702, and mode III 712, or
any combinations thereof, may propagate damage and fractures
perpendicular or parallel to bedding planes through the use of a
volumetric increase in layers outside of a reservoir interval. The
shearing modes may cause material to disaggregate.
[0102] FIG. 8 is a drawing of rubblization 800 during shearing 802
at a fracture boundary 804. Direct hydraulic fracturing of a
reservoir generally causes tensile fracturing of reservoir rocks as
discussed with respect mode I shown in FIG. 3. In contrast, the
shearing 802 that takes place in embodiments, as discussed with
respect to FIG. 7, can force formation surfaces to slide against
each other at a fracture boundary 804. Frictional engagement of
features on the surfaces may cause the formation to break, leading
to the formation of a rubblized layer within the fracture boundary
804.
[0103] As mentioned previously, the flow conductivity of
delamination fractures may be enhanced by cycling the induced
flexures such that the delaminated formations "rubblize" at the
fracture boundaries 804 due to frictional contact and relative
movement between formation surfaces. This process may create a
propped bed of failed formation material in-situ. Based on
measurements of formation debris fields created during movements of
faults, the thickness of the rubblized zone adjacent to the
delamination fractures may up to about 20% of the cumulative linear
or transverse movement of the fracture surfaces. Although the
amount of formation debris created may be lower with each
subsequent cycle, significant porosity may be created in fracture
debris zones through the cyclic movement. The failed formation is
referred to herein as Cyclic Rubblized Material ("CRM"). CRM
results in secondary permeability, i.e., dual porosity. The cycling
of the induced flexures may also relieve stress in the hydrocarbon
bearing subterranean formation, which may allow the fracture planes
to rotate from vertical to horizontal, as discussed with respect to
FIG. 9.
[0104] FIG. 9 is a drawing of an azimuthal rotation 900 of fracture
planes 902 within a formation that may occur as a result of cyclic
treatment of the formation. The in-situ earth stresses determine
the predominant orientation of hydraulic fractures. At shallow
depths, hydraulic fractures generally are horizontal and easily
create arching, uplift and delamination fractures in formation
layers above. However, at deeper depths, hydraulic fractures
generally are vertical and the horizontal stresses must be
increased to locally re-orient hydraulic fractures.
[0105] As discussed above with respect to FIG. 2, the earth
stresses can be divided into three principal stresses. In this
case, .sigma..sub.z is the vertical overburden stress and is
initially the highest stress in the system. Further,
.sigma..sub.max is the maximum horizontal stress, while
.sigma..sub.min is the minimum horizontal stress, where
.sigma..sub.v>.sigma..sub.max>.sigma..sub.min. Although, at
all depths, injection of fluids creates volumetric increases due to
pore dilation or formation thermal expansion, the initial fracture
plane 904 that forms with the treatment zone may be vertical, which
may not place an effective amount of stress on the hydrocarbon
bearing subterranean formation. Specially engineered stress
conditions may shift the position of the overburden stress to the
intermediate (.sigma..sub.min) or minimum stress (.sigma..sub.min),
especially in regions near the well.
[0106] As a result, the axis of each successive fracture plane 902
in a cyclic fracturing process may be slightly shifted or rotated
from the last fracture plane 902, as indicated by an arrow 906.
This may continue until a final fracture plane 908 may be
horizontal. Fracture re-orientation is dependent on the
characteristics of the pumping treatment (i.e., fluid rheology,
temperature, pressure, rate, solids content, treatment duration,
shut-down schedule), and generally occurs initially about the
"azimuth" axis and subsequently about the "inclination" axis until
turning horizontal.
[0107] FIG. 10 is a drawing of a delamination fracturing process
1000 illustrating the use of a separate production well 1002 and
treatment well 1004. The techniques described herein are not
limited to using a single well for both treatment and production.
In some embodiments, the treatment interval 1006 may be accessed by
one or more treatment wells 1004 other than the production well
1002 accessing the reservoir interval 1008. Furthermore, more than
one treatment well 1004 may be utilized to achieve a desired degree
of stimulation in a production well 1002. Similarly, more than one
production well 1002 may be utilized for a single treatment well
1004. Further, various combinations of treatment wells 1004 and
production wells 1002 may be located in sufficient proximity to
create synergistic enhancement in their interactions.
[0108] To recap, in one embodiment, the inventive methods include a
method for fracturing a subterranean formation, comprising applying
stress in a zone proximate to the subterranean formation to
indirectly translate a mechanical stress to the subterranean
formation and effect a permeability increase within the
subterranean formation. A single wellbore may be used to reach both
the zone proximate and the hydrocarbon bearing subterranean
formation, or separate wellbore may be used for access to each of
the zone proximate and the subterranean formation. Similarly, a set
of wells may be used for application of the principles and methods
disclosed and provided herein, such as in a field-wide plan that
utilizes numerous wellbores to effect the techniques provided
herein. The inventive methods and systems provided herein may also
be applied using any of a variety of wellbore configurations, such
as substantially vertical wells, horizontal wells, multi-branch
wells, deviated wellbores, and combinations thereof. Similarly, the
zone proximate and hydrocarbon bearing subterranean formation may
be substantially parallel or coplanar with respect to each other,
or situated in non-parallel planes, and each may comprise a single
geologic formation, zone, lens, or structure, or multiple
formations, zones, lenses, or structures. The zone proximate and
hydrocarbon bearing subterranean formation may also be oriented
substantially horizontal, vertical, deviated, folded, originally
arched, faulted, or irregularly positioned with respect to the
wellbore and each other.
[0109] In many embodiments, the desired permeability increase is
effected by creation of a fracture network in the subterranean
formation, such as by delamination fracturing during uplifting,
down-folding or other affected movement of the subterranean
formation. The desired permeability may also be the result of other
types of fracturing, but is noted that for simplification purposes,
all such fracturing and displacements may be referred to herein
generally as fracturing.
[0110] The volumetric increase in the zone proximate is created by
introducing a stress-inducing force into the zone proximate, such
as via hydraulic fluid, explosively generated gases or pressure,
thermal expansion, proppant or cuttings introduction, or other
means of effecting such forces. The introduced force may be
residual and long lasting or maintained such as via hydraulic fluid
introduction, or short in duration such as via explosives. Either
such action may introduce residual volume increases, even though at
least a portion of the volume increase may be lost when the force
is removed. The action in the zone proximate is then translated or
transferred into the objective formation, the subterranean
formation, whereby a fracture or rubblization network is created
within the subterranean formation.
[0111] In some embodiments, stress may be introduced into the zone
proximate in the form of, or so as to effect a reduction in, a
reduction of structural support within the zone proximate that is
then translated into at least a partially corresponding reduction
in stability in the hydrocarbon bearing subterranean formation,
resulting in creation of a fracture or rubblization network within
the subterranean formation. Examples of effecting a stress
reduction in the zone proximate may include freshwater dissolution
of salt from a zone proximate, production of water or other fluids
from a zone proximate to reduce structural support in the
subterranean formation, chemical dissolution of the rock material
within the zone proximate, physical removal of portion of the zone
proximate, such as via a network of relatively large or underreamed
wellbores within the zone proximate, and similar actions or
treatments to reduce structural strength of the zone proximate with
respect to the in-situ, pre-treatment, or pre-action strength. In
some embodiments, application and removal of the stress and strain
on the zone proximate may be cycled to cause subsequent
rubblization and fracturing within the subterranean formation.
[0112] As discussed in the above paragraphs, applying stress
changes to the zone proximate may cause the zone proximate to
either arch (expand, bow, collapse, settle, or otherwise displace
or experience growth or reduction in volume, with the effect of
such action generally being most prominent in the vicinity of the
wellbore or point of application or introduction, and then
radiating or diffusing outwardly from the point of such application
or introduction) toward or away from the subterranean formation,
whereby the subterranean formation may arch compliantly as a result
of such actions in the zone proximate and as translated through any
intermediate formations. Stated differently, the applied stress in
the zone proximate produces a stress reduction or increase in the
in-situ or pre action stress level in the zone proximate, producing
strain in the zone proximate, and enables at least a portion (the
affected portion) of the subterranean formation to arch toward or
away from, as appropriate, at least a portion of the zone
proximate, producing a fracture (including rubblization) network in
at least a portion of the arched or affected portion of the
subterranean formation.
[0113] It is noted that the techniques and methods disclosed herein
are described generally from two different standpoints, although
both are closely related. In one standpoint, the techniques are
described in terms of creating or effecting "volumetric changes"
(increase or decrease, or both) in the zone proximate and/or in the
subterranean formation. As discussed herein, many of the methods
used to accomplish the objectives and techniques disclosed herein
(e.g., to fracture, rubblize, delaminate a geologic formation
objective to create improved permeability within a hydrocarbon or
other reservoir or formation), may effect a volumetric change in
such formations or zones, relative to an insitu or pre-treatment
state. From another standpoint, the methods herein are described in
terms of altering the geomechanical stresses of a formation
(including external and/or internal stresses), such alterations
including volumetric changes, but also including dislocation,
displacement, strain changes, and/or fracturing of a zone proximate
or subterranean formation, without substantial volumetric change
therein, but which otherwise none-the-less effect translation of
force, stress, and/or energy (either applied or reduced, as
compared to pretreatment levels) from a zone proximate to an
objective subterranean formation, The common steps include,
generally, treating a zone proximate to effect a stress change
therein or thereupon, to effect permeability increases in a
hydrocarbon bearing subterranean formation. Both such descriptions
are within the scope of the present inventive methods and
techniques.
[0114] As discussed herein, embodiments of the present techniques
can increase well productivity, lessen environmental impact,
enhance well integrity & reliability, and improve well
utilization and hydrocarbon recovery. Further, production rates and
the recovery factor may be enhanced by cyclic "rubblization" over
the full formation thickness. In contrast to hydraulic fracturing,
which is generally halted by geological drainage boundaries, such
as faults and pinchouts, delamination fractures may extend beyond
geologic drainage boundaries, thereby reducing the number of wells
and associated environmental footprint required for economic
development. For example, the delamination may cover an area of
about nine times the area of the volumetric expansion.
[0115] Still other embodiments of the claimed subject matter may
include:
[0116] A. A method (500) for fracturing a subterranean formation
(404, 604), comprising causing (504) a volumetric increase (406,
610) in a zone (402, 606) proximate to the subterranean formation
(404, 604) so as to apply a mechanical stress to the subterranean
formation (404, 604).
[0117] B. The method of paragraph 1, wherein the zone (402, 606) is
below the subterranean formation (404, 604).
[0118] C. The method of paragraph 1, wherein the mechanical stress
is applied to only a portion of the zone (402, 604) so as to create
a bending motion in the subterranean formation (404, 604) and cause
fractures (614, 620, 622) to form through delamination (618).
[0119] D. The method of paragraph 1, further comprising:
[0120] reversing the volumetric increase (406, 610); and
[0121] repeating the volumetric increase (406, 610) for one or more
cycles to cause rubblization (800) along a delaminated joint
(804).
[0122] E. The method of paragraph 1, wherein the subterranean
formation (404, 604) comprises a hydrocarbon formation.
[0123] F. The method of paragraph 1, wherein creating the
volumetric increase (406, 610) comprises pumping a fracturing fluid
into the zone (402, 604).
[0124] G. The method of paragraph F, wherein the fracturing fluid
comprises a suspension of a proppant.
[0125] H. The method of paragraph G, wherein the proppant comprises
waste product tailings.
[0126] I. The method of paragraph 1, wherein creating the
volumetric increase (406, 610) comprises thermally expanding the
zone (402, 604).
[0127] J. A hydrocarbon production system (400), comprising:
[0128] a hydrocarbon bearing subterranean formation (404);
[0129] a zone (402) proximate to the hydrocarbon bearing
subterranean formation (404);
[0130] a stimulation well (102) drilled to the zone (402); and
[0131] a stimulation system configured to create a volumetric
increase (406) in the zone (402).
[0132] K. The hydrocarbon production system of paragraph J, wherein
the hydrocarbon bearing subterranean formation (404) comprises an
unconventional gas layer.
[0133] L. The hydrocarbon production system of paragraph J, wherein
the zone (402) comprises a formation layer in an underburden.
[0134] M. The hydrocarbon production system of paragraph J,
comprising a production well drilled into the hydrocarbon bearing
subterranean formation (404).
[0135] N. The hydrocarbon production system of paragraph J,
comprising a production well drilled into the hydrocarbon bearing
subterranean formation (404) from the stimulation well (102).
[0136] Still other embodiments may include the methods disclosed in
the following paragraphs:
[0137] 1. A method for fracturing a subterranean formation,
comprising applying stress in a zone proximate to the subterranean
formation to indirectly translate a mechanical stress to the
subterranean formation and effect a permeability increase within
the subterranean formation.
[0138] 2. The method of paragraph 1, wherein the permeability
increase is effected by creation of a fracture network in the
subterranean formation.
[0139] 3. The method of paragraph 1, wherein the applied stress in
the zone proximate affects a volumetric increase in the within the
zone proximate.
[0140] 4. The method of paragraph 1, wherein the stress in the zone
proximate causes at least a portion of the zone proximate to arch
against at least a portion of the subterranean formation, producing
a fracture network in the arched at least a portion of the
subterranean formation.
[0141] 5. The method of paragraph 1, wherein the applied stress in
the zone proximate produces a stress reduction in the in-situ
stress of the zone proximate and enables the subterranean formation
to arch toward at least a portion of the zone proximate, producing
a fracture network in the arched at least a portion of the
subterranean formation.
[0142] 6. The method of paragraph 1, wherein the effected
permeability increase results from creation of a fracture network
within an arched portion of the subterranean formation.
[0143] 7. The method of paragraph 6, wherein at least a portion of
the fracture network results from delamination fracturing within
the arched portion of the subterranean formation.
[0144] 8. The method of paragraph 1, wherein the zone proximate is
below the subterranean formation, with respect to the wellbore
path.
[0145] 9. The method of paragraph 1, applying the stress to a
near-wellbore portion of the zone proximate to the subterranean
formation to bend the subterranean formation and cause fractures to
form in the subterranean formation.
[0146] 10. The method of paragraph 1, further comprising:
[0147] thereafter reducing the applied stress to reversing at least
a portion of the volumetric increase and effect rubblization within
the subterranean formation; and
[0148] thereafter reapplying the applied stress to repeat the
volumetric increase to cause further rubblization within the
subterranean formation.
[0149] 11. The method of paragraph 1, wherein the subterranean
formation comprises a hydrocarbon-bearing formation and the method
further comprises extracting at least a portion of the hydrocarbons
from the subterranean formation into a wellbore.
[0150] 12. The method of paragraph 1, wherein the zone proximate
comprises an underburden formation layer.
[0151] 13. The method of paragraph 1, wherein creating the
volumetric increase comprises pumping a fluid into the zone
proximate.
[0152] 14. The method of paragraph 13, wherein the pumped fluid
comprises a suspension of a proppant.
[0153] 15. The method of paragraph 14, wherein the proppant
comprises waste product tailings.
[0154] 16. The method of paragraph 1, wherein applying the stress
in the zone proximate comprises thermally expanding the zone
proximate.
[0155] 17. The method of paragraph 1, wherein applying the stress
to the zone proximate comprises expanding the zone proximate by a
pressurized fluid without hydraulically fracturing the zone
proximate.
[0156] 18. The method of paragraph 1, wherein applying the stress
to the zone proximate comprises expanding a cavity or tunnel in the
zone proximate by a pressurized fluid.
[0157] 19. The method of paragraph 1, wherein applying the stress
to the zone proximate comprises expanding the zone proximate by a
chemical reaction.
[0158] 20. The method of paragraph 1, wherein applying the stress
to the zone proximate comprises expanding the zone proximate by a
pressurized fluid.
[0159] 21. The method of paragraph 1, wherein applying the stress
to the zone proximate comprises expanding the zone proximate with
explosives.
[0160] 22. The method of paragraph 1, further comprising applying
stress to the zone proximate so as to cause at least a portion of
the subterranean formation to arch in a direction away from the
zone proximate.
[0161] 23. The method of paragraph 1, further comprising applying
stress to the zone proximate by reducing the in-situ geomechanical
stress in the zone proximate so as to cause at least a portion of
the subterranean formation to arch in a direction toward the zone
proximate.
[0162] 24. A method for production of a hydrocarbon from a
reservoir, comprising:
[0163] penetrating a zone proximate a hydrocarbon bearing
subterranean formation with a wellbore;
[0164] applying stress to the zone proximate to the subterranean
formation to indirectly translate a mechanical stress change to the
subterranean formation to arch at least a portion of the
subterranean formation and thereby effect enhanced permeability
within the arched portion of the subterranean formation; and
[0165] extracting hydrocarbons from the enhanced permeability
subterranean formation into the wellbore.
[0166] 25. The method of paragraph 24, further comprising
penetrating both the zone proximate and the hydrocarbon bearing
subterranean formation with the wellbore.
[0167] 26. The method of paragraph 24, wherein the enhanced
permeability results from creation of a fracture network within the
arched portion of the subterranean formation.
[0168] 27. The method of paragraph 26, wherein at least a portion
of the fracture network results from delamination fracturing within
at least a portion of the arched portion of the subterranean
formation.
[0169] 28. The method of paragraph 24, wherein the hydrocarbon
bearing subterranean formation comprises a tight gas reservoir.
[0170] 29. The method of paragraph 24, wherein the hydrocarbon
bearing subterranean formation comprises a shale gas reservoir.
[0171] 30. The method of paragraph 24, wherein the hydrocarbon
bearing subterranean formation comprises a coal bed methane
reservoir.
[0172] 31. The method of paragraph 24, wherein the hydrocarbon
bearing subterranean formation comprises a tight oil reservoir.
[0173] 32. The method of paragraph 30, wherein a cleat system
within the coal bed methane reservoir is opened to enhance
conductivity.
[0174] 33. The method of paragraph 24, further comprising drilling
a stimulation well to the zone proximate and applying the stress to
the zone proximate from the stimulation well; and
[0175] extracting the hydrocarbons from a wellbore other than the
stimulation well.
[0176] 34. The method of paragraph 33, comprising drilling a
production well from the stimulation well into the hydrocarbon
bearing subterranean formation.
[0177] 35. The method of paragraph 24, further comprising applying
stress to the zone proximate so as to cause at least a portion of
the subterranean formation to arch in a direction away from the
zone proximate.
[0178] 36. The method of paragraph 24, further comprising applying
stress to the zone proximate by reducing the in-situ stress in the
zone proximate so as to cause at least a portion of the
subterranean formation to arch in a direction toward the zone
proximate.
[0179] 37. The method of paragraph 24, further comprising drilling
a production well into the hydrocarbon bearing subterranean
formation after applying the stress to the zone proximate.
[0180] 38. The method of paragraph 24, further comprising drilling
a production well into the hydrocarbon bearing subterranean
formation before the step of applying the stress to the zone
proximate is completed.
[0181] 39. The method of paragraph 24, further comprising cycling
applying the stress and relieving the applies stress to cause a
cycle of an expansion of the zone proximate and a contraction of
the zone proximate to effect rubblizing a layer of material within
the hydrocarbon bearing subterranean formation.
[0182] 40. The method of paragraph 24, further comprising:
[0183] injecting waste product tailings into the zone proximate to
prop open any fractures within the zone proximate.
[0184] 41. A hydrocarbon production system, comprising:
[0185] a hydrocarbon bearing subterranean formation;
[0186] a zone proximate to the hydrocarbon bearing subterranean
formation;
[0187] a stimulation well drilled to the zone proximate; and
[0188] a stimulation system configured to applying stress in the
zone proximate to the subterranean formation to indirectly affect a
mechanical stress to the hydrocarbon bearing subterranean formation
and effect a volumetric increase within the hydrocarbon bearing
subterranean formation.
[0189] 42. The hydrocarbon production system of paragraph 41,
wherein the hydrocarbon bearing subterranean formation comprises a
tight gas layer.
[0190] 43. The hydrocarbon production system of paragraph 41,
wherein the hydrocarbon bearing subterranean formation comprises a
shale gas layer.
[0191] 44. The hydrocarbon production system of paragraph 41,
wherein the hydrocarbon bearing subterranean formation comprises a
coal bed methane layer.
[0192] 45. The hydrocarbon production system of paragraph 41,
wherein the hydrocarbon bearing subterranean formation comprises a
tight oil layer.
[0193] 46. The hydrocarbon production system of paragraph 41,
wherein the zone comprises a formation layer in an underburden.
[0194] 47. The hydrocarbon production system of paragraph 41,
comprising a production well drilled into the hydrocarbon bearing
subterranean formation.
[0195] 48. The hydrocarbon production system of paragraph 41,
comprising a production well drilled into the hydrocarbon bearing
subterranean formation from the stimulation well.
[0196] 49. The hydrocarbon production system of paragraph 41,
further comprising applying stress to the zone proximate so as to
cause at least a portion of the subterranean formation to arch in a
direction away from the zone proximate.
[0197] 50. The hydrocarbon production system of paragraph 41,
further comprising applying stress to the zone proximate by
reducing the in-situ stress in the zone proximate so as to cause at
least a portion of the subterranean formation to arch in a
direction toward the zone proximate.
[0198] 51. A method for fracturing a subterranean formation,
comprising causing a volumetric increase in a zone proximate to the
subterranean formation so as to apply a mechanical stress to the
subterranean formation.
[0199] While the present techniques may be susceptible to various
modifications and alternative forms, the exemplary embodiments
discussed above have been shown only by way of example. However, it
should again be understood that the present techniques are not
intended to be limited to the particular embodiments disclosed
herein. Indeed, the present techniques include all alternatives,
modifications, and equivalents falling within the true spirit and
scope of the appended claims.
* * * * *
References