Note: Descriptions are shown in the official language in which they were submitted.
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METHODS FOR ESTABLISHING A SUBSURFACE FRACTURE NETWORK
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the priority benefit of U.S. Provisional
Patent Application
61/405,069 filed 20 October 2010 entitled METHODS FOR ESTABLISHING A
SUBSURFACE FRACTURE NETWORK, the entirety of which is incorporated by
reference
herein.
BACKGROUND
[00021 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
[00031 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
[00041 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.
100051 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.
[00061 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
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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.
100071 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.
100081 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.
[00091 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.
100101 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
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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.
[00111 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.
P)0121 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.
[00131 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.
f00141 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
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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.
P)0151 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."
[00161 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.
P)0171 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.
[00181 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.
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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
[00231 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.
100241 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
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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.
100281 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
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reservoir comprises injecting the fluid through selected wells completed for
the injection of
fluids.
[0031j 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 CO2 storage capacity.
f00331 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.
[00341 A method of producing hydrocarbons from a subsurface formation is
also
provided herein. The formation has a permeability less than about 10
millidarcies.
[0035j 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.
100361 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
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oriented plane, sometimes referred to herein as vertical fractures, that is
substantially
perpendicular to the direction of least principal or minimum stress.
[00371
The method then includes producing hydrocarbon fluids through the vertical
fractures along the first and second zones.
[00381 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.
[00391
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.
100401
Preferably, the wellbore has further been perforated within the subsurface
formation along a third zone. In this instance,
= 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;
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= 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
= producing hydrocarbons through the first set of new fractures further
comprises
producing hydrocarbons through the vertical fractures along the third zone.
[0041j 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.
[00421 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.
100431 In a related aspect, the method further comprises:
= 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;
= 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.
[00441 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.
[0045j In some implementations, the method includes providing a wellbore
in the
subsurface formation. The wellbore has been completed as a deviated wellbore.
Further, the
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wellbore has been perforated within the subsurface formation along at least a
first zone and a
second zone.
[0046j 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.
[00471 The method then includes producing hydrocarbon fluids through the
vertical
fractures along the first and second zones.
[00481 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.
[0049] 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.
100501 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.
[00511 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)
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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
[0052j Preferably, the wellbore has further been perforated within the
subsurface
formation along a third zone. In this instance,
= 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; and
= 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.
f00531 The method then further comprises:
= 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
= producing hydrocarbons through the new fractures and the new perforations
along
the third zone.
[00541 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.
[00551 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.
[00561 In some implementations, the method further comprises:
= 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
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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 new fractures in the subsurface
formation
along the second zone at least partially towards the first zone; and
= producing hydrocarbons through the new fractures and the perforations
along the
second zone.
f00571 In some implementations, the method further comprises:
= 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 new fractures in the subsurface
formation
along the second zone at least partially towards the third zone; and
= producing hydrocarbons through the new fractures and the perforations
along the
second zone.
BRIEF DESCRIPTION OF THE DRAWINGS
100581 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.
100,591 Figure 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.
[00601 Figures 2A through 2K are perspective views of a bottom portion
of the wellbore
of Figure 1. The wellbore is divided or apportioned into three illustrative
zones for the
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production of hydrocarbon fluids from the subsurface formation. The wellbore
is lined with a
string of production casing.
[0061] In Figure 2A, the casing has been perforated in each of a first
zone, a second zone,
and a third zone.
[0062] In Figure 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.
[0063] In Figure 2C, vertical fractures have been formed in each of the
first, second, and
third zones.
100641 In Figure 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.
[0065] In Figure 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.
[0066] In Figure 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.
[00671 In Figure 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.
[0068] In Figure 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.
100691 In Figure 21, 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.
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[00701 In Figure 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.
[00711 In Figure 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.
[00721 Figures 3A and 3B are a single flowchart showing steps for
performing a method
of producing hydrocarbons from a subsurface formation.
[00731 Figures 4A through 4Q are perspective views of a bottom portion
of the wellbore
of Figure 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.
[00741 In Figure 4A, the casing has been perforated in each of a first
zone, a second zone,
and a third zone.
100751 In Figure 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.
[00761 In Figure 4C, fractures in a vertical plane have been formed in
each of the first,
second, and third zones.
[00771 In Figure 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.
[00781 In Figure 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.
[00791 In Figure 4F, production from each of the first and third zones
has been
temporarily suspended. Fracturing fluids are now being injected into the
subsurface
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formation along the first and third zones under high pressure. Fluids are also
being injected
into the second zone to maintain formation pressure.
[0080] In Figure 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.
[00811 In Figure 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.
[0082] In Figure 41, 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.
[00831 In Figure 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.
[0084] In Figure 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.
[00851 In Figure 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.
100861 In Figure 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.
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100871 In Figure 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.
[00881 In Figure 40, 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.
[00891 In Figure 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.
[00901 In Figure 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.
100911 Figures 5A through 5C are a single flowchart showing steps for
performing a
method of producing hydrocarbons from a subsurface formation.
10092] Figure 6A shows a perspective view of a designed fracture
network.
100931 Figures 6B is another perspective view of a designed fracture
network
100941 Figure 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.
[00951 Figure 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.
[00961 Figure 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
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[0097]
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.
[0098]
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 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.
[00991
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).
[0100] 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.
[0101]
As used herein, the term "gas" refers to a fluid that is in its vapor phase
at 1
atm and 15 C.
[0102] As used herein, the term "oil" refers to a hydrocarbon fluid
containing
primarily a mixture of condensable hydrocarbons.
[0103]
As used herein, the term "subsurface" refers to geologic strata occurring
below
the earth's surface.
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[0104] The term "zone of interest" refers to a portion of a formation
containing
hydrocarbons.
[0105] 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.
[0106] 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.
[0107] 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.
[0108] 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.
[0109] 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."
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Description of Selected Specific Embodiments
[0110] 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.
[0111] Figure 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.
[0112] 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.
[0113] 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.
[0114] 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.
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[0115] In Figure 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.
[0116] 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.
[0117] 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.
[0118] 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.
[0119] 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.
[0120] 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
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wellbore 100 of Figure 1, the horizontal portion 160 is divided into three
zones 154, 156,
158. While only three zones are shown in Figure 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.
[0121] 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 Figures
2A through 2K.
[0122] Figures 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
Figure 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.
[0123] 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.
[0124] 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 Figures
2A through 2K. The casing 202 defines an elongated tubular body forming a bore
205
therethrough. In the wellbore arrangement of Figures 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.
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[0125] 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 Figures 4A through 4Q).
[0126] In Figure 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.
[0127] In each of Figures 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.
[0128] In Figure 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.
[0129] Figure 2B presents a next view of the wellbore 200. In Figure
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.
[0130] Figure 2C presents a next view of the wellbore 200. In Figure
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'
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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.
[0131] Figure 2D presents a next view of the wellbore 200. In Figure
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."
[0132] It is noted that each of the fractures 214', 224', 234'
creates a first zone of
production. This is indicated schematically in Figure 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'.
[0133] 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.
[0134] The wellbore 200 may be monitored in various ways. For example,
monitoring the wellbore 200 may comprise determining when a designated volume
of
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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.
[0135] 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.
[0136] Figure 2E presents a next view of the wellbore 200. In Figure 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 Figure 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.
[0137] Figure 2F presents a next view of the wellbore 200. In Figure
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.
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[0138] 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'.
[0139] Figure 2G presents a next view of the wellbore 200. In Figure 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.
[0140] 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."
[0141] 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 Figure 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'.
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[0142] 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.
[0143] Figure 2H presents a next view of the wellbore 200. In Figure 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 Figure 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.
[0144] Figure 21 presents a next view of the wellbore 200. In Figure
21, 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.
[0145] 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.
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[0146] Figure 2J presents a next view of the wellbore 200. In Figure
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.
[0147] 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."
[0148] 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 Figure 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".
[0149] 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.
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[0150] Figure 2K presents this optional additional step. In Figure
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.
[0151] 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.
[0152] Figures 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 Figures 2A through 2K.
[0153] 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.
[0154] 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.
[0155] 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
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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.
[0156] 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.
[0157] 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.
[0158] 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.
[0159] 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 CO2, 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.
[0160] 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.
[0161] 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
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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.
[0162] 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.
[0163] 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.
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.
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[0165] 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 Figure
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.
[0166] 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.
[0167] 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 Figure 21. 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.
[0168] 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 Figures 4A through 4Q.
[0169] Figures 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
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Figure 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.
[0170] 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
Figures 4A through 4Q. The casing 402 defines an elongated tubular body
forming a bore
405 therethrough. In the wellbore arrangement of Figures 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.
[0171] 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.
[0172] In Figure 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.
[0173] In each of Figures 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.
[0174] In Figure 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.
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[0175] Figure 4B presents a next view of the wellbore 400. In Figure
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.
[0176] Figure 4C presents a next view of the wellbore 400. In Figure
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.
[0177] Figure 4D presents a next view of the wellbore 400. In Figure
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."
[0178] It is noted that each of the fractures 414', 424', 434'
creates a first zone of
production. This is indicated schematically in Figure 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'.
[0179] Figure 4E presents a next view of the wellbore 400. In Figure 4E,
production
from the second zone 420 has been suspended. A fluid is now being injected
into the
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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.
[0180] 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
Figure 4B). It is preferred in the step of Figure 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.
[0181] 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 Figure
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.
[0182] In one aspect, the step of Figure 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.
[0183] 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.
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[0184] 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.
[0185] 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.
[0186] Figure 4F presents a next view of the wellbore 400. In Figure
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.
[0187] 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.
[0188] Figure 4G presents a next view of the wellbore 400. In Figure
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'.
[0189] 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
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network within the subsurface formation 450 has beneficially increased, even
by using just a
single wellbore 400.
[0190] 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'.
[0191] Figure 4H presents a next view of the wellbore 400. In Figure
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.
[0192] 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."
[0193] 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 Figure 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 Figure 4D).
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[0194] 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 Figures 41 through 4P.
[0195] Figure 41 presents a next view of the wellbore 400. In Figure 41,
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.
[0196] 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.
[0197] Figure 4J presents a next view of the wellbore 400. In Figure
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.
[0198] In one aspect, the step of Figure 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.
[0199] 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 Figure 41
through the
separate first 440 and second 445 tubing strings.
[0200] Figure 4K presents a next view of the wellbore 400. In Figure
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
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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.
[0201] Figure 4L presents a next view of the wellbore 400. In Figure
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."
[0202] Of note, a second zone of production 425" is now provided
along the second
zone 420. This is indicated schematically as a circle in Figure 4L. The second
zone of
production 425" is larger than the first zone of production seen at 425' in
Figure 4H.
[0203] Figure 4M presents a next view of the wellbore 400. In Figure
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.
[0204] 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."
[0205] Figure 4N presents a next view of the wellbore 400. In Figure 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.
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[0206] 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 Figure 4N through the
separate first
440 and second 445 tubing strings.
[0207] Figure 40 presents a next view of the wellbore 400. In Figure
40, 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.
[0208] 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'.
[0209] Figure 4P presents a next view of the wellbore 400. In Figure
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.
[0210] 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."
[0211] Figures 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
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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.
[0212] It is noted that the steps shown in Figures 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 (Figures 41 through 4P) in the second zone 420 before
creating the
transverse fractures (Figures 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
(Figures 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
Figures 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.
[0213] 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.
[0214] 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.
[0215] Figure 4Q presents this optional additional step. In Figure 4Q, new
intermediate perforations have been formed along the casing 402. First,
perforations 462 are
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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.
[0216] 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.
[0217] As can be seen, Figures 4A through 4Q present steps for a
process of
producing hydrocarbon fluids. The steps may be set out textually in a
flowchart. Figures 5A
through 5C present such a flow chart, and show steps for a method 500 of
producing
hydrocarbon fluids.
[0218] 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.
[0219] 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.
[0220] 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.
[0221] 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.
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[0222] 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.
[0223] 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 CO2, foamed nitrogen, or other non-reactive fluids may
also be
inj ected.
[0224] 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.
[0225] 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.
[0226] 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.
[0227] 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
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readings or tilt-meter readings indicate a change in in situ stresses. Of
course, combinations
of these techniques are preferably employed.
[0228] 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.
[0229] 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.
[0230] 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.
[0231] 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.
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[0232] 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.
[0233] 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.
[0234] 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.
[0235] 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.
[0236] 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.
[0237] 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.
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[0238] 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.
[0239] The method 500 then includes producing hydrocarbons through the
perforations along the second zone. This is seen at Box 590.
[0240] 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.
[0241] 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.
[0242] The methods 300 and 500 of Figures 3A-3B and Figures 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.
[0243] In order to optimize the production of hydrocarbons from a
formation, the
reservoir engineer or other field developer designs a desired fracture
network. Figure 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.
[0244] 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.
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[0245] The concept of intersecting fractures shown in the fracture
network 600A is
but one of many possible arrangements. Figure 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.
[0246] 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.
[0247] 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.
[0248] 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
Figures 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 Figure 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
Figures 6A and 6B, the second vertical orientation is at substantially a 90-
degree angle to the
first vertical orientation.
[0249] Figure 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.
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[0250] 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.
[0251] 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.
[0252] 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.
[0253] 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 Figures 6A and 6B.
[0254] Figure 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.
[0255] 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
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reservoir may also include so-called acid gases, such as carbon dioxide and
hydrogen sulfide.
The reservoir may also incidentally contain water or brine.
[0256] Alternatively, the reservoir may be a geothermal zone
containing water and,
possibly, minerals. In this instance, the reservoir will produce steam.
[0257] 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 Figures 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.
[0258] 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.
[0259] In a preferred aspect, downhole stress modeling may be
conducted. For
example, ABAQUSTM 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.
[0260] 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.
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[0261] 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 Figure 7.
[0262] 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 Figure
2C. The result is that the fractures do not interconnect and provide limited
exposure of the
wellbores to the formation.
[0263] 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.
[0264] 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 Figure 9.
[0265] Figure 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.
[0266] 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
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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).
[0267] 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.
[0268] 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.
[0269] 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.
[0270] 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.
[0271] 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
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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.
[0272] 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.
[0273] 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.
[0274] 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.
[0275] 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.
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[0276] 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
CO2 storage capacity.
[0277] 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.
[0278] 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 Figures 3A-3B
and/or
Figures 5A-5C.
[0279] 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.
[0280] 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
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CA 02814750 2013-04-15
WO 2012/054139 PCT/US2011/049579
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.
[0281] 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 Figure 8. The step of Box 880 may, for example, be in
accordance
with any of the steps shown in Figure 9. The reservoir may again be fractured
as the stress
field changes.
[0282] 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 CO2.
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.
[0283] 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
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