U.S. patent application number 13/184158 was filed with the patent office on 2013-01-17 for applying treatment fluid to a subterranean rock matrix.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Harvey J. Fitzpatrick. Invention is credited to Harvey J. Fitzpatrick.
Application Number | 20130014951 13/184158 |
Document ID | / |
Family ID | 47518265 |
Filed Date | 2013-01-17 |
United States Patent
Application |
20130014951 |
Kind Code |
A1 |
Fitzpatrick; Harvey J. |
January 17, 2013 |
APPLYING TREATMENT FLUID TO A SUBTERRANEAN ROCK MATRIX
Abstract
The present disclosure relates to applying treatment fluid to a
rock matrix in a subterranean formation. An injection fluid is
received in a wellbore in a subterranean formation. The
subterranean formation includes a rock matrix about the wellbore.
Shear bands are induced in the rock matrix by communicating the
injection fluid from the wellbore into the rock matrix. A chemical
treatment fluid is communicated through the shear bands into the
matrix. The chemical treatment is conducted from the wellbore
primarily by a portion of the rock matrix that forms a wall of the
wellbore, primarily by a subset of the shear bands that intersect
the wall of the wellbore, or primarily by a combination of them. In
some instances, the shear bands may improve uniformity or
efficiency of the chemical treatment.
Inventors: |
Fitzpatrick; Harvey J.;
(Katy, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Fitzpatrick; Harvey J. |
Katy |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
47518265 |
Appl. No.: |
13/184158 |
Filed: |
July 15, 2011 |
Current U.S.
Class: |
166/305.1 ;
166/90.1 |
Current CPC
Class: |
E21B 43/26 20130101 |
Class at
Publication: |
166/305.1 ;
166/90.1 |
International
Class: |
E21B 43/16 20060101
E21B043/16; E21B 43/22 20060101 E21B043/22 |
Claims
1. A method of performing a chemical treatment of a rock matrix,
the method comprising: receiving an injection fluid in a wellbore
defined in a subterranean formation, the subterranean formation
comprising a rock matrix about the wellbore; inducing shear bands
in the rock matrix about the wellbore by communicating the
injection fluid from the wellbore into the rock matrix about the
wellbore; and communicating a chemical treatment fluid through the
shear bands and into the rock matrix about the wellbore, the
chemical treatment fluid conducted from the wellbore primarily by
at least one of a portion of the rock matrix forming a wall of the
wellbore or a subset of the shear bands intersecting the wall.
2. The method of claim 1, a leak-off rate of the injection fluid in
the rock matrix prevents initiation of a dominant fracture at the
wellbore wall.
3. The method of claim 1, wherein the injection fluid comprises the
chemical treatment fluid.
4. The method of claim 1, wherein the wellbore comprises a wellbore
casing, and fluids communicated from the wellbore into the rock
matrix are communicated through perforations in the wellbore
casing.
5. The method of claim 1, wherein the wellbore comprises an open
hole wellbore.
6. The method of claim 1, further comprising: receiving the
chemical treatment fluid in the wellbore after communicating the
injection fluid into the rock matrix; and communicating the
chemical treatment fluid from the wellbore through the shear bands
after communicating the injection fluid into the rock matrix.
7. The method of claim 1, wherein inducing shear bands comprises
inducing the shear bands in the rock matrix substantially uniformly
over a range of azimuthal directions about the wellbore.
8. The method of claim 7, wherein communicating a chemical
treatment fluid into the rock matrix comprises communicating the
chemical treatment fluid into the rock matrix substantially
uniformly over the range of azimuthal directions about the
wellbore.
9. The method of claim 1, wherein inducing shear bands comprises
inducing the shear bands in the rock matrix substantially uniformly
about a longitudinal section of the wellbore.
10. The method of claim 9, wherein communicating a chemical
treatment fluid into the rock matrix comprises communicating the
chemical treatment fluid into the rock matrix substantially
uniformly about the longitudinal section of the wellbore
11. The method of claim 1, wherein inducing shear bands comprises
inducing the shear bands in the rock matrix substantially uniformly
over a radial distance about the wellbore.
12. The method of claim 11, wherein communicating a chemical
treatment fluid into the rock matrix comprises communicating the
chemical treatment fluid into the rock matrix substantially
uniformly over the radial distance about the wellbore
13. The method of claim 1, wherein inducing shear bands in the rock
matrix comprises inducing shear bands in a first interval of the
rock matrix, the method further comprising: inducing additional
shear bands in multiple additional intervals of the rock matrix by
communicating the injection fluid from the wellbore into the
additional intervals of the rock matrix about the wellbore, wherein
the injection fluid is communicated into each of the intervals at
different time periods; and communicating the chemical treatment
fluid through the additional shear bands and into additional
intervals of the rock matrix.
14. The method of claim 1, wherein the injection fluid comprises a
thin injection fluid containing substantially no solids, and
wherein the thin injection fluid forms substantially no filter
cakes.
15. The method of claim 1, wherein the rock matrix comprises a soft
rock formation having a Young's Modulus less than two million.
16. The method of claim 1, wherein the chemical treatment comprises
at least one of: an acid stimulation treatment; a solvent
treatment; a formation stabilization treatment; a consolidation
treatment; or a scale inhibitor treatment.
17. A chemical treatment method for treating a rock matrix about a
subterranean wellbore, the chemical treatment method comprising:
communicating a first fluid from the wellbore into an interval of
the rock matrix about the wellbore at a pressure that forms shear
bands in the interval about the wellbore; and communicating a
chemical treatment fluid substantially uniformly into the interval
of the rock matrix about the wellbore by conducting the chemical
treatment fluid through the shear bands in the interval, the
chemical treatment fluid conducted from the wellbore primarily by
at least one of a portion of the rock matrix forming a wall of the
wellbore or a subset of the shear bands intersecting the wall.
18. The method of claim 17, a leak-off rate of the first fluid in
the rock matrix prevents initiation of a dominant fracture at the
wellbore wall.
19. The method of claim 17, wherein the first fluid is the chemical
treatment fluid.
20. The method of claim 17, wherein inducing the shear bands in the
rock matrix increases a permeability of the rock matrix.
21. The method of claim 17, wherein the first fluid and the
chemical treatment fluid are two different fluids and the chemical
treatment fluid is communicated into the interval after the first
fluid is communicated into the interval.
22. The method of claim 21, further comprising communicating
additional fluids into the rock matrix.
23. The method of claim 17, wherein the first fluid comprises a
thin injection fluid containing substantially no solids, and
wherein the thin injection fluid forms substantially no filter
cakes, and wherein the rock matrix comprises a soft rock formation
having a Young's Modulus less than two million.
24. The method of claim 17, the interval comprising a first
interval, the method further comprising: injecting a diverter-laden
fluid into the first interval; communicating the first fluid from
the wellbore into a second, different interval of the rock matrix
about the wellbore at a pressure that forms shear bands in the
second interval about the wellbore; and communicating the chemical
treatment fluid substantially uniformly into the second interval of
the rock matrix about the wellbore by conducting the chemical
treatment fluid through the shear bands in the second interval.
25. The method of claim 24 where the diverter comprises at least
one of sand, a proppant, a plugging material, an emulsion, foam, or
a relative permeability modifier.
26. A chemical treatment system for applying a chemical treatment
to a rock matrix, the system comprising: a fluid supply system
comprising a thin injection fluid and a chemical treatment fluid; a
conduit system in a wellbore in a subterranean formation, the
conduit system in fluid communication with the fluid supply system,
the subterranean formation comprising a rock matrix; and a port
system in the wellbore and in fluid communication with the conduit
system, the port system operable to receive the thin injection
fluid and the chemical treatment fluid from the conduit system, to
communicate the thin injection fluid into the rock matrix under a
condition that induces shear bands in the rock matrix about the
wellbore, and to communicate the chemical treatment fluid into the
rock matrix primarily through at least one of the rock matrix at a
wall of the wellbore or a subset of the shear bands intersecting
the wall.
27. The system of claim 26, wherein the fluid supply system resides
at a well system surface, and wherein the fluid supply system
comprises a single fluid composition that is both the thin
injection fluid and the chemical treatment fluid.
28. The system of claim 26, wherein the fluid supply system resides
at a well system surface, and wherein the fluid supply system
comprises a first fluid composition that is the thin injection
fluid and second, different fluid composition that is the chemical
treatment fluid.
29. The system of claim 26, wherein the conduit system comprises
one or more conduits in a production string, and wherein the port
system comprises a plurality of inflow control devices in the
production string.
30. The system of claim 26, wherein the conduit system comprises
one or more conduits within a wellbore casing, and wherein the port
system comprises a plurality of perforations in the wellbore
casing.
31. The system of claim 26, wherein the condition comprises at
least one of an injection pressure condition or an injection flow
rate condition.
Description
BACKGROUND
[0001] The present disclosure relates to applying treatment fluid
to a rock matrix in a subterranean formation. Chemical treatments
are often applied to subterranean formations by injecting the
chemical treatment fluid through a wellbore in the formation. For
example, conventional chemical treatments include acid stimulation
treatments, scale inhibitor treatments, heat treatments,
consolidation treatments, and others. Such chemical treatments are
used to enhance resource production from the formation, to
strengthen the structure of the formation, or to otherwise
condition the formation for various types of activities.
SUMMARY
[0002] The present disclosure relates to applying treatment fluid
to a rock matrix in a subterranean formation. In a general aspect,
discontinuities are formed in the rock matrix, and the
discontinuities conduct the treatment fluid in the rock matrix.
[0003] In one aspect, a method of performing a chemical treatment
of a rock matrix includes receiving an injection fluid in a
wellbore in a subterranean formation. The subterranean formation
includes a rock matrix about the wellbore. Shear bands are induced
in the rock matrix by communicating the injection fluid from the
wellbore into the rock matrix. A chemical treatment fluid is
communicated through the shear bands into the matrix. The injection
fluid and the chemical treatment fluid may be the same fluid. The
chemical treatment fluid is conducted from the wellbore primarily
by a portion of the rock matrix that forms a wall of the wellbore,
primarily by a subset of the shear bands that intersect the wall of
the wellbore, or primarily by a combination of them. The rock
matrix may be exposed to the wellbore either directly as with an
open hole exposure to the wellbore or via fluid transmitting
penetrations of a (tubular) lining of the wellbore.
[0004] Implementations of these and other aspects may include one
or more of the following features. A leak-off rate of the injection
fluid increases the pore pressure of the rock matrix surrounding
the wellbore. Increased pore pressure causes dilatancy, lower
effective stress, reduced stress anisotropy, and lower
consolidation strength in the rock matrix surrounding the well
bore. A leak-off rate of the injection fluid in the rock matrix
prevents initiation of a dominant fracture at the wellbore wall.
The injection fluid is the chemical treatment fluid. Or, the
injection fluid and the chemical treatment fluid may be two
different fluids. The chemical treatment fluid is received in the
wellbore and communicated through the shear bands after the
injection fluid is communicated into the rock matrix. The shear
bands are induced substantially uniformly in the rock matrix about
a longitudinal section of the wellbore. The rock matrix includes a
soft rock formation having a Young's Modulus less than two million.
The chemical treatment includes an acid stimulation treatment, a
solvent treatment, a formation stabilizing treatment, a
consolidation treatment, or a scale inhibitor treatment.
[0005] In one aspect, a chemical treatment method for treating a
rock matrix about a subterranean wellbore includes communicating a
first fluid from the wellbore into an interval of the rock matrix
about the wellbore. The first fluid is communicated into the
interval under a condition that forms shear bands in the interval.
A chemical treatment fluid is communicated uniformly into the
interval. The chemical treatment fluid is conducted from the
wellbore primarily by a portion of the rock matrix that forms a
wall of the wellbore, primarily by a subset of the shear bands that
intersect the wall of the wellbore, or primarily by a combination
of them.
[0006] Implementations of these and other aspects may include one
or more of the following features. The condition that forms shear
bands in the interval can be a pressure condition, an injection
rate condition, or both. The chemical treatment fluid is
communicated to the wall of the wellbore by perforations through a
wellbore liner. Inducing the shear bands in the rock matrix
effectively increases the bulk permeability of the rock matrix near
the wellbore. The first fluid is a thin injection fluid that
contains substantially no solids and forms substantially no filter
cakes. The interval is a first interval. A proppant-laden fluid may
be injected into the first interval. A diverter material may be
used to limit injection into the first interval. The first fluid is
communicated into a second, different interval of the rock matrix
at a pressure and rate that forms shear bands in the second
interval. The chemical treatment fluid is conducted into the second
interval through the shear bands in the second interval.
[0007] In one aspect, a chemical treatment system for applying a
chemical treatment to a rock matrix includes a conduit system in a
wellbore. The chemical treatment system includes a fluid supply
system in communication with the conduit system. The fluid supply
system includes a thin injection fluid and a chemical treatment
fluid. The chemical treatment system includes a port system in
fluid communication with the conduit system. The port system is
operable to receive the injection fluid and the chemical treatment
fluid from the conduit system. The port system is operable to
communicate the injection fluid into the rock matrix at an
injection pressure and rate that induces shear bands in the rock
matrix about the wellbore. The port system is operable to
communicate the chemical treatment fluid into the rock matrix
primarily through a portion of the rock matrix that forms a wall of
the wellbore, primarily through a subset of the shear bands that
intersect the wall of the wellbore, or primarily through a
combination of them.
[0008] Implementations of these and other aspects may include one
or more of the following features. The fluid supply system resides
at a well system surface. The fluid supply system includes a single
fluid composition that includes both the injection fluid and the
chemical treatment fluid. The fluid supply system includes a first
fluid composition that is the thin injection fluid, and the fluid
supply system includes a second, different fluid composition that
is the chemical treatment fluid. The conduit system includes an
injection tubular or a production string, and the port system
includes one or more inflow control devices. The conduit system
includes a wellbore casing, and the port system includes one or
more perforations in the wellbore casing. The chemical treatment
fluid is communicated to the wall of the wellbore by perforations
through a wellbore liner.
[0009] The details of one or more implementations of the subject
matter described in this specification are set forth in the
accompanying drawings and the description below. Other features,
aspects, and advantages of the subject matter will become apparent
from the description, the drawings, and the claims.
DESCRIPTION OF DRAWINGS
[0010] FIG. 1 is a diagram of an example well system for applying a
chemical treatment to a subterranean formation.
[0011] FIG. 1A is a diagram of the example well system for applying
a chemical treatment to a subterranean formation showing open hole
exposure of a rock matrix.
[0012] FIG. 2A is a diagram of an example rock matrix that includes
shear bands.
[0013] FIG. 2B is a diagram of an example rock matrix that includes
bi-wing fractures.
[0014] FIG. 2C is a diagram of an example rock matrix that includes
radial shear bands.
[0015] FIG. 3 is a diagram of an example well system for applying a
chemical treatment to a subterranean formation.
[0016] FIGS. 4A, 4B, and 4C are a diagrams of an example well
system for applying a chemical treatment to multiple intervals of a
subterranean formation.
[0017] FIG. 5 is a flow chart for an example process for applying a
chemical treatment to a subterranean formation.
[0018] Like reference symbols in the various drawings indicate like
elements.
DETAILED DESCRIPTION
[0019] FIG. 1 is a diagram of an example well system 100 for
applying a chemical treatment to a subterranean formation 101. The
well system 100 includes an injection system 110 that applies a
treatment fluid 108 to a rock matrix 106 of the subterranean
formation 101. The injection system 110 includes control trucks
112, pump trucks 114, a wellbore 103, a work string 104 and other
equipment. In the example shown in FIG. 1, the pump trucks 114, the
control trucks 112 and other related equipment are above the
surface 102, and the wellbore 103, the work string 104, and other
equipment are beneath the surface 102. An injection system can be
configured as shown in FIG. 1 or in a different manner, and may
include additional or different features as appropriate. The
injection system may be deployed via skid equipment, marine vessel
deployed or may be comprised of sub-sea deployed equipment.
[0020] The subterranean formation 101 includes the rock matrix 106
about the wellbore 103. In some implementations, a chemical
treatment is applied substantially uniformly to the rock matrix
106. For example, the chemical treatment can be applied by
injecting a treatment fluid into the rock matrix 106 through the
wellbore 103. The treatment fluid can be injected into a soft rock
formation about the wellbore 103 to uniformly permeate an interval
of the formation and form shear discontinuities in the rock. The
treatment fluid can be a thin, low viscosity fluid that has a high
leak-off rate in the rock. The treatment fluid can be injected at
or above a fracture pressure and rate or rock matrix parting
pressure and rate so as to induce shear bands without forming a
dominant fracture (e.g., a bi-wing fracture) at the wellbore wall.
The shear bands can conduct the chemical treatment fluid from the
wellbore into the rock matrix, and in some cases, thereby achieve
more uniform placement of the chemical treatment fluid in the rock
matrix.
[0021] The formation can include a soft, highly plastic rock that
does not have a dominant stress contrast at the wellbore. The
mechanical properties of the rock along with the fluid properties
of the chemical treatment fluid may induce shear bands in the rock
formation about the wellbore without initiating or propagating a
dominant fracture at the wellbore wall on injection of the
treatment. As such, the injection can from a complex network of
interconnected shear bands in the rock matrix, which may act as a
conduit for communicating treatment fluids uniformly throughout the
rock matrix adjacent to the wellbore. For example, by creating
shear bands in the rock matrix, the chemical treatment can, in some
cases, more uniformly permeate the near wellbore rock matrix.
[0022] In some instances, fluids containing adjunct materials
(e.g., sand, gravel, proppant material, diverter material,
permeability modifier, etc.) may also be injected, for example, in
addition to the thin injection fluid that forms the shear bands.
The particulate or diverter materials can be placed, for example,
at an interface between the wellbore and the rock matrix to modify
the flow path of the treatment fluid. Such diverter material can be
used to enhance the uniform placement of the treatment fluid, for
example, in other intervals of the rock formation.
[0023] The wellbore 103 shown in FIG. 1 includes vertical and
horizontal sections, and the treatment fluid 108 is applied to the
rock matrix 106 surrounding the horizontal portion of the wellbore.
Generally, a wellbore may include horizontal, vertical, slant,
curved, and other types of wellbore geometries and orientations,
and the chemical treatment may generally be applied to a rock
matrix surrounding any portion of a wellbore. The wellbore 103 can
include a casing that is cemented or otherwise secured to the
wellbore wall. The wellbore 103 can be uncased or include uncased
sections. Perforations can be formed in the casing to allow
treatment fluids and/or other materials to flow into the rock
matrix 106. Perforations can be formed using shape charges, a
perforating gun, and/or other tools.
[0024] The pump trucks 114 may include mobile vehicles, immobile
installations, skids, hoses, tubes, fluid tanks or reservoirs,
pumps, valves, and/or other suitable structures and equipment. The
pump trucks 114 supply treatment fluid 108 from a fluid supply 118.
The pump trucks can communicate with the control trucks 112, for
example, by a communication link 113. The fluid supply system can
include a tank, reservoir, connections to external fluid supplies,
and/or other suitable structures and equipment. The pump trucks 114
are coupled to the work string 104 to communicate the treatment
fluid 108 into the wellbore 103.
[0025] The working string 104 may include coiled tubing, sectioned
pipe, and/or other structures that communicate fluid through the
wellbore 103. The working string 104 can include flow control
devices, bypass valves, ports, and or other tools or well devices
that control a flow of fluid from the interior of the working
string 104 into the rock matrix 106. For example, the working
string 104 may include ports that abut the wellbore wall to
communicate the treatment fluid 108 directly into the rock matrix
106, and/or the working string 104 may include ports that are
spaced apart from the wellbore wall to communicate the treatment
fluid 108 into an annulus in the wellbore between the working
string 104 and the wellbore wall. Although FIG. 1 shows the
horizontal section of the working string 104 represents an inner
tubular structure of the well system 100, in some embodiments, such
inner tubular structure may be absent.
[0026] The control trucks 112 can include mobile vehicles, immobile
installations, and/or other suitable structures. The control trucks
112 control and/or monitor the injection treatment. For example,
the control trucks 112 may include communication links that allows
the control trucks 112 to communicate with tools, sensors, and/or
other devices installed in the wellbore 103. The control trucks 112
may include communication links that allow the control trucks 112
to communicate with the pump trucks 114 and/or other systems at the
surface 102. The control trucks 112 may include an injection
control system that controls the flow of the treatment fluid 108
into the rock matrix 106. For example, the control trucks 112 may
monitor and/or control the density, volume, flow rate, flow
pressure, location, and/or other properties of the treatment fluid
108 injected into the rock matrix 106.
[0027] The injection system 110 may also include surface and
down-hole sensors (not shown) to measure pressure, rate,
temperature and/or other parameters of treatment. The injection
system 110 may include pump controls and/or other types of controls
for starting, stopping and/or otherwise controlling pumping as well
as controls for selecting and/or otherwise controlling fluids
pumped during the injection treatment. An injection control system
(e.g. in the control trucks 112) may communicate with such
equipment to monitor and control the injection treatment.
[0028] Applying the chemical treatment includes injecting the
chemical treatment fluid 108 into the rock matrix 106 to treat the
rock matrix 106. In some cases, it is desirable to treat the rock
matrix uniformly around (e.g., 360 degrees) the wellbore and
uniformly along longitudinal section of the wellbore. In some
implementations of the well system 100, a chemical treatment is
applied more uniformly by injecting the chemical treatment fluid
108 at a pressure that forms shear bands in the rock matrix and by
using the shear bands to conduct the fluid into the rock matrix.
For example, the shear bands may be formed by injecting the
chemical treatment fluid above a fracture pressure and by using a
low efficiency fluid that does not open a dominant fracture at the
wellbore wall.
[0029] Example chemical treatments include acid stimulation
treatments, formation stabilization treatments, consolidation
treatments, scale inhibitor treatments, treatments that remove
buildup of paraffin, asphaltene, or another substance from the rock
material, heat transfer treatments, water flood treatments, and
others. Acid stimulation treatments apply an acidic fluid to a rock
formation to improve the production or injection flow capacity, for
example, by dissolving material plugging the pores or by enlarging
the pore spaces. Formation stabilization treatments apply treatment
fluid to a subterranean zone to reduce movement of the matrix
formation grains and fine particles during operation of the well
including production or injection operations. Consolidation
treatments apply treatment fluid to a subterranean zone to control
production of sand and other undesirable substances from the zone.
For example, a consolidation treatment can be applied to a weak
sandstone formation to chemically bind the grains of sand while
maintaining sufficient permeability to achieve viable production
rates. Scale inhibitor treatments apply treatment fluid to control
or prevent scale deposition in the production conduit or completion
system. Heat transfer treatments apply heated fluids to a
subterranean zone to affect material properties of the zone, for
example, to achieve a desired flow rate. Waterflood treatments
inject fluids to act as a secondary recovery treatment, for
example, to displace residual hydrocarbons.
[0030] In one aspect of operation, the injection system 110 applies
a chemical treatment to the rock matrix 106. The control truck 112
controls and monitors the pump truck 114 which pumps the treatment
fluid 108 from the fluid supply system 118 through the work string
104, into the wellbore 103, and subsequently into the rock matrix
106. The treatment fluid 108 can be injected at a pressure that
induces shear bands in the rock matrix 106. The treatment fluid 108
can be injected in a manner that prevents a dominant fracture from
forming at the interior wall of the wellbore 103. For example, the
treatment fluid 108 can have a sufficiently high leak-off rate in
the rock matrix 106 to prevent formation of a dominant fracture. As
such, the shear bands formed by the treatment fluid 108 conduct the
injection fluid into the rock matrix 106. In some cases, a portion
of rock matrix 106 that forms the interior wall of the wellbore
acts as the primary fluid conductor that communicates fluid from
the interior of the wellbore into the rock matrix 106. In some
cases, shear bands formed by the treatment fluid 108 intersect the
interior wall of the wellbore, and the shear bands intersecting the
interior wall act as the primary fluid conductor that communicates
fluid from the interior of the wellbore into the rock matrix 106.
In some cases, both the shear bands and the rock matrix at the
wellbore wall act as the primary conductor.
[0031] FIG. 1A is a diagram of the example well system for applying
a chemical treatment to a subterranean formation showing open hole
exposure of rock matrix. Elements in FIG. 1A are similar to those
of FIG. 1, except that FIG. 1A shows open hole exposure of the rock
matrix 106 between the horizontal section of the wellbore 103 and
the rock matrix 106.
[0032] FIG. 2A is a diagram 200a of an example rock matrix 202a
that includes shear bands 203. The diagram 200a is viewed at a
cross-section, with a wellbore 201a at the center of the diagram.
The shear bands 203 can be induced by pumping highly permeable
fluids through the wellbore 201a and into the rock matrix 202a at a
fluid pressure that induces discontinuities in the rock matrix
202a, for example, at or above a fracture pressure. For example, a
thin fluid can be communicated into the rock matrix 202a from the
wellbore 201a, and the pressure of the thin fluid in the rock
matrix 202a can create zones of intense shearing strain that induce
the shear bands 203.
[0033] In some instances, the shear bands 203 are induced by
plastic deformation of the rock matrix 202a under the pressure of
the thin injection fluid. For example, the deformation can be
caused by material instability in the rock matrix corresponding to
increase in pore pressure surrounding the wellbore. In some
instances, the shear bands 203 are formed due to shear loading
applied to the rock matrix 202a by a thin fluid that has a
significant leak-off rate and low viscosity in the rock matrix
202a, in combination with the subterranean formation that restrains
the rock matrix 202a. As a result of the shear bands 203 that have
been formed in the rock matrix 202a, fluid subsequently injected
into the rock matrix 202a through the wellbore 201a in FIG. 2A will
be conducted from the wellbore 201a primarily through the portion
of the rock matrix 202a forming the wall of the wellbore 201a,
primarily through any of the shear bands 203 intersecting the
interior wall of the wellbore 201a, or primarily through both the
rock matrix and the shear bands.
[0034] In some implementations, fluid injection parameters can be
controlled to achieve the conditions that cause shear bands 203 to
form in the rock matrix 202a. For example, in some cases a
sufficiently high injection rate can induce some or all of the
shear bands 203. In some cases, treatment adjuncts, additives or
formulations can be used to effectively cause an increase in bottom
hole treating pressure or change the treatment penetration profile
such that the fracture system includes the entire target interval.
For example, treatment adjuncts may include sand, gravel, proppant,
foam, particulate diverter materials, plugging diverter materials
of various forms or shapes, relative permeability modifiers, and/or
others. Such adjunct materials can be included with treatment
fluids to block fluid entry into and leak-off from existing
fracture networks (e.g., in other zones), thus allowing subsequent
injection to create new fracture networks and radial penetration of
treatment through out the treatment interval.
[0035] FIG. 2B is a diagram 200b of an example rock matrix 202b
that includes bi-wing fractures 212. The diagram 200b is also
viewed at a cross-section, with a wellbore 201b at the center of
the rock matrix 202b. The bi-wing fractures 212 are formed by a
fracture initiation at the wellbore wall and propagation of the
fracture from the wellbore wall due to high stress concentration.
The bi-wing fractures 212 are the dominant fractures in the rock
matrix 202b. The example bi-wing fracture shown in FIG. 2B includes
two fractures radially opposite from each other. Dominant fractures
having other geometries may be formed in a similar manner. Fluid
injected into the rock matrix 202b through the wellbore 201b in
FIG. 2B will be conducted from the wellbore 201b primarily through
the open space in the dominant fractures.
[0036] FIG. 2C is a diagram of an example rock matrix that includes
radial shear bands. The diagram 200c is viewed at a cross-section,
with a wellbore 201c at the center of the diagram. The example
radial shear bands shown in FIG. 2C extend radially from the well
bore. The shear bands 203 can be induced by pumping highly
permeable fluids through the wellbore 201c and into the rock matrix
202c at a fluid pressure that induces discontinuities in the rock
matrix 202c, for example, at or above a fracture pressure. For
example, a thin fluid can be communicated into the rock matrix 202c
from the wellbore 201c, and the pressure of the thin fluid in the
rock matrix 202c can create zones of intense shearing strain that
induce the shear bands 203. In some implementations, radial shear
bands are formed during an initial phase of shear band formation in
the rock matrix 202c.
[0037] In some instances, the shear bands 203 are induced by
plastic deformation of the rock matrix 202c under the pressure of
the thin injection fluid. For example, the deformation can be
caused by material instability in the rock matrix corresponding to
increase in pore pressure surrounding the wellbore. In some
instances, the shear bands 203 are formed due to shear loading
applied to the rock matrix 202c by a thin fluid that has a
significant leak-off rate and low viscosity in the rock matrix
202c, in combination with the subterranean formation that restrains
the rock matrix 202c. In some instances, the induced shear bands
may initially form a radial fracture pattern from the wellbore
201c. In some instances, the induced shear bands may initially form
a different type of fracture pattern. As a result of the shear
bands 203 that have been formed in the rock matrix 202c, fluid
subsequently injected into the rock matrix 202c through the
wellbore 201c in FIG. 2C will be conducted from the wellbore 201c
primarily through the portion of the rock matrix 202c forming the
wall of the wellbore 201c, primarily through any of the shear bands
203 intersecting the interior wall of the wellbore 201c, or
primarily through both the rock matrix and the shear bands.
[0038] As shown in FIGS. 2A and 2B, different forms of rock
discontinuities are created by different loading conditions and
different properties of treatment fluids. The shear bands 203 in
FIG. 2A can be formed, for example, in a rock matrix 202a that has
softer mechanical properties and may also lack a dominant stress
concentration. In addition, the treatment fluids have permeability
high enough to allow significant leak-off such that a complex
fracture system can be created near the wellbore 201a. The
treatment fluids can then leak out of the fracture system into the
rock matrix formation 202a and effectively create a radial
penetration of the treatment around the wellbore 201a. The thin,
low viscosity treatment fluids can be pumped at rates and pressures
sufficient to cause multiple or complex or shear failure mode
fracture networks emanating from the wellbore 201a to the rock
matrix 202a. In this manner, the treatment fluids can generate a
system of smaller and irregular discontinuities in the rock matrix
202a near the wellbore, and the network of discontinuities can
communicate production fluids between the wellbore and the rock
matrix 202a. By contrast, in FIG. 2B the bi-wing fracture 212 is
created in a traditional manner with low permeability fluids pumped
at a rate that causes an opening mode of fracture.
[0039] FIG. 3 is a diagram of an example well system 300 for
applying a chemical treatment to a subterranean formation 101. The
example well system 300 can include the features of the example
well system 100 in FIG. 1. The example working string 104 shown in
FIG. 3 includes three flow control devices 122a, 122b, and 122c. A
working string may include a different number of flow control
devices. Each of the flow control devices 122a, 122b, 122c controls
the flow of injection fluid 308 into the rock matrix 106 about the
wellbore 103. Packers 124 reside in the wellbore 103 in the annulus
between the working string 104 and the interior wall of the
wellbore 103 (or between the working string 104 and the casing,
where the wellbore 103 is cased). The packers 124 isolate
longitudinal sections of the annulus. Each of the longitudinal
sections receive the fluid injected from one of the flow control
devices 122a, 122b, 122c. The packers 124 may include mechanical
packers, fluid inflatable packers, sand packers, swellable packers,
chemical isolation implementations and/or other types of
packers.
[0040] The injection fluid 308 can have the mechanical properties
of a Newtonian fluid, for example, a fluid whose stress at any
point is linearly proportional to its strain rate at that point,
where the constant of proportionality is the viscosity of the
fluid. The injection fluid 308 can be a thin fluid, for example,
that contains substantially no solids and does not form filter
cakes in the wellbore. The injection fluid 308 can be an
incompressible fluid, a multiphase fluid, and/or a composition of
multiple different types of fluids. The injection fluid 308 can
substantially uniformly permeate the rock matrix 106 about the
wellbore 103 and create shear discontinuities in the rock matrix
106.
[0041] In some implementations of the example system 300, each of
the flow control devices 122a, 122b, 122c can be selectively
opened, selectively closed, or otherwise reconfigured, for example,
by well intervention, by pressure signals or electromagnetic
signals propagated from the surface, and/or by another technique.
In some implementations, the flow control devices 122a, 122b, 122c
can be simultaneously opened or closed. In some instances, the
injection fluid 308 is communicated through the flow control
devices 122a, 122b and 122c into the rock matrix 106 at a pressure
that forms shear bands 330 in the rock matrix. The injection fluid
308 can be communicated simultaneously through two or more of the
flow control devices 122a, 122b, 122c, or the injection fluid 308
can be communicated through each of the flow control devices 122a,
122b, 122c at different times. As such, the shear bands 330 can be
formed throughout the rock matrix 106 concurrently, over multiple
time intervals, or in another manner.
[0042] The shear bands 330 can be formed substantially uniformly
about the wellbore 103. For example, the shear bands 330 can be
distributed through the rock matrix 106 such that the rock matrix
106 does not have substantial spatial variations in permeability
that would create preferential flow through certain regions of the
rock matrix 106. As such, in some instances, the shear bands 330
permit substantially uniform flow of a chemical treatment fluid
from the wellbore 103 into the rock matrix 106 about the wellbore
103. In some instances, the shear bands 330 are uniform over a
targeted section of the rock matrix 106. For example, the shear
bands may be uniform over a longitudinal section, an azimuthal
section, and/or a radial section about the wellbore.
[0043] The fluid supply 118 can supply a single fluid or it can
supply multiple different fluids. In some implementations, the
injection fluid 308 that forms the shear bands 330 is also the
chemical treatment fluid. For example, the injection fluid 308 that
forms the shear bands 330 can be the treatment fluid for an acid
stimulation treatment, a scale inhibitor treatment, a formation
stabilization treatment, a consolidation treatment, or another type
of chemical treatment fluid. In some implementations, the chemical
treatment fluid is a separate fluid that is injected after the
injection fluid 308 that forms the shear bands 330. For example,
after the injection fluid 308 has been injected to form the shear
bands 330, the treatment fluid for an acid stimulation treatment, a
scale inhibitor treatment, a formation stabilization treatment, a
consolidation treatment, or another type of chemical treatment
fluid can be injected.
[0044] FIGS. 4A, 4B, and 4C are diagrams of an example well system
400 for applying a chemical treatment to multiple intervals of a
subterranean formation 101. The example well system 400 shown in
FIGS. 4A, 4B, and 4C can include the features of the example well
system 300 in FIG. 3. The fluid supply 118 of FIGS. 4A, 4B, and 4C
includes two different fluids, and may include additional fluids
that are not illustrated in the figures. In particular, the fluid
supply 118 includes a thin injection fluid 119a that can be
injected into the rock matrix 106 to form shear bands in the rock
matrix. The fluid supply 118 also includes an adjunct-laden
injection fluid 119b that can be injected into the rock matrix 106
to plug an interval of the rock matrix 106.
[0045] As shown in FIGS. 4A, 4B, and 4C, the rock matrix 106
includes multiple intervals 116a, 116b, 116c. Each of the intervals
116a, 116b, and 116c is adjacent to one of the longitudinal
sections of the wellbore 103 defined by the packers 124. As such,
the intervals 116a, 116b, and 116c are identified by locations of
the packers 124 in the annulus of the wellbore 103. Intervals may
be identified by additional or different types of structures, or in
a different manner. In the example shown, each of the flow control
devices 122a, 122b, and 122c is operable to inject fluid into one
of the intervals 116a, 116b, and 116c. For example, due to the
fluid isolation provided by the packers 124, the flow control
device 122a injects fluid into the interval 116a, the flow control
device 122b injects fluid into the interval 116b, and the flow
control device 122c injects fluid into the interval 116c. In some
instances, more than one flow control device can be used to inject
fluid into each of the intervals.
[0046] Each of the individual intervals 116a, 116b, 116c can be
treated in sequence, or some or all of the intervals 116a, 116b,
116c can be treated simultaneously. In the example process shown by
FIGS. 4A, 4B, and 4C, the first interval 116a is treated, then the
second interval 116b is treated, and the third interval 116c can be
treated subsequently. Generally, the intervals 116a, 116b, 116c can
be treated in any order, in a cyclical fashion, or in another
manner.
[0047] In some implementations, a more uniform treatment of the
rock matrix 106 can be achieved by applying the chemical treatment
to individual intervals of the rock matrix 106. For example, to the
extent that there are variations in permeability among the
intervals 116a, 116b, 116c, the permeability within interval can be
substantially uniform. As such, if the one of the intervals has a
higher permeability than the other two, preferential treatment of
the high permeability interval may be reduced or avoided by
isolating the high permeability interval from the others.
[0048] The operations shown in FIGS. 4A, 4B, and 4C can, in some
implementations, achieve more uniform placement of treatment fluid
across the length of the rock matrix 106. For example, the system
400 may achieve more uniform radial penetration for sand
consolidation treatments to give more reliable recovery, higher
production rates without sand, and improved longevity of sand free
production in the treated formation. In some other examples, the
system 400 may achieve more uniform acid coverage, penetration and
stimulation of a target interval in an acid stimulation treatment,
and more uniform coverage to assure all parts of the zone receive
the inhibitor in a scale inhibitor treatment.
[0049] As shown in FIG. 4A, flow control device 122a is open while
the flow control devices 122b and 122c are closed. The thin
injection fluid 119a is pumped into the interval 116a through the
flow control device 122a. The thin injection fluid 119a in the
first interval 116a of the rock matrix 106 forms shear bands 430a
in the first interval 116a. A chemical treatment fluid can be
applied to the first interval. For example, the thin injection
fluid 119a or another fluid can be the chemical treatment fluid
that treats the first interval 116a.
[0050] As shown in FIG. 4B, after the chemical treatment has been
applied to the first interval 116a, the adjunct-laden fluid 119b
can be injected into the first interval 116a. The adjunct-laden
injection fluid 119b can be communicated into all or part of the
first interval 116a through the first flow control device 122a. The
adjunct-laden fluid plugs the first interval 116a to reduce the
flow of fluids into the first interval 116a when subsequent
intervals (e.g., 116b, 116c) are treated.
[0051] The treatment process can then continue to the next interval
as shown in FIG. 4C. The operations described with respect to FIGS.
4A and 4B can be repeated for the second interval 116b, and
subsequently for the third interval 116c. For example, as shown in
FIG. 4C, the flow control devices 122a and 122c are closed and the
flow control device 122b is open. The thin injection fluid 119a is
communicated into the second interval 116b and forms shear bands
430b in the interval 116b. Subsequently, after the chemical
treatment has been applied to the second interval 116b, the
adjunct-laden injection fluid 119b can be applied to the second
interval 116b. Similarly, the flow control devices 122a and 122b
can be closed and the flow control device 122c can be opened. The
thin injection fluid 119a can be communicated into the third
interval 116c and form shear bands in the third interval 116c.
Subsequently, after the chemical treatment has been applied to the
third interval 116c, the adjunct-laden injection fluid 119b can be
applied to the third interval 116c. Additional intervals (not
shown) can be treated by the same technique.
[0052] FIG. 5 is a flow chart showing an example process 500 for
performing a chemical treatment of a rock matrix. All or part of
the example process 500 may be implemented using features and
attributes of the example well systems shown in FIGS. 1, 3, 4A, 4B,
and 4C. In some cases, the process 500 may be implemented by a
different type of system. Aspects of the example process 500 may be
performed in a single-well system, a multi-well system, a well
system that includes multiple interconnected wellbores, and/or in
another type of well system, which may include any suitable
wellbore orientations. In some instances, the process 500 is used
for applying a chemical treatment to a rock matrix prior to
producing resources through the rock matrix or fracturing the rock
matrix. The process 500, including individual operations of the
process 500 and/or groups of the operations, may be iterated or
repeated, and/or they may be performed in connection with another
process. In some cases, the process 500 may include the same,
additional, fewer, and/or different operations performed in the
same or a different order.
[0053] At 502, a first interval in a subterranean formation is
identified. The subterranean formation can include a soft rock
formation having low stiffness, for example, a rock formation that
includes rock materials having a Young's Modulus value less than
two million. Examples of soft rock formations include shale, coal,
and certain types of geologically young formations (e.g., Miocene
and Pliocene period formations, and others). In some cases, the
material in such rock formations can include brittle rock having
low elasticity.
[0054] The interval is an interval along a wellbore in the
subterranean formation. The interval includes the rock formation
around a longitudinal section the wellbore. The longitudinal
section can be any suitable length. The longitudinal section may
include a section of a vertical, slant, curved, or horizontal
wellbore, including a toe, heel, or intermediate section in the
horizontal wellbore. The interval may be isolated by seals,
packers, or other types of isolators installed in the wellbore.
[0055] The interval can be identified for receiving a chemical
treatment. The chemical treatment to be applied to the interval can
include any type of chemical treatment to be applied uniformly in
the interval. Example chemical treatments include acid stimulation
treatments, formation stabilization treatments, consolidation
treatments, scale inhibitor treatments, treatments that remove
buildup of paraffin, asphaltene, or another substance from the rock
material, heat transfer treatments, water flood treatments, and
others. The chemical treatment can be a radial treatment to be
placed radially about the wellbore over a radial depth into the
rock formation from the wellbore wall.
[0056] At 504, fluid is communicated into the first interval to
induce shear bands in the interval. The fluid can be communicated
to induce shear bands at any stage of a treatment. For example,
shear bands can be induced during a first injection stage, or any
subsequent injection stage. The fluid can be part of the chemical
treatment and/or the fluid can be injected to prepare the interval
to later receive the chemical treatment. As such, the fluid that
induces the shear bands can be or can contain the chemical
treatment fluid, or the fluid that induces the shear bands can be a
separate fluid from the chemical treatment fluid. The fluid can
have mechanical properties of a Newtonian fluid, for example, a
fluid whose stress at any point is linearly proportional to its
strain rate at that point, where the constant of proportionality is
the viscosity of the fluid. The fluid can be a thin fluid, for
example, that contains substantially no solids and does not form
filter cakes in the wellbore. The fluid can be an incompressible
fluid, a multiphase fluid, and/or a composition of multiple
different types of fluids.
[0057] The fluid can be received in the wellbore from a fluid
supply system at the surface of the well system, and the fluid can
be communicated through the wellbore by a conduit system in the
wellbore. For example, the fluid can flow through any type work
string, tubing, or casing in the wellbore. The fluid is
communicated into the interval from the wellbore at 504, for
example, through perforations in the wellbore casing, through a
port in a production string (e.g., an inflow control device, a
valve, or another type of device), or through another type of port
system in the wellbore.
[0058] The fluid may be communicated into the rock matrix at 504 at
or above a fracture pressure without causing dominant fractures to
propagate from the wellbore wall. As such, the fluid can be
communicated into the rock matrix without forming conventional
bi-wing fractures or similar discontinuities in the rock matrix.
For example, by using thin fluids that have a low viscosity and/or
a high leak-off rate in the rock matrix, the fluid can be injected
above a fracture pressure without initiating or propagating a
dominant open fracture at the wellbore wall. Because dominant open
fractures are not formed at the wellbore wall, fluid can be
conducted from the wellbore primarily by the rock matrix itself
(i.e., a portion of the rock matrix that forms a wall of the
wellbore) and/or primarily by shear bands in the rock matrix (i.e.,
shear bands that intersect the wall of the wellbore).
[0059] The shear bands are formed in the interval substantially
uniformly about the wellbore. For example, the distribution of the
induced shear bands can be substantially uniform over a full range
of azimuthal directions about the wellbore, over the full
longitudinal length of the interval, and/or over a finite depth
into the formation from the wellbore wall. The full range of
azimuthal directions can be a full 360 degrees about the wellbore,
or a smaller range when appropriate. In some instances, the full
longitudinal length of the interval is the distance between packers
that isolate the interval from a neighboring interval. The finite
depth into the formation from the wellbore can be a depth of
several centimeters to several meters or more.
[0060] The uniformity of the shear bands in the interval results in
a higher permeability of the rock matrix that is substantially
uniform over the interval. For example, the increased permeability
may be substantially uniform over a full range of azimuthal
directions about the wellbore, over the full longitudinal length of
the interval, and/or over a finite depth into the formation from
the wellbore wall. In such cases, the fluid is communicated
substantially uniformly into the rock matrix as the fluid is
conducted through the shear bands in the interval. Thus, in some
implementations, the shear bands improve the uniformity, range,
and/or speed of fluid distribution in the interval.
[0061] In some implementations of the process 500, the first
interval is plugged at 506 after the shear bands are formed in the
interval. For example, the first interval may be plugged by
communicating a proppant-laden fluid into the first interval. The
proppant-laden fluid contains proppant material (i.e., solids) that
plug open volumes in the interval. The interval may be plugged in a
different manner, for example, by closing a port of a production
string (e.g., by reconfiguring an inflow control device, a valve,
or another device), by use of a relative permeability modifier, or
by plugging perforations in a well casing. Plugging the interval
prevents or substantially reduce the rate at which fluid can be
communicated into the interval from the wellbore. As such, when
subsequent intervals are treated, the plugging material can prevent
or reduce the communication of fluids into the first interval (or
any intervals that have been plugged).
[0062] After the first interval is plugged, a next interval of the
subterranean formation is identified at 508. Fluid is then
communicated into the next interval to induce shear bands in the
next interval (504). The operations 504, 506, and 508 may be
iterated for any number of intervals along the wellbore. In some
implementations of the process 500, only a single interval is used.
For example, the first interval may be the entire target region for
the chemical treatment, or the first interval may be the only
interval available. As such, in some implementations no additional
intervals are identified and/or the first interval is not
plugged.
[0063] At 510, additional fluid may be communicated into the first
interval and/or into one or more other intervals in the
subterranean formation. The additional fluid applied at 510 may be
the same or a different fluid than was used to induce the shear
bands at 504. The additional fluid communicated into the
interval(s) at 510 can be part of a different chemical treatment
than the fluid that was used to induce the shear bands at 504. The
additional fluid communicated into the interval(s) at 510 can be
part of the same chemical treatment that was applied at 504. Due to
the presence of the shear bands, the additional fluid is
communicated substantially uniformly into the rock matrix within
each interval as the fluid is conducted through the shear bands in
the interval(s). Thus, in some implementations, the shear bands
improve the uniformity, range, and/or speed of distribution of the
additional fluid in the interval. The additional fluid can be
conducted from the wellbore primarily by the rock matrix itself
and/or primarily by shear bands in the rock matrix intersecting the
wall of the wellbore.
[0064] In some implementations of the process 500, the additional
fluid is communicated into the first interval prior to inducing
shear bands in any other interval. For example, after inducing the
shear bands in the first interval at 504 and communicating
additional fluid into the first interval at 510, the first interval
may be plugged at 506, the next interval may be identified at 508,
and one or more of the operations (504, 510, 506, 508) may be
iterated for subsequent intervals.
[0065] In some implementations of the process 500, the additional
fluid is communicated into the first interval after inducing the
shear bands in the other intervals. For example, after inducing
shear bands in multiple intervals, any intervals that have been
plugged can be unplugged to allow communication of the additional
fluid into the intervals. An interval may be unplugged, for
example, by dissolving or otherwise removing the proppant or other
diverter materials that were used to plug the interval. An interval
may be unplugged by opening a port of a production string (e.g., by
reconfiguring an inflow control device, a valve, or another device)
or by dissolving or otherwise removing a plug from perforations in
a well casing. As such, the additional fluid may be communicated
into multiple different intervals simultaneously, sequentially, or
in a different manner.
[0066] A number of embodiments have been described. Nevertheless,
it will be understood that various modifications may be made
without departing from the spirit and scope of the invention.
Accordingly, other embodiments are within the scope of the
following claims.
* * * * *