U.S. patent application number 13/820943 was filed with the patent office on 2013-08-08 for method and system for fracture stimulation.
The applicant listed for this patent is Bruce A. Dale, Yueming Liang, Kevin H. Searles, Elizabeth Land Templeton-Barrett. Invention is credited to Bruce A. Dale, Yueming Liang, Kevin H. Searles, Elizabeth Land Templeton-Barrett.
Application Number | 20130199787 13/820943 |
Document ID | / |
Family ID | 45994322 |
Filed Date | 2013-08-08 |
United States Patent
Application |
20130199787 |
Kind Code |
A1 |
Dale; Bruce A. ; et
al. |
August 8, 2013 |
Method and System for Fracture Stimulation
Abstract
The present techniques provide systems and methods for
fracturing a production formation. A method includes creating a
notch in a formation and causing a volumetric change in a treatment
interval proximate to a production interval so as to apply a
mechanical stress on the production interval, wherein the treatment
interval, the production interval, or both are located within the
formation. A horizontal fracture is created in the formation
originating from the notch.
Inventors: |
Dale; Bruce A.; (Sugar Land,
TX) ; Liang; Yueming; (Sugar Land, TX) ;
Searles; Kevin H.; (Kingwood, TX) ;
Templeton-Barrett; Elizabeth Land; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Dale; Bruce A.
Liang; Yueming
Searles; Kevin H.
Templeton-Barrett; Elizabeth Land |
Sugar Land
Sugar Land
Kingwood
Houston |
TX
TX
TX
TX |
US
US
US
US |
|
|
Family ID: |
45994322 |
Appl. No.: |
13/820943 |
Filed: |
October 14, 2011 |
PCT Filed: |
October 14, 2011 |
PCT NO: |
PCT/US11/56361 |
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 |
|
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|
61544757 |
Oct 7, 2011 |
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Current U.S.
Class: |
166/302 ;
166/244.1; 166/299; 166/308.1; 166/369; 166/52 |
Current CPC
Class: |
E21B 43/30 20130101;
E21B 43/263 20130101; E21B 43/26 20130101; G06F 30/20 20200101;
E21B 43/305 20130101 |
Class at
Publication: |
166/302 ;
166/244.1; 166/308.1; 166/369; 166/299; 166/52 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 43/30 20060101 E21B043/30 |
Claims
1. A method for fracturing a production formation, comprising:
creating a notch in a formation; causing a volumetric change in a
treatment interval proximate to a production interval so as to
apply a mechanical stress on the production interval, wherein the
treatment interval, the production interval, or both are located
within the formation; and creating a horizontal fracture in the
formation originating from the notch.
2. The method of claim 1, comprising creating a fracture field in
the production interval from the mechanical stress.
3. The method of claim 1, comprising creating the notch in the
treatment interval.
4. The method of claim 1, comprising creating the notch in the
production interval.
5. The method of claim 4, comprising creating the horizontal
fracture in the production interval to couple a fracture field to a
production well.
6. The method of claim 1, wherein both the treatment interval and
the production interval are located in a reservoir.
7. The method of claim 1, wherein only the production interval is
located in a reservoir.
8. The method of claim 1, comprising repeating the volumetric
change for one or more cycles to cause rubblization along a
delamination fracture.
9. The method of claim 1, comprising: pumping a higher viscosity
fluid to sustain an initial fracture; and pumping a lower viscosity
fluid to create or open secondary fractures.
10. The method of claim 1, comprising: creating a plurality of
notches in the treatment interval; and fracturing the treatment
interval sequentially at each of the plurality of notches to create
a volumetric increase in the treatment interval.
11. The method of claim 10, comprising fracturing the plurality of
notches in a sequence from a lowest notch to a highest notch.
12. The method of claim 1, comprising drilling a deviated well
through the treatment interval and the production interval;
stimulating the treatment interval through the deviated well; and
producing hydrocarbons from the production interval through the
deviated well.
13. The method of claim 12, comprising: drilling a well comprising
a plurality of deviated branches through the treatment interval and
the production interval; stimulating the treatment interval through
the plurality of deviated branches; and producing hydrocarbons from
the production interval through the plurality of deviated
branches.
14. The method of claim 1, comprising: creating a plurality of
notches in the treatment interval; and fracturing the treatment
interval substantially simultaneously at each of the plurality of
notches to create a volumetric increase in the treatment
interval.
15. The method of claim 1, comprising pumping a fracturing fluid
into the treatment interval to cause the volumetric change.
16. The method of claim 1, comprising thermally expanding the
treatment interval to cause the volumetric change.
17. The method of claim 1, comprising expanding the treatment
interval with explosives to cause the volumetric change.
18. The method of claim 1, comprising producing hydrocarbon from
the production interval.
19. A method for production of a hydrocarbon from a reservoir,
comprising: expanding a treatment interval below a production
interval to mechanically stress the production interval; creating a
fracture field to enhance conductivity within the production
interval; creating a notch in the production interval; fracturing
the production interval at the notch to form a horizontal fracture
coupling the fracture field to a production well; and producing
hydrocarbon from the production interval.
20. The method of claim 19, comprising: creating a notch in the
treatment interval; and fracturing the treatment interval at the
notch to create a horizontal fracture.
21. The method of claim 19, comprising: creating a plurality of
notches in the treatment interval; and fracturing the treatment
interval at the plurality of notches to created an uplifted
fractured field.
22. A hydrocarbon production system, comprising: a production
interval in a hydrocarbon bearing subterranean formation; a
treatment interval proximate to the production interval; a
stimulation well drilled to the treatment interval; a production
well drilled to the production interval; a notching system
configured to create notches in a formation comprising the
production interval, the treatment interval, or both; a stimulation
system configured to create a volumetric change in the treatment
interval; and a fracturing system configured to fracture the
formation at the notches to create horizontal fractures.
23. The hydrocarbon production system of claim 22, wherein the
production interval comprises a tight gas layer.
24. The hydrocarbon production system of claim 22, wherein the
treatment interval comprises a layer in an underburden.
25. The hydrocarbon production system of claim 22, comprising a
fracture field created by mechanical stress induced by the
volumetric change in the treatment interval.
26. The hydrocarbon production system of claim 22, wherein the
production well and stimulation well are portions of a single
deviated or vertical wellbore.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. Provisional
Patent Application No. 61/407,249 filed Oct. 27, 2010 entitled
METHOD AND SYSTEM FOR FRACTURE STIMULATION, and also claims benefit
to U.S. Provisional Application No. 61/544,757, filed Oct. 7, 2011,
entitled METHOD AND SYSTEM FOR FRACTURE STIMULATION BY CYCLIC
FORMATION SETTLING AND DISPLACEMENT and U.S. Provisional
Application No. 61/544,766, filed Oct. 7, 2011 entitled METHOD AND
SYSTEM FOR FRACTURE STIMULATION BY FORMATION 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 bearing subterranean formations 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 formations 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. 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
formations; 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 bearing subterranean formation
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] The other technique is to use wellbore notching or other
methods to induce stress concentrations near the wellbore so that a
hydraulic fracture may be initiated and propagated in a desired
direction. For example, during 1959 and 1960, the British American
Oil Company conducted an experimental program on fracturing with
the single-plane entry technique (Strain, H. J., "Well-Bore
Notching and Hydraulic Fracturing", 12.sup.th SPE Annual Technical
Meeting, Edmonton, 1961). With this technique, the wellbore is
prepared at a selected point using a hydraulic or a mechanical
notching tool, then the well is fractured with a treatment designed
to generate a single, extensive horizontal fracture. A partial
monolayer of large-sized propping agent is distributed in the
fracture to give high-flow capacity after the treatment. Field
tests indicated that wells fractured with this technique have
higher and more sustained productivity than those fractured by
conventional methods.
[0014] U.S. Pat. No. 5,482,116, to El-Rabaa and Olson, discloses a
method to guide hydraulic fracturing through a wellbore that is
drilled in a direction parallel to a desired fracture direction.
The wellbore is prepared with notches or perforations that lie in
the desired fracture plane. A longitudinal fracture is then created
in the desired direction by pumping fracturing fluid at high rate.
It was found that the higher the net pressure in the fracture, the
longer the fracture will extend in the plane.
[0015] 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, Wyoming," 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
[0016] An embodiment of the present techniques provides a method
for fracturing a production formation. The method includes creating
a notch in a formation and causing a volumetric change in a
treatment interval proximate to a production interval so as to
apply a mechanical stress on the production interval. The treatment
interval, the production interval, or both are located within the
formation. A horizontal fracture in the formation is created
originating from the notch.
[0017] Another embodiment of the present techniques provides a
method for production of a hydrocarbon from a reservoir. The method
includes expanding a treatment interval below a production interval
to mechanically stress the production interval. A fracture field is
created to enhance conductivity within the production interval. A
notch is created a notch in the production interval. The production
interval is fractured at the notch to form a horizontal fracture
coupling the fracture field to a production well. Hydrocarbons are
produced from the production interval.
[0018] Another embodiment provides a hydrocarbon production system
that includes a production interval in a hydrocarbon bearing
subterranean formation and a treatment interval that is proximate
to the production interval. The system also includes a stimulation
well that is drilled to the treatment interval and a production
well that is drilled to the production interval. A notching system
is configured to create notches in a formation comprising the
production interval, the treatment interval, or both. A stimulation
system is configured to create a volumetric change in the treatment
interval, and a fracturing system is configured to fracture the
formation at the notches to create horizontal fractures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] The advantages of the present techniques are better
understood by referring to the following detailed description and
the attached drawings, in which:
[0020] FIG. 1 is a diagram of a hydraulic fracturing process;
[0021] FIG. 2 is a drawing of a local stress state for an element
in a hydrocarbon bearing subterranean formation;
[0022] FIG. 3 is a drawing of an opening mode (mode I) of fracture
formation, commonly resulting from a standard hydraulic fracturing
process;
[0023] FIG. 4 is an exemplified drawing of a well treatment system
such as a hydraulic fracturing system, wherein a zone below a
hydrocarbon bearing subterranean formation is subjected to a
volumetric expansion, which can place stress on the hydrocarbon
bearing subterranean formation leading to fracturing;
[0024] 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;
[0025] FIG. 6 is a more detailed schematic view of a delamination
fracture stimulation performed by inflating a zone proximate to a
production zone;
[0026] FIG. 7 is a drawing of two modes of sliding fracture
formation that may participate in delamination fracture stimulation
as discussed herein;
[0027] FIG. 8 is a drawing of rubblization during shearing at a
fracture interface or boundary;
[0028] FIGS. 9(A) and 9(B) are plots of surface deformation induced
by a vertical fracture and a horizontal fracture in a underlying
formation;
[0029] FIG. 10 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;
[0030] FIG. 11 is a drawing of a vertical well passing through a
reservoir interval and a treatment interval, in which a notch has
been formed in the treatment interval;
[0031] FIG. 12 is a drawing of the stress distribution in the
formation around the tip of a notch;
[0032] FIGS. 13(A) and 13(B) are plots of horizontal stress states
in a formation around a vertical well and in the formation when
vertical fractures are present in the formation;
[0033] FIG. 14 is a drawing of a fracturing process;
[0034] FIG. 15 is a drawing of a technique that may be useful for
increasing the effects of the treatment of a zone on the
hydrocarbon bearing subterranean formation by fracturing and
injecting pressurized fluid or steam into a treatment formation at
multiple points along a well;
[0035] FIG. 16 is a drawing of a multi-stage injection method that
may be useful for increasing the effects of the treatment of a zone
on the hydrocarbon bearing subterranean formation if particulate
solids are used to dilate the zone;
[0036] FIG. 17 is a plot of formation uplift resulting from
sequentially fracturing at ten points along a well, using the
procedure discussed with respect to FIG. 16;
[0037] FIG. 18 is process flow diagram of a method for completing a
formation using a notching procedure for the direct stimulation of
the hydrocarbon bearing subterranean formation;
[0038] FIG. 19 is process flow diagram of a method for fracturing a
formation using a notching procedure in conjunction with a
treatment of a zone other than the production interval;
[0039] FIG. 20 is process flow diagram of a method for an inverse
pumping sequence to fracture a hydrocarbon bearing subterranean
formation through notches.
[0040] FIG. 21 is process flow diagram of another method for an
inverse pumping sequence to fracture a hydrocarbon bearing
subterranean formation through notches;
[0041] FIGS. 22(A)-(D) are well configurations that may be used to
directly stimulate a subterranean hydrocarbon bearing formation;
and
[0042] FIGS. 23(A)-(D) are drawings of a number of well
configurations that can be used in embodiments of the techniques
described herein.
DETAILED DESCRIPTION
[0043] 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.
[0044] 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.
[0045] The "Bulk modulus" of a rock sample from a formation relates
the pressure to the volume change given by the dilation .sub.kk. It
is an elastic property of the material and is usually denoted by
the English alphabet K having units the same as that of stress, and
is given by:
K = 3 .lamda. + 2 .mu. 3 . ##EQU00001##
[0046] "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.
[0047] "Cleat system" is the system of naturally occurring joints
that are created as a coal seam forms over geologic time. A cleat
system allows for the production of natural gas if the provided
permeability to the coal seam is sufficient.
[0048] "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.
[0049] "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).
[0050] 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.
[0051] "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.
[0052] "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.
[0053] 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.
[0054] As used herein, 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.
[0055] "Formation" refers to a body or section of geologic strata,
structure, formation, or other subsurface solids or collected
material that is sufficiently distinctive and continuous with
respect to other geologic strata or other characteristics that it
can be mapped, for example, by seismic techniques. A formation can
be a body of geologic strata of predominantly one type of rock or a
combination of types of rock, or a fraction of strata having
substantially common set of characteristics. A formation can
contain one or more hydrocarbon-bearing subterranean formations.
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 hydrocarbon
reservoir or 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. An
interval or production interval may generally refer to a sub-region
or portion of a reservoir. A hydrocarbon-bearing zone, or
production formation, may 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.
[0056] A "fracture" is a crack, delamination, surface breakage,
separation, crushing, rubblization, or other destruction within a
geologic formation or fraction of formation that is 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.
[0057] "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, usually formed
during hydraulic fracturing. A "fracture field" is a group of
fractures, which may or may not be interconnected, and are created
by a single fracturing event, such as by a volumetric change in a
zone proximate to a target formation, which fractures the target
formation.
[0058] "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.
[0059] "Geomechanical stress" or "stress" including a change
related thereto, or similar phrase, refers generally to the forces
external to or interior to a formation acting upon or within such
formation. The forces may define a stress state, condition, or
property of a formation, zone, or other geologic strata, and/or any
fluid contained therein. In embodiments, the stress state may be
manipulated to control the creation of fractures in particular
directions.
[0060] "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.
[0061] "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 a 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 magnitude of the vertical stress relative to the
horizontal stresses. 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.
[0062] "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.
[0063] "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 hydrocarbon bearing
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, asphaltenes, oils, natural gas, 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.
[0064] 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 magnitude of the vertical stress
relative to the horizontal stresses.
[0065] "Ideally elastic" refers to a material in which a body
formed of the material recovers its original form completely upon
removal of the forces causing the deformation, and a material that
has a one-to-one, i.e., unique relationship between the state of
stress and the state of strain at a given temperature. For many
materials, strain is directly proportional to the stress, at least
at stresses below the yield strength of a material, This linear
relationship between strain .sub.ij and stress .sub.ij occurring at
stresses below the yield strength is known as the generalized
Hooke's law, and is represented by the formula:
.sigma..sub.ij=C.sub.ijkl.epsilon..sub.kl
where summation convention is employed, meaning that in Cartesian
coordinates whenever the same letter subscript occurs twice in a
term, that subscript is to be given all possible values and the
results added together, and here i,j,k,l each take the values
1,2,3. The 9 equations represented above contain 81 elastic
constants, C.sub.ijkl, but symmetry of the stress tensor, .sub.ij,
and existence of a strain energy function reduce the number of
distinct constants to 21. A "plane of elastic symmetry" is a plane
in which the elastic constants at a point have the same values for
every pair of coordinate systems which are mirror images of each
other in a certain plane.
[0066] "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.
[0067] "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 affecting 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.
[0068] An "isotropic" material is one in which the body's elastic
constants, C.sub.ijkl, are the same in every set of reference axes
at any point for a given situation. For a such a material, the
number of distinct elastic constants is two, and the strains can be
related to the stresses by Hooke's Law:
.sigma..sub.ij=.lamda..delta..sub.ij.epsilon..sub.kk+2.mu..epsilon..sub.-
ij,
where the distinct elastic constants are and, the Lame constants.
is also known as the "modulus of rigidity" or "shear modulus" and
is sometimes expressed as G. Three additional constants, E, K, and
can be defined as combinations of the Lame constants.
[0069] 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 Rock Core Specimens," ASTM D 2938-95; a
"Standard Test Method for Splitting Tensile Strength of Intact Rock
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 Rock Core Specimens and Determining Dimensional and Shape
Tolerances," ASTM D 4435-01; "Standard Test Method for Elastic
Moduli of Intact Rock Core Specimens in Uniaxial Compression," ASTM
D 3148-02; "Standard Test Method for Triaxial Compressive Strength
of Undrained Rock Core Specimens Without Pore Pressure
Measurements," ASTM D 2664-04; "Standard Test Method for Creep of
Cylindrical Soft Rock Specimens in Uniaxial Compressions," ASTM D
4405-84, Reapproved 1989; "Standard Test Method for Performing
Laboratory Direct Shear Strength Tests of Rock Specimens Under
Constant Normal Stress," ASTM D 5607-95; "Method of Test for Direct
Shear Strength of Rock Core Specimen," U.S. Military Rock Testing
Handbook, RTH-203-80, available at
"http://www.wes.army.mil/SL/MTC/handbook/RT/RTH/203-80.pdf" (last
accessed on Oct. 1, 2010); and "Standard Method of Test for
Multistage Triaxial Strength of Undrained Rock Core Specimens
Without Pore Pressure Measurements," U.S. Military Rock 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 rock specimens from formations may be
used to determine the physical constants used herein.
[0070] "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.
[0071] An "orthotropic" material is one that has three symmetry
planes and nine independent elastic constants if a strain-energy
function exists. If the principal axes of strain coincide with the
symmetry axes, then so do the principal axes of stress.
[0072] "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.
[0073] "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).
[0074] "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).
[0075] "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 rock type found in formations,
Belridge, has very high porosity, at about 60%, but the
permeability is very low, for example, less than about 0.1
millidarcy.
[0076] The "Poisson's ratio" of a rock sample from a formation is
the ratio of a unit of lateral contraction to a unit of
longitudinal extension for tension. It is a dimensionless elastic
property of the material and is usually denoted by the Greek
alphabet, and is given by:
v = .lamda. 2 ( .lamda. + .mu. ) . ##EQU00002##
[0077] "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).
[0078] As previously mentioned, a "reservoir" or "hydrocarbon
reservoir" is defined as a pay zone or production interval (for
example, a hydrocarbon bearing subterranean formation) 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.
[0079] "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.
[0080] 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 rock physics model may provide values that may
be used as a velocity model for a seismic survey.
[0081] "Shale" is a fine-grained clastic sedimentary rock that may
be found in formations, and may often have 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.
[0082] "Stimulated Rock Volume" (SRV) describes a relatively large
formation volume that has experienced increased permeability and
associated hydrocarbon production potential through the use of
changed in-situ stress (either applied or reduced stress) and
strain 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.
[0083] "Strain" is the fractional change in dimension or volume of
the deformation induced in the material by applying stress. Stain
is usually denoted by the Greek alphabet The nine components which
fully define the strain at a given point are expressed as .sub.ij,
where i,j, each take the values 1,2,3.
[0084] "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. The force f could be
compressional, leading to longitudinally compressing the strength
member, or tensional, leading to longitudinally extending the
strength member. Stress is usually denoted by the Greek alphabet
The nine components which fully define the stress state at a given
point are expressed as where i,j, each take the values 1,2,3.
[0085] "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.
[0086] "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.
[0087] "Tight oil" is used to reference formations with relatively
low matrix permeability, porosity, or both, where liquid
hydrocarbon production potential exists. In these formations,
liquid hydrocarbon production may also include natural gas
condensate.
[0088] "Underburden" refers to the subsurface formation below or
farther downhole than a formation containing one or more
hydrocarbon-bearing zones, e.g., a hydrocarbon reservoir. For
example, underburden may include rock, shale, mudstone, or a
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 hydrocarbon bearing formation or may be a
selected fraction within a common formation shared between the
underburden portion and the hydrocarbon bearing portion.
Intermediate layers may also reside between the underburden layer
and the hydrocarbon bearing zone.
[0089] The "Young's modulus" of a rock sample from a formation is
the stiffness of the rock sample, defined as the amount of axial
load (or stress) sufficient to make the rock 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 more stress is required to deform it. 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, and is
given by:
E = .mu. ( 3 .lamda. + 2 .mu. ) .lamda. + .mu. . ##EQU00003##
[0090] Overview
[0091] Embodiments of the present techniques provide well
completions and methods for stimulation of hydrocarbon bearing
subterranean formations, or portions thereof, on a large scale, up
to stimulating an entire formation at once. The methods include
fracturing a subterranean formation by applying stress in a zone
proximate to the subterranean formation to indirectly translate a
mechanical stress to the subterranean formation and affect a
permeability increase within the subterranean formation. The
desired permeability increase is effected by creation of a fracture
field 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 it is
noted that for simplification purposes, all such fracturing and
displacements may be referred to herein generally as
fracturing.
[0092] In embodiments, a notch may be formed from a well into a
formation, creating a stress concentration at the tip of the notch.
When a notch parallel to the horizontal plane is pressurized with a
fracturing fluid, the stress concentration can change the
orientations of principal stresses at notch tip and promote the
growth of a horizontal fracture. As the fracture grows out away
from the notch, stresses in the formation can cause the fracture to
change direction, for example, shifting to vertical. The distance
over which the fracture will remain horizontal may depend on the
notch size and geometry, differential between in-situ vertical and
horizontal stresses, the pumping rate, and the viscosity of the
fracturing fluid, among others. Notches may be formed in the zone
proximate, the hydrocarbon bearing subterranean formation, or
both.
[0093] A notch formed in the hydrocarbon bearing subterranean
formation may be used to create a horizontal fracture to couple the
production well to a fracture field created by imposing a stress on
the zone proximate to the hydrocarbon bearing subterranean
formation. The horizontal fracture may follow a bedding plane in
the hydrocarbon bearing subterranean formation. The notching may be
performed before treating the zone proximate to lubricate the
delamination planes, increasing the amount of delamination
resulting from stressing the zone proximate.
[0094] A notch formed in the zone proximate to the hydrocarbon
bearing subterranean formation may increase the effectiveness of a
treatment of that zone, for example, by increasing the lateral
extent of the stress that can be placed on the field. Further, the
notching may be used to control the formation of multiple
horizontal fractures that are vertically stacked in either the zone
or the hydrocarbon bearing subterranean formation. The formation of
multiple fractures may increase the effects without requiring
higher net pressure or flow rates for each fracture and may also
allow achieving a desired treatment displacement profile.
[0095] The fracturing may follow a normal sequence for the injected
fluids or may use an inverted injection sequence. In a normal
injection sequence, the fluids increase in viscosity as the
injection occurs, for example, from a thin fluid to a crosslinked
polymer solution. In an inverted sequence, a thin fluid is injected
first, then thicker fluids, followed by thinner fluids to
finish.
[0096] 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,
e.g., low permeability, gas reservoirs.
[0097] In embodiments described herein a single wellbore may be
used to reach both the zone proximate and the hydrocarbon bearing
subterranean formation, or separate wellbores 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. Well completions that may be used in
embodiments are discussed further with respect to FIGS. 22 and
23.
[0098] In embodiments, the stress on the zone proximate to the
target formation may be applied by increasing a volume of the zone
proximate. For example, a volumetric increase may be created in the
zone proximate 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 affecting 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 field is created within
the subterranean formation.
[0099] In embodiments, the stresses within the zone proximate to
the target formation may be altered by decreasing a volume of the
zone proximate. The decrease in the volume of the zone proximate
may effect a reduction in stress and structural support within the
zone proximate. This reduction in structural support translates
into a corresponding reduction in stability of the hydrocarbon
bearing subterranean formation, resulting in creation of a fracture
field 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 formation
material within the zone proximate, physical removal of portion of
the zone proximate, such as via a network of relatively large or
under-reamed 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.
[0100] Further, the changes in the stress of the zone proximate do
not have to involve a volumetric change. The methods described
herein may include any number of other techniques that alter the
geomechanical stresses of a formation, including external or
internal stresses, by dislocation, displacement, strain changes, or
fracturing of a zone proximate or subterranean formation, without
substantial volumetric change therein. Although a volumetric change
is not necessarily involved, the stress can still be communicated
from the zone proximate to the targeted subterranean formation. The
techniques described herein generally include treating a zone
proximate to a target formation to effect a stress change in the
zone proximate, which will effect a permeability increase in the
target formation.
[0101] Further, the application of the stress, e.g., through
volumetric changes, does not have to be performed as a single
event. 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. The
increased rubblization at fracture surfaces can lead to further
improvements in permeability within the targeted formation.
[0102] The stress applied to the targeted formation can cause
delamination of layers and other forms of non-hydraulic fracturing,
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 to the target 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 a period of months,
such as if waste tailings are used to fracture and prop open the
fractures in the zone proximate formation.
[0103] 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. Further, the formation
surfaces can be 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, since
such stresses 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.
[0104] Although shown as being substantially parallel or coplanar
with respect to each other in the figures to follow, the zone
proximate and the hydrocarbon bearing subterranean formation may be
situated in non-parallel planes. 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. Each may comprise a single geologic formation, zone, lens,
or structure, or multiple formations, zones, lenses, or
structures.
[0105] As discussed herein, embodiments of the present techniques
can increase well productivity, lessen environmental impact,
enhance well integrity and 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 when the
strength of the activated bedding plane interfaces is sufficiently
low.
[0106] 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 formation layers where the oil or gas is trapped.
The pressure of the water creates tiny fissures or fractures in the
formation. After pumping is finished the sand props open the
fractures, allowing the oil or gas to escape from the formation and
flow up a well.
[0107] 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 formations in the hydrocarbon bearing
subterranean formation 106. A mobile command center 126 may be used
to control the fracturing process.
[0108] 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 formation. 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.
[0109] 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.
[0110] 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 elastic moduli 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.
[0111] The earth stresses can be divided into three principal
stresses where .GAMMA..sub.v is the vertical stress in this
drawing, .sigma..sup.H.sub.max is the maximum horizontal stress,
while .sigma..sup.h.sub.min is the minimum horizontal stress, where
.sigma..sub.v>.sigma..sup.H.sub.max>.sigma..sup.h.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.
[0112] 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.
[0113] However, other stress conditions may exist in formations.
These stress conditions may contribute to the tendency for
horizontal or vertical fractures to form. For example, depending on
geologic conditions, the vertical stress could be substantially
equivalent to the orthogonal lateral stresses. In this condition,
termed lithostatic, the direction of a fracture may be controlled
by any stress perturbations that take place in the formation. One
such perturbation is the wellbore itself, which may favor the
formation of vertical fractures. Another perturbation would be the
creation of a notch in the formation, as discussed with respect to
FIG. 11. The notch may favor the creation of horizontal fractures
in the formation.
[0114] In another condition, the formation may be formed from a
rock that is transversely isotropic. In this case, the rock itself
is formed along planar layers that favor the formation of fractures
along the planes. If the planes are parallel to the surface, the
formation may have an increased tendency to form horizontal
fractures, even under high vertical stress. As another example, a
formation may be overpressured, in which the formation has a high
pore pressure. Under this condition, the high pore pressure may
have a tendency to offset a high vertical stress, allowing the
fracturing to be controlled by the addition of stress perturbations
in the formation. Generally, as the pressure in the hydrocarbon
bearing subterranean formation drops, for example, during
production, further fracturing may be horizontal due to
reorientation of the stresses. This is discussed in further detail
with respect to FIG. 9. The stresses may also be adjusted to favor
the growth of horizontal fractures, as discussed with respect to
FIGS. 10-12.
[0115] FIG. 3 is a drawing of an opening 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 formation. 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.
[0116] 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 or decrease
in a layer adjacent to the hydrocarbon bearing subterranean
formation can be used to place or relieve a stress on the
reservoir, leading to fracturing in the reservoir.
[0117] FIG. 4 is an exemplified drawing of 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 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 heating and
cooling cycles, or successive fluid injections and removal
cycles.
[0118] 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 effects of
volumetric contraction 406 may be enhanced by alternately injecting
(for example, hours, days, weeks, months, and even years) and then
producing fluid in successive cycles.
[0119] A number of liquids may be sequentially injected to perform
the horizontal hydraulic fracturing in the hydrocarbon bearing
subterranean formation. A first liquid pumped into the fracture
zone is termed a pad, and may be a low viscosity brine
solution.
[0120] After the pad, a higher viscosity linear or cross-linked gel
may be pumped into the fracture zone to create the primary planar
fractures. Once the planar fractures are created, a slick water
fluid can be pumped, along with the high permeability proppant 116,
to fill the primary fracture and to create secondary fractures or
open natural fracture systems. Other pumping orders and system may
be used in embodiments, for example, when fracturing zones
proximate to the hydrocarbon bearing subterranean formation.
[0121] 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. This may occur from dilating, enlarging, or uplifting
formations in the zone 402 from below. The method used to treat the
hydrocarbon bearing subterranean formation 404 would need to create
the stress state sufficient to impose delamination fracturing along
preferred layers of interest. 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.
[0122] FIG. 5 is a block diagram of a method 500 for stimulation of
a reservoir by treating an interval outside of the reservoir. As
used herein, a reservoir is a portion of hydrocarbon bearing
subterranean formation that is being used for the production of
hydrocarbons. A treatment interval is a zone proximate to the
reservoir that is being treated to enhance the production from the
reservoir. The treatment interval or zone may lie within the
reservoir, or may be separate from 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.
[0123] For 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 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 inserting a heat source into the
treatment interval to cause inflation of the treatment interval by
thermal expansion.
[0124] 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. The
method 500 is not limited to the order shown. In embodiments, the
well may be completed at block 506 before the treatment at block
504 to allow direct treating of the reservoir prior to
production.
[0125] 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 rock 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.
[0126] 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.
[0127] 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 or rubblization. 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 expansion conditions, may cause a vertical
motion of about 1 cm over a horizontal distance of about 1000
m.
[0128] Further, the arch or dome 612 may have a highest stress
region, e.g., the area in which the fractures form within the
hydrocarbon bearing subterranean formation 604, that is not
centered on the injection well 602. As the distance between the
volumetric expansion 610 and the hydrocarbon bearing subterranean
formation 604 increases, so does the distance between the well 602
and the highest stress point in the hydrocarbon bearing
subterranean formation 604. Accordingly, if the highest stress
point in the hydrocarbon bearing subterranean formation 604 is
sufficiently separated from the well 602, fracturing of the
hydrocarbon bearing subterranean formation 604 may be used to
couple the fracture field around the highest stress point with the
well 602.
[0129] 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.
[0130] 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.
[0131] 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 the 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 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.
10-13.
[0132] 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. In some embodiments, the zone 606 may be
decreased in volume, for example, by erosion, chemical attack,
removal of fluids and the like. The reduction of volume in the zone
606 can cause delamination fractures to occur from subsidence of
the hydrocarbon bearing subterranean formation 604.
[0133] 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.
[0134] In contrast with the direct hydraulic fracture stimulation
of a hydrocarbon bearing subterranean formation 604, the
delamination fracture stimulation 600 can decrease 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.
[0135] In some embodiments described herein, a notching technique
may be used to promote the growth of horizontal fractures in the
zone 606. This can increase the efficiency of the indirect process
by increasing the area over which the forces act on the hydrocarbon
bearing subterranean formation 604. Notching may also be used in
the hydrocarbon bearing subterranean formation 604 to promote
horizontal fractures used to couple the fracture field to the well
612 for production. This may be performed before the treatment of
the zone 606, in order to initiate and lubricate the fracture
planes in the hydrocarbon bearing subterranean formation 604,
increasing the effects resulting from the treatment of the zone
606.
[0136] 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.
[0137] 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
formation, rather than tensile parting of the formation. 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.
[0138] 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 bedding plane interface or 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 or adjacent to the fracture boundary 804.
[0139] As mentioned previously, the flow conductivity of
delamination fractures may be enhanced by cycling the induced
flexures such that the delaminated formations "rubblize" within or
adjacent to 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 permeability and
porosity.
[0140] Stress Distribution and Rearrangement
[0141] FIGS. 9(A) and 9(B) are plots 900 of surface deformation
induced by fractures in a lower lying formation. In FIG. 9(A), a
vertical fracture field 902 induces a surface deformation 904 that
has a minimum in the vicinity of a well 906 that is used for the
treatment. In FIG. 9(B), a horizontal fracture field 908 causes a
larger surface deformation 910. A local maximum may exist in the
vicinity of the well 912, but this depends on the separation 914
between the surface and the horizontal fracture field 908.
Accordingly, the measured deformation pattern may reveal the shape
and dimension of the treatment. The deformations also show an
advantage of creating a horizontal fracture field 908 over a
vertical fracture field 902 can create a larger deformation, and,
thus, a greater stress, in an overlying formation. Horizontal
fracture fields 908 may be promoted in a number of different ways,
as discussed with respect to FIGS. 10-13.
[0142] FIG. 10 is a drawing of an azimuthal rotation 1000 of
fracture planes 1002 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.
[0143] As discussed above with respect to FIG. 2, the earth
stresses can be expressed as three principal stresses. In this
case, .sigma..sub.v is the vertical overburden stress and is
initially the highest stress in the system. Further,
.sigma..sup.H.sub.max is the maximum horizontal stress, while
.sigma..sup.h.sub.min is the minimum horizontal stress, where
.sigma..sub.v>.sigma..sup.H.sub.max>.sigma..sup.h.sub.min.
Although, at all depths, injection of fluids creates volumetric
increases due to pore dilation or thermal expansion, the initial
fracture plane 1004 that forms within 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..sup.H.sub.max) or minimum stress
(.sigma..sup.h.sub.min), especially in regions near the well. For
example, the engineering of the stress conditions may be performed
by sequentially fracturing and propping the formation, leading to
an increase in horizontal stresses. As the horizontal stresses
dominate the vertical stresses, the fracture planes will rotate
into the horizontal.
[0144] As a result, the axis of each successive fracture plane 1002
in a cyclic fracturing process may be slightly shifted or rotated
from the last fracture plane 1002, as indicated by an arrow 1006.
This may continue until a final fracture plane 1008 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.
[0145] Although the technique discussed with respect to FIG. 10
will increase stress in the formation and rotate the fracture plane
to generate horizontal fractures, it will take a number of cycles
to perform the rotation. Other techniques may be used to initiate
horizontal fracture in a faster time frame, as discussed with
respect to FIGS. 11-13.
[0146] FIG. 11 is a drawing 1100 of a vertical well 1102 passing
through a reservoir interval 1104 and a treatment interval 1106, in
which a notch 1108 has been formed in the treatment interval. The
notch 1108 is a carved indentation in the treatment interval 1106
that creates a stress increase at the tip, promoting a horizontal
fracture. The notch 1106 can be created using any number of down
hole tools, such as a jet drilling tool. The notch 1106 can also be
created using any number of other techniques, such as an
under-reaming tool to mechanically remove material around the
wellbore in the desired plane for fracture growth. Alternative,
other means may include an acid wash to create a plane of wormholes
in the treatment interval 1106. The notching is not limited to the
treatment interval 1106, but may also be performed in the reservoir
interval 1104 to promote the growth of a horizontal fracture, for
example, to couple a fracture field to the vertical well 1102, to
lubricate fracture planes, or both.
[0147] FIG. 12 is a drawing 1200 of the stress distribution in the
formation around the tip of a notch 1202. As can be seen in FIG.
12, the notch 1202 creates a high stress region 1204 at the tip,
facilitating an origination of a crack which propagates out in a
perpendicular direction 1206 from a well 1208. This technique may
also be used in the hydrocarbon bearing subterranean formation to
enhance the growth of horizontal fractures that may be used to
couple the well to a fracture field.
[0148] Although the induced stress will preferentially start a
horizontal fracture in the perpendicular direction 1206 from the
well 1208, as the fracture moves out into a formation, the stress
distribution in the formation may steer the fracture in a different
direction. For example, the fracture may turn from the horizontal
direction to the vertical direction in formations having a higher
vertical stress component.
[0149] FIGS. 13(A) and (B) are plots of horizontal stress states
1300 in a formation around a vertical well 1302 and in the
formation when vertical fractures are present in the formation.
Stress states 1300 in the formation may be altered using thermal
heating, poroelastic dilation, or fracture opening approaches. Each
approach will induce dilation in the formation volume so that
horizontal stresses in the formation are increased. FIG. 13(A)
shows the changes in stress states after dilating a formation using
a thermal or poroelastic approach, in which the dilation occurs
over a formation volume near the wellbore.
[0150] FIG. 13(B) shows an example of increased horizontal stresses
around a well 1302 due to the opening of a vertical fracture. In
this case, high stress states extend farther out from the well 1302
than for the poroelastic dilation. A combination of the various
approaches may be used to perform an efficient stress control
treatment. For example, steam may be injected through a vertical
fracture at high pressure so that all three components of the
dilation, e.g., thermal heating, poroelastic dilation, and fracture
opening, may be combined to alter earth stress. This stress control
treatment may include an initial injection of steam or cold fluid
through the well 1302, and/or a vertical fracture, into the
treatment interval to increase horizontal stresses. Once the
horizontal stresses become greater than the vertical stress, the
formation can be fractured to create horizontal treatment
fractures.
[0151] FIG. 14 is a schematic 1400 of fracturing by an inverse
pumping sequence. In an inverse pumping sequence, the fluids are
not injected in order of increasing viscosity, but are injected in
an order that is, at least in part, from higher viscosity fluids to
lower viscosity fluids. The fracturing is performed from the well
1402 by forming notches in the formation at openings 1404 in the
well 1402. Packers 1406 can be placed in the well 1402 to isolate
sections that have already been treated from sections that are
currently being treated. After notching, the fracture 1408 can be
created by the injection of various fluids under pressure.
[0152] A first injection fluid can a thin brine solution, called
the pad 1410. The pad 1410 is normally present in wells, as the
brine solution can be a component of many of the drilling fluids.
In the inverse fracturing process shown, a thick solution 1412 can
be used to create the initial horizontal fractures 1408, generally
of significant fracture aperture width than lower viscosity fluids.
The thick solution 1412 can be a cross linked polymer solution, a
linear polymer solution, or any number of other high viscosity
fluids. For example, the thick solution 1412 can include guars,
cellulose acetates, polyacrylamides, and the like.
[0153] After the thick solution 1412 is injected, a slick water
solution 1414 can be injected. Slick water is an aqueous solution
that contains low molecular weight additives that lubricate the
flow of the solution, such as low molecular weight surfactants,
polyethylene oxides, and the like. The wider fractures created with
the more viscous fluids allow the slick water solution to be pumped
at a higher rates than other materials, resulting in higher down
hole pressures. The higher down hole pressures result in the
opening of secondary fractures 1416 along the horizontal fractures
1416.
[0154] The slick water 1414 can also be mixed with proppants to
hold open the fractures 1408 and 1416, allowing materials to flow
from the formation. The proppants can include any number of known
materials, such as sieved sand, crushed not shells, ceramic
spheres, polymer spheres, and the like. In some embodiments, the
proppant may be selected to match the density of the slickwater
solution, lowering the amount of proppant that may settle or float
out.
[0155] The delamination fracture (D-frac) stimulation process
described herein may use a large volume of fluid to dilate and/or
heat the treatment interval. As a result, long treatment times and
increased treatment cost, may be required if the permeability or
the thermal conductivity of the treatment interval are low.
Further, when particulate solids, such as drill cuttings, cements,
or waste products, are used as the primary treating agent, dilation
of the treatment interval is mainly achieved through the opening of
the treatment fractures. If a single treatment fracture is used,
extremely large net pressure may be required to create a large
volumetric dilation. Due to the brittle nature of most rock types
in unconventional resources, achieving large net pressure in a
single fracture may be impossible as the fracture will
propagate.
[0156] The control of the fracturing direction allows techniques to
be used to increase the efficacy of the treatments. For example, a
sequence of horizontal fractures may be generated in a zone or
formation and expanded as described herein. The use of multiple
fractures may decrease the net pressure required to expand the
formation, as well as the amount of time needed for the
treatment.
[0157] FIG. 15 is a drawing 1500 of a technique that may be useful
for increasing the effects of the treatment of a zone on the
hydrocarbon bearing subterranean formation by fracturing and
treating a treatment formation at multiple points along a well. In
this example, the well 102 is vertically drilled to a zone 402
below a hydrocarbon bearing subterranean formation 404. Like
numbered items are as described with respect to FIG. 4. As shown in
the drawing 1500, multiple horizontal fractures 1502 may first be
created and propped open in the zone 402, then fluid or steam may
be injected into the treatment interval at a pressure slightly
higher than the vertical stress so that fluid or steam may enter
the fractures 1502 and diffuse into the formation. Due to the
smaller spacing between fractures allowed by the controlled
formation of the horizontal fractures 1502, pressure or temperature
within the zone 402 will increase and equilibrate over a shorter
time frame. Thus, if thermal or poroelastic treatment methods are
used, simultaneous injection through multiple treatment fractures
may greatly reduce the treatment time required for generating
sufficient delamination. Further, if particulate solids, such as
cement, drill cuttings or waste products, are used as treating
materials, multi-stage injection may be performed through a number
of stacked horizontal fractures with manageable net pressure for
each stage. In either case, the Multi-Zone Stimulation Technology
(MZST) may be used to expedite the process of creating multiple
treatment fractures, thereby reducing time, and cost of the
treatment.
[0158] FIG. 16 is a drawing 1600 of a multi-stage injection method
that may be useful for increasing the effects of the treatment of a
zone 402 on the hydrocarbon bearing subterranean formation 404.
Like numbered items are as described with respect to FIG. 4. In the
technique, multiple horizontal fractures 1602, 1604, and 1606 are
created in the zone 402. Each of the horizontal fractures 1602,
1604, and 1606 may be successively inflated by the pumping of high
pressure fluid containing particulate solids into the horizontal
fractures 1602, 1604, and 1606 in a sequential fashion, for
example, inflating horizontal fracture 1602, then horizontal
fracture 1604, and finally horizontal fracture 1606. The techniques
are not limited to this order, as any sequence may be used. The
procedure generally includes determining a total required net
pressure (P.sub.total) for a single fracture with the designed
treatment volume (V) and the radius (R) of the treatment fracture
using an equation:
P.sub.total=P.sub.total(V,R,M),
wherein C.sub.ijkl are the elastic constants of the rock in the
treatment interval. In a particular embodiment in which the
treatment interval has very low permeability and the fracture is
stable or stationary, the total required pressure is given as
P total = 3 16 V R 3 E 1 - v 2 . ##EQU00004##
wherein E is the Young's modulus of the rock in the treatment
interval and is Poisson's ratio for the rock in the treatment
interval. A number of stages (N.sub.stage) may be determined using
the maximum allowable net pressure per stage (P.sub.c):
N.sub.stage=P.sub.total/P.sub.c. The location of the fractures in
each stage can be determined, for example, based on the thickness
of the treatment interval, with Stage 1 being farthest from the
reservoir interval. The treatment can then be sequentially
performed through each stage while maintaining manageable and
relatively constant net pressure for each stage
[0159] FIG. 17 is a plot of formation uplift resulting from
sequentially fracturing at ten points along a well 102, using the
procedure discussed with respect to FIG. 16. The treatment is
started towards the bottom of the formation and is sequentially
progressed up the formation, as shown by an arrow 1702.
[0160] Methods for Fracturing a Well
[0161] FIG. 18 is process flow diagram of a method 1800 for
completing a formation using a notching procedure for the direct
stimulation of the hydrocarbon bearing subterranean formation. At
block 1802, geologic data about the hydrocarbon bearing
subterranean formation is collected, including core, logs,
stresses, stratigraphy, etc. The data is used to select initial
treatment locations based on in-situ stresses, stratigraphy and
reservoir properties. The optimal treatment location and volumes
are selected based on economic constraints and recovery models
[0162] At block 1804, a plug is set below the reservoir interval or
above last treatment location. At block 1806, a notching tool is
lowered to the treatment location, the notch is created, and the
tool is tripped out of the well. At block 1808, the fracturing
treatment is performed. At block 1810, a determination is made as
to whether all stages have been treated. If not, process flow
returns to block 1804 to treat the next stage. If, at block 1810,
it is determined that all stages have been treated, at block 1812,
the plugs are milled out.
[0163] FIG. 19 is process flow diagram of a method 1900 for
fracturing a formation using a notching procedure in conjunction
with a treatment of a zone other than the production interval. At
block 1902, treatment locations and processes may be determined, as
discussed with respect to block 1802 of FIG. 18. At block 1904, the
well is completed and the hydrocarbon bearing subterranean
formation is fractured, generally following the method 1800
described with respect to FIG. 18.
[0164] At block 1906, a plug is placed above toe depth (TD) or the
last treatment location. At block 1908, a notching tool is lowered
to the treatment location, the notch is created, and the tool is
tripped out of the well. At block 1910, the treatment of the zone
is performed to create delamination fractures (D-Fracs) in the
reservoir interval by dilation or contraction of the treating
interval. At block 1910, a determination is made as to whether all
stages of the treatment have been completed.
[0165] If at block 1910, it is determined that more stages remain,
process flow returns to block 1906 to perform the next treatment.
If not, process flow ends at block 1914.
[0166] FIG. 20 is process flow diagram of a method 2000 for an
inverse pumping sequence to fracture a hydrocarbon bearing
subterranean formation through notches. The method begins at block
2002 with the pumping of a pad. At block 2004, a linear or
cross-linked gel is pumped to create a primary planar fracture. At
block 2006, slick water and proppants are pumped to fill the
primary fracture and to create secondary fractures or open natural
fracture systems. At block 2008, the fluids are flushed, leaving
the proppants in place. When used in conjunction with the treatment
of the zone to cause D-Fracs in the reservoir interval, the
fracture design is similar to that for the reservoir except that it
may not be necessary to create secondary fractures.
[0167] FIG. 21 is process flow diagram of another method 2100 for
an inverse pumping sequence to fracture a hydrocarbon bearing
subterranean formation through notches. The method begins at block
2102 with the pumping of a pad. At block 2104, linear or
cross-linked gel is pumped to create a primary fracture. At block
2106, fluids, for example, mixed with waste tailings, chemicals,
steam, or other materials, are pumped to induce a volumetric
increase or decrease in the zone. At block 2108, the fracturing
fluids are flushed out. This may not be used if the fracturing is
used as a waste disposal process.
[0168] Well Configurations
[0169] The techniques described herein may be used in any number of
well configurations, both in the zone and in the hydrocarbon
bearing subterranean formation. FIGS. 22 and 23 are drawings of a
number of well configurations that can be used in various
embodiments of the techniques described herein. The well design
options include, but are not limited to: vertical wells, deviated
wells, multi-arm vertical wells, and multi-arm deviated well.
[0170] FIGS. 22(A)-(D) are well configurations that may be used to
directly stimulate a subterranean hydrocarbon bearing formation.
FIG. 22(A) is a drawing of a vertical well 2202 having a series of
notches 2204, at which a fracturing treatment can be used to create
horizontal fractures 2206. The fracturing may be performed at all
notches in a substantially simultaneous procedure. In other
embodiments, the fracture treatment may be performed at each notch
2204 from the base of the reservoir interval, for example, in a
number of stages as described in FIGS. 16 and 17.
[0171] FIG. 22(B) is a drawing of a deviated well 2208 having a
series of notches 2204 through which horizontal treatment fractures
have been created and propagated into the reservoir formation. As
used herein, a deviated well has an angle that is substantially
offset from vertical, for example, being at an angle of 5.degree.,
10.degree., or more. The fracture treatment may be performed
substantially simultaneously, or sequentially from the base of the
reservoir interval in a number of stages as described in FIGS. 16
and 17. A deviated configuration may allow coupling of a production
well to a fracture field without further fracturing, since the well
may directly pass through an offset fracture field.
[0172] FIG. 22(C) is a drawing of a multi-arm vertical well 2210
having a series of notches 2204 through which horizontal treatment
fractures have been created and propagated into the reservoir
formation. The fracture treatment may be performed substantially
simultaneously, or sequentially from the base of the reservoir
interval in a number of stages as described in FIGS. 16 and 17.
[0173] FIG. 22(D) is a drawing of a multi-arm deviated well 2210
having a series of notches 2204 through which horizontal treatment
fractures have been created and propagated into the reservoir
formation. The fracture treatment may be performed substantially
simultaneously, or sequentially from the base of the reservoir
interval in a number of stages as described in FIGS. 16 and 17.
[0174] FIGS. 23(A)-(D) are drawings of a number of well
configurations that can be used in embodiments of the techniques
described herein. In each of the well configurations shown in FIG.
23, the wells penetrate both a treatment zone 402 and a hydrocarbon
bearing subterranean formation 404. In some embodiments, the D-Frac
method may first be used in the hydrocarbon bearing subterranean
formation 404 to create lubricating fractures and then in the zone
402 to create treatment fractures. This may be performed
substantially simultaneously or sequentially from the bottom to the
top of each interval.
[0175] FIG. 23(A) is a drawing of a vertical well 2302 drilled
through both the zone 402 and the hydrocarbon bearing subterranean
formation 404. FIG. 23(B) is a deviated well 2304 drilled through
both the zone and the hydrocarbon bearing subterranean
formation.
[0176] FIG. 23(C) is a drawing of a multi arm vertical well 2306
drilled through both the zone 402 and the hydrocarbon bearing
subterranean formation 404. FIG. 23(D) is a drawing of a multi arm
deviated well 2308 drilled through both the zone 402 and the
hydrocarbon bearing subterranean formation 404. The multi-arm
deviated wells may be drilled to penetrate both the zone 402 and
the hydrocarbon bearing subterranean formation 404 at multiple
locations. For each arm, the hydrocarbon bearing subterranean
formation 404 may be treated first to create lubricating fractures
and then the zone 402 may be treated to create delamination
fractures. Optimal stimulation results may be achieved through
manipulation of treatment between treating arms.
[0177] Embodiments of the claimed subject matter may include the
methods and systems disclosed in the following lettered
paragraphs:
[0178] A. A method for fracturing a production formation,
including: [0179] creating a notch in a formation; [0180] causing a
volumetric change in a treatment interval proximate to a production
interval so as to apply a mechanical stress on the production
interval, wherein the treatment interval, the production interval,
or both are located within the formation; and [0181] creating a
horizontal fracture in the formation originating from the
notch.
[0182] B. The method of paragraph A, including creating a fracture
field in the production interval from the mechanical stress.
[0183] C. The method of paragraph A, including creating the notch
in the treatment interval.
[0184] D. The method of paragraph A, including creating the notch
in the production interval.
[0185] E. The method of paragraph D, including creating the
horizontal fracture in the production interval to couple a fracture
field to a production well.
[0186] F. The method of paragraph A, wherein both the treatment
interval and the production interval are located in a
reservoir.
[0187] G. The method of paragraph A, including: [0188] pumping a
higher viscosity fluid to sustain an initial fracture; and [0189]
pumping a lower viscosity fluid to create or open secondary
fractures.
[0190] H. The method of paragraph A, including: [0191] creating a
plurality of notches in the treatment interval; and [0192]
fracturing the treatment interval sequentially at each of the
plurality of notches to create a volumetric increase in the
treatment interval.
[0193] I. The method of paragraph H, including fracturing the
plurality of notches in a sequence from a lowest notch to a highest
notch.
[0194] J. The method of paragraph A, including [0195] drilling a
deviated well through the treatment interval and the production
interval; [0196] stimulating the treatment interval through the
deviated well; and [0197] producing hydrocarbons from the
production interval through the deviated well.
[0198] K. A hydrocarbon production system, including: [0199] a
production interval in a hydrocarbon bearing subterranean
formation; [0200] a treatment interval proximate to the production
interval; [0201] a stimulation well drilled to the treatment
interval; [0202] a production well drilled to the production
interval; [0203] a notching system configured to create notches in
a formation including the production interval, the treatment
interval, or both; [0204] a stimulation system configured to create
a volumetric change in the treatment interval; and [0205] a
fracturing system configured to fracture the formation at the
notches to create horizontal fractures.
[0206] L. The hydrocarbon production system of paragraph K, wherein
the production interval includes a tight gas layer.
[0207] M. The hydrocarbon production system of paragraph K, wherein
the treatment interval includes a layer in an underburden.
[0208] N. The hydrocarbon production system of paragraph K,
including a fracture field created by mechanical stress induced by
the volumetric change in the treatment interval.
[0209] O. The hydrocarbon production system of paragraph K, wherein
the production well and stimulation well are portions of a single
deviated or vertical wellbore.
[0210] Still other embodiments of the claimed subject matter may
include the methods and systems disclosed in the following numbered
paragraphs:
[0211] 1. A method for fracturing a production formation,
including: [0212] creating a notch in a formation; [0213] causing a
volumetric change in a treatment interval proximate to a production
interval so as to apply a mechanical stress on the production
interval, wherein the treatment interval, the production interval,
or both are located within the formation; and [0214] creating a
horizontal fracture in the formation originating from the
notch.
[0215] 2. The method of paragraph 1, including creating a fracture
field in the production interval from the mechanical stress.
[0216] 3. The method of paragraph 1, including creating the notch
in the treatment interval.
[0217] 4. The method of paragraph 1, including creating the notch
in the production interval.
[0218] 5. The method of paragraph 4, including creating the
horizontal fracture in the production interval to couple a fracture
field to a production well.
[0219] 6. The method of paragraph 1, wherein both the treatment
interval and the production interval are located in a
reservoir.
[0220] 7. The method of paragraph 1, wherein only the production
interval is located in a reservoir.
[0221] 8. The method of paragraph 1, including repeating the
volumetric change for one or more cycles to cause rubblization
along a delamination fracture.
[0222] 9. The method of paragraph 1, including: [0223] pumping a
higher viscosity fluid to sustain an initial fracture; and [0224]
pumping a lower viscosity fluid to create or open secondary
fractures.
[0225] 10. The method of paragraph 1, including: [0226] creating a
plurality of notches in the treatment interval; and [0227]
fracturing the treatment interval sequentially at each of the
plurality of notches to create a volumetric increase in the
treatment interval.
[0228] 11. The method of paragraph 10, including fracturing the
plurality of notches in a sequence from a lowest notch to a highest
notch.
[0229] 12. The method of paragraph 1, including [0230] drilling a
deviated well through the treatment interval and the production
interval; [0231] stimulating the treatment interval through the
deviated well; and [0232] producing hydrocarbons from the
production interval through the deviated well.
[0233] 13. The method of paragraph 12, including: [0234] drilling a
well including a plurality of deviated branches through the
treatment interval and the production interval; [0235] stimulating
the treatment interval through the plurality of deviated branches;
and [0236] producing hydrocarbons from the production interval
through the plurality of deviated branches.
[0237] 14. The method of paragraph 1, including: [0238] creating a
plurality of notches in the treatment interval; and [0239]
fracturing the treatment interval substantially simultaneously at
each of the plurality of notches to create a volumetric increase in
the treatment interval.
[0240] 15. The method of paragraph 1, including pumping a
fracturing fluid into the treatment interval to cause the
volumetric change.
[0241] 16. The method of paragraph 1, including thermally expanding
the treatment interval to cause the volumetric change.
[0242] 17. The method of paragraph 1, including expanding the
treatment interval with explosives to cause the volumetric
change.
[0243] 18. The method of paragraph 1, including producing
hydrocarbon from the production interval.
[0244] 19. A method for production of a hydrocarbon from a
reservoir, including: [0245] expanding a treatment interval below a
production interval to mechanically stress the production interval;
[0246] creating a fracture field to enhance conductivity within the
production interval; [0247] creating a notch in the production
interval; [0248] fracturing the production interval at the notch to
form a horizontal fracture coupling the fracture field to a
production well; and [0249] producing hydrocarbon from the
production interval.
[0250] 20. The method of paragraph 19, including: [0251] creating a
notch in the treatment interval; and [0252] fracturing the
treatment interval at the notch to create a horizontal
fracture.
[0253] 21. The method of paragraph 19, including: [0254] creating a
plurality of notches in the treatment interval; and [0255]
fracturing the treatment interval at the plurality of notches to
created an uplifted fractured field.
[0256] 22. A hydrocarbon production system, including: [0257] a
production interval in a hydrocarbon bearing subterranean
formation; [0258] a treatment interval proximate to the production
interval; [0259] a stimulation well drilled to the treatment
interval; [0260] a production well drilled to the production
interval; [0261] a notching system configured to create notches in
a formation including the production interval, the treatment
interval, or both; [0262] a stimulation system configured to create
a volumetric change in the treatment interval; and [0263] a
fracturing system configured to fracture the formation at the
notches to create horizontal fractures.
[0264] 23. The hydrocarbon production system of paragraph 22,
wherein the production interval includes a tight gas layer.
[0265] 24. The hydrocarbon production system of paragraph 22,
wherein the treatment interval includes a layer in an
underburden.
[0266] 25. The hydrocarbon production system of paragraph 22,
including a fracture field created by mechanical stress induced by
the volumetric change in the treatment interval.
[0267] 26. The hydrocarbon production system of paragraph 22,
wherein the production well and stimulation well are portions of a
single deviated or vertical wellbore.
[0268] 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