U.S. patent application number 13/825796 was filed with the patent office on 2013-08-29 for methods for establishing a subsurface fracture network.
The applicant listed for this patent is Jose Oliverio Alvarez, Abdel Wadood M. El-Rabaa, Pavlin B. Entchev, Stephen Karner, Michael E. McCracken, Leonard V. Moore, Chris E. Shuchart. Invention is credited to Jose Oliverio Alvarez, Abdel Wadood M. El-Rabaa, Pavlin B. Entchev, Stephen Karner, Michael E. McCracken, Leonard V. Moore, Chris E. Shuchart.
Application Number | 20130220604 13/825796 |
Document ID | / |
Family ID | 45975799 |
Filed Date | 2013-08-29 |
United States Patent
Application |
20130220604 |
Kind Code |
A1 |
El-Rabaa; Abdel Wadood M. ;
et al. |
August 29, 2013 |
Methods For Establishing A Subsurface Fracture Network
Abstract
A method of creating a network of fractures in a reservoir is
provided. The method includes designing a desired fracture network
system, and determining required in situ stresses to create the
desired fracture network within the reservoir. The method further
includes designing a layout of wells to alter the in situ stresses
within the stress field, and then injecting a fracturing fluid
under pressure into the reservoir to create an initial set of
fractures within the reservoir. The method also includes monitoring
the in situ stresses within the stress field, and modifying the in
situ stresses within the stress field. The method then includes
injecting a fracturing fluid under pressure into the reservoir in
order to expand upon the initial set of fractures and to create the
network of fractures. A method for producing hydrocarbons from a
subsurface formation is also provided herein, wherein a fracture
network is created from a single, deviated wellbore production.
Inventors: |
El-Rabaa; Abdel Wadood M.;
(Houston, TX) ; Moore; Leonard V.; (Sealy, TX)
; McCracken; Michael E.; (Flower Mound, TX) ;
Shuchart; Chris E.; (Missouri City, TX) ; Entchev;
Pavlin B.; (Moscow, RU) ; Karner; Stephen;
(Kingwood, TX) ; Alvarez; Jose Oliverio; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
El-Rabaa; Abdel Wadood M.
Moore; Leonard V.
McCracken; Michael E.
Shuchart; Chris E.
Entchev; Pavlin B.
Karner; Stephen
Alvarez; Jose Oliverio |
Houston
Sealy
Flower Mound
Missouri City
Moscow
Kingwood
Houston |
TX
TX
TX
TX
TX
TX |
US
US
US
US
RU
US
US |
|
|
Family ID: |
45975799 |
Appl. No.: |
13/825796 |
Filed: |
August 29, 2011 |
PCT Filed: |
August 29, 2011 |
PCT NO: |
PCT/US11/49579 |
371 Date: |
March 22, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61405069 |
Oct 20, 2010 |
|
|
|
Current U.S.
Class: |
166/259 ;
166/297; 166/302; 166/303; 166/307; 166/308.1 |
Current CPC
Class: |
E21B 49/006 20130101;
E21B 43/26 20130101 |
Class at
Publication: |
166/259 ;
166/308.1; 166/303; 166/302; 166/307; 166/297 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A method of creating a network of fractures in a reservoir, the
reservoir having an in situ stress field, and the method
comprising: designing a desired fracture network system using
geomechanical simulation; determining required in situ stresses to
create the desired fracture network within a reservoir having an in
situ stress field; designing a layout of wells to alter the in situ
stresses within the stress field; injecting a fracturing fluid
under pressure into the reservoir in order to create an initial set
of fractures; monitoring the in situ stresses within the stress
field; updating the geomechanical simulation based on the monitored
in situ stresses; designing a program of modifying the in situ
stress within the stress field using geomechanical simulation;
modifying the in situ stresses within the stress field by
implementing at least one aspect of the program; and injecting a
fracturing fluid under pressure into the reservoir in order to
expand upon the initial set of fractures and to create the desired
fracture network.
2. The method of claim 1, wherein the reservoir has a permeability
less than 10 millidarcies.
3. The method of claim 2, wherein: at least two wells in the layout
of wells are completed for the production of hydrocarbon fluids;
and the network of fractures is designed to optimize production of
the hydrocarbon fluids.
4. The method of claim 3, wherein injecting a fracturing fluid
under pressure into the reservoir comprises injecting the fluid
through the at least two wells completed for the production of
hydrocarbon fluids.
5. The method of claim 3, wherein at least two wells in the layout
of wells are completed for the injection of fluids as part of
enhanced oil recovery.
6. The method of claim 5, wherein injecting a fluid under pressure
into the reservoir comprises injecting the fluid through the wells
completed for the injection of fluids.
7. The method of claim 6, wherein the fluids represent an aqueous
fluid.
8. The method of claim 4, further comprising: producing hydrocarbon
fluids from the wells completed for the production of hydrocarbon
fluids after the initial set of fractures is created.
9. The method of claim 8, wherein modifying the in situ stresses
comprises the producing of hydrocarbon fluids.
10. The method of claim 8, wherein modifying the in situ stresses
comprises injecting a fluid into at least a portion of the
reservoir in order to increase pore pressure within the in situ
stress field.
11. The method of claim 2, further comprising: after monitoring the
in situ stresses within the stress field, again injecting a
fracturing fluid under pressure into the reservoir.
12. The method of claim 1, wherein: at least two wells in the
layout of wells are completed for the production of
geothermally-produced steam; injecting a fluid under pressure into
the reservoir comprises injecting the fluid through selected wells
completed for the production of the geothermally-produced steam;
and the network of fractures is designed to optimize heat transfer
for geothermal applications.
13. The method of claim 2, wherein at least two wells in the layout
of wells are completed for the injection of acid gases; and
injecting a fluid under pressure into the reservoir comprises
injecting the fluid through selected wells completed for the
injection of acid gases.
14. The method of claim 13, wherein: the acid gases primarily
comprise carbon dioxide; and the carbon dioxide is injected as part
of an enhanced oil recovery project.
15. The method of claim 13, wherein: the acid gases primarily
comprise carbon dioxide; the carbon dioxide is injected as part of
a sequestration operation; and the network of fractures is designed
to optimize CO.sub.2 storage capacity.
16. The method of claim 2, wherein: at least two wells in the
layout of wells are completed for the injection of drill cuttings;
and injecting a fluid under pressure into the reservoir comprises
injecting the fluid through selected wells completed for the
injection of drill cuttings.
17. The method of claim 2, wherein determining required in situ
stresses to create the desired fracture network comprises (i)
reviewing downhole pressure measurements from existing wells, (ii)
reviewing micro-seismic monitoring conducted in existing wells,
(iii) conducting downhole stress modeling, (iv) reviewing tiltmeter
readings, or (v) combinations thereof.
18. The method of claim 2, wherein: injecting a fluid under
pressure into the reservoir comprises injecting a fluid through a
plurality of wells that are part of the layout of wells; and
modifying the in situ stresses comprises injecting a fluid under
pressure into each of the plurality of wells either (i)
simultaneously, or (ii) in stages such that fluid is injected into
one or more wells sequentially.
19. The method of claim 18, wherein modifying the in situ stresses
further comprises (i) specifying a length of time for injecting for
selected wells, (ii) specifying a viscosity of fluid for injection
into selected wells, (iii) modifying a temperature of the
reservoir, or (iv) combinations thereof.
20. The method of claim 19, wherein modifying a temperature of the
reservoir comprises (i) injecting a heated gas into the reservoir,
(ii) applying resistive heat to a rock matrix comprising the
reservoir, (iii) actuating one or more downhole combustion burners,
(iv) injecting a cooler fluid into the reservoir, or (v)
combinations thereof.
21. The method of claim 2, wherein modifying the in situ stresses
comprises providing new perforations into the reservoir from
selected wellbores, with the perforations being shot at a
non-transverse angle relative to the wellbores.
22. The method of claim 2, wherein modifying the in situ stresses
comprises producing hydrocarbon fluids from the reservoir.
23. The method of claim 2, wherein modifying the in situ stresses
comprises injecting a fluid into the reservoir to increase pore
pressure.
24. The method of claim 2, wherein modifying the in situ stresses
comprises establishing an assistive fracture path (i) by creating a
plurality of radially offset perforations into the reservoir
through a plurality of wells, (ii) by injecting an acidic fluid
through a plurality of wells to create worm holes in the reservoir,
or (iii) combinations thereof.
25. The method of claim 2, wherein injecting a fluid into the
reservoir to create the network of fractures comprises determining
pump rates and associated shear rates for selected wells.
26. The method of claim 2, wherein: the reservoir comprises two or
more zones; and the network of fractures is created within at least
two different zones, such that: designing a desired fracture
network system comprises designing a fracture network system in
each of the at least two zones, and injecting a fluid under
pressure into the reservoir comprises injecting a fluid into each
of the at least two zones so as to create the network of fractures
within the at least two zones.
27. A method of producing hydrocarbons from a subsurface formation,
the formation having a permeability less than about 10
millidarcies, and the method comprising: providing a wellbore in
the subsurface formation, the wellbore having been completed as a
deviated wellbore, and the wellbore having been perforated within
the subsurface formation along at least a first zone and a second
zone; fracturing the subsurface formation along the first and
second zones to form substantially vertical fractures extending
from the wellbore; producing hydrocarbon fluids through the
vertical fractures along the first and second zones; monitoring the
wellbore to determine when a change in orientation of the maximum
principal stress occurs within the subsurface formation along the
first and second zones; injecting a fracturing fluid into the
subsurface formation through perforations in the first and second
zones, thereby creating a first new fractures within the subsurface
formation that at least partially extends from the vertical
fractures along a plane that is substantially transverse to the
vertical fractures; and producing hydrocarbons through the first
new fractures and through the vertical fractures along the first
and second zones.
28. The method of claim 27, wherein: the deviated wellbore is
completed as a substantially horizontal wellbore within the
subsurface formation; and the vertical fractures extend
substantially transverse to the wellbore.
29. The method of claim 28, wherein: monitoring the wellbore
comprises (i) determining when a designated volume of hydrocarbon
fluids have been produced from the wellbore; (ii) determining when
a designated reduction in reservoir pressure within the subsurface
formation has taken place; (iii) determining when a selected period
of time of production has taken place; (iv) determining whether
micro-seismic readings indicate a change in in situ stresses; (v)
or combinations thereof.
30. The method of claim 28, wherein: the wellbore has further been
perforated within the subsurface formation along a third zone;
fracturing the subsurface formation further comprises fracturing
the subsurface formation along the third zone to form additional
vertical fractures extending from the wellbore; producing
hydrocarbon fluids through the vertical fractures further comprises
producing hydrocarbon fluids along the third zone; monitoring the
wellbore further comprises monitoring the wellbore to determine
when a change in maximum principal stress may occur within the
subsurface formation along the third zone; injecting a fracturing
fluid into the subsurface formation to create the first new
fractures further comprises injecting a fracturing fluid through
perforations in the third zone; and producing hydrocarbons through
the first new fractures further comprises producing hydrocarbons
through the vertical fractures along the third zone.
31. The method of claim 30, further comprising: injecting a
fracturing fluid into the subsurface formation through perforations
in the first, second, and third zones, thereby creating second new
fractures within the subsurface formation that at least partially
extend from the (i) vertical fractures, (ii) the first new
fractures, or (iii) both, along a plane that is substantially
transverse to the vertical fractures; and producing hydrocarbons
through (i) the second new fractures, (ii) the first new fractures,
and (iii) the vertical fractures along the first, second, and third
zones.
32. The method of claim 31, wherein the perforations along the
first zone, the second zone, and the third zone are separated by a
distance of between about 20 feet (6.1 meters) and 500 feet (152.4
meters).
33. The method of claim 31, wherein the vertical fractures extend a
distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters)
from the wellbore.
34. The method of claim 31, further comprising: perforating the
wellbore to create new perforations along a selected zone, wherein
the new perforations are shot at a non-transverse angle relative to
the wellbore; injecting a fracturing fluid into the subsurface
formation through the new perforations in the selected zone in
order to fracture the subsurface formation along the selected zone;
and producing hydrocarbon fluids through perforations along the
selected zone.
35. A method of producing hydrocarbons from a subsurface formation,
the formation having a permeability less than about 10
millidarcies, and the method comprising: providing a wellbore in
the subsurface formation, the wellbore having been completed as a
deviated wellbore, and the wellbore having been perforated along at
least a first zone and a second zone; fracturing the subsurface
formation along the first and second zones to form substantially
vertical fractures extending from the wellbore; producing
hydrocarbon fluids through the vertical fractures along the first
and second zones; injecting a fluid into the subsurface formation
through perforations in the second zone, thereby raising reservoir
pressure in the subsurface formation along the first zone and
causing a change in the in situ stresses within the subsurface
formation along the first zone; injecting a fluid into the
subsurface formation through perforations in the first zone,
thereby causing a propagation of fractures in the subsurface
formation along the first zone at least partially towards the
second zone; and producing hydrocarbons through the perforations
along the first zone.
36. The method of claim 35, wherein: the deviated wellbore is
completed as a substantially horizontal wellbore within the
subsurface formation; and the vertical fractures extend
substantially transverse to the wellbore.
37. The method of claim 36, further comprising: producing
hydrocarbons through the perforations along the second zone along
with the production of hydrocarbons from the first zone.
38. The method of claim 36, further comprising: monitoring the
wellbore to determine when a change in maximum principal stress may
occur within the subsurface formation along the first zone as a
result of injecting the fluid into the second zone.
39. The method of claim 36, wherein: monitoring the wellbore
comprises (i) determining when a designated volume of hydrocarbon
fluids have been produced from the first zone; (ii) determining
when a designated reduction in reservoir pressure within the
subsurface formation along the first zone has taken place; (iii)
determining when a selected period of time of production has taken
place; (iv) determining whether micro-seismic readings indicate a
change in in situ stresses; (v) determining any changes in in situ
stresses; (vi) determining when a selected volume of fluid has been
injected into the subsurface formations through the perforations in
the second zone; or (vii) combinations thereof.
40. The method of claim 36, wherein: the wellbore has further been
perforated within the subsurface formation along a third zone;
fracturing the subsurface formation further comprises fracturing
the subsurface formation along the third zone to form additional
vertical fractures extending from the wellbore; producing
hydrocarbon fluids through the vertical fractures further comprises
producing hydrocarbon fluids along the third zone; injecting a
fluid into the subsurface formation through perforations in the
second zone further raises reservoir pressure in the subsurface
formation along the third zone, and further causes a change in the
in situ stresses within the subsurface formation along the third
zone; and the method further comprises: injecting a fluid into the
subsurface formation through perforations in the third zone,
thereby causing a propagation of fractures in the subsurface
formation along the third zone at least partially towards the
second zone; and producing hydrocarbons through the perforations
along the third zone.
41. The method of claim 40, further comprising: producing
hydrocarbons through the perforations along the first and second
zones along with the production of hydrocarbons from the third
zone.
42. The method of claim 36, wherein the perforations along the
first zone and the second zone are separated by a distance of
between about 20 feet (6.1 meters) and 500 feet (152.4 meters).
43. The method of claim 36, wherein the fractures extending
substantially transverse to the wellbore extend a distance of about
100 feet (30.5 meters) to 500 feet (152.4 meters) from the
wellbore.
44. The method of claim 36, further comprising: discontinuing
production of hydrocarbons from the first zone; injecting a fluid
into the subsurface formation through perforations in the first
zone, thereby raising reservoir pressure in the subsurface
formation along the second zone and causing a change in the in situ
stresses within the subsurface formation along the second zone;
injecting a fluid into the subsurface formation through
perforations in the second zone, thereby causing a propagation of
fractures in the subsurface formation along the second zone at
least partially towards the first zone; and producing hydrocarbons
through the perforations along the second zone.
45. The method of claim 40, further comprising: discontinuing
production of hydrocarbons from the third zone; injecting a fluid
into the subsurface formation through perforations in the third
zone, thereby raising reservoir pressure in the subsurface
formation along the first zone and causing a change in the in situ
stresses within the subsurface formation along the first zone;
injecting a fluid into the subsurface formation through
perforations in the second zone, thereby causing a propagation of
fractures in the subsurface formation along the second zone at
least partially towards the third zone; and producing hydrocarbons
through the perforations along the second zone.
46. The method of claim 36, further comprising: perforating the
wellbore to create new perforations along a selected zone, wherein
the new perforations are shot at a non-transverse angle relative to
the wellbore; injecting a fracturing fluid into the subsurface
formation through the new perforations in the selected zone in
order to fracture the subsurface formation along the selected zone;
and producing hydrocarbon fluids through perforations along the
selected zone.
47. A method of creating a network of fractures in a reservoir, the
reservoir having an in situ stress field, and the method
comprising: monitoring the in situ stresses within the stress
field; injecting a fracturing fluid under pressure through a first
set of perforations into the reservoir in order to create an
initial set of fractures; producing native fluids from the
reservoir to change in situ stresses within the stress field; and
injecting a fracturing fluid under pressure through a second set of
perforations into the reservoir in order to expand upon the initial
set of fractures and to create the network of fractures.
48. The method of claim 47, further comprising: designing a desired
fracture network system; determining required in situ stresses to
create the desired fracture network within the reservoir; and
designing a layout of wells to alter the in situ stresses within
the stress field.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the priority benefit of U.S.
Provisional Patent Application 61/405,069 filed 20 Oct. 2010
entitled METHODS FOR ESTABLISHING A SUBSURFACE FRACTURE NETWORK,
the entirety of which is incorporated by reference herein.
BACKGROUND
[0002] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present disclosure. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present disclosure. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
FIELD
[0003] The present inventions relate to the formation of artificial
fractures in a subsurface formation. More specifically, the
inventions relate to the manipulation of in situ stresses within a
subsurface formation in order to control the propagation of
fractures from wells completed in the formation.
GENERAL DISCUSSION OF TECHNOLOGY
[0004] Natural resources sometimes reside in subsurface formations
in the form of a fluid. Such natural resources include oil, gas,
coal bed methane, and geothermal steam. Typically, such natural
resources reside many feet below the surface.
[0005] In order to access hydrocarbon fluids or steam, one or more
wellbores is formed from the surface down to the depth of the
subsurface formation. The wellbore provides fluid communication
between the surface and the subsurface formation. Fluids may then
be transported to the surface, either by means of reservoir
pressure, by means of artificial pressure, through pumping, or by
combinations thereof.
[0006] The recovery of such natural resources is sometimes made
difficult by the nature of the rock matrix in which they reside. In
this respect, some rock matrices have very limited permeability.
Examples of formations where the rock matrix has low permeability
are the shale gas reservoirs found in North America. These include
the Marcellus shale formation, the Barnett shale formation, the
Haynesville shale formation, and the Horn River shale formation.
Another example of a formation where the rock matrix has low
permeability is the so-called tight gas sandstone and siltstone
intervals found in the Piceance Basin.
[0007] It is well known in the oil and gas industry to increase
permeability in a subsurface rock matrix through hydraulic
fracturing. Hydraulic fracturing is a technique involving the
injection of fluid under high pressure into a selected subsurface
zone. The fluid is pumped into the wellbore, and then injected
through perforations previously shot in production casing and into
the surrounding rock matrix. Typically, the rock matrix is a
hydrocarbon bearing formation. The fluid is injected at a pressure
sufficient enough to create fractures within the rock matrix
extending from the perforations. This pressure is sometimes
referred to as a "parting" pressure or a "fracturing" pressure.
Preferably, the fluid includes a proppant used to hold the
fractures open after the fluid pressure is relieved.
[0008] A problem encountered with hydraulic fracturing is that the
fractures do not always propagate from the wellbore in a direction
that is optimal for well productivity or injection. Further,
fractures may propagate from different zones in parallel
orientations. This means that the fractures do not interconnect,
and the artificial fluid channels created for fluid flow to the
wellbore remain somewhat isolated.
[0009] The orientation of fractures in an underground formation is
generally controlled by the in situ stress of the formation. It is
known that subsurface formations are subjected to three principal
stresses. These represent a vertical stress and two orthogonal
horizontal stresses. When a formation is hydraulically fractured,
the created fractures should propagate along a path of least
resistance. Under principals of geomechanics, the path of least
resistance should be in a direction that is perpendicular to the
direction of least principal stress.
[0010] In deeper formations (generally, formations deeper than
about 1,000 to 2,000 feet), one of the horizontal stresses is
usually the smallest stress. Consequently, fractures tend to
propagate vertically and/or horizontally perpendicular to the
direction of least principal stress, the fractures together forming
an approximately vertically oriented planar fracture. In other
words, if the horizontal directions are the x and y axes and the
vertical direction is defined by a z axis, and the direction of
least principal stress is in the x direction, fractures would form
in the y-z plane. This is also generally true for any naturally
occurring fractures which may be present in the deeper
formation.
[0011] Attempts have been made in the past to modify the direction
in which fractures propagate. For example, in U.S. Pat. No.
5,111,881, entitled "Method to Control Fracture Orientation in
Underground Formation," it was proposed to first determine the
anticipated fracture orientation of a hydrocarbon-bearing
formation. The wellbore was then perforated in the anticipated
direction of the fracture, and fluid was injected into the wellbore
to form a first fracture. A substance was then injected into the
first fracture which would temporarily harden. The formation was
then perforated in a direction perpendicular to the original
anticipated fracture orientation of the hydrocarbon bearing
formation, and re-fractured to form a second fracture. It was
believed that the second fracture would propagate in a direction
away from that of the first fracture. The result was that
independent fractures in two horizontal directions would be
formed.
[0012] The '881 patent also suggested a modified arrangement to
this process. The operator would first determine whether the stress
field around a first hydraulic fracture would be altered to allow a
reversal of the in situ stresses. The anticipated initial fracture
orientation of the hydrocarbon-bearing formation is then
determined. The formation is then perforated in a direction
parallel to the anticipated fracture orientation, and also
perforated in a direction perpendicular to the anticipated fracture
orientation. The formation is then fractured in each of the two
directions simultaneously.
[0013] U.S. Pat. Publ. No. 2009/0095482 and U.S. Pat. Publ. No.
2009/0194273 describe a method for orchestrating multiple
subsurface fractures at multiple well locations in a region. This
is done by flowing a well treatment fluid from a centralized well
treatment fluid center. In operation, a fracture is formed at a
first well location, and the effects of that fracture on stress
fields within the formation are measured. Sensors disposed about
the region are adapted to output effects on the stress fields. This
process is then repeated for subsequent fractures. The location and
orientation of subsequent fractures are based on the combined
stress effects on the stress fields as a result of the prior
fractures.
[0014] The above publications also disclose a method of servicing
multiple well locations. The method includes the step of
configuring a central location for the distribution of "well
development task fluids to centralized service factories" through
fluid lines. The method also includes preparing the treatment
fluids at the centralized service factories, and treating wells
with the treatment fluids according to well development tasks
associated with each well.
[0015] As can be seen, the methods of the above publications focus
on coordinating the flow of fluids from a centralized well
treatment fluid center. The methods ostensibly provide for "optimal
region development."
[0016] U.S. Pat. No. 4,830,106 entitled "Simultaneous Hydraulic
Fracturing," describes the use of simultaneous fracturing to change
fracture trajectories due to the pressurization of the formation.
Fracturing is conducted in at least two wellbores simultaneously,
causing the fractures to propagate in a direction contrary to the
far-field in situ stresses. The fractures may curve away from each
well or towards each well depending on the relative position and
spacing of the wells in the stress field and the magnitude of the
applied far field stresses. Preferably, the generated fractures
will intercept at least one naturally-occurring fracture in the
hydrocarbon-bearing interval.
[0017] U.S. Pat. No. 4,724,905, also entitled "Simultaneous
Hydraulic Fracturing," discloses the use of hydraulic fracturing in
one well to control the direction of propagation of a second
hydraulic fracture in a second well located nearby. The first well
is fractured, with the fractures generally forming parallel to the
fractures in the natural fracture system. The hydraulic pressure is
maintained in the first well, and another hydraulic fracturing
operation is conducted at the second well within a zone of
anticipated in situ stress alteration caused by the first hydraulic
fracture. Preferably, the second hydraulic fracture propagates at
an angle that is substantially perpendicular to the first hydraulic
fracture.
[0018] A need exists for an improved method of creating a network
of fractures. More specifically, a need exists for a method of
creating a fracture network wherein a desired fracture network
system is determined for a group of wells or even for a field
before all of the wells are completed. Further, a need exists for a
method of producing hydrocarbons from a single deviated wellbore by
manipulating in situ stresses through sequential producing and
fracturing stages in the single wellbore.
SUMMARY
[0019] A method of creating a network of fractures in a reservoir
is first provided. The reservoir has an in situ stress field. The
method has particular application to subsurface rock formations
having a permeability that is less than 10 millidarcies.
[0020] In one embodiment, the method includes designing a desired
fracture network system. The fracture network system represents a
system of fractures or, alternatively, sets of fractures. The
fractures are designed to interconnect within the reservoir. The
step of designing a desired fracture network is done using
geomechanical simulation, which involves use of a software program
and a processor.
[0021] The method also includes determining required in situ
stresses to create the desired fracture network within the
reservoir. Determining required in situ stresses may be done by,
for example, (i) reviewing downhole pressure measurements from
existing wells, (ii) reviewing micro-seismic and/or tiltmeter
monitoring conducted in existing wells, (iii) conducting downhole
stress modeling, or (iv) combinations thereof.
[0022] The method further includes designing a layout of wells to
alter the in situ stresses within the stress field. The layout may
refer to the location of wellheads at the surface, the orientation
of wellbores along the reservoir, the completion architecture, or
combinations thereof.
[0023] The method additionally includes injecting a fracturing
fluid under pressure into the reservoir. The purpose is to create
an initial set of fractures within the reservoir. The fluid may be
injected through wells completed for the production of hydrocarbon
fluids. Alternatively or in addition, the fluid may be injected
through wells completed for the injection of fluids, such as
brine.
[0024] The method also includes monitoring the in situ stresses
within the stress field. Monitoring may be done by, for example,
(i) reviewing downhole pressure measurements from wells in the
field, (ii) reviewing micro-seismic and/or tiltmeter monitoring
conducted in wells in the field, (iii) conducting downhole stress
modeling, or (iv) combinations thereof.
[0025] The method additionally includes updating the geomechanical
simulation based on the monitored in situ stresses. Further, the
method includes designing a program of modifying the in situ stress
within the stress field. The step of designing a program is also
done using geomechanical simulation.
[0026] The method further includes modifying the in situ stresses
within the stress field. In one aspect, the modifying step is
performed at least in part by producing hydrocarbon fluids from the
reservoir. In another aspect, the modifying step is performed at
least in part by injecting fluids into the reservoir. This
injection is for the purpose of increasing pore pressure, and not
to further fracture the reservoir. The injection of fluids may take
place through a plurality of wells either simultaneously, or in
stages such that fluid is injected into two or more wells
sequentially.
[0027] Modifying the in situ stresses may further comprise (i)
specifying a length of time for injecting for selected wells, (ii)
specifying a viscosity of fluid for injection into selected wells,
(iii) modifying a temperature of the reservoir, or (iv)
combinations thereof. Alternatively, modifying the in situ stresses
may comprise providing new perforations into the reservoir from
selected wellbores, with the perforations being shot at a
non-transverse angle relative to the wellbores.
[0028] The method then includes injecting a fracturing fluid under
pressure into the reservoir in order to expand upon the initial set
of fractures and to create the desired fracture network.
Preferably, injecting a fluid under pressure into the reservoir
comprises injecting a fluid through a plurality of wells that are
part of the layout of wells.
[0029] In one aspect of the method, at least two wells in the
layout of wells are completed for the production of hydrocarbon
fluids. In this instance, the network of fractures is designed to
optimize production of the hydrocarbon fluids. Optionally,
injecting a fracturing fluid under pressure into the reservoir
comprises injecting the fluid through the at least two wells
completed for the production of hydrocarbon fluids. The method then
further comprises producing hydrocarbon fluids from the wells
completed for the production of hydrocarbon fluids after the
initial set of fractures is created.
[0030] In another aspect, at least two wells in the layout of wells
are completed for the injection of fluids as part of enhanced
hydrocarbon recovery. The fluids may represent an aqueous fluid
such as brine. In this instance, injecting a fluid under pressure
into the reservoir comprises injecting the fluid through selected
wells completed for the injection of fluids.
[0031] In yet another aspect, at least two wells in the layout of
wells are completed for the production of geothermally-produced
steam. In this instance, the network of fractures is designed to
optimize heat transfer for geothermal applications. Injecting a
fluid under pressure into the reservoir comprises injecting the
fluid through selected wells completed for the production of the
geothermally-produced steam.
[0032] In still another aspect, at least two wells in the layout of
wells are completed for the injection of acid gases. In this
instance, injecting a fluid under pressure into the reservoir
comprises injecting the fluid through selected wells completed for
the injection of acid gases. The acid gases may comprise, for
example, primarily carbon dioxide. The carbon dioxide may be
injected as part of an enhanced hydrocarbon recovery project.
Alternatively, the carbon dioxide may be injected as part of a
sequestration operation. There, the network of fractures is
designed to optimize CO.sub.2 storage capacity.
[0033] In yet another aspect, at least two wells in the layout of
wells are completed for the injection of drill cuttings. In this
instance, injecting a fluid under pressure into the reservoir
comprises injecting the fluid through selected wells completed for
the injection of drill cuttings.
[0034] A method of producing hydrocarbons from a subsurface
formation is also provided herein. The formation has a permeability
less than about 10 millidarcies.
[0035] In one embodiment, the method includes providing a wellbore
in the subsurface formation. The wellbore has been formed as a
deviated wellbore. Further, the wellbore has been perforated within
the subsurface formation along at least a first zone and a second
zone.
[0036] The method also includes fracturing the subsurface formation
along the first and second zones. This forms a plurality of
fractures extending from the wellbore in an approximately
vertically oriented plane that is substantially perpendicular to
the direction of least principal or minimum stress. Preferably the
deviated wellbore is completed as a substantially horizontal
wellbore within the subsurface formation. In this instance, the
fractures extend substantially transverse to the wellbore in an
approximately vertically oriented plane, sometimes referred to
herein as vertical fractures, that is substantially perpendicular
to the direction of least principal or minimum stress.
[0037] The method then includes producing hydrocarbon fluids
through the vertical fractures along the first and second
zones.
[0038] The method further includes monitoring the wellbore. The
wellbore is monitored to determine when a change in orientation of
the maximum principal stress occurs within the subsurface formation
along the first and second zones. Monitoring the wellbore may
comprise (i) determining when a designated volume of hydrocarbon
fluids have been produced from the wellbore; (ii) determining when
a designated reduction in reservoir pressure within the subsurface
formation has taken place; (iii) determining when a selected period
of time of production has taken place; (iv) determining whether
micro-seismic and/or tiltmeter readings indicate a change in in
situ stresses; (v) or combinations thereof.
[0039] The method also includes injecting a fracturing fluid into
the subsurface formation. The fluid is injected through
perforations in the first and second zones. This creates a first
set of new fractures within the subsurface formation that at least
partially extends from the vertical fractures along a plane that is
substantially transverse to, or at least angled away from, the
vertical fractures. The new fractures are still located within an
approximately vertically oriented plane, but the plane of the new
fractures is at an angle to the vertically oriented planar network
of the originally created fractures. The method further includes
producing hydrocarbons through the first set of new fractures and
through the vertical fractures along the first and second
zones.
[0040] Preferably, the wellbore has further been perforated within
the subsurface formation along a third zone. In this instance,
[0041] fracturing the subsurface formation further comprises
fracturing the subsurface formation along the third zone to form
additional vertical fractures extending from the wellbore; [0042]
producing hydrocarbon fluids through the vertical fractures further
comprises producing hydrocarbon fluids along the third zone; [0043]
monitoring the wellbore further comprises monitoring the wellbore
to determine when a change in maximum principal stress may occur
within the subsurface formation along the third zone; [0044]
injecting a fracturing fluid into the subsurface formation to
create the first set of new fractures further comprises injecting a
fracturing fluid through perforations in the third zone; and [0045]
producing hydrocarbons through the first set of new fractures
further comprises producing hydrocarbons through the vertical
fractures along the third zone.
[0046] In one aspect, the method further comprises injecting a
fracturing fluid into the subsurface formation through perforations
in the first, second, and (optional) third zones. This creates a
second set of new fractures within the subsurface formation that at
least partially extend from the (i) vertical fractures, (ii) the
first set of new fractures, or (iii) both. The fractures in the
second new set of fractures extend along a plane that may be
substantially transverse to, or at least at an angle to, the
vertical fractures. The method then further includes producing
hydrocarbons through (i) the second set of new fractures, (ii) the
first set of new fractures, and (iii) the vertical fractures along
the first, second, and (optional) third zones.
[0047] The perforations along the first zone, the second zone, and
the third zone are separated. For example, separation may be by a
distance of between about 20 feet (6.1 meters) and 500 feet (152.4
meters). In addition, the vertical fractures may extend a distance
of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the
wellbore.
[0048] In a related aspect, the method further comprises: [0049]
perforating the wellbore to create new perforations along a
selected zone, with the new perforations being shot at a
non-transverse angle relative to the wellbore; [0050] injecting a
fracturing fluid into the subsurface formation through the new
perforations in the selected zone in order to fracture the
subsurface formation along the selected zone; and [0051] producing
hydrocarbon fluids through perforations along the selected
zone.
[0052] Other aspects of methods of producing hydrocarbons from a
subsurface formation are also provided herein. Once again, the
formation has a permeability less than about 10 millidarcies.
[0053] In some implementations, the method includes providing a
wellbore in the subsurface formation. The wellbore has been
completed as a deviated wellbore. Further, the wellbore has been
perforated within the subsurface formation along at least a first
zone and a second zone.
[0054] The method also includes fracturing the subsurface formation
along the first and second zones. This forms a plurality of
fractures formed in a vertical plane, referred to herein as
vertical fractures, extending from the wellbore. Preferably the
deviated wellbore is completed as a substantially horizontal
wellbore within the subsurface formation. In this instance, the
vertical fractures extend substantially transverse to the
wellbore.
[0055] The method then includes producing hydrocarbon fluids
through the vertical fractures along the first and second
zones.
[0056] The method also includes injecting a fluid into the
subsurface formation. The fluid is injected through perforations in
the second zone. This serves to raise the reservoir pressure in the
subsurface formation along the first zone, and also causes a change
in the in situ stresses within the subsurface formation along the
first zone. It is noted that the fluid is not injected at a
pressure in excess of the formation parting pressure.
[0057] The method further includes injecting a fluid into the
subsurface formation through perforations in the first zone. In
this instance, fluid injection causes a propagation of fractures in
the subsurface formation along the first zone at least partially
towards the second zone.
[0058] The method also includes producing hydrocarbons through the
perforations along the first zone. The method may further include
producing hydrocarbons through the perforations along the second
zone along with the production of hydrocarbons from the first
zone.
[0059] In one aspect, the method further comprises monitoring the
wellbore to determine when a change in maximum principal stress may
occur within the subsurface formation along the first zone as a
result of injecting the fluid into the second zone. Monitoring the
wellbore may be done by (i) determining when a designated volume of
hydrocarbon fluids have been produced from the first zone; (ii)
determining when a designated reduction in reservoir pressure
within the subsurface formation along the first zone has taken
place; (iii) determining when a selected period of time of
production has taken place; (iv) determining whether micro-seismic
and/or tiltmeter readings indicate a change in in situ stresses;
(v) determining when a selected volume of fluid has been injected
into the subsurface formations through the perforations in the
second zone; or (vi) combinations thereof.
[0060] Preferably, the wellbore has further been perforated within
the subsurface formation along a third zone. In this instance,
[0061] fracturing the subsurface formation further comprises
fracturing the subsurface formation along the third zone to form
additional vertical fractures extending from the wellbore; [0062]
producing hydrocarbon fluids through the vertical fractures further
comprises producing hydrocarbon fluids along the third zone; and
[0063] injecting a fluid into the subsurface formation through
perforations in the second zone further raises reservoir pressure
in the subsurface formation along the third zone, and further
causes a change in the in situ stresses within the subsurface
formation along the third zone.
[0064] The method then further comprises: [0065] injecting a fluid
into the subsurface formation through perforations in the third
zone, thereby causing a propagation of new fractures in the
subsurface formation along the third zone at least partially
towards the second zone; and [0066] producing hydrocarbons through
the new fractures and the new perforations along the third
zone.
[0067] The method may also include producing hydrocarbons through
the perforations along the first and second zones along with the
production of hydrocarbons from the third zone.
[0068] The perforations along the first zone, the second zone, and
the optional third zone are separated. For example, separation may
be by a distance of between about 20 feet (6.1 meters) and 500 feet
(152.4 meters). In addition, the fractures may extend a distance of
about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the
wellbore.
[0069] In some implementations, the method further comprises:
[0070] discontinuing production of hydrocarbons from the first
zone; [0071] injecting a fluid into the subsurface formation
through perforations in the first zone, thereby raising reservoir
pressure in the subsurface formation along the second zone and
causing a change in the in situ stresses within the subsurface
formation along the second zone; [0072] injecting a fluid into the
subsurface formation through perforations in the second zone,
thereby causing a propagation of new fractures in the subsurface
formation along the second zone at least partially towards the
first zone; and [0073] producing hydrocarbons through the new
fractures and the perforations along the second zone.
[0074] In some implementations, the method further comprises:
[0075] discontinuing production of hydrocarbons from the third
zone; [0076] injecting a fluid into the subsurface formation
through perforations in the third zone, thereby raising reservoir
pressure in the subsurface formation along the first zone and
causing a change in the in situ stresses within the subsurface
formation along the first zone; [0077] injecting a fluid into the
subsurface formation through perforations in the second zone,
thereby causing a propagation of new fractures in the subsurface
formation along the second zone at least partially towards the
third zone; and [0078] producing hydrocarbons through the new
fractures and the perforations along the second zone.
BRIEF DESCRIPTION OF THE DRAWINGS
[0079] So that the present inventions can be better understood,
certain drawings, charts, graphs and/or flow charts are appended
hereto. It is to be noted, however, that the drawings illustrate
only selected embodiments of the inventions and are therefore not
to be considered limiting of scope, for the inventions may admit to
other equally effective embodiments and applications.
[0080] FIG. 1 is a cross-sectional view of an illustrative
wellbore. The wellbore has been completed as a deviated wellbore
within a subsurface formation. The subsurface formation contains
hydrocarbon fluids.
[0081] FIGS. 2A through 2K are perspective views of a bottom
portion of the wellbore of FIG. 1. The wellbore is divided or
apportioned into three illustrative zones for the production of
hydrocarbon fluids from the subsurface formation. The wellbore is
lined with a string of production casing.
[0082] In FIG. 2A, the casing has been perforated in each of a
first zone, a second zone, and a third zone.
[0083] In FIG. 2B, a fracturing fluid is being injected through the
perforations in the casing. The subsurface formation is being
fractured along the first zone, the second, and the third zone.
[0084] In FIG. 2C, vertical fractures have been formed in each of
the first, second, and third zones.
[0085] In FIG. 2D, the wellbore has been placed in full production.
Hydrocarbon fluids are being produced from the subsurface formation
along each of the first, second, and third zones. A first zone of
production is seen along each of the wellbore zones.
[0086] In FIG. 2E, production from the wellbore has been
temporarily suspended. Fluid is now being injected through the
perforations along each of the first, second, and third zones under
high pressure.
[0087] In FIG. 2F, a first new set of fractures is formed in each
of the first, second and third zones. The new sets of fractures
extend from the original vertical fractures at least partially in a
direction that is transverse to the original vertical
fractures.
[0088] In FIG. 2G, the wellbore has been placed back in production.
Hydrocarbon fluids are again being produced from the subsurface
formation along each of the first, second, and third zones. A
second larger zone of production is seen along each of the
zones.
[0089] In FIG. 2H, production from the wellbore has been
temporarily suspended. Fluid is now being reinjected under high
pressure into the subsurface formation through perforations in each
of the first, second, and third zones.
[0090] In FIG. 2I, a second new set of fractures has been formed.
The fractures in the second new set of fractures extend from the
original vertical fractures and the first new set of fractures.
[0091] In FIG. 2J, the wellbore has been put back into production.
Hydrocarbon fluids are being produced through the second and first
new sets of fractures, along with the original vertical fractures.
A third larger zone of production is seen around each of the
zones.
[0092] In FIG. 2K, new intermediate perforations have been formed
along the casing. The illustrative perforations are oriented at an
angle non-transverse to the casing. The subsurface formation has
also been fractured from the intermediate perforations.
[0093] FIGS. 3A and 3B are a single flowchart showing steps for
performing a method of producing hydrocarbons from a subsurface
formation.
[0094] FIGS. 4A through 4Q are perspective views of a bottom
portion of the wellbore of FIG. 1. The wellbore is again divided
into three illustrative zones for the production of hydrocarbon
fluids from the subsurface formation. The wellbore is lined with a
string of production casing.
[0095] In FIG. 4A, the casing has been perforated in each of a
first zone, a second zone, and a third zone.
[0096] In FIG. 4B, a fracturing fluid is being injected through the
perforations in the casing. The subsurface formation is being
fractured along the first, the second, and the third zones.
[0097] In FIG. 4C, fractures in a vertical plane have been formed
in each of the first, second, and third zones.
[0098] In FIG. 4D, the wellbore has been placed in production.
Hydrocarbon fluids are being produced from the subsurface formation
along each of the first, second, and third zones. A first zone of
production is seen along each of the wellbore zones.
[0099] In FIG. 4E, production from the second zone has been
temporarily suspended. A fluid is also being injected into the
second zone. This raises the reservoir pressure along the second
zone, and extending into stress fields along the first and third
zones.
[0100] In FIG. 4F, production from each of the first and third
zones has been temporarily suspended. Fracturing fluids are now
being injected into the subsurface formation along the first and
third zones under high pressure. Fluids are also being injected
into the second zone to maintain formation pressure.
[0101] In FIG. 4G, first new sets of fractures have been created in
the first and third zones. The first new fractures propagate at
least partially towards the second (intermediate) zone. Stated
another way, the new sets of fractures extend at least partially
from the original vertical fractures in a direction that is at
least partially transverse to the vertical fractures.
[0102] In FIG. 4H, the wellbore has been placed back in full
production. Hydrocarbon fluids are again being produced from the
subsurface formation along each of the first, second, and third
zones. A second larger zone of production is seen along the first
and third zones.
[0103] In FIG. 4I, production has been temporarily suspended from
the first zone. Fluid is now being injected into the subsurface
formation through perforations in the first zone to raise reservoir
pressure in the first zone and extending into the stress field of
the second zone.
[0104] In FIG. 4J, production has been suspended from the second
zone as well. Fracturing fluid is being injected into the
subsurface formation along the second zone under high pressure in
order to form a new set of fractures.
[0105] In FIG. 4K, new fractures have been formed along the second
zone. The fractures in the second new set of fractures extend from
the original vertical fractures and towards the first zone. Stated
another way, the second set of fractures extends from the original
vertical fractures in a direction that is transverse, or at least
partially transverse, to the vertical fractures.
[0106] In FIG. 4L, the wellbore has been put back into production.
Hydrocarbon fluids are being produced through the first new sets of
fractures and the original vertical fractures in each of the first,
second, and third zones. A second larger zone of production is now
seen along the second zone.
[0107] In FIG. 4M, production has been temporarily suspended from
the third zone. Fluid is now being injected into the subsurface
formation through perforations in the third zone to raise reservoir
pressure in the third zone and extending into the second zone.
[0108] In FIG. 4N, production has been temporarily suspended from
the second zone as well. Fluid is being injected into the
subsurface formation along the second zone under high pressure in
order to form a new set of fractures.
[0109] In FIG. 4O, new fractures have again been formed along the
second zone. The fractures in the new set of fractures extend from
the original vertical fractures and towards the third zone.
[0110] In FIG. 4P, the wellbore has been put back into production.
Hydrocarbon fluids are being produced through the new sets of
fractures and the original vertical fractures in each of the first,
second, and third zones. A third larger zone of production is seen
along the second zone.
[0111] In FIG. 4Q, new intermediate perforations have been formed
along the casing. The illustrative perforations are oriented at an
angle non-transverse to the casing. The subsurface formation has
also been fractured from the intermediate perforations.
[0112] FIGS. 5A through 5C are a single flowchart showing steps for
performing a method of producing hydrocarbons from a subsurface
formation.
[0113] FIG. 6A shows a perspective view of a designed fracture
network.
[0114] FIG. 6B is another perspective view of a designed fracture
network
[0115] FIG. 7 provides a plan view of a hydrocarbon development
area. A well layout and completion arrangement is set out for the
creation of a fracture network and the subsequent production of
hydrocarbon fluids.
[0116] FIG. 8 is a flow chart showing steps for performing a method
of creating a network of fractures in a reservoir, in one
embodiment. The reservoir preferably represents a rock matrix
having a low permeability.
[0117] FIG. 9 is a flow chart setting forth various steps for
determining or for monitoring in situ stresses in a stress
field.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
[0118] As used herein, the term "hydrocarbon" refers to an organic
compound that includes primarily, if not exclusively, the elements
hydrogen and carbon. Hydrocarbons generally fall into two classes:
aliphatic, or straight chain hydrocarbons, and cyclic, or closed
ring, hydrocarbons including cyclic terpenes. Examples of
hydrocarbon-containing materials include any form of natural gas,
oil, coal, and bitumen that can be used as a fuel or upgraded into
a fuel.
[0119] As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids.
For example, hydrocarbon fluids may include a hydrocarbon or
mixtures of hydrocarbons that are gases or liquids at formation
conditions, at processing conditions or at ambient conditions
(15.degree. C. and 1 atm pressure). Hydrocarbon fluids may include,
for example, oil, natural gas, coalbed methane, shale oil,
pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and
other hydrocarbons that are in a gaseous or liquid state.
[0120] As used herein, the terms "produced fluids" and "production
fluids" refer to liquids and/or gases removed from a subsurface
formation, including, for example, an organic-rich rock formation.
Produced fluids may include both hydrocarbon fluids and
non-hydrocarbon fluids. Production fluids may include, but are not
limited to, oil, pyrolyzed shale oil, gas, synthesis gas, a
pyrolysis product of coal, carbon dioxide, hydrogen sulfide and
water (including steam).
[0121] As used herein, the term "fluid" refers to gases, liquids,
and combinations of gases and liquids, as well as to combinations
of gases and solids, combinations of liquids and solids, and
combinations of gases, liquids, and solids.
[0122] As used herein, the term "gas" refers to a fluid that is in
its vapor phase at 1 atm and 15.degree. C.
[0123] As used herein, the term "oil" refers to a hydrocarbon fluid
containing primarily a mixture of condensable hydrocarbons.
[0124] As used herein, the term "subsurface" refers to geologic
strata occurring below the earth's surface.
[0125] The term "zone of interest" refers to a portion of a
formation containing hydrocarbons.
[0126] As used herein, the term "formation" refers to any definable
subsurface region. The formation may contain one or more
hydrocarbon-containing layers, one or more non-hydrocarbon
containing layers, an overburden, and/or an underburden of any
geologic formation.
[0127] As used herein, the term "hydrocarbon-rich formation" refers
to any formation that contains more than trace amounts of
hydrocarbons. For example, a hydrocarbon-rich formation may include
portions that contain hydrocarbons at a level of greater than 5
percent by volume. The hydrocarbons located in a hydrocarbon-rich
formation may include, for example, oil, natural gas, heavy
hydrocarbons, and solid hydrocarbons.
[0128] As used herein, the term "organic-rich rock" refers to any
rock matrix holding solid hydrocarbons and/or heavy hydrocarbons.
Rock matrices may include, but are not limited to, sedimentary
rocks, shales, siltstones, sands, silicilytes, carbonates, and
diatomites. Organic-rich rock may contain kerogen.
[0129] As used herein, the term "hydraulic fracture" refers to 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 inventions herein are not limited to use in hydraulic
fractures. The invention is suitable for use in any fracture
created in any manner considered to be suitable by one skilled in
the art. 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.
[0130] As used herein, the term "wellbore" refers to a hole in the
subsurface made by drilling or insertion of a conduit into the
subsurface. A wellbore may have a substantially circular cross
section, or other cross-sectional shapes. As used herein, the term
"well", when referring to an opening in the formation, may be used
interchangeably with the term "wellbore."
Description of Selected Specific Embodiments
[0131] The inventions are described herein in connection with
certain specific embodiments. However, to the extent that the
following detailed description is specific to a particular
embodiment or a particular use, such is intended to be illustrative
only and is not to be construed as limiting the scope of the
inventions.
[0132] FIG. 1 is a cross-sectional view of an illustrative wellbore
100. The wellbore 100 defines a bore 105 that extends from a
surface 101, and into the earth's subsurface 110. The bore 105
preferably includes a shut-in valve 108. The shut-in valve 108
controls the flow of production fluids from the wellbore 100 in the
event of a catastrophic event at the surface 101.
[0133] The wellbore 100 includes a wellhead, shown schematically at
120. The wellhead 120 contains various items of flow control
equipment such as a lower master fracturing valve 122 and an upper
master fracturing valve 124. It is understood that the wellhead 120
will include other components during the formation and completion
of the wellbore 100, such as a blowout preventer (not shown). In a
subsea context, the wellhead may also include a lower marine riser
package.
[0134] The wellbore 100 has been completed by setting a series of
pipes into the subsurface 110. These pipes include a first string
of casing 130, sometimes known as surface casing or a conductor.
These pipes also include a final string of casing 150, known as a
production casing. The pipes also include one or more sets of
intermediate casing 140. Typically, the string of surface casing
130 and the intermediate string of casing 140 are set in place
using a cement sheath. A cement sheath 135 is seen isolating the
subsurface 110 along the surface casing 130, while a cement sheath
145 is seen isolating the subsurface 110 along the intermediate
casing 140.
[0135] The illustrative wellbore 100 is completed horizontally. A
horizontal portion is shown at 160. The horizontal portion 160 has
a heel 162. The horizontal portion 160 also has a toe 164 that
extends through a hydrocarbon-bearing interval 170. While the
wellbore 100 is shown as a horizontal completion, it is understood
that the present inventions have equal application in deviated
wells that extend through more than one zone of interest.
[0136] In FIG. 1, the horizontal portion 160 of the wellbore 100
extends laterally through a formation 170. The formation 170 may be
a carbonate or sand formation having good consolidation but poor
permeability. More preferably, however, the formation 170 is a
shale formation having low permeability. In any instance, the
formation 170 may have a permeability of less than 100
millidarcies, or less than 50 millidarcies, or less than 10
millidarcies, or even less than 1 millidarcy.
[0137] For the illustrative wellbore 100, the production casing 150
represents a liner. This means that the casing 150 does not extend
back to the surface 101, but is hung from an intermediate string of
casing 140 using a liner hanger 152. The production casing 150
extends substantially to the toe 164 of the wellbore 100, and is
cemented in place with a cement sheath 155.
[0138] The horizontal portion 160 of the wellbore 100 extends for
many hundreds of feet. For example, the horizontal portion 160 may
extend for over 250 feet, or over 1,000 feet, or even more than
5,000 feet. Extending the horizontal portion 160 of the wellbore
100 such great distances increases the exposure of the
low-permeability formation 170 to the wellbore 100.
[0139] To permit the in-flow of hydrocarbon fluids from the
formation 170 into the production casing 150, the production casing
150 is perforated. Perforations are shown at 157. While only three
sets of perforations 157 are shown, it is understood that the
horizontal portion 160 may have many more sets of perforations
157.
[0140] In preparation for the production of hydrocarbons, the
operator may wish to stimulate the formation 170 by circulating an
acid solution. This serves to clean out residual drilling mud both
along the wall of the borehole 105 and into the near-wellbore
region (the region within formation 170 close to the production
casing 150). In addition, the operator may wish to fracture the
formation 170. This is done by injecting a fracturing fluid under
high pressure through the perforations 157 and into the formation
170. The fracturing process creates fissures 159 along the
formation 170 to enhance fluid flow into the production casing
150.
[0141] To facilitate the injection of fracturing fluid and
stimulation fluid into the formation 170, the wellbore 100 may be
apportioned into sections or zones. In the illustrative wellbore
100 of FIG. 1, the horizontal portion 160 is divided into three
zones 154, 156, 158. While only three zones are shown in FIG. 1, it
is understood that a horizontally completed wellbore may be divided
into numerous additional zones. Each zone may represent, for
example, a length of up to about 30 meters (100 feet). In
operation, the operator may fracture and treat each zone 154, 156,
158 separately.
[0142] It is desirable to increase the complexity of fractures 159
in the formation 170. This increases the exposure of the rock
matrix making up the formation 170 to the perforations 157 and,
hence, to the bore 105. Therefore, a process is provided herein
whereby fractures may be incrementally formed within the formation
170 at different axes and angles. Illustrative steps for such a
process, in one embodiment, are shown in FIGS. 2A through 2K.
[0143] FIGS. 2A through 2K are perspective views of a bottom
portion of a wellbore 200. The wellbore 200 may be the bottom
portion of illustrative wellbore 100 of FIG. 1, in one embodiment.
The wellbore 200 is completed as a deviated wellbore through a
subsurface formation 250. The illustrative wellbore 200 is
completed substantially horizontally.
[0144] The subsurface formation 250 represents a rock matrix having
limited permeability. For example, the formation may have a
permeability less than about 10 millidarcies. The subsurface
formation represents a hydrocarbon-producing reservoir such as a
tight-gas formation, a shale gas formation, or a coal bed methane
formation. The reservoir may contain methane along with so-called
acid gases such as carbon dioxide and hydrogen sulfide. The
reservoir may also incidentally contain water or brine.
[0145] The wellbore 200 includes a string of casing 202. The casing
202 has been cemented into the formation 250. A cement sheath 204
is shown cut away in each of FIGS. 2A through 2K. The casing 202
defines an elongated tubular body forming a bore 205 therethrough.
In the wellbore arrangement of FIGS. 2A through 2K, the bore 205 is
bifurcated into sections 240 and 245. The sections 240, 245 are
separated by a wall 242 so that no fluid communication exists
between the sections 240, 245. Each of sections 240 and 245 has a
semi-circular profile. However, other profiles may be employed.
[0146] The benefit of bifurcating the bore 205 is that it permits
the operator to alternatively produce fluids from and inject fluids
into the subsurface formation 250. This may be done without running
alternating strings of production tubing and injection tubing into
and out of the casing 202. However, the methods claimed below
permit either the use of a bifurcated tubular body or the cyclical
running of production and tubing strings. Further, the claims allow
for the placement of both a tubing string and an injection string
together within the bore 205 of the casing (as shown in FIGS. 4A
through 4Q).
[0147] In FIG. 2A, separate arrows "P" and "I" are seen. Arrow "I"
indicates a path of injection for fluids into the subsurface
formation 250. Injection fluids may travel through section 240.
Similarly, arrow "P" indicates a flow of production fluids from the
subsurface formation 250. Production fluids may travel through
section 245.
[0148] In each of FIGS. 2A through 2K, the wellbore 200 is divided
into three illustrative zones 210, 220, 230. Each zone 210, 220,
230 is within the subsurface formation 250 and passes through
hydrocarbon fluids.
[0149] In FIG. 2A, the casing 202 has been perforated in the first
zone 210, the second zone 220, and the third zone 230. Perforations
in the first zone 210 are seen at 212; perforations in the second
zone 220 are seen at 222; and perforations in the third zone 230
are seen at 232. The perforations 212, 222, 232 extend through the
casing 202 and the cement sheath 204, and place the bore 205 in
fluid communication with the surrounding formation 250.
[0150] FIG. 2B presents a next view of the wellbore 200. In FIG.
2B, a fracturing fluid is being injected into the subsurface
formation 250. Fluid flows into section 240 in accordance with
arrow "I." From there, the fluid flows under high pressure through
the perforations 212, 222, 232 in the casing 202, and into the
subsurface formation 250. Arrows 216 indicate the flow of
fracturing fluid into the first zone 210; arrows 226 indicate the
flow of fluid into the second zone 226; and arrows 236 indicate the
flow of fluid into the third zone 236.
[0151] FIG. 2C presents a next view of the wellbore 200. In FIG.
2C, the fracturing fluid has created vertical fractures in each of
the first 210, second 220, and third 230 zones. Vertical fractures
214' are formed along the first zone 210; vertical fractures 224'
are formed along the second zone 220; and vertical fractures 234'
are formed along the third zone 230. While the vertical fractures
214', 224', 234' are shown in linear form, it is understood that
the fractures will actually be planar. In addition, while each of
the vertical fractures 214', 224', 234' are shown in only two
lines, it is understood that each zone 210, 220, 230 will most
likely be fractured along more than one vertical plane. Again, it
also understood that while fractures are referred to and
illustrated as vertical fractures, that fractures tend to propagate
vertically and/or horizontally perpendicular to the direction of
least principal stress, the fractures together forming an
approximately vertically oriented planar fracture. In other words,
if the horizontal directions are the x and y axes and the vertical
direction is defined by a z axis, and the direction of least
principal stress is in the x direction, multiple fractures would
form in the y-z plane.
[0152] FIG. 2D presents a next view of the wellbore 200. In FIG.
2D, the wellbore 200 has been placed in full production.
Hydrocarbon fluids are being produced from the subsurface formation
250 along each of the first 210, second 220, and third 230 zones.
Fluids flow from the subsurface formation 250, through the vertical
fractures 214', 224', 234', and through the respective perforations
212, 222, 232. From there, production fluids flow through section
245 within the casing 202, and towards the surface (not shown)
according to arrow "P."
[0153] It is noted that each of the fractures 214', 224', 234'
creates a first zone of production. This is indicated schematically
in FIG. 2D. The first zone of production in the first zone 210 is
seen at 215'; the first zone of production in the second zone 220
is seen at 225'; and the first zone of production in the third zone
is seen at 235'. Because of the low permeability of the rock matrix
making up the subsurface formation 250, the zones of production
215', 225', 235' remain closely tied to the fracture planes created
by the vertical fractures 214', 224', 234'.
[0154] In accordance with one of the methods of producing
hydrocarbons herein, the wellbore 200 is monitored during
production. Particularly, the wellbore 200 is monitored to
determine when a change in the orientation of maximum principal
stress may occur within the subsurface formation 250.
[0155] The wellbore 200 may be monitored in various ways. For
example, monitoring the wellbore 200 may comprise determining when
a designated volume of hydrocarbon fluids have been produced from
the wellbore 200. Alternatively, monitoring the wellbore 200 may
comprise determining when a designated reduction in reservoir
pressure within the subsurface formation 250 has taken place. This
may be done through reservoir simulation or may be based on
experience with existing wells in the field.
[0156] Alternatively still, monitoring the wellbore 200 may
comprise determining when a selected period of time of production
has taken place. And alternatively still, monitoring the wellbore
200 may comprise determining whether micro-seismic readings or
tilt-meter readings indicate a change in in situ stresses.
Combinations of these techniques are preferably employed.
[0157] FIG. 2E presents a next view of the wellbore 200. In FIG.
2E, production from the wellbore 200 has been suspended. This takes
place once it is determined that the orientation of maximum
principal stress in the first 210, second 220, and third 230 zones
has changed. In FIG. 2E, fluid is now being injected through the
perforations 212, 222, 232 along each of the three zones 210, 220,
230 under high pressure. Fluid travels according to injection arrow
"I" into the first section 240 of the casing 202. Fluid then exits
the casing 202 through the perforations 212, 222, 232 according to
respective fracture injection arrows 216, 226, 236.
[0158] FIG. 2F presents a next view of the wellbore 200. In FIG.
2F, a first new set of fractures is formed in each of the first
210, second 220, and third 230 zones. New fractures in the first
zone 210 are seen at 214''; new fractures in the second zone 220
are seen at 224''; and new fractures in the third zone 230 are seen
at 234''. The new fractures 214'' in the first zone 210 largely
extend from the original vertical fractures 214' in that zone 210.
Similarly, the new fractures 224'' in the second zone 220 largely
extend from the original vertical fractures 224' in that zone 220.
Similarly still, the new fractures 234'' in the third zone 230
largely extend from the original vertical fractures 234' in that
zone 230. Each of the new fractures 214'', 224'', 234'' extends at
least partially in a direction that is transverse to the respective
vertical fractures 214', 224', 234'. This is because of the change
in maximum principal stress within the subsurface formation 250.
The result is that the complexity of the fracture network within
the subsurface formation 250 has beneficially increased, even using
just a single wellbore.
[0159] The direction in which the new fractures 214'', 224'', and
234'' propagate should be re-emphasized. Because of the change in
maximum principal stress within the subsurface formation 250, the
new fractures 214'', 224'', 234'' will at least initially extend
away from the planes of the original vertical fractures 214', 224',
and 234'. However, as the new fractures 214'', 224'', and 234''
propagate away from the vertical fractures 214', 224', 234', they
move through a transition area of maximum principal stress and
begin to bend back so that the plane formed by the new fractures
214'', 224'', and 234'' is in approximate alignment or parallel
with the plane formed by the original vertical fractures 214', 224'
and 234'.
[0160] FIG. 2G presents a next view of the wellbore 200. In FIG.
2G, the wellbore 200 has been placed back in full production.
Hydrocarbon fluids are again being produced from the subsurface
formation 250 along each of the first 210, second 220, and third
230 zones. In the first zone 210, fluids flow from the subsurface
formation 250, through the first set of new fractures 214'',
through the vertical fractures 214', through the perforations 212,
and into the casing 202. In the second zone 220, fluids flow from
the subsurface formation 250, through the first set of new
fractures 224'', through the vertical fractures 224', through the
perforations 222, and into the casing 202. In the third zone 230,
fluids flow from the subsurface formation 250, through the first
set of new fractures 234'', through the vertical fractures 234',
through the perforations 232, and into the casing 202.
[0161] The fluids from the various zones 210, 220, 230 are
commingled within the second section 245 of the casing 202. From
there, production fluids flow toward the surface according to arrow
"P."
[0162] It is noted that in connection with each zone 210, 220, 230,
the new fractures 214'', 224'', 234'' create respective second
zones of production. This is indicated schematically in FIG. 2G.
The second zone of production in the first zone 210 is seen at
215''; the second zone of production in the second zone 220 is seen
at 225''; and the second zone of production in the third zone 230
is seen at 235''. Because of the low permeability of the rock
matrix making up the subsurface formation 250, the zones of
production 215'', 225'', 235'' remain closely tied to the fracture
planes created by the new sets of fractures 214'', 224'', 234''.
However, the second zones of production 215'', 225'', 235'' are
larger than their respective first zones of production 215', 225',
235'.
[0163] In accordance with one of the methods of producing
hydrocarbons herein, the wellbore 200 is once again monitored
during production. Particularly, the wellbore 200 is monitored to
determine when a change in the orientation of maximum principal
stress may once again occur within the subsurface formation
250.
[0164] FIG. 2H presents a next view of the wellbore 200. In FIG.
2H, production from the wellbore 200 has been suspended. This takes
place once it is determined that the orientation of maximum
principal stress in the first 210, second 220, and third 230 zones
has once again changed. In FIG. 2H, fluid is now being re-injected
through the perforations 212, 222, 232 along each of the three
zones 210, 220, 230 under high pressure. Fluid travels according to
injection arrow "I" into the first section 240 of the casing 202.
Fluid then exits the casing 202 through the perforations 212, 222,
232 according to respective fracture injection arrows 216, 226,
236.
[0165] FIG. 2I presents a next view of the wellbore 200. In FIG.
2I, a second new set of fractures is formed in each of the first
210, second 220, and third 230 zones. New fractures in the first
zone 210 are seen at 214'''; new fractures in the second zone 220
are seen at 224'''; and new fractures in the third zone 230 are
seen at 234'''. The new fractures 214''' in the first zone 210
largely extend from the first new fractures 214'' in that zone 210.
Similarly, the new fractures 224''' in the second zone 220 largely
extend from the first new fractures 224'' in that zone 220.
Similarly still, the new fractures 234''' in the third zone 230
largely extend from the first new fractures 234'' in that zone
230.
[0166] Each of the second new fractures 214''', 224''', 234'''
extends at least partially in a direction that is transverse to the
respective vertical fractures 214', 224', 234'. This is because of
the change in maximum principal stress within the subsurface
formation 250. The result is that the complexity of the fracture
network within the subsurface formation 250 has beneficially
increased. However, as the second new fractures 214''', 224''', and
234''' propagate away from the vertical fractures 214', 224', 234',
they move through a transition area of maximum principal stress and
begin to bend back so that the plane formed by the new fractures
214''', 224''', and 234''' is in approximate alignment or parallel
with the plane formed by the original vertical fractures 214', 224'
and 234', just as the first new fractures 214'', 224'', 234''
did.
[0167] FIG. 2J presents a next view of the wellbore 200. In FIG.
2J, the wellbore 200 has been put back into production. Hydrocarbon
fluids are again being produced from the subsurface formation 250
along each of the first 210, second 220, and third 230 zones. In
the first zone 210, production fluids flow from the subsurface
formation 250 and through the fracture network formed by fractures
214', 214'', and 214'''. The production fluids then flow through
the perforations 212 and into the casing 202. In the second zone
220, production fluids flow from the subsurface formation 250 and
through the fracture network formed by fractures 224', 224'',
224'''. The production fluids then flow through the perforations
222 and into the casing 202. In the third zone 230, production
fluids flow from the subsurface formation 250 and through the
fracture network formed by fractures 234', 234'', 234'''. The
production fluids then flow through the perforations 232 and into
the casing 202.
[0168] The fluids from the various zones 210, 220, 230 are
commingled within the second section 245 of the casing 202. From
there, production fluids flow toward the surface according to arrow
"P."
[0169] It is noted that in connection with each zone 210, 220, 230,
the new fractures 214''', 224''', 234''' create respective third
zones of production. This is indicated schematically in FIG. 2J.
The third zone of production in the first zone 210 is seen at
215'''; the third zone of production in the second zone 220 is seen
at 225'''; and the third zone of production in the third zone is
seen at 235'''. Because of the low permeability of the rock matrix
making up the subsurface formation 250, the zones of production
215'', 225'', 235'' remain closely tied to the fracture planes
created by the second new fractures 214'', 224'', 234''. However,
the third zones of production 215''', 225''', 235''' are larger
than their respective second zones of production 215'', 225'',
235''.
[0170] As can be seen, multiple cycles of fracturing, producing,
and monitoring may be employed in order to create an ever-expanding
network of fractures. However, in low-permeability formations the
fracture networks created within the separate zones may or may not
interconnect. Accordingly, an additional optional fracturing step
may be employed. That step involves the placement of additional
perforations and corresponding fractures intermediate to the first
210, second 220, and/or third 230 zones.
[0171] FIG. 2K presents this optional additional step. In FIG. 2K,
new intermediate perforations have been formed along the casing
202. First, perforations 262 are formed between the first zone 210
and the second zone 220. Second, perforations 272 are formed
between the second zone 220 and the third zone 230. Intermediate
fractures 264 are created from perforations 262, while intermediate
fractures 274 are created from perforations 274.
[0172] It is preferred that the perforations 262, 272 be oriented
at an angle that is non-transverse to the casing 202. In this way,
fractures 264, 274 are at least initially propagated at an angle,
and may intersect with fractures in adjoining zones.
[0173] FIGS. 3A and 3B present a flow chart showing steps for a
method 300 of producing hydrocarbons from a subsurface formation.
The method 300 generally presents the steps from FIGS. 2A through
2K.
[0174] The method 300 has application to subsurface formations with
limited permeability. The method 300 is particularly beneficial to
formations having a permeability less than about 10 millidarcies.
According to the method 300, the subsurface formation represents a
hydrocarbon-producing reservoir such as a tight-gas formation, a
shale gas formation, or a coal bed methane formation. The reservoir
may contain methane along with so-called acid gases such as carbon
dioxide and hydrogen sulfide.
[0175] The method 300 first includes providing a wellbore in the
subsurface formation. This is shown at Box 305. The wellbore has
been formed as a deviated wellbore. Preferably, the deviated
wellbore is completed as a substantially horizontal wellbore within
the subsurface formation.
[0176] For purposes of this disclosure, the term "providing" is
intended to be broad. "Providing" a wellbore means that the
wellbore has been drilled by a government, by a company, or by an
individual, association, or partnership. Alternatively, "providing"
may mean that a drilling company or a service company has drilled
the wellbore at the request or direction of a government, a
company, or an individual, association or partnership.
Alternatively still, "providing" may mean that a government, an
individual, an association, or a business concern has purchased the
wellbore. In any instance, the wellbore has been perforated within
the subsurface formation along at least a first zone and a second
zone. The wellbore may have been perforated by the owner, the
lessor, or by a service company or business affiliate on behalf of
the owner or lessor.
[0177] The method 300 also includes fracturing the subsurface
formation along the first and second zones. This is provided at Box
310. Fracturing the formation along these zones creates one or more
substantially vertical fractures extending from the wellbore. Where
the wellbore is substantially horizontal, the fractures will be
transverse to the wellbore, oriented in a vertical plane.
[0178] The method 300 further includes producing hydrocarbon fluids
through the vertical fractures along the first and second zones.
This is seen at Box 315. In one aspect, the vertical fractures
extend a distance of about 100 feet (30.5 meters) to 500 feet
(152.4 meters) from the wellbore. Of course, non-hydrocarbon fluids
such as water and carbon dioxide may be incidentally produced along
with the hydrocarbon fluids.
[0179] The method 300 also includes monitoring the wellbore. This
is provided at Box 320. Monitoring the wellbore is conducted to
determine when a change in the direction or orientation of maximum
principal stress may occur within the subsurface formation along
the first and second zones. The wellbore may be monitored in a
number of different ways as discussed above.
[0180] The method 300 additionally includes injecting a fracturing
fluid into the subsurface formation. This is provided at Box 325.
The fluid is preferably a hydraulic fluid such as brine. However,
liquid CO.sub.2, foamed nitrogen, or other non-reactive fluids may
also be injected. The fluid is injected through perforations in the
first and second zones. This serves to create first new fractures
within the subsurface formation that at least partially extend from
the vertical fractures along a plane that is substantially
transverse to, or at least at an angle to, the vertical
fractures.
[0181] The method 300 also includes producing hydrocarbons. This is
shown at Box 330. Hydrocarbon fluids are produced through the first
new fractures and through the vertical fractures along the first
and second zones.
[0182] The method 300 as described above only recites two zones.
However, the method 300 may include more than two zones. In one
aspect, the wellbore is perforated to create new perforations along
a third zone. This is provided at Box 335. Perforations may be
provided along the first zone, the second zone, and a third zone,
with the zones being separated by a distance of between, for
example, about 20 feet (6.1 meters) and 500 feet (152.4 meters).
The perforations along the third zone may be provided at the same
time as the perforations along the first and second zones or at a
later time. Accordingly, it should be understood that the methods
300 described herein may be applicable on any number of zones,
including two or more zones. Additionally or alternatively, the
methods 300 described herein may be implemented on multiple zones
in either a simultaneous manner or in a sequential manner. For
convenience in describing the methods herein, the multiple zones
are referenced by ordinals such as first, second, third, etc. It
should be understood that reference to a first zone in an
illustration is exemplary of any of the other zones and is merely
for identification purposes and for description of one zone
relative to another. The principles and steps of the methods
described herein may be applied with respect to any one or more
zones in a wellbore.
[0183] Accordingly, in some implementations, the method 300 may
then include fracturing the subsurface formation along the third
zone to form additional vertical fractures extending from the
wellbore. This is seen at Box 340.
[0184] Where a third zone is perforated, the method 300 also
includes producing hydrocarbon fluids through the vertical
fractures in the third zone. This is shown at Box 345. During
production, the wellbore continues to be monitored. Hence,
monitoring the wellbore further comprises monitoring the wellbore
to determine when a change in orientation of maximum principal
stress may occur within the subsurface formation along the third
zone. This is seen at Box 350. In this embodiment, production from
the third zone preferably takes place simultaneously with
production from the first and second zones. In other words, the
production steps in Boxes 315 and 350 may overlap.
[0185] Where a third zone is perforated, the method 300 also
includes injecting a fracturing fluid through perforations in the
third zone. This is provided at Box 355. The injection step of Box
355 may be done simultaneously with the injection step of Box 325.
In addition, the method 300 includes producing hydrocarbons through
the first set of new fractures along the third zone. This is shown
at Box 360. The production step of Box 360 is preferably done
simultaneously with the production step of Box 330.
[0186] It is noted here that still additional zones may optionally
be perforated, fractured, and produced in accordance with the steps
described above. For example, new perforations may be formed in a
selected zone, as shown in Box 365 of FIG. 3B. Preferably, the new
perforations along the selected zone are shot at a non-transverse
angle relative to the wellbore. The subsurface formation is then
fractured along the selected zone, as indicated at Box 370.
Perforating the wellbore at an oriented angle helps cause fractures
to form at an angle so as to intersect existing natural fractures
and artificial fractures from adjoining zones.
[0187] The perforating 365 and fracturing 370 steps may be
conducted in stages with the first, second, and third zones using
multi-interval procedures. For the present method 300, the
injection stages may be aided through the use of packers,
fracturing ports, mechanical plugs, sand plugs, sliding sleeves,
and other devices known in the art. Hydrocarbon fluids are then
produced through the perforations along the selected zone.
[0188] It is also noted that additional cycles of fracturing,
producing, and monitoring may be undertaken. Thus, the method 300
may include the step of injecting a fracturing fluid into the
subsurface formation through perforations in the first, second, and
third zones, thereby creating a second new set of fractures within
the subsurface formation. The second new fractures will at least
partially extend from the vertical fractures. Alternatively or in
addition, the second new fractures will at least partially extend
from the first new fractures as shown and discussed in connection
with FIG. 2I. In any instance, the second new fractures extend
along a plane that is at least partially transverse to the vertical
fractures. Hydrocarbons are then produced through (i) the second
new fractures, (ii) the first new fractures, and (iii) the vertical
fractures along the first, second, and third zones.
[0189] The method 300 allows for the creation of a complex network
of fractures using only a single wellbore. In the method 300, the
wellbore may be divided into a plurality of zones, with the zones
being fractured and produced from together. However, it is also
proposed herein to create a complex network of fractures from a
single wellbore wherein the various zones are not always fractured
and produced from together. This is demonstrated through a process
shown in FIGS. 4A through 4Q.
[0190] FIGS. 4A through 4Q provide perspective views of a bottom
portion of a wellbore 400. The wellbore 400 may be the bottom
portion of illustrative wellbore 100 of FIG. 1, in one embodiment.
The wellbore 400 is completed as a deviated wellbore through a
subsurface formation 450 having low permeability. The illustrative
wellbore 400 is completed substantially horizontally.
[0191] The wellbore 400 includes a string of casing 402. The casing
402 has been cemented into the formation 450. A cement sheath 404
is seen in cut-away view in each of FIGS. 4A through 4Q. The casing
402 defines an elongated tubular body forming a bore 405
therethrough. In the wellbore arrangement of FIGS. 4A through 4Q,
the bore 405 employs two separate tubing strings. These represent a
first string 440 used for the injection of fluids into the
subsurface formation 450, and a second string 445 used for the
production of fluids from the subsurface formation 450.
[0192] The benefit of using separate strings 440, 445 within the
bore 205 is that it permits the operator to alternatively inject
fluids into and produce fluids from the subsurface formation 450.
This may be done without running alternating strings of production
tubing and injection tubing into and out of the casing 402.
However, the methods claimed below also permit the use of a
bifurcated tubular body or the cyclical running of production and
tubing strings as discussed above.
[0193] In FIG. 4A, separate arrows "P" and "I" are seen. Arrow "I"
indicates a path of injection for fluids into the subsurface
formation 450. Injection fluids may travel through first tubing
string 440. Similarly, arrow "P" indicates a flow of production
fluids from the subsurface formation 450. Production fluids may
travel through second tubing string 445.
[0194] In each of FIGS. 4A through 4Q, the wellbore 400 is divided
into three illustrative zones 410, 420, 430. Each zone 410, 420,
430 is within the subsurface formation 450 and passes through
hydrocarbon fluids.
[0195] In FIG. 4A, the casing 402 has been perforated in the first
zone 410, in the second zone 420, and in the third zone 430.
Perforations in the first zone 410 are seen at 412; perforations in
the second zone 420 are seen at 422; and perforations in the third
zone 430 are seen at 432. The perforations 412, 422, 432 extend
through the cement sheath 404 and place the bore 405 in fluid
communication with the surrounding formation 450.
[0196] FIG. 4B presents a next view of the wellbore 400. In FIG.
4B, a fracturing fluid is being injected into the subsurface
formation 450. Fluid flows into tubing string 440 in accordance
with arrow "I." From there, the fluid flows under high pressure
through the perforations 412, 422, 432 in the casing 402, and into
the subsurface formation 450. Arrows 416 indicate the flow of
fracturing fluid into the first zone 410; arrows 426 indicate the
flow of fluid into the second zone 426; and arrows 436 indicate the
flow of fluid into the third zone 436.
[0197] FIG. 4C presents a next view of the wellbore 400. In FIG.
4C, the fracturing fluid has created vertical fractures in each of
the first 410, second 420, and third 430 zones. Vertical fractures
414' are formed along the first zone 410; vertical fractures 424'
are formed along the second zone 420; and vertical fractures 434'
are formed along the third zone 430. While the vertical fractures
414', 424', 434' are shown in linear form, it is understood that
the fractures will actually be planar. In addition, while the
vertical fractures 414', 424', 434' are shown in only two lines, it
is understood that each zone 410, 420, 430 will most likely be
fractured along more than one vertical plane.
[0198] FIG. 4D presents a next view of the wellbore 400. In FIG.
4D, the wellbore 400 has been placed in full production.
Hydrocarbon fluids are being produced from the subsurface formation
450 along each of the first 410, second 420, and third 430 zones.
Fluids flow from the subsurface formation 450, through the vertical
fractures 414', 424', 434', and through the respective perforations
412, 422, 432. From there, production fluids flow through tubing
string 445 within the casing 402, and towards the surface (not
shown) according to arrow "P."
[0199] It is noted that each of the fractures 414', 424', 434'
creates a first zone of production. This is indicated schematically
in FIG. 4D as circles. The first zone of production in first zone
410 is seen at 415'; the first zone of production in the second
zone 420 is seen at 425'; and the first zone of production in the
third zone 430 is seen at 435'. Because of the low permeability of
the rock matrix making up the subsurface formation 450, the zones
of production 415', 425', 435' remain closely tied to the fracture
planes created by the vertical fractures 414', 424', 434'.
[0200] FIG. 4E presents a next view of the wellbore 400. In FIG.
4E, production from the second zone 420 has been suspended. A fluid
is now being injected into the subsurface formation 450 along the
second zone 420. This raises the reservoir pressure along the
second zone 420, and extending into the first 410 and third 430
zones. The injection of fluids is indicated by injection arrow "I."
The fluids travel through the first tubing string 440, and exit
perforations 422 in the second zone 420. The injection of fluids
into the subsurface formation 450 is shown by arrows 428.
[0201] It is noted that the injection of fluids into the subsurface
formation, denoted by arrows 428, is at a lower pressure than the
injection of fluids for fracturing purposes. The injection of
fluids under the higher fracturing pressures is denoted by arrows
426 (seen in FIG. 4B). It is preferred in the step of FIG. 4E that
fluids be injected at a pressure lower than the fracturing
pressure, as the purpose is to raise reservoir pressure in the
subsurface formation 450 and modify in situ stresses.
[0202] At the same time as fluids are injected into the second zone
420, production continues in the first 410 and third 430 zones. The
production of fluids is indicated by production arrow "P." The
simultaneous production and injection of fluids requires the use of
separate flow paths. Such an approach is provided through the
separate first 440 and second 445 tubing strings. Alternatively,
this may be provided through separate flow-channels specially
machined in a tubular body as shown at 240, 245 in FIG. 2A.
Alternatively, the casing 402 may be equipped with valves or
sliding sleeves along the casing 402 controlled through fiber
optics or other communication means.
[0203] In one aspect, the step of FIG. 4E takes place once it is
determined that the orientation of maximum principal stress in the
first 410 and third 430 zones has changed. To this end, the
wellbore 400 may be monitored. Particularly, the wellbore 400 may
be monitored to determine when a change in the orientation of
maximum principal stress may occur within the subsurface formation
450.
[0204] The wellbore 400 may be monitored in various ways. For
example, monitoring the wellbore 400 may comprise determining when
a designated volume of hydrocarbon fluids have been produced from
the wellbore 400. Alternatively, monitoring the wellbore 400 may
comprise determining when a designated reduction in reservoir
pressure within the subsurface formation 450 has taken place. This
may be done through reservoir simulation, or may be based on
experience with existing wells in the field.
[0205] Alternatively still, monitoring the wellbore 400 may
comprise determining when a selected period of time of production
has taken place, or when a selected period of injection has taken
place. And alternatively still, monitoring the wellbore 400 may
comprise determining whether micro-seismic readings or tilt-meter
readings indicate a change in in situ stresses. Combinations of
these techniques are preferably employed.
[0206] In any event, at some point it is determined that in situ
stresses in the subsurface formation 450 within the first zone 410
and the third zone 430 have changed. More specifically, the
orientation of maximum principal stress has changed.
[0207] FIG. 4F presents a next view of the wellbore 400. In FIG.
4F, fluid is now being injected into the subsurface formation 450
along the first zone 410 and the third zone 430. Fluid travels
according to injection arrow "I" into the first tubing string 440
in the casing 202. Fluid then exits the casing 402 through the
perforations 412 and 432 as provided by fracture injection arrows
416 and 436, respectively.
[0208] The fluid is injected into the subsurface formation 450
under high pressure. The result is that new fractures are formed in
the subsurface formation 450 along the first 410 and third 430
zones. This again is indicated by fracture injection arrows 416 and
436. At the same time, fluid is optionally also injected at a lower
pressure into the subsurface formation 450 along the second zone
420. This is indicated by fluid injection arrows 428.
[0209] FIG. 4G presents a next view of the wellbore 400. In FIG.
4G, a first new set of fractures has been created in each of the
first 410 and third 430 zones. The new fractures propagate at least
partially towards the second (intermediate) zone 420. Stated
another way, the new sets of fractures extend from the original
vertical fractures in a direction that is at least partially
transverse to the vertical fractures 414', 434'.
[0210] New fractures in the first zone 410 are seen at 414''. The
new fractures 414'' in the first zone 410 largely extend from the
original vertical fractures 414' in that zone 410. New fractures in
the third zone 430 are seen at 434''. The new fractures 434'' in
the third zone 430 largely extend from the original vertical
fractures 434' in that zone 430. Each of the new fractures 414'',
434'' extends at least partially in a direction that is transverse
to the respective vertical fractures 414', 434'. This is because of
the change in maximum principal stress within the subsurface
formation 450. The result is that the complexity of the fracture
network within the subsurface formation 450 has beneficially
increased, even by using just a single wellbore 400.
[0211] The direction in which the new fractures 414'' and 434''
propagate should be re-emphasized. Because of the change in maximum
principal stress within the subsurface formation 450, the new
fractures 414'', 434'' will at least initially extend away from the
planes of the original vertical fractures 414', 434'. However, as
the new fractures 414'', 444'' propagate away from the vertical
fractures 414', 434', they move through a transition area of
maximum principal stress and begin to bend back in so that the
plane formed by the new fractures 414'' and 444'' is in approximate
alignment or parallel with the plane formed by the original
vertical fractures 414' and 434'.
[0212] FIG. 4H presents a next view of the wellbore 400. In FIG.
4H, the wellbore 400 has been placed back in full production.
Hydrocarbon fluids are again being produced from the subsurface
formation 450 along each of the first 410, second 420, and third
430 zones. In the first zone 410, fluids flow from the subsurface
formation 450, through the first new set of fractures 414'',
through the vertical fractures 414', through the perforations 412,
and into the casing 402. In the second zone 420, production fluids
flow from the subsurface formation 250, through the vertical
fractures 424', through the perforations 422, and into the casing
402. In the third zone 430, production fluids flow from the
subsurface formation 450, through the first new set of fractures
434'', through the vertical fractures 434', through the
perforations 432, and into the casing 402.
[0213] The fluids received from the various zones 410, 420, 430 are
commingled within the second tubing string 445 of the casing 402.
From there, production fluids flow toward the surface according to
arrow "P."
[0214] It is noted that in connection with each zone 410, 420, 430,
the new fractures 414'' and 434'' create respective second zones of
production. This is indicated schematically in FIG. 4H as circles.
The second zone of production in first zone 410 is seen at 415'';
the second zone of production in the third zone is seen at 435''.
Because of the low permeability of the rock matrix making up the
subsurface formation 450, the zones of production 415'', 435''
remain closely tied to the fracture planes created by the new sets
of fractures 414'', 434''. However, the second zones of production
415'', 435'' are larger than their respective first zones of
production 415', 435' (as shown in FIG. 4D).
[0215] The second zone 420 is also in production. However, the zone
of production is still the first zone 425'. It is possible though
using the current method and the singular wellbore 400 to increase
the size of the zone of production along the second zone 420. This
is shown in the steps provided in FIGS. 4I through 4P.
[0216] FIG. 4I presents a next view of the wellbore 400. In FIG.
4I, production has been suspended from the first zone 410. Fluid is
now being injected into the subsurface formation 450 through
perforations in the first zone 410 to raise reservoir pressure in
the first zone 410, and extending into the second zone 420. The
fluid injection is indicated by injection arrow "I" and by
injection arrows 418.
[0217] The injection of fluid into the subsurface formation 450
along the first zone 410 is not for the purpose of fracturing the
formation 450, but just to build reservoir pressure. In this way,
the orientation of the maximum principal stress along the second
zone 420 is ultimately changed.
[0218] FIG. 4J presents a next view of the wellbore 400. In FIG.
4J, production has been suspended from the second zone 420 as well.
Fluid is being injected into the formation 450 under high pressure.
Arrows 426 indicate a flow of fracturing fluid.
[0219] In one aspect, the step of FIG. 4J takes place once it is
determined that the orientation of maximum principal stress in the
second zone 420 has changed. To this end, the wellbore 400 may be
monitored. Particularly, the wellbore 400 may be monitored to
determine when a change in the orientation of maximum principal
stress may occur within the subsurface formation 450.
[0220] At the same time as fluids are injected into the second zone
420, production continues in the third 430 zone. The production of
fluids is indicated by production arrow "P." As noted above, the
simultaneous production and injection of fluids requires the use of
separate flow paths. Such an approach is illustratively provided in
FIG. 4I through the separate first 440 and second 445 tubing
strings.
[0221] FIG. 4K presents a next view of the wellbore 400. In FIG.
4K, new fractures 424'' have been formed in the subsurface
formation 450 along the second zone 420. The fractures 424'' extend
from the original vertical fractures 424' and at least partially
towards the first zone 410. Stated another way, the new fractures
424'' extend from the original vertical fractures 424' in a
direction that is at least partially transverse to the vertical
fractures 424'. This is because of the change in maximum principal
stress within the subsurface formation 450.
[0222] FIG. 4L presents a next view of the wellbore 400. In FIG.
4L, the wellbore 400 has been put back into production. Hydrocarbon
fluids are being produced from the subsurface formation 450 along
each of the first 410, second 420, and third 430 zones. Fluids flow
from the subsurface formation 450, through the new transverse
fractures 414'', 424'', 434'', through the vertical fractures 414',
424', 434', and through the respective perforations 412, 422, 432.
From there, production fluids flow through tubing string 445 within
the casing 402, and towards the surface according to arrow "P."
[0223] Of note, a second zone of production 425'' is now provided
along the second zone 420. This is indicated schematically as a
circle in FIG. 4L. The second zone of production 425'' is larger
than the first zone of production seen at 425' in FIG. 4H.
[0224] FIG. 4M presents a next view of the wellbore 400. In FIG.
4M, production has been suspended from the third zone 430. Fluid is
now being injected into the subsurface formation 450 through
perforations in the third zone 430 to raise reservoir pressure in
the third zone 430 and extending into the second zone 420. The
fluid injection is indicated by injection arrow "I" and by
injection arrows 438.
[0225] The injection of fluid into the subsurface formation 450
along the third zone 430 is not for the purpose of fracturing the
formation 450, but just to build reservoir pressure. In this way,
the orientation of the maximum principal stress along the second
zone 420 is ultimately changed. During this time, production may
continue in the second zone 420. Production fluids leave the
subsurface formation through perforations 422 and according to
production arrow "P."
[0226] FIG. 4N presents a next view of the wellbore 400. In FIG.
4N, production has been suspended from the second zone 420 as well.
Fluid is now being injected into the subsurface formation 450 along
the second zone under high pressure in order to form yet additional
fractures. The fluids travel through the first tubing string 440,
and exit perforations 422 in the second zone 420. The injection of
fluids into the subsurface formation 450 is shown by arrows
426.
[0227] At the same time as fluids are injected into the second zone
420, production may continue in the first zone 410. The production
of fluids is indicated by production arrow "P." As noted above, the
simultaneous production and injection of fluids requires the use of
separate flow paths. Such an approach is provided in FIG. 4N
through the separate first 440 and second 445 tubing strings.
[0228] FIG. 4O presents a next view of the wellbore 400. In FIG.
4O, new fractures have again been formed along the second zone 420.
The new fractures are seen at 424''. The new fractures 424'' extend
from the original vertical fractures and towards the third zone
430.
[0229] The direction in which the new fractures 424'' propagate
should be re-emphasized. Because of the change in maximum principal
stress within the subsurface formation 450, the new fractures 424''
will at least initially extend away from the planes of the original
vertical fractures 424'. However, as the new fractures 424''
propagate away from the vertical fractures 424', they move through
a transition area of maximum principal stress and begin to bend
back so that the plane formed by the new fractures 424'' is in
approximate alignment or parallel with the plane formed by the
original vertical fractures 424'.
[0230] FIG. 4P presents a next view of the wellbore 400. In FIG.
4P, the wellbore 400 has been put back into full production.
Hydrocarbon fluids are being produced through the new sets of
fractures 414'', 424'', 434'' and the original vertical fractures
414', 424', 434' in each of the first 410, second 420, and third
430 zones, respectively.
[0231] Hydrocarbon fluids are being produced from the subsurface
formation 450 along each of the first 410, second 420, and third
430 zones. Fluids flow from the subsurface formation 450, through
the new transverse fractures 414'', 424'', 434'', through the
vertical fractures 414', 424', 434', and through the respective
perforations 412, 422, 432. From there, production fluids flow
through tubing string 445 within the casing 402, and towards the
surface according to production arrow "P."
[0232] FIGS. 4A through 4P demonstrate steps that may be taken to
increase the complexity of a fracture network in a low-permeability
formation. Of importance, the steps are accomplished through a
single wellbore which remains in a substantially constant state of
production. As in situ stresses are changed during the course of
production, additional fractures are created within the subsurface
formation, creating ever-expanding zones of production. Ideally,
the fractures in the various zones become interconnected.
[0233] It is noted that the steps shown in FIGS. 4A through 4P need
not be taken in the order demonstrated in the drawings. For
example, the operator may choose to create new transverse fractures
(FIGS. 4I through 4P) in the second zone 420 before creating the
transverse fractures (FIGS. 4B through 4J) in the first 410 and
third 430 zones. Alternatively, transverse fractures may be created
in the first 410 and third 430 zones (FIGS. 4E through 4G)
separately rather than simultaneously. In addition, once transverse
fractures are created in the first 410, second 420, and third 430
zones, additional transverse fractures may be formed simultaneously
in accordance with the steps shown in FIGS. 2E through 2J. Thus,
regardless of the order in which transverse fractures are created,
the complexity of the fracture network within the subsurface
formation 450 is beneficially increased.
[0234] It is further noted that the wellbore 400 with its three
zones 410, 420, 430 is merely illustrative. The steps presented
incident to the wellbore 400 may be taken through just two
adjoining zones without the presence of a third zone.
Alternatively, there may be more than three zones. As discussed
above, the use of three zones and the nomenclature used to refer to
the individual zones is for explanatory purposes. The order of
operations on the individual zones may be independent of the
ordinal assigned to the zone. For example, while a step is
illustrated and discussed as being performed on a first zone
relative to a second zone, the step may be performed on the second
relative to the first, the second relative to the third, the fifth
relative to the sixth, or any other pair of adjacent zones.
[0235] Regardless of the number of zones, it can be seen that
multiple cycles of producing and fracturing may be employed in
order to create an ever-expanding network of fractures. However, in
low-permeability formations the fracture networks created within
the separate zones may or may not interconnect. Accordingly, an
additional optional fracturing step may be employed. That step
involves the placement of additional perforations and corresponding
fractures intermediate to the first 410, second 420, and third 430
zones.
[0236] FIG. 4Q presents this optional additional step. In FIG. 4Q,
new intermediate perforations have been formed along the casing
402. First, perforations 462 are formed between the first zone 410
and the second zone 420. Second, perforations 472 are formed
between the second zone 420 and the third zone 430. Intermediate
fractures 464 are created from perforations 462, while intermediate
fractures 474 are created from perforations 472.
[0237] It is preferred that the perforations 462, 472 be oriented
at an angle that is non-transverse to the casing 402. In this way,
fractures 464, 474 are at least initially propagated at an angle,
and may intersect with fractures in adjoining zones.
[0238] As can be seen, FIGS. 4A through 4Q present steps for a
process of producing hydrocarbon fluids. The steps may be set out
textually in a flowchart. FIGS. 5A through 5C present such a flow
chart, and show steps for a method 500 of producing hydrocarbon
fluids.
[0239] In the method 500, the hydrocarbon fluids are produced from
a subsurface formation. The subsurface formation represents a
reservoir containing hydrocarbon fluids. The fluids may be, for
example, methane and other lighter hydrocarbon fluids. The
reservoir may also include so-called acid gases such as carbon
dioxide and hydrogen sulfide. The reservoir may also incidentally
contain water or brine.
[0240] In any instance, the subsurface formation is a
low-permeability formation. The formation may have a permeability
less than, for example, about 10 millidarcies. In this instance,
the reservoir may be a tight-gas formation, a shale gas formation,
or a coal bed methane formation.
[0241] The method 500 first includes providing a wellbore in the
subsurface formation. This is shown at Box 505. The wellbore has
been completed as a deviated wellbore. Preferably, the deviated
wellbore is a substantially horizontal wellbore within the
subsurface formation. The wellbore has been perforated along at
least a first zone and a second zone.
[0242] The method 500 also includes fracturing the subsurface
formation along the first and second zones. This is provided at Box
510. Fracturing the formation along these zones creates one or more
substantially vertical fractures extending from the wellbore.
[0243] The method 500 further includes producing hydrocarbon fluids
through the vertical fractures along the first and second zones.
This is seen at Box 515. In one aspect, the vertical fractures
extend a distance of about 100 feet (30.5 meters) to 500 feet
(152.4 meters) from the wellbore.
[0244] The method 500 additionally includes injecting a fluid into
the subsurface formation. This is provided at Box 520. The fluid is
preferably a hydraulic fluid such as brine. However, liquid
CO.sub.2, foamed nitrogen, or other non-reactive fluids may also be
injected.
[0245] In the injecting step of Box 520, the fluid is injected
through perforations in the second zone. This serves to raise the
reservoir pressure in the subsurface formation along the first
zone. This also helps to cause a change in the in situ stresses
within the subsurface formation along the first zone. However, the
fluid preferably is not injected at a parting pressure and does not
extend existing fractures.
[0246] The method 500 may also include monitoring the wellbore.
This is shown at Box 525. The wellbore is monitored to determine
when a change in orientation of maximum principal stress may occur
within the subsurface formation along the first zone. The change in
maximum principal stress occurs as a result of producing fluids
from the first zone and injecting the fluid into the second
zone.
[0247] The wellbore may be monitored in a number of different ways.
For example, monitoring the wellbore may comprise determining when
a designated volume of hydrocarbon fluids have been produced from
the first zone or from the subsurface formation in general.
Alternatively, monitoring the wellbore may comprise determining
when a designated reduction in reservoir pressure within the
subsurface formation along the first zone has taken place. This may
be done through reservoir simulation or based on experience with
existing wells in the field. Alternatively, monitoring the wellbore
may comprise determining when a selected volume of fluid has been
injected into the subsurface formations through the perforations in
the second zone.
[0248] Alternatively still, monitoring the wellbore may comprise
determining when a selected period of time of production has taken
place from the first zone. And still alternatively, monitoring the
wellbore may comprise determining whether micro-seismic readings or
tilt-meter readings indicate a change in in situ stresses. Of
course, combinations of these techniques are preferably
employed.
[0249] The method 500 further includes injecting a fluid into the
subsurface formation through perforations in the first zone. This
is seen at Box 530. The injection of fluid in the first zone is at
high pressures, and causes a propagation of fractures in the
subsurface formation along the first zone. The direction of maximum
principal stress has been changed in the near-wellbore region along
the first zone. Accordingly, the fractures tend to propagate at
least partially towards the second zone.
[0250] The method 500 also includes producing hydrocarbons. This is
shown at Box 535. Hydrocarbon fluids are produced through the
perforations along the first zone. Preferably, hydrocarbon fluids
are also produced through the perforations along the second zone as
well. This is seen at Box 540.
[0251] The method 500 as described above only recites two zones.
However, the method 500 may be applied to a wellbore that is
perforated in more than two zones. In one aspect, the wellbore is
perforated to create new perforations along a third zone. This is
provided at Box 545. Perforations may be provided along the first
zone, the second zone, and a third zone, with the zones preferably
being separated by a distance of between about 20 feet (6.1 meters)
and 500 feet (152.4 meters). As described above, the methods 500
may be performed on wellbores having multiple zones and may be
performed simultaneously on more than two zones and may be
performed sequentially on more than two zones. The specific manner
of implementation may depend on the size of the field, the age of
the field, or other factors that may become apparent to an
operator. For example, the methods may be applied to more than two
zones simultaneously and then later applied to still further
zones.
[0252] The method 500 would then include fracturing the subsurface
formation along the third zone to form additional vertical
fractures extending from the wellbore. This is seen at Box 550. The
perforating 545 and fracturing 550 steps may be conducted in stages
with the first, second, and third zones using multi-interval
procedures known in the art of well completions.
[0253] Where a third zone is perforated, the method 500 also
includes producing hydrocarbon fluids through the vertical
fractures in the third zone. This is shown at Box 555. The
producing step of Box 555 may take place with the producing step of
Box 515.
[0254] The method 500 still includes injecting a fluid into the
subsurface formation through perforations in the second zone. This
was provided at Box 520. The injection step of Box 520 will further
raise reservoir pressure in the subsurface formation along the
third zone, and will further cause a change in the in situ stresses
within the subsurface formation along the third zone. This is
indicated at Box 560. During this time, hydrocarbon fluids continue
to be produced from the third zone in accordance with the producing
step of Box 555.
[0255] Where a third zone is perforated, the method 500 also
includes injecting a fluid into the subsurface formation through
perforations in the third zone. This is provided at Box 565. The
injection step of Box 565 creates a first set of new fractures in
the subsurface formation along the third zone. These new fractures
propagate at least partially towards the second zone.
[0256] The method 500 next includes again producing hydrocarbon
fluids from the third zone. This is provided at Box 570.
Preferably, hydrocarbon fluids are also simultaneously produced
from the first and second zones. Thus, the step of producing in Box
570 may take place simultaneously with the producing step of Box
535.
[0257] It is noted here that the process of injecting fluid in one
zone to increase reservoir pressure and to change in situ stresses
in an adjoining zone may be applied in any order. Further, the
process may be alternated such that after one zone has been
re-fractured and produced, an adjoining zone may be re-fractured
and produced. Thus, in the method 500, after producing fluids from
the first, second and third zones in Boxes 535 and 570, production
is temporarily suspended from the first zone. This is seen at Box
575.
[0258] After discontinuing the production of fluids from the first
zone, fluid is then injected into the subsurface formation through
perforations in the first zone. This is shown at Box 580. This
injection is not for the purpose of creating new fractures in the
first zone, but to raise reservoir pressure in the subsurface
formation along the second zone. This causes a change in the in
situ stresses within the subsurface formation along the second
zone.
[0259] The method 500 then includes injecting a fluid into the
subsurface formation through perforations in the second zone. This
is provided at Box 585. The injection of fluids into the second
zone is at high pressures, thereby causing a propagation of
fractures in the subsurface formation along the second zone at
least partially towards the first zone.
[0260] The method 500 then includes producing hydrocarbons through
the perforations along the second zone. This is seen at Box
590.
[0261] The steps of Boxes 580 through 590 may be applied again with
respect to the third zone. The result is that additional fractures
are created in the second zone that extends at least partially
towards the third zone. Thus, a more complex network of fractures
is created in the subsurface formation, increasing the exposure of
the formation to production channels and the wellbore.
[0262] It can be seen that the method 500 involves the selective
injection of fluids at different pressures and in different stages.
Further, the method 500 involves the production of fluids from
selected zones at different stages. The steps of the method 500 may
be aided through the use of packers, fracturing ports, mechanical
plugs, sand plugs, sliding sleeves, and other devices known in the
art.
[0263] The methods 300 and 500 of FIGS. 3A-3B and FIGS. 5A-5C,
respectively, relate to the creation of a fracture network from a
single wellbore. However, the concept of manipulating in situ
stresses to increase the complexity of a fracture network may be
approached on a multi-well basis.
[0264] In order to optimize the production of hydrocarbons from a
formation, the reservoir engineer or other field developer designs
a desired fracture network. FIG. 6A presents such an illustrative
fracture network 600A. The fracture network 600A comprises a series
of interconnecting fractures 610, 620. Each of the fractures 610,
620 is oriented in a substantially vertical plane.
[0265] In the illustrative fracture network 600A, the fractures
610, 620 are arranged in pairs 650A. Each of the fractures 610 is
oriented along an x-y plane. At the same time, each of the
fractures 620 is oriented along a z-y plane. In this way, each of
the x-y fractures 610 is intersected at substantially a right angle
by a single corresponding z-y fracture 620. A plurality of pairs
650A is provided for the fracture network 600A.
[0266] The concept of intersecting fractures shown in the fracture
network 600A is but one of many possible arrangements. FIG. 6B
presents an alternate but related arrangement for a fracture
network 600B. Here, instead of providing a single z-y fracture 620
with each of the x-y fractures 610, two z-y fractures 620 are
provided with each of the x-y fractures 610. Such groupings are
shown at 650B.
[0267] Other related variations may readily be employed. For
example, instead of providing a single z-y fracture 620 with each
of the x-y fractures 610, three z-y fractures 620 may be provided
with each of the x-y fractures 610. Inversely, instead of providing
a single x-y fracture 610 with each of the z-y fractures 620, two,
three, or more x-y fractures 610 may be provided with each of the
z-y fractures 610.
[0268] In order to create such an arrangement of fractures 610,
620, the reservoir engineer (or other field developer) may complete
a plurality of horizontal wells in a subsurface formation. In one
aspect, some wells are completed along an x-axis within the
formation, while other wells are completed along a z-axis in the
formation. The purpose is to provide substantial coverage of a
field with a fracture network.
[0269] A fracturing fluid is injected into a first set of wells,
such as the horizontal wells completed along the x-axis, in order
to create fractures in the formation in a first vertical
orientation. This may be done in accordance with the steps shown,
for example, in FIGS. 2A through 2C. Subsequently, steps are taken
to change the orientation of the minimum principal stress in the
formation. This may be done in accordance with the step shown, for
example, in FIG. 2E. Thereafter, a fracturing fluid is injected
into a second set of wells, such as the horizontal wells completed
along the z-axis, in order to create fractures in the formation in
a second vertical orientation along the x-y plane. In the
arrangements of FIGS. 6A and 6B, the second vertical orientation is
at substantially a 90-degree angle to the first vertical
orientation.
[0270] FIG. 7 provides a plan view of a hydrocarbon development
area 700, in one embodiment. The hydrocarbon development area 700
has a surface 710. The hydrocarbon development area 700 also has a
subsurface 720. The subsurface 720 includes a formation 725
containing hydrocarbon fluids. The formation 725 comprises a rock
matrix having low permeability. The formation 725 may have, for
example, a permeability less than about 10 millidarcies.
[0271] It is desirable to optimize the production of hydrocarbon
fluids from the formation 725. Because the formation 725 has
limited permeability, one way of optimizing production is by
creating a network of interconnecting fractures. In order to create
the fracture network, a first set of wells is completed
horizontally. The wellbores for the first set of wells are shown at
732. These wellbores 732 extend along an x-axis. Thereafter, the
subsurface formation 725 is fractured from perforations in the
wellbores 732 for the first set of wells. Fractures are seen at
740. Hydrocarbon fluids are then produced from through the
fractures 740 and the corresponding wellbores 732.
[0272] After a period of production, the in situ stress field
within the subsurface formation 725 is changed. This may be as a
natural result of the fluid production process. Alternatively, this
may be as a result of selective injection of water or other fluids
into the subsurface formation 725 in order to increase in situ
pressure. In any instance, a second set of wells having wellbores
734 is also formed. These wellbores are also completed
horizontally, and are oriented along a z-axis.
[0273] After the in situ stress field within the subsurface
formation 725 is changed, the subsurface formation 725 is fractured
from perforations in the wellbores 734 for the second set of wells.
Illustrative fractures from the wellbores 734 are seen at 750.
Hydrocarbon fluids are then produced from through the fractures 750
and the corresponding wellbores 734.
[0274] It is noted that the wellbores 732 along the x-axis and the
wellbores 734 along the z-axis cross. They do not intersect, but
they do cross. This allows the respective fractures 740, 750 to
intersect. The intersecting fractures 740, 750 create a fracture
network analogous to the fracture networks 650A, 650B shown in
FIGS. 6A and 6B.
[0275] FIG. 8 is a flow chart showing steps for performing a method
700 for creating a network of fractures in a reservoir, in one
embodiment. The reservoir preferably represents a rock matrix
having a low permeability. For example, the permeability may be
less than 10 millidarcies.
[0276] The reservoir may be a hydrocarbon-producing reservoir. For
example, the reservoir may contain methane and other hydrocarbon
gases. In this instance, the reservoir may be a tight-gas
formation, a shale gas formation, or a coal bed methane formation.
The reservoir may also include so-called acid gases, such as carbon
dioxide and hydrogen sulfide. The reservoir may also incidentally
contain water or brine.
[0277] Alternatively, the reservoir may be a geothermal zone
containing water and, possibly, minerals. In this instance, the
reservoir will produce steam.
[0278] The method 800 generally includes designing a desired
fracture network. This is shown at Box 810. The fracture network
may be, for example, in accordance with the illustrative fracture
networks 650A, 650B shown and discussed in FIGS. 6A and 6B. The
step of designing a desired fracture network of Box 810 is done
using geomechanical simulation, which involves use of a software
program and a processor.
[0279] The method 800 also includes determining required in situ
stresses to create the fracture network within the reservoir. This
is provided at Box 820. Determining required in situ stresses may
be done in several ways. For example, downhole pressure
measurements may be taken from existing wells. Such measurements
are indicative of pore pressure acting within a rock matrix.
Alternatively or in addition, micro-seismic testing may be
conducted. Alternatively or in addition, tiltmeter readings may be
monitored.
[0280] In a preferred aspect, downhole stress modeling may be
conducted. For example, ABAQUS.TM. software may be used to develop
in situ stresses and resulting fractures. To run a model, the rock
matrix making up the reservoir is initialized with certain
mechanical properties. Such properties may be, for example, elastic
moduli and Poisson ratios. Elastic moduli and Poisson ratios may be
estimated based on interpreted lithologies for the rocks included
in the model.
[0281] A stress field may be demonstrated by x, y, and z
coordinates. In the Piceance Basin, for instance, the in situ
stress field will be affected in one of the horizontal directions
due to tectonic forces acting from the Rocky Mountain range to the
east. From the stress field modeling, the direction of least
principal stress is determined. For formations deeper than about
1,000 feet, the direction of least principal stress will likely be
in the "x" or "z" directions, where the x and z directions are
horizontal and "y" is the vertical direction, such that
hydraulically-induced fractures will be oriented in plane
perpendicular to the "x" or "z" direction.
[0282] The method 800 further includes designing a layout of wells
to alter the in situ stresses. This is provided at Box 830.
Designing such a layout of wells means that wells are completed in
the subsurface for the production and/or injection of fluids for
the purpose of altering the in situ stress field. The layout of
wells may be, for example, in accordance with the layout of
wellbores 732 and 734 of FIG. 7.
[0283] The method 800 also includes injecting a fracturing fluid
under pressure into the reservoir. The purpose is to create an
initial set of fractures. This is shown at Box 840. The fractures
will likely extend in a vertical plane through the formation, as
shown in FIG. 2C. The result is that the fractures do not
interconnect and provide limited exposure of the wellbores to the
formation.
[0284] Historically, an operator might choose to extend the length
of the fractures in order to increase exposure of the wellbores to
the formation. Fractures have been reported in some field
developments that extend many thousands of feet. However, this is
undesirable where the fractures are anticipated to form in a
vertical plane. In this respect, the fractures may propagate beyond
the targeted production intervals and, potentially, into aquifers
or unconsolidated formations.
[0285] In the method 800, a next step is taken to monitor the in
situ stresses in the reservoir. This is seen at Box 850. Monitoring
the in situ stresses in the reservoir may be done in several ways.
These are generally shown in the flow chart of FIG. 9.
[0286] FIG. 9 is a flow chart showing illustrative steps that may
be taken for monitoring in situ stress fields. First, monitoring
may include conducting downhole pressure measurements. This is seen
at Box 910. Alternatively or in addition, monitoring may include
micro-seismic and/or tiltmeter monitoring. This is provided at Box
920. Alternatively or in addition, monitoring may include taking
readings from tiltmeters on a surface above the reservoir. This is
shown at Box 930. Alternatively or in addition, monitoring may
include performing downhole stress modeling. This is seen at Box
940. Of course, combinations of any of these techniques may be
employed.
[0287] The method 800 additionally includes updating the
geomechanical simulation based on the monitored in situ stresses.
This is indicated at Box 855. Further, the method 800 includes
designing a program of modifying the in situ stress within the
stress field. This is seen at Box 860. The step of designing a
program of Box 860 is also done using geomechanical simulation. The
geomechanical simulations may be performed using commercially
available software capable of capturing the complex interplay
between the in situ stress state and the engineering practices.
Examples of such software include finite element software (e.g.
Abaqus or ELFEN); and discrete element software (e.g. PFC3D or
ELFEN).
[0288] The geomechanical simulations incorporate fully-coupled
constitutive relations that enable mathematical representations of
in situ stress state and pore pressure, rock mechanical properties,
engineering stimulation practices at the wellbores, and field
production. Newly acquired data is input into the geomechanical
simulations to foster iteration between history matching and
predictive modes.
[0289] The method 800 also includes modifying the in situ stresses
in the reservoir. This is seen at Box 865. Modifying the in situ
stresses permits the operator to determine when the direction of
least principal stress within the in situ stress field has
changed.
[0290] The in situ stresses may be modified through reservoir
depletion over time. In this instance, the step 860 will comprise
producing hydrocarbon fluids from the reservoir. Alternatively or
in addition, the step 865 may comprise injecting a fluid into the
reservoir. The fluid is injected at a pressure lower than the
parting pressure of the rock matrix. The fluid may be injected into
each of a plurality of wells either (i) simultaneously, or (ii) in
stages such that fluid is injected into one or more wells or one or
more zones sequentially.
[0291] In a related embodiment, modifying the in situ stresses
further comprises (i) specifying a length of time for injecting for
selected wells, (ii) specifying a viscosity of fluid for injection
into selected wells, (iii) modifying a temperature of the
reservoir, or (iv) combinations thereof. Modifying a temperature of
the reservoir may comprise (i) injecting a heated gas into the
reservoir, (ii) applying resistive heat to a rock matrix comprising
the reservoir, (iii) actuating one or more downhole combustion
burners, (iii) injecting a cooler fluid into the reservoir or (v)
combinations thereof.
[0292] Modifying the in situ stresses may also comprise
establishing assistive fracture paths. The assistive fracture paths
are in addition to the initial fractures created in step 840.
Establishing the assistive fracture paths may be done by creating a
plurality of radially offset perforations into the reservoir
through a plurality of wells. The orientation of the perforations
may also be adjusted so that the perforations do not extend
transverse to the wellbores. Alternatively or in addition,
establishing the assistive fracture paths may be done by injecting
an acidic fluid through a plurality of wells to create worm holes
in the reservoir.
[0293] Once the in situ stresses have been modified, the reservoir
may be further fractured. This enables a true network of fractures
to be created, as opposed to simply re-opening or, perhaps,
extending the same fractures in the same direction. Thus, the
method 800 further includes injecting a fluid under pressure into
the reservoir in order to expand upon the initial set of fractures
and to create the network of fractures. This is shown at Box 870.
Injecting a fluid into the reservoir to create the network of
fractures may be done by determining pump rates and associated
shear rates for selected wells.
[0294] In one aspect of the method 800, at least two of the wells
in the layout of wells are completed for the production of
hydrocarbon fluids. In this instance, the network of fractures is
designed to optimize production of the hydrocarbon fluids.
Injecting a fluid into the reservoir under pressure in accordance
with the steps of Boxes 840 and 870 may comprise injecting the
fluid through wells that have been completed principally for the
production of hydrocarbon fluids.
[0295] In another aspect, at least two of the wells in the layout
of wells are being completed for the injection of fluids as part of
enhanced oil recovery. In this instance, injecting a fluid under
pressure into the reservoir in accordance with the steps of Boxes
840 and 870 may further comprise injecting the fluid through
selected wells that are completed for the injection of fluids. The
fluids being injected may represent an aqueous fluid such as
brine.
[0296] In yet another aspect, at least two of the wells in the
layout of wells are completed for the production of
geothermally-produced steam. The network of fractures is designed
to optimize heat transfer for geothermal applications. In this
instance, injecting a fluid under pressure into the reservoir in
accordance with the steps of Boxes 840 and 870 may comprise
injecting the fluid through selected wells completed for the
production of the geothermally-produced steam.
[0297] In still another aspect, at least two of the wells in the
layout of wells are completed for the injection of acid gases. In
this instance, injecting a fluid under pressure into the reservoir
in accordance with the steps of Boxes 840 and 870 comprises
injecting the fluid through selected wells completed for the
injection of acid gases. The acid gases may primarily comprise
carbon dioxide. The carbon dioxide may be injected as part of an
enhanced oil recovery project. Alternatively, the carbon dioxide
may be injected as part of a sequestration operation. In this
instance, the network of fractures is designed to optimize CO.sub.2
storage capacity.
[0298] In yet another aspect, at least two of the wells in the
layout of wells are completed for the injection of drill cuttings.
In this instance, injecting a fluid under pressure into the
reservoir in accordance with the steps of Boxes 840 and 870
comprises injecting the drill cutting through selected wells for
injection into the reservoir.
[0299] In one embodiment of the methods herein, the reservoir
comprises two or more zones. In this instance, the network of
fractures is created within at least two different zones. Designing
a desired fracture network system then involves designing a
fracture network system in each of the at least two zones. In
addition, injecting a fluid under pressure into the reservoir
involves injecting a fluid into each of the at least two zones so
as to create the network of fractures within the at least two
zones. For example, the network of fractures may be created in the
manner described above in connection with FIGS. 3A-3B and/or FIGS.
5A-5C.
[0300] In another embodiment, a plurality of wells within the
layout of wells has already been perforated into the reservoir.
Further, the reservoir has undergone hydrocarbon production for a
period of time. In this instance, injecting a fluid under pressure
into the reservoir in order to create the network of fractures
involves re-fracturing each of the plurality of wells.
[0301] As can be seen, methods are offered herein to enhance
hydrocarbon production from subterranean formations by manipulating
the downhole in situ stresses. Manipulating in situ stresses allows
the operator to create fractures in different directions and to
enhance reservoir connectivity. In accordance with the methods, a
desired fracture network system is first designed for draining the
reservoir. The in situ stresses needed to create the fracture
network system are then determined. A comprehensive system
consisting of well/pad layout and well architecture is designed to
alter the stress field around the individual wells. A customized
network of fractures is then created.
[0302] As a result of fracturing, there is increased fracture
complexity and increased reservoir access. The change in downhole
in situ stresses and accompanying fracture orientation are
preferably monitored or modeled to provide continuous feedback.
This is indicated at Box 880 of FIG. 8. The step of Box 880 may,
for example, be in accordance with any of the steps shown in FIG.
9. The reservoir may again be fractured as the stress field
changes.
[0303] The methods disclosed herein are particularly beneficial for
the development of unconventional reservoirs such as tight gas,
shale gas, and coal bed methane, and the recovery of gas. The
methods are also beneficial for the sequestration of CO.sub.2. In
geothermal applications, the present methods will help to increase
contact area from the wellbore to the reservoir. For water/cuttings
injection wells, the methods can be used to control fracture
geometry and orientation.
[0304] While it will be apparent that the inventions herein
described are well calculated to achieve the benefits and
advantages set forth above, it will be appreciated that the
inventions are susceptible to modification, variation and change
without departing from the spirit thereof.
* * * * *