U.S. patent application number 12/777965 was filed with the patent office on 2011-11-17 for subterranean flow barriers containing tracers.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Alvin S. Cullick, Leldon M. Farabee, Stewart A. Levin, Robert F. Shelley, Norm R. Warpinski.
Application Number | 20110277996 12/777965 |
Document ID | / |
Family ID | 44626313 |
Filed Date | 2011-11-17 |
United States Patent
Application |
20110277996 |
Kind Code |
A1 |
Cullick; Alvin S. ; et
al. |
November 17, 2011 |
SUBTERRANEAN FLOW BARRIERS CONTAINING TRACERS
Abstract
Some aspects of the present disclosure include monitoring fluid
flow in a subterranean reservoir. In some implementations, a
sealant mixture is injected into a subterranean reservoir to form a
flow barrier in the subterranean reservoir. The sealant mixture
includes a sealant material and a tracer. The tracer may be stored
in the flow barrier, and the tracer may be displaced from the flow
barrier, for example, by fluid flow in the subterranean reservoir.
The displaced tracer may be detected, for example, in fluid
produced into a well bore in the subterranean reservoir. Fluid flow
in the subterranean reservoir may be analyzed based on detection of
the tracer.
Inventors: |
Cullick; Alvin S.; (Houston,
TX) ; Farabee; Leldon M.; (Houston, TX) ;
Warpinski; Norm R.; (Cypress, TX) ; Shelley; Robert
F.; (Katy, TX) ; Levin; Stewart A.;
(Centennial, CO) |
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
44626313 |
Appl. No.: |
12/777965 |
Filed: |
May 11, 2010 |
Current U.S.
Class: |
166/250.12 ;
166/66 |
Current CPC
Class: |
E21B 33/138 20130101;
E21B 43/16 20130101; E21B 47/11 20200501 |
Class at
Publication: |
166/250.12 ;
166/66 |
International
Class: |
E21B 47/00 20060101
E21B047/00; E21B 43/16 20060101 E21B043/16 |
Claims
1. A method for monitoring fluid flow in a subterranean reservoir,
the method comprising: injecting a sealant mixture into a
subterranean reservoir to form a flow barrier in the subterranean
reservoir, the sealant mixture comprising a sealant material and a
tracer; and detecting the tracer displaced from the flow barrier by
fluid flow in the subterranean reservoir.
2. The method of claim 1, wherein detecting the tracer comprises
detecting the tracer in fluids received into a well bore in the
subterranean reservoir.
3. The method of claim 2, wherein the fluids comprise a treatment
fluid injected into the subterranean reservoir through a different
well bore.
4. The method of claim 1, wherein injecting the sealant mixture
comprises injecting a chemical tracer mixed with the sealant
material.
5. The method of claim 1, wherein injecting the sealant mixture
comprises injecting a radioactive tracer mixed with the sealant
material.
6. The method of claim 1, wherein injecting the sealant mixture
comprises injecting a noble gas tracer mixed with the sealant
material.
7. The method of claim 1, wherein injecting the sealant mixture
comprises injecting an active radio frequency tracer device mixed
with the sealant material.
8. The method of claim 1, wherein injecting the sealant mixture
comprises injecting a water-soluble tracer mixed with the sealant
material.
9. The method of claim 1, wherein injecting the sealant mixture
comprises injecting a hydrocarbon-soluble tracer mixed with the
sealant material.
10. The method of claim 1, wherein injecting the sealant mixture
comprises injecting the sealant mixed with a tracer that includes a
coating adapted to dissolve when contacted by a particular
fluid.
11. The method of claim 1, wherein the sealant in the subterranean
reservoir reduces fluid flow through the flow barrier.
12. The method of claim 1, wherein the sealant in the subterranean
reservoir prevents fluid flow through the flow barrier.
13. The method of claim 1, wherein the sealant mixture comprises a
first sealant mixture comprising a first tracer, the method further
comprising: injecting a second sealant mixture into the
subterranean reservoir to form a second flow barrier in the
subterranean reservoir, the second sealant mixture comprising the
sealant material and a second tracer; and detecting the second
tracer displaced from the second flow barrier by fluid flow in the
subterranean reservoir.
14. The method of claim 1, wherein the sealant mixture comprises a
first sealant mixture comprising a first tracer, and the first
sealant mixture forms a first portion of the flow barrier, the
method further comprising: injecting a second sealant mixture into
the subterranean reservoir to form a second portion of the flow
barrier, the second sealant mixture comprising the sealant material
and a second tracer; and detecting the second tracer displaced from
the flow barrier by fluid flow in the subterranean reservoir.
15. A system for monitoring fluid flow in a subterranean reservoir,
the system comprising: a treatment well that injects treatment
fluid into a subterranean reservoir to displace hydrocarbon fluid
in the subterranean reservoir, the subterranean reservoir
comprising a flow barrier that stores a tracer; and a detector
adapted to detect the tracer displaced from the flow barrier in at
least one of the hydrocarbon fluid or the treatment fluid.
16. The system of claim 15, wherein the detector comprises a down
hole detector installed in the well bore and adapted to detect the
tracer released from the flow barrier.
17. The system of claim 15, wherein the detector comprises a
detector located exterior the well bore and adapted to detect the
tracer released from the flow barrier.
18. The system of claim 15, further comprising a computing
subsystem that analyzes fluid flow in the subterranean reservoir
based on data provided by the detector.
19. The system of claim 15, wherein the treatment fluid comprises
water and the hydrocarbon fluid comprises oil.
20. The system of claim 15, wherein the tracer comprises a salt
stored in the barrier and detecting the tracer comprises detecting
a change of resistivity of at least one of the hydrocarbon fluid or
the treatment fluid.
21. A method for analyzing fluid flow in a subterranean reservoir,
the method comprising: forming a flow barrier in a subterranean
reservoir, the flow barrier comprising a tracer; and analyzing
fluid flow in the subterranean reservoir based on detecting the
tracer in fluids received into a well bore from the subterranean
reservoir.
22. The method of claim 21, wherein analyzing fluid flow in the
subterranean reservoir comprises identifying that the fluids
contacted the flow barrier in the subterranean reservoir.
23. The method of claim 21, wherein analyzing fluid flow in the
subterranean reservoir comprises identifying locations in the
subterranean reservoir where the fluids contacted the flow
barrier.
24. The method of claim 21, wherein analyzing fluid flow in the
subterranean reservoir comprises identifying a breach in the flow
barrier.
25. The method of claim 21, wherein forming the non-conductive
barrier comprises injecting the tracer and a sealant material into
the subterranean reservoir.
Description
BACKGROUND
[0001] Production of resources from a subterranean reservoir can be
enhanced by injecting fluids into the reservoir to displace or
sweep the resources to a production well. For example, water,
steam, and/or other fluids are injected into subterranean
reservoirs to induce migration of oil and gas resources to nearby
production wells. The permeability of the reservoir rock, the
connectivity of fractures in the reservoir, and other factors
influence how the injected fluids and hydrocarbons flow through the
reservoir. Fractures are typically formed in a reservoir to
increase the fluid conductivity of the reservoir. Non-conductive
barriers may also be formed in the reservoir to prevent the flow of
fluid in a certain region of the reservoir. Such non-conductive
barriers can be formed by injecting low permeability materials into
fractures in the reservoir, including hydraulically induced
fractures and/or natural fractures. The resulting non-conductive
barriers divert the flow of injected water or steam, and thereby
increase the volume of the reservoir swept by the injected
fluids.
SUMMARY
[0002] In a general aspect, a tracer is stored in a subterranean
flow barrier. The tracer may be released or displaced from the flow
barrier and detected. In some cases, fluid flow may be analyzed
based on the tracer.
[0003] In one aspect, a method for monitoring fluid flow in a
subterranean reservoir includes injecting a sealant mixture into a
subterranean reservoir to form a flow barrier in the subterranean
reservoir. The sealant mixture includes a sealant material and a
tracer. The tracer may remain in the flow barrier for a period of
time. The tracer is displaced from the flow barrier by fluid flow
in the subterranean reservoir, and the displaced tracer is
detected.
[0004] Implementations may include one or more of the following
features. Detecting the tracer includes detecting the tracer in
fluids received into a well bore in the subterranean reservoir. The
fluid flow includes flow of a treatment fluid injected into the
subterranean reservoir through a different well bore. Injecting the
sealant mixture includes injecting a chemical tracer mixed with the
sealant material. Injecting the sealant mixture includes injecting
at least one of a radioactive tracer mixed with the sealant
material, a noble gas tracer mixed with the sealant material, a
radio frequency tracer device mixed with the sealant material, a
water-soluble tracer mixed with the sealant material, and/or a
hydrocarbon-soluble tracer mixed with the sealant material.
Injecting the sealant mixture includes injecting the sealant mixed
with a tracer, where the tracer includes a coating adapted to
dissolve when contacted by a particular fluid. The sealant in the
subterranean reservoir prevents fluid flow through the flow
barrier. The sealant mixture is a first sealant mixture that
includes a first tracer. A second sealant mixture includes a second
tracer. The second sealant mixture is injected into the
subterranean reservoir to form a second flow barrier in the
subterranean reservoir. The second tracer is displaced from the
second flow barrier by fluid flow in the subterranean reservoir.
The second tracer displaced from the second flow barrier is
detected. The first sealant mixture forms a first portion of the
flow barrier. A second sealant mixture is injected into the
subterranean reservoir to form a second portion of the flow
barrier. The second tracer is displaced from the flow barrier by
fluid flow in the subterranean reservoir. The second tracer
displaced from the flow barrier is detected.
[0005] In one aspect, a system for monitoring fluid flow in a
subterranean reservoir includes a treatment well and a detector.
The treatment well injects treatment fluid into a subterranean
reservoir to displace hydrocarbon fluid in the subterranean
reservoir. The subterranean reservoir includes a flow barrier that
stores a tracer. The detector is adapted to detect the tracer
displaced from the flow barrier by the hydrocarbon fluid and/or the
treatment fluid.
[0006] Implementations may include one or more of the following
features. The detector includes a down hole detector installed in
the well bore and adapted to detect the tracer released from the
flow barrier. The detector includes a detector located exterior the
well bore and adapted to detect the tracer released from the flow
barrier. The system includes a computing subsystem that analyzes
fluid flow in the subterranean reservoir based on data provided by
the detector. The treatment fluid is water and the hydrocarbon
fluid is oil. The tracer includes a salt stored in the barrier.
Detecting the tracer includes detecting a change of resistivity of
the hydrocarbon fluid and/or the treatment fluid.
[0007] In one aspect, a method for analyzing fluid flow in a
subterranean reservoir includes forming a flow barrier in a
subterranean reservoir. The flow barrier includes a tracer. Fluid
flow in the subterranean reservoir is analyzed based on detecting
the tracer in fluids received into a well bore from the
subterranean reservoir.
[0008] Implementations may include one or more of the following
features. Analyzing fluid flow in the subterranean reservoir
includes identifying that the fluids contacted the flow barrier in
the subterranean reservoir. Analyzing fluid flow in the
subterranean reservoir includes identifying a breach in the flow
barrier. Forming the non-conductive barrier includes injecting the
tracer and a sealant material into the subterranean reservoir.
Analyzing the fluid flow includes identifying a direction of fluid
flow in the subterranean reservoir. Geological features of the
subterranean reservoir, for example geological heterogeneity,
causes fluid to flow in multiple different directions, and
analyzing the fluid flow includes identifying the directions of
fluid flow and/or the geological features. An injection treatment
is designed and/or modified based on detecting the tracers and/or
on the analysis of the fluid flow. Designing the injection
treatment includes selecting a location to inject treatment fluid,
selecting a volume of treatment fluid to inject, selecting
properties of a flow barrier to be formed. The injection treatment
may be designed and/or modified to improve recovery of hydrocarbons
from the reservoir.
DESCRIPTION OF DRAWINGS
[0009] FIG. 1 is a diagram of an example well system that includes
a barrier in a subterranean reservoir.
[0010] FIG. 2 is a diagram of an example well system storing
reservoir tracers in subterranean barriers.
[0011] FIG. 3 is a diagram of an example treatment well.
[0012] FIG. 4 is a diagram of an example well system detecting
tracers released into a subterranean reservoir from a barrier.
[0013] FIG. 5 is a diagram of an example well system detecting
tracers released into a subterranean reservoir from a barrier.
[0014] FIG. 6 is a flow chart showing an example technique for
analyzing fluid flow in a reservoir.
[0015] FIGS. 7A-7D are diagrams of subterranean reservoir
properties from example simulations.
[0016] Like reference symbols in the various drawings indicate like
elements.
DETAILED DESCRIPTION
[0017] FIG. 1 is diagram of an example well system 100. The example
well system 100 includes a production well 103 and treatment well
104 in a subterranean region 101 beneath a surface 102. The well
system 100 can include one or more additional production wells
and/or one or more additional treatment wells. The example
production well 103 shown in FIG. 1 includes a horizontal well
bore, and the example treatment well 104 shown in FIG. 1 includes a
vertical well bore. However, production wells and treatment wells
in the well system 100 may include any combination of horizontal,
vertical, slant, curved, and/or other well bore geometries. The
subterranean region 101 may include a reservoir 105 that contains
hydrocarbon resources, such as oil, natural gas, and/or others. The
reservoir 105 may include porous and permeable rock containing
liquid and/or gaseous hydrocarbons. The reservoir 105 may include a
conventional reservoir, a non-conventional reservoir, a tight gas
reservoir, and/or other types of reservoir. The well system 100
produces the resident hydrocarbon resources from the reservoir 105
to the surface 102.
[0018] A production well 103 may extend through a
hydrocarbon-containing subterranean formation area and into a
water-bearing area. The water-bearing area may include, for
example, fresh water, saltwater (e.g., water containing one or more
salts dissolved therein), brine (e.g., saturated saltwater), and/or
similar fluids. Typically, the water-bearing area may include a
small proportion of hydrocarbon and/or other materials, the
hydrocarbon-bearing area may include a small proportion of water
and/or other materials, and the areas may overlaps in an
intermediate area containing varying proportions of water and
hydrocarbons. In some implementations, the water may come from a
variety of sources, including in-situ water, injected water, or
water entering the reservoir from an external source. For example,
the water may be introduced into the formation through the
injection well 104.
[0019] The reservoir 105 includes multiple subterranean fractures
106 in fluid communication with the production well 103. The
fractures 106 may include fractures formed by a fracture treatment
applied through the production well 103, natural fractures, complex
fractures, and/or a network of propagated and natural fractures.
For example, in addition to the bi-wing fractures shown in FIG. 1,
the reservoir 105 may include a complex fracture network with
multiple connected fractures at multiple orientations. The
fractures 106 may extend at any angle, orientation, and azimuth
from the production well 103. The fractures 106 include transverse
fractures, longitudinal fractures (e.g., curtain wall fractures),
and/or deviated fractures that extend along natural fracture lines.
Hydraulically propagated fractures may have a geometry, size and/or
orientation determined by injection tool settings.
[0020] The fractures 106 may contain proppant material injected
into the fractures 106 to hold the fractures 106 open for resource
production. Fluids typically flow more readily through the
fractures 106 than through the rock and/or other geological
material surrounding the fractures 106. For example, in some
instances, the permeability of the rock in the reservoir 105 may be
several orders of magnitude less than the permeability in the
fractures 106.
[0021] The subterranean region 101 includes multiple barriers 108
adjacent the production well 103. Each barrier 108 includes sealant
material that inhibits fluid flow in the barrier 108. The sealant
material can include a low-permeability material. In some
implementations, the permeability of the barrier 108 can be
slightly less than or significantly less than the permeability of
the reservoir 105 surrounding the barrier 108. In some
implementations, a fracture may be partially sealed in an area near
the well bore rather than completely sealed all the way to the
fracture tip. Sealing the near well bore area may partially divert
injection fluids to improve sweep.
[0022] As shown in FIG. 1, the well bore 103 includes a fluid
control unit 107 that can prevent axial flow through the well bore
that would circumvent the flow barrier 108. For example, a bridge
plug or other zonal isolation device may be installed in the well
bore to prevent axial flow through the well bore that would
circumvent the flow barrier 108.
[0023] Fluid flow within a reservoir may be modified by the
presence of a barrier. Selective or non-selective flow barriers may
modify flow patterns within an entire reservoir or portions of a
reservoir. In some implementations, a sealant that includes a
relative permeability modifier may allow hydrocarbon materials to
selectively flow through the barrier in relation to an aqueous
fluid. In some implementations, multiple barriers may have varying
permeabilities, and a series of barriers may guide the flow of at
least one desired fluid, for example, to a producing well. In some
cases, multiple selective and/or non-selective barriers may be used
to modify the flow regime inside the hydrocarbon reservoir to
improve the volumetric sweep efficiency of the hydrocarbons in the
formation. The sealant and fluid used to provide the driving force
for flow and sweep the hydrocarbon fluids can be selected to
improve and/or maximize the amount of hydrocarbons recovered in a
hydrocarbon reservoir.
[0024] A barrier 108 can be formed by injecting sealant material
into the reservoir, for example, through the production well 103
and/or another well. Injecting the sealant material may fracture
the reservoir rock as the sealant is injected, and/or the sealant
material may be injected into existing fractures. For example, the
sealant may be injected into fractures previously formed by a
fracture treatment, natural fractures, complex fractures, and/or a
network of propagated and natural fractures. The barriers 108 may
extend at any angle, orientation, and azimuth from the production
well 103. The barriers 108 may include variations in size, shape,
thickness, permeability, and/or variations in other
characteristics. In some implementations, the reservoir 105
includes barriers that are not adjacent to a production well bore.
The sealant may be injected in an existing fracture by squeezing
the sealant into the fracture, which may be accomplished, for
example, by isolating perforations adjacent to the existing
fracture using a packer on the end of tubing, then pumping the
sealant in a fluid state through the tubing and through the
perforations and into the fracture to be sealed until a sufficient
volume of sealant has been placed into the fracture to provide the
flow barrier.
[0025] Treatment fluids 110 are injected into the reservoir 105
through the treatment well 104 to induce migration of the resident
hydrocarbon resources to the production well 103. For example,
steam, water, gas, compressed air and/or other types of treatment
fluids may be injected into the reservoir 105 through the treatment
well 104. The injected treatment fluid 110 can displace or sweep
oil, gas, and/or other resources into the production well 103, for
example, via the fractures 106. The injected treatment fluid 110
may be injected in connection with a fireflood treatment, steam
assisted gravity drainage treatment, and/or many other types of
treatments that mobilize hydrocarbons in the reservoir 105.
Barriers 108 in the reservoir 105 may influence the flow of
treatment fluids 110 and hydrocarbon resources in the reservoir
105. The barriers 108 can be designed to improve sweep efficiency
in the reservoir 105. The arrows 116 show an example pattern of
fluid flow through the reservoir 105, where the flow is diverted by
the barriers 108. As illustrated by the arrows 116 in FIG. 1, the
treatment fluid 110 flows through the reservoir 105 toward the
production well 103, contacts the barriers 108, and flows into the
production well 103 through the fractures 106. In the example
shown, the barriers 108 divert the treatment fluid 110 away from
the production well 103 and cause the treatment fluid to sweep a
larger region of the reservoir 105. Increasing the volume of the
reservoir 105 that is swept by the treatment fluid 110 may enhance
resource production from the reservoir 105. Barriers may be
designed to influence fluid flow in the reservoir 105 in a
different manner than the examples shown.
[0026] As shown in FIGS. 2, 4, and 5, barriers may contain
reservoir tracers that can be used to analyze the flow of fluid in
the reservoir 105. The tracers can be stored in the barriers 108,
208, 408, 508a, 508b. In some implementations, tracers stored in a
barrier reside in or near the barrier until an event causes the
tracer to be displaced from the barrier in the reservoir. When a
tracer is displaced from the barrier, it may be released and/or
transported out of and/or away from the barrier. Contact by a
particular type of fluid and/or other events may cause the tracer
to be displaced from the barrier. Tracers stored in a barrier may
reside in or near the barrier for hours, days, weeks, months,
years, or longer before the tracers are displaced from the barrier,
for example, by fluid flow in the reservoir. In some instances, the
treatment fluid 110 is injected with treatment fluid tracers
through the treatment well 104. Such treatment fluid tracers
injected with the treatment fluid 110 are traditionally used to
identify the treatment well 104 as the source of the treatment
fluid 110. The tracers stored in the barriers are injected with the
sealant that forms the barriers, rather than being injected with
the treatment fluid 110. As such, the tracers stored in the
barriers may be used in some cases to identify and/or analyze
additional and/or different types of information than the
traditional treatment fluid tracers injected with the treatment
fluid 110.
[0027] The production well 103, the reservoir 105, and/or other
locations can be monitored for tracers that have been transported
from the barriers 108 into the formation 105. Detecting such
tracers may provide information on fluid flow in the reservoir 105.
For example, detecting the tracer may indicate that the fluid
containing the tracer interacted with one or more of the barriers
108. Detecting the tracers may provide additional and/or different
information. For example, detecting tracers may provide
spatio-temporal information regarding fluid flow patterns in the
reservoir 105. Fluid flow patterns may indicate the location of a
barrier breach, connectivity of subterranean fractures, rates of
fluid flow in the reservoir 105, regions of low fluid conductivity
in the reservoir 105, regions of high fluid conductivity in the
reservoir 105, and/or other information. Detecting tracers may
indicate a type of fluid (e.g., oil, water, etc.) contacting the
barrier 108, and/or other information regarding fluid flow in the
reservoir 105. Detecting tracers may indicate a level of stress in
the reservoir, for example, when the tracers are designed to be
released into the reservoir 105 by stress in the barriers 108.
[0028] In some implementations, a computing system analyzes data
received from a tracer detection subsystem and analyzes the data to
provide information describing fluid flow in the reservoir 105. For
example, the computing system may receive input data relating to
the time the tracer was detected, the location where the tracer was
detected, the type of tracer detected, the amount of tracer
detected, and/or other measurements provided by a detector. The
computing system may access input data describing barriers,
fractures, well bores, and/or other features of the region 101,
including the types of tracers stored in the barriers 108. The
computing system may include programs, scripts, and/or other types
of computer instructions that generate output data based on the
input data. The output data may include spatio-temporal
descriptions of fluid flow patterns in the reservoir 105, which may
identify paths of fluid flow in the reservoir 105, barrier
breaches, fracture locations, fluid flow rates, and/or other
information.
[0029] The well system 100 may be modified or adjusted based on the
detection of tracers released from the barriers 108 into the
reservoir 105. For example, well system tools, and/or other
subsystems may be installed, adjusted, activated, terminated, or
otherwise modified based on the information provided by the
tracers. In some cases, fluid injection at the treatment well 104
can be modified, locations and characteristics of the barriers 108
can be modified, additional barriers can be formed in the reservoir
105, additional fractures can be formed in the reservoir 105,
production tubing and packers in the production well 103 can be
reconfigured, and/or other modifications can be made based on
information provided by the tracers. In the present disclosure, the
term "based on" indicates that an item or operation is based at
least in part on one or more other items or operations--and may be
based exclusively, partially, primarily, secondarily, directly, or
indirectly on the one or more other items or operations. In some
implementations, the modifications of the well system 100 are
selected and/or parameterized to improve production from the
reservoir 105. For example, the modifications may improve the sweep
efficiency of the treatment fluids 110. In some implementations,
the modifications of the well system 100 are selected and/or
parameterized by the computing system based on data analysis
performed by the computing system.
[0030] FIG. 2 is a diagram of an example well system 200 forming
barriers 208 in a reservoir 205. The barriers 208 include sealant
226 and tracers 228. The sealant 226 may include materials that
inhibit or reduce flow in the barrier 208. The sealant 226 may
include materials that harden and/or become less viscous in the
barrier 208.
[0031] In some implementations, the sealant used to provide the
barrier may be any material capable of selectively or
non-selectively reducing the flow of one or more fluids within a
subterranean formation. A non-selective barrier substantially seals
the fracture. A selective barrier modifies the permeability or
relative permeability to allow fluids to selectively flow through
the fracture. Example sealant materials include cements, linear
polymer mixtures, linear polymer mixtures with a cross-linker,
in-situ polymerized monomer mixtures, resin-based fluids,
epoxy-based fluids, magnesium-based slurries, metallic particles, a
clay based slurry (e.g., a bentonite based slurry), an emulsion, a
precipitate (e.g., a polymeric precipitate), or an in-situ
precipitate. An in-situ precipitate can be formed within the
subterranean formation, for example, using a polymeric solution
introduced into a subterranean formation followed by an
activator.
[0032] A subterranean barrier may incorporate components with
physical properties that aid remote geophysical measurement of the
barrier geometry and/or the internal barrier structure. Such
considerations can be useful for quality control, remedial
intervention, and/or other tasks. In some implementations, the
material composition of the barrier 208 is selected to make the
barrier 208 more "visible" (i.e., detectable) by remote geophysical
measuring devices. For example, some selected materials such as
barite included in the barrier 208 may increase density contrast of
the barrier 208 with the surrounding reservoir 205, thus making the
barrier 208 more visible to seismic probing; other selected
materials (e.g., metallic particles and/or others) included in the
barrier may enhance the electromagnetic response from the barrier
208, making the response more distinguishable from the surrounding
reservoir 205.
[0033] The sealant 226 can be injected in a fluid state and become
viscous or solid in the reservoir 205. The viscous or solid sealant
226 in the reservoir can act as a barrier to fluid migration. An
example sealant is H2ZERO.TM., an organically cross-linked polymer
that can be used to fracture the reservoir and form a flow barrier
in the resulting fracture. Other sealants may include particles,
ground cuttings, drilling mud, cuttings, slag, and/or others.
Drilling mud may include all types of drilling mud including oil
based muds, invert emulsions, polymer based muds, clay based muds,
weighted muds, and/or others. Sealants including a wide range of
particle sizes may help produce low permeability in the barrier 208
as compared to the surrounding reservoir 205.
[0034] In some implementations, the sealant may include swellable
particles. A swellable particle can swell upon contact with a
fluid, for example, an aqueous fluid, an oil-based fluid, gas,
and/or others. In some instances, swellable particles swell by up
to 200% of their original size at the surface. Under downhole
conditions, this swelling may be more, or less, depending on the
conditions present. For example, the swelling may be at least 10%
under downhole conditions. In some implementations, the swelling
may be up to approximately 50% under downhole conditions. The rate
of swelling may be seconds, minutes, hours, or days. An example of
a swellable particle includes a swellable elastomer that swells in
the presence of an oil-based fluid or an aqueous-based fluid.
Swelling elastomers may be used to activate tracers, for example,
by crushing a capsule when the elastomer expands upon contact with
hydrocarbons or other fluids. Some specific examples of swellable
elastomers that swell in the presence of an oil-based fluids
include natural rubbers, acrylate butadiene rubbers, isoprene
rubbers, chloroprene rubbers, butyl rubbers, brominated butyl
rubbers, chlorinated butyl rubbers, chlorinated polyethylenes,
neoprene rubbers, styrene butadiene copolymer rubbers, chlorinated
polyethylene, sulphonated polyethylenes, ethylene acrylate rubbers,
epichlorohydrin ethylene oxide copolymers, epichlorohydrin
terpolymer, ethylene-propylene rubbers, ethylene vinyl acetate
copolymers, ethylene-propylene-diene terpolymer rubbers, ethylene
vinyl acetate copolymer, nitrile rubbers, acrylonitrile butadiene
rubbers, hydrogenated acrylonitrile butadiene rubbers, carboxylated
high-acrylonitrile butadiene copolymers, polyvinylchloride-nitrile
butadiene blends, fluorosilicone rubbers, silicone rubbers, poly
2,2,1-bicyclo heptenes (polynorbornene), alkylstyrenes,
polyacrylate rubbers such as ethylene-acrylate copolymer,
ethylene-acrylate terpolymers, fluorocarbon polymers, copolymers of
poly(vinylidene fluoride) and hexafluoropropylene, terpolymers of
poly(vinylidene fluoride), hexafluoropropylene, and
tetrafluoroethylene, terpolymers of poly(vinylidene fluoride),
polyvinyl methyl ether and tetrafluoroethylene, perfluoroelastomers
such as tetrafluoroethylene perfluoroelastomers, highly fluorinated
elastomers, butadiene rubber, polychloroprene rubber, polyisoprene
rubber, polynorbornenes, polysulfide rubbers, polyurethanes,
silicone rubbers, vinyl silicone rubbers, fluoromethyl silicone
rubber, fluorovinyl silicone rubbers, phenylmethyl silicone
rubbers, styrene-butadiene rubbers, copolymers of isobutylene and
isoprene known as butyl rubbers, brominated copolymers of
isobutylene and isoprene, chlorinated copolymers of isobutylene and
isoprene, and any combination thereof. An example of a commercially
available product including such swellable particles may include a
commercially available product from Easy Well Solutions, in Norway,
under the trade name "EASYWELL."
[0035] Examples of fluoroelastomers that swell in the presence of
an oil-based fluid include copolymers of vinylidene fluoride and
hexafluoropropylene and terpolymers of vinylidene fluoride,
hexafluoropropylene and tetrafluoroethylene. Fluoroelastomers
include elastomers that may have one or more vinylidene fluoride
units ("VF2" or "VdF"), one or more hexafluoropropylene units
("HFP"), one or more tetrafluoroethylene units ("TFE"), one or more
chlorotrifluoroethylene ("CTFE") units, and/or one or more
perfluoro(alkyl vinyl ether) units ("PAVE"), such as
perfluoro(methyl vinyl ether) ("PMVE"), perfluoro(ethyl vinyl
ether) ("PEVE"), and perfluoropropyl vinyl ether ("PPVE"). These
elastomers can be homopolymers or copolymers. Some fluoroelastomers
contain vinylidene fluoride units, hexafluoropropylene units, and,
optionally, tetrafluoroethylene units and fluoroelastomers
containing vinylidene fluoride units, perfluoroalkyl perfluorovinyl
ether units, and tetrafluoroethylene units, such as the vinylidene
fluoride type fluoroelastomer known under the trade designation
"AFLAS.RTM." available from Asahi Glass Co., Ltd. Copolymers may
include vinylidene fluoride and hexafluoropropylene units may. If
the fluoropolymers contain vinylidene fluoride units, the polymers
may contain up to 40 mole % VF2 units, e.g., 30-40 mole %. If the
fluoropolymers contain hexafluoropropylene units, the polymers may
contain up to 70 mole % HFP units. If the fluoropolymers contain
tetrafluoroethylene units, the polymers may contain up to 10 mole %
TFE units. When the fluoropolymers contain chlorotrifluoroethylene
the polymers may contain up to 10 mole % CTFE units. When the
fluoropolymers contain perfluoro(methyl vinyl ether) units, the
polymers may contain up to 5 mole % PMVE units. When the
fluoropolymers contain perfluoro(ethyl vinyl ether) units, the
polymers may contain up to 5 mole % PEVE units. When the
fluoropolymers contain perfluoro(propyl vinyl ether) units, the
polymers may contain up to 5 mole % PPVE units. The fluoropolymers
may contain 66%-70% fluorine. An example commercially available
fluoroelastomer is known under the trade designation "TECHNOFLON
FOR HS.RTM." sold by Ausimont USA. This material contains
"Bisphenol AF" manufactured by Halocarbon Products Corp. Another
commercially available fluoroelastomer is known under the trade
name "VITON.RTM. AL 200," by DuPont Dow Elastomers, which is a
terpolymer of VF2, HFP, and TFE monomers containing 67% fluorine.
Another suitable commercially available fluoroelastomer is
"VITON.RTM. AL 300," by DuPont Dow Elastomers. A blend of the
terpolymers known under the trade designations "VITON.RTM. AL 300"
and "VITON.RTM. AL 600" can also be used (e.g., one-third AL-600
and two-thirds AL-300); both are available from DuPont Dow
Elastomers. Other useful elastomers include products known under
the trade designations "7182B" and "7182D" from Seals Eastern, Red
Bank, N.J.; the product known under the trade designation "FL80-4"
available from Oil States Industries, Inc., Arlington, Tex.; and
the product known under the trade designation "DMS005" available
from Duromould, Ltd., Londonderry, Northern Ireland.
[0036] Techniques for making a swellable elastomer may involve
grafting an unsaturated organic acid molecule. An example of an
unsaturated organic acid used for this purpose is maleic acid.
Other molecules that can be used include mono- and di-sodium salts
of maleic acid and potassium salts of maleic acid. Although other
unsaturated carboxylic acids may also be grafted onto commercial
unsaturated elastomers, acids that exist in solid form may not
require additional steps or manipulation. Mixing other unsaturated
acids such as acrylic acid and methacrylic acid is also possible.
Unsaturated acids such as palmitoleic acid, oleic acid, linoleic
acid, and linolenic acid may also be used. The initial reaction
leads to a relatively non-porous "acid-grafted rubber." To enhance
the swelling of elastomers, addition of a small amount of alkali
such as soda ash, along with or separate from the unsaturated acid,
may lead to formation of a porous, swellable acid grafted rubber.
Micro-porosities may form in the composition, allowing a fluid to
rapidly reach the interior region of a molded part and increase the
rate and extent of swelling. An organic peroxide vulcanizing agent
may be employed to produce a vulcanized, porous, swellable
acid-grafted rubber formulation. In some implementations, 100 phr
of EPDM, 5-100 phr of maleic acid, 5-50 phr of sodium carbonate,
and 1-10 phr of dicumyl peroxide as vulcanizing agent showed at
least 150 percent swelling of elastomer when exposed to both water
at 100.degree. C. for 24 hrs and at room temperature for 24 hrs in
kerosene. Other commercially available grades of organic peroxides,
as well as other vulcanization agents, may be used. The resulting
elastomeric compositions may include non-porous or porous, swelled,
acid-grafted rubbers, which may or may not be vulcanized.
Vulcanization may refer to a physicochemical change resulting from
crosslinking of the unsaturated hydrocarbon chain of polyisoprene
with sulfur, usually with the application of heat. The relatively
hydrophobic linear or branched chain polymers and relatively
hydrophilic water-soluble monomers, either grafted onto the polymer
backbone or blended therein, may act together to cost-effectively
increase the water- and/or oil-swellability of oilfield elements.
Use of unsaturated organic acids, anhydrides, and their salts (for
example maleic acid, maleic anhydride, and theirs salts), may offer
inexpensive composites materials with good water, and/or
hydrocarbon fluid swellability, depending on the type of inorganic
additives and monomers used.
[0037] Elastomers such as nitrile rubber, hydrogenated nitrile
rubber (HNBR), fluoroelastomers, or acrylate-based elastomers, or
their precursors, if added in variable amounts to an EPDM polymer
or its precursor monomer mixture, along with a sufficient amount
(from approximately 1 to 10 phr) of an unsaturated organic acid,
anhydride, or salt thereof, such as maleic acid, optionally
combined with a sufficient amount (from approximately 1 to 10 phr)
an inorganic swelling agent such as sodium carbonate, may produce a
water-swellable elastomer having variable low-oil swellability.
Adding to the monomer mixture or to the elastomer after
polymerization of a sufficient amount (from approximately 0.5 to 5
phr) of a highly acidic unsaturated compound such as
2-acrylamido-2-methylpropane sulfonic acid (AMPS), may result in a
water-swellable elastomer having variable oil-swellability, and
which may be further swellable in low pH fluids such as completion
fluids containing zinc bromide. A second addition of a sufficient
amount (from 1 to 10 phr more than the original addition) of
inorganic swelling agent may enhance swellability in low pH, high
concentration brines. Finally, the addition of a sufficient amount
(from 1 to 20 phr) of zwitterionic polymer or copolymer of a
zwitterionic monomer with an unsaturated monomer, may result in a
cross-linked elastomer. The amounts of the various ingredients at
each stage may be varied. For example, to produce a highly
cross-linked, moderately water-swellable (approximately 100 percent
swell) elastomer having very low oil-swellability but very high
swellability in low pH fluids, a recipe of 60 to 80 phr of EPDM,
and 20 to 40 phr of nitrile or HNBR, and 4 to 5 phr of AMPS, as
well as approximately 15 to 20 phr of a zwitterionic polymer or
monomer may be used.
[0038] Another reaction scheme that may enable a low-cost procedure
for making swellable elastomers, involves the use of AMPS monomer
and like sulfonic acid monomers. Since AMPS monomer is chemically
stable up to at least 350.degree. F. (177.degree. C.), mixtures of
EPDM and AMPS monomer which may or may not be grafted on to EPDM
may function as a high-temperature resistant water-swellable
elastomer. The use of AMPS and like monomers maybe used in like
fashion to functionalize any commercial elastomer to make a
high-temperature water-swellable elastomer. An advantage of using
AMPS is that it is routinely used in oilfield industry in loss
circulation fluids and is resistant to down hole chemicals and
environments.
[0039] Other swellable elastomers behave in a similar fashion with
respect to aqueous fluids. Some specific examples of suitable
swellable elastomers that swell in the presence of an aqueous-based
fluid, include starch-polyacrylate acid graft copolymer, polyvinyl
alcohol cyclic acid anhydride graft copolymer, polyacrylamide,
poly(acrylic acid-co-acrylamide), poly(2-hydroxyethyl
methacrylate), poly(2-hydroxypropyl methacrylate), isobutylene
maleic anhydride, acrylic acid type polymers, vinylacetate-acrylate
copolymer, polyethylene oxide polymers, carboxymethyl cellulose
type polymers, starch-polyacrylonitrile graft copolymers and the
like, and highly swelling clay minerals such as sodium bentonite
having montmorillonite as main ingredient, and combinations
thereof.
[0040] Additional water swellable particles may include particulate
matter embedded in a matrix material. One example of such
particulate matter is salt, including dissociating salt, which can
be uniformly compounded into a base rubber. Suitable salts may
include acetates, bicarbonates, carbonates, formates, halides
(MxHy) (H=Cl, Br or I), hydrosulphides, hydroxides, imides,
nitrates, nitrides, nitrites, phosphates, sulphides, sulphates, and
combinations thereof. Also, other salts can be applied wherein the
cation is a non-metal like NH.sub.4Cl. CaCl.sub.2 may be useful in
view of its divalent characteristic and because of its reduced
tendency to leach out from a base rubber due to reduced mobility of
the relatively large Ca atom in the base rubber.
[0041] To limit or control leaching out of the salt from the
swellable elastomer, the swellable particles may include a
hydrophilic polymer containing polar groups of either oxygen or
nitrogen in the backbone or side groups of the polymer matrix
material. These side groups can be partially or fully neutralized.
Hydrophilic polymers of such type include, for example, alcohols,
acrylates, methacrylates, acetates, aldehydes, ketones, sulfonates,
anhydrides, maleic anhydrides, nitriles, acrylonitriles, amines,
amides, oxides (polyethylene oxide), cellulose types including all
derivatives of these types, all copolymers including one of the
above all grafted variants. In some implementations, a ternary
system may be applied which includes an elastomer, a polar SAP and
a salt, whereby the polar SAP is grafted onto the backbone of the
elastomer. Such system has the advantage that the polar SAP
particles tend to retain the salt particles in the elastomer matrix
thereby reducing leaching of the salt from the elastomer. The polar
salt may be attracted by electrostatic forces to the polar SAP
molecules which are grafted onto the backbone of the rubber.
[0042] Combinations of suitable swellable elastomers may also be
used. In some implementations, some of the elastomers that swell in
oil-based fluids may also swell in aqueous-based fluids. Elastomers
that may swell in both aqueous-based and oil-based fluids, include
ethylene propylene rubbers, ethylene-propylene-diene terpolymer
rubbers, butyl rubbers, brominated butyl rubbers, chlorinated butyl
rubbers, chlorinated polyethylene, neoprene rubbers, styrene
butadiene copolymer rubbers, sulphonated polyethylenes, ethylene
acrylate rubbers, epichlorohydrin ethylene oxide copolymer,
silicone rubbers and fluorosilicone rubbers, and any combination
thereof. Appropriate fluids may be used to swell the swellable
elastomer compositions.
[0043] In some implementations, the swellable elastomers may be
crosslinked and/or lightly crosslinked. Other swellable elastomers
behave in a similar fashion with respect to fluids. Appropriate
swellable elastomers may be selected based on a variety of factors,
including the application in which the composition will be used and
the desired swelling characteristics.
[0044] Swellable particles may be included in an amount sufficient
to provide the desired barrier properties. In some implementations,
the swellable particles may be placed in a fracture or void in a
treatment fluid including an amount up to approximately 50% by
volume of the treatment fluid. In some implementations, the
swellable particles may be present in a range of approximately 5%
to approximately 95% by volume of the treatment fluid used to place
the particles.
[0045] In addition, the swellable particles that are utilized may
have a wide variety of shapes and sizes of individual particles.
For example, the swellable particles may have a well-defined
physical shape as well as an irregular geometry, including the
physical shape of platelets, shavings, fibers, flakes, ribbons,
rods, strips, spheroids, beads, pellets, tablets, or any other
physical shape. In some implementations, the swellable particles
may have a particle size in the range of approximately 5 microns to
approximately 1,500 microns. In some implementations, the swellable
particles may have a particle size in the range of approximately 20
microns to approximately 500 microns. However, particle sizes
outside these ranges may also be used.
[0046] The sealant may include a cement. An example of a cement
includes hydraulic cement, which may include calcium, aluminum,
silicon, oxygen, and/or sulfur and which sets and hardens by
reaction with water. Examples of hydraulic cements include a
Portland cement, a pozzolan cement, a gypsum cement, a high alumina
content cement, a silica cement, a high alkalinity cement, or
combinations thereof. Hydraulic cements include Portland cements,
for example, a class A, B, C, G, or H Portland cement. Another
example of a suitable cement is microfine cement, for example,
MICRODUR RU microfine cement available from Dyckerhoff GmBH of
Lengerich, Germany. Combinations of cements and swellable particles
may also be used.
[0047] The sealant may include a water soluble relative
permeability modifier. A relative permeability modifier may refer
to a compound capable of reducing the permeability of a
subterranean formation to aqueous-based fluids without
substantially changing its permeability to hydrocarbons. In some
implementations, the water-soluble relative permeability modifiers
may include a hydrophobically modified polymer. "Hydrophobically
modified" refers to the incorporation into the hydrophilic polymer
structure of hydrophobic groups, wherein the alkyl chain length is
from approximately 4 to approximately 22 carbons. In some
implementations, the water-soluble relative permeability modifiers
include a hydrophilically modified polymer. "Hydrophilically
modified" refers to the incorporation into the hydrophilic polymer
structure of hydrophilic groups. In some implementations, the
water-soluble relative permeability modifiers include a
water-soluble polymer without hydrophobic or hydrophilic
modification.
[0048] Hydrophobically modified polymers typically have molecular
weights in the range of from approximately 100,000 to approximately
10,000,000. In some implementations, a mole ratio of a hydrophilic
monomer to the hydrophobic compound in the hydrophobically modified
polymer is in the range of from approximately 99.98:0.02 to
approximately 90:10, wherein the hydrophilic monomer is an amount
present in the hydrophilic polymer. In some implementations, the
hydrophobically modified polymers include a polymer backbone that
include polar heteroatoms. The polar heteroatoms present within the
polymer backbone of the hydrophobically modified polymers may
include oxygen, nitrogen, sulfur, and/or phosphorous.
[0049] In some implementations, the hydrophobically modified
polymers can be a reaction product of a hydrophilic polymer and a
hydrophobic compound. The hydrophilic polymers for forming the
hydrophobically modified polymers may be capable of reacting with
hydrophobic compounds. Suitable hydrophilic polymers include,
homo-, co-, or terpolymers, for example, polyacrylamides,
polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl
acrylate polymers in general. Additional examples of alkyl acrylate
polymers include polydimethylaminoethyl methacrylate,
polydimethylaminopropyl methacrylamide,
poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic
acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl
propane sulfonic acid/dimethylaminoethyl methacrylate),
poly(acrylamide/dimethylaminopropyl methacrylamide), poly(acrylic
acid/dimethylaminopropyl methacrylamide), and poly(methacrylic
acid/dimethylaminopropyl methacrylamide). In some implementations,
the hydrophilic polymers include a polymer backbone and reactive
amino groups in the polymer backbone or as pendant groups, the
reactive amino groups capable of reacting with hydrophobic
compounds. In some implementations, the hydrophilic polymers
include dialkyl amino pendant groups. In some implementations, the
hydrophilic polymers include a dimethyl amino pendant group and at
least one monomer including dimethylaminoethyl methacrylate or
dimethylaminopropyl methacrylamide. In some implementations, the
hydrophilic polymers include a polymer backbone, the polymer
backbone including polar heteroatoms, where the polar heteroatoms
present within the polymer backbone of the hydrophilic polymers
include oxygen, nitrogen, sulfur, and/or phosphorous. Suitable
hydrophilic polymers that include polar heteroatoms within the
polymer backbone include homo-, co-, or terpolymers, for example,
celluloses, chitosans, polyamides, polyetheramines,
polyethyleneimines, polyhydroxyetheramines, polylysines,
polysulfones, gums, starches, and derivatives thereof. In some
implementations, the starch is a cationic starch. A suitable
cationic starch may be formed by reacting a starch, such as corn,
maize, waxy maize, potato, and tapioca, and the like, with the
reaction product of epichlorohydrin and trialkylamine.
[0050] Hydrophobic compounds capable of reacting with the
hydrophilic polymers include alkyl halides, sulfonates, sulfates,
and organic acid derivatives. Examples of suitable organic acid
derivatives include octenyl succinic acid; dodecenyl succinic acid;
and anhydrides, esters, and amides of octenyl succinic acid or
dodecenyl succinic acid. In some implementations, the hydrophobic
compounds may have an alkyl chain length of from approximately 4 to
approximately 22 carbons. For example, where the hydrophobic
compound is an alkyl halide, the reaction between the hydrophobic
compound and hydrophilic polymer may result in the quaternization
of at least some of the hydrophilic polymer amino groups with an
alkyl halide, where the alkyl chain length is from approximately 4
to approximately 22 carbons.
[0051] In some implementations, hydrophobically modified polymers
may be prepared from the polymerization reaction of at least one
hydrophilic monomer and at least one hydrophobically modified
hydrophilic monomer.
[0052] A variety of hydrophilic monomers may be used to form
hydrophobically modified polymers. Examples of suitable hydrophilic
monomers include homo-, co-, and terpolymers of acrylamide,
2-acrylamido-2-methyl propane sulfonic acid,
N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl
methacrylate, acrylic acid, dimethylaminopropylmethacrylamide,
vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate
chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic
acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam,
N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium
halide, itaconic acid, styrene sulfonic acid,
methacrylamidoethyltrimethyl ammonium halide, quaternary salt
derivatives of acrylamide, and quaternary salt derivatives of
acrylic acid.
[0053] A variety of hydrophobically modified hydrophilic monomers
also may be used to form hydrophobically modified polymers.
Examples of suitable hydrophobically modified hydrophilic monomers
include alkyl acrylates, alkyl methacrylates, alkyl acrylamides,
alkyl methacrylamides alkyl dimethylammoniumethyl methacrylate
halides, and alkyl dimethylammoniumpropyl methacrylamide halides,
wherein the alkyl groups have from approximately 4 to approximately
22 carbon atoms. In some implementations, the hydrophobic ally
modified hydrophilic monomer includes
octadecyldimethylammoniumethyl methacrylate bromide,
hexadecyldimethylammoniumethyl methacrylate bromide,
hexadecyldimethylammoniumpropyl methacrylamide bromide,
2-ethylhexyl methacrylate, or hexadecyl methacrylamide.
[0054] The hydrophobically modified polymers formed from the
above-described polymerization reaction may have estimated
molecular weights in the range of from approximately 100,000 to
approximately 10,000,000 and mole ratios of the hydrophilic
monomer(s) to the hydrophobically modified hydrophilic monomer(s)
in the range of from approximately 99.98:0.02 to approximately
90:10. Hydrophobically modified polymers having molecular weights
and mole ratios in the ranges set forth above include
acrylamide/octadecyldimethylammoniumethyl methacrylate bromide
copolymer, dimethylaminoethyl
methacrylate/hexadecyldimethylammoniumethyl methacrylate bromide
copolymer, dimethylaminoethyl methacrylate/vinyl
pyrrolidone/hexadecyldimethylammoniumethyl methacrylate bromide
terpolymer and acrylamide/2-acrylamido-2-methyl propane sulfonic
acid/2-ethylhexyl methacrylate terpolymer.
[0055] In some implementations, the water-soluble relative
permeability modifiers include a hydrophilically modified polymer.
Hydrophilically modified polymers typically have molecular weights
in the range of from approximately 100,000 to approximately
10,000,000. In some implementations, the hydrophilically modified
polymers include a polymer backbone, the polymer backbone including
polar heteroatoms. The polar heteroatoms present within the polymer
backbone of the hydrophilically modified polymers may include
oxygen, nitrogen, sulfur, and/or phosphorous.
[0056] In some implementations, a hydrophilically modified polymer
may be a reaction product of a hydrophilic polymer and a
hydrophilic compound. Hydrophilic polymers suitable for forming
hydrophilically modified polymers may be capable of reacting with
hydrophilic compounds. In some implementations, hydrophilic
polymers include homo-, co-, or terpolymers, for example,
polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols),
and alkyl acrylate polymers in general. Additional examples of
alkyl acrylate polymers include polydimethylaminoethyl
methacrylate, polydimethylaminopropyl methacrylamide,
poly(acrylamide/dimethylamino ethyl methacrylate), poly(methacrylic
acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl
propane sulfonic acid/dimethylaminoethyl methacrylate),
poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylic
acid/dimethylaminopropyl methacrylamide), and poly(methacrylic
acid/dimethylaminopropyl methacrylamide). In some implementations,
the hydrophilic polymers include a polymer backbone and reactive
amino groups in the polymer backbone or as pendant groups, the
reactive amino groups capable of reacting with hydrophilic
compounds. In some implementations, the hydrophilic polymers
include dialkyl amino pendant groups. In some implementations, the
hydrophilic polymers include a dimethyl amino pendant group and at
least one monomer including dimethylaminoethyl methacrylate or
dimethylaminopropyl methacrylamide. In some implementations, the
hydrophilic polymers include a polymer backbone including polar
heteroatoms, wherein the polar heteroatoms present within the
polymer backbone of the hydrophilic polymers include oxygen,
nitrogen, sulfur, and/or phosphorous. Suitable hydrophilic polymers
that include polar heteroatoms within the polymer backbone include
homo-, co-, or terpolymers, such as celluloses, chitosans,
polyamides, polyetheramines, polyethyleneimines,
polyhydroxyetheramines, polylysines, polysulfones, gums, starches,
and derivatives thereof. In some implementations, the starch is a
cationic starch. A suitable cationic starch may be formed by
reacting a starch, such as corn, maize, waxy maize, potato,
tapioca, and the like, with the reaction product of epichlorohydrin
and trialkylamine.
[0057] Hydrophilic compounds suitable for reaction with the
hydrophilic polymers include polyethers that include halogens;
sulfonates; sulfates; and organic acid derivatives. Examples of
suitable polyethers include polyethylene oxides, polypropylene
oxides, and polybutylene oxides, and copolymers, terpolymers, and
mixtures thereof. In some implementations, the polyether includes
an epichlorohydrin-terminated polyethylene oxide methyl ether.
[0058] Hydrophilically modified polymers formed from the reaction
of a hydrophilic polymer with a hydrophilic compound may have
estimated molecular weights in the range of from approximately
100,000 to approximately 10,000,000 and may have weight ratios of
the hydrophilic polymers to the polyethers in the range of from
approximately 1:1 to approximately 10:1. Hydrophilically modified
polymers having molecular weights and weight ratios in the ranges
set forth above include the reaction product of
polydimethylaminoethyl methacrylate and epichlorohydrin-terminated
polyethyleneoxide methyl ether; the reaction product of
polydimethylaminopropyl methacrylamide and
epichlorohydrin-terminated polyethyleneoxide methyl ether; and the
reaction product of poly(acrylamide/dimethylaminopropyl
methacrylamide) and epichlorohydrin-terminated polyethyleneoxide
methyl ether. In some implementations, the hydrophilically modified
polymer includes the reaction product of a polydimethylaminoethyl
methacrylate and epichlorohydrin-terminated polyethyleneoxide
methyl ether having a weight ratio of polydimethylaminoethyl
methacrylate to epichlorohydrin-terminated polyethyleneoxide methyl
ether of approximately 3:1.
[0059] In some implementations, the water-soluble relative
permeability modifiers include a water-soluble polymer without
hydrophobic or hydrophilic modification. Examples of suitable
water-soluble polymers without hydrophobic or hydrophilic
modification include homo-, co-, and terpolymers of acrylamide,
2-acrylamido-2-methyl propane sulfonic acid,
N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl
methacrylate, acrylic acid, dimethylaminopropylmethacrylamide,
vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate
chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic
acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam,
N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium
halide, itaconic acid, styrene sulfonic acid,
methacrylamidoethyltrimethyl ammonium halide, quaternary salt
derivatives of acrylamide, and quaternary salt derivatives of
acrylic acid.
[0060] The tracers 228 may include material that can be transported
from the barrier 208 and detected. The tracers 228 may include
material that is not naturally present in the reservoir 205 (at
least, not naturally present in quantities that exceed the
detection threshold of tracer detection instruments) that can be
transported by means of fluid migration and detected by well-based
or surface-based instrumentation. The tracers 228 may include
chemical tracers, radioactive tracers, noble gas tracers, micro-
and nano-devices, water soluble tracers, hydrocarbon soluble
tracers, other types of tracers, and/or combinations of these.
Chemical tracers include substances that can be detected based on
chemical properties (e.g., pH, resistivity, etc.) of fluids
containing the tracer. Example chemical tracers include alcohols,
salts, acids, and others. Radioactive tracers include substances
that can be detected based on properties of radioactivity (e.g.,
frequency, intensity of gamma rays emitted, and/or others) in the
subterranean region 201. Radioactive tracers may be chosen, for
example, based on their half-life and/or other properties. Example
radioactive tracers include radioactive nuclei having half lives
ranging from 1 day to 500 days, including antimony 124, iridium
192, scandium 46, gold 198, iodine 131, zinc 65, silver 100, cobalt
57, and others. Noble gas tracers include noble gases, for example,
helium, neon, argon, krypton, and xenon. Micro- and nano-device
tracers may include manufactured radio frequency devices,
microelectromechanical (MEMS) devices, metal-oxide-semiconductor
(MOS) devices, and/or similar devices. Tracer devices may function
as passive or active radio frequency emitting devices that can be
detected by a radio frequency detector. Tracers may include
fluorinated benzoic acid. Tracer devices may be used to detect and
record properties of fluid flow. For example, tracer devices may
detect and record phase composition, flow velocity, location,
and/or other data. Other example tracers include dyes, such as
flourescein dyes, oil soluble dyes, and oil dispersible dyes;
organic materials, such as guar, sugars, glycerol, surfactants,
scale inhibitors, etc.; phosphorescent pigments; fluorescent
pigments; photoluminescent pigments; oil dispersible pigments;
metals; and/or others.
[0061] The tracers 228 can be selected for use in the system 200
based on their interaction or reaction to fluids in the reservoir
205. Some tracers can be released from the barrier 208 when
contacted by certain types of fluid. For example, a tracer that
dissolves in the treatment fluid that is used to sweep the
reservoir 205 may be selected; or a tracer that dissolves in
hydrocarbons resident in the reservoir 205 may be selected. A
water-soluble tracer dissolves in water, and a hydrocarbon-soluble
tracer dissolves in hydrocarbon. A tracer may have a coating that
dissolves in certain types of fluids to release the tracer. For
example, the tracer may have a water-soluble or hydrocarbon-soluble
coating. A tracer may be stress activated. For example, a tracer
may be injected with a coating that is crushed by a certain amount
of stress, and the tracer may be released into the reservoir 205
after the coating has been crushed under stress in the barrier
208.
[0062] The well system 200 includes an injection system 211 that
injects the sealant mixture into the reservoir 205. The injection
system 211 can be used to create the barriers 108 of FIG. 1, the
barriers 208 of FIG. 2, the barriers 408 of FIG. 4, the barriers
508a and 508b of FIG. 5, and/or other barriers. In some
implementations, an injection system is used to create fractures in
the subterranean reservoir, for example, the fracture 106 of FIG.
1, the fractures 206 of FIG. 2, the fractures 406 of FIG. 4, the
fractures 506 of FIG. 5, and/or other fractures. The injection
system 211 includes pump trucks 221, instrument trucks 222, working
string 220, flow control device 223, packers 224, and other
equipment. The injection system 211 may include features of the
injection system 330 shown in FIG. 3 and/or other features.
[0063] The pump trucks 221 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 221 supply sealant material 226 and tracers 228. The
pump trucks 221 may contain multiple different sealant materials,
multiple different tracers, and/or multiple different
sealant/tracer mixtures. The pump trucks may include mixers that
mix the sealant 226 and tracers 228.
[0064] The pump trucks 221 are coupled to the working string 220 to
communicate the sealant material 226, the tracers 228, and/or a
mixture containing the sealant material 226 and tracers 228 into
the well bore 203. The working string 220 may include coiled
tubing, sectioned pipe, and/or other features that communicate
fluid through the well bore 203. The working string 220 is coupled
to the flow control device 223. The flow control device 223 may
include a valve, a sliding sleeve, a port, and/or other features
that communicate fluid from the working string 220 into the
reservoir 205. The flow control device 223 may include a fracturing
tool. Example fracturing tools include hydrajetting tools, such as
the SURGIFRAC tool (manufactured by HALLIBURTON), the COBRA FRAC
tool (manufactured by HALLIBURTON), and others. The barriers 208
may be formed without use of a flow control device 223. For
example, fluids may be injected by an open end of the working
string 220 without using a flow control device 223. The packers 224
reside in an annulus between the working string 220 and the well
bore wall (or casing, where the well bore 203 is cased). The
packers 224 isolate an interval of the reservoir 205 that receives
the injected materials from the flow control device 223. The
packers 224 may include mechanical packers, fluid inflatable
packers, sand packers, and/or other types of packers.
[0065] The instrument trucks 222 may include mobile vehicles,
immobile installations, and/or other suitable structures. The
instrument trucks 222 control and/or monitor the injection
treatment. For example, the instrument trucks 222 may include
communication links 225 that allow the instrument trucks 222 to
communicate with tools, sensors, and/or other devices installed in
the well bore 203; the instrument trucks 222 may include
communication links 225 that allow the instrument trucks 222 to
communicate with the pump trucks 221 and/or other systems at the
surface 202. The instrument trucks 222 may include an injection
control system that controls the flow of sealant and tracer
materials into the reservoir 205 to achieve barriers 208 having
desired properties. For example, the instrument trucks 222 may
monitor and/or control the density, volume, flow rate, flow
pressure, location, and/or other characteristics of the tracers 228
and/or the sealant 226 injected into the reservoir 205. The
instrument trucks 222 may control the type of tracer injected into
each of the barriers 208 and/or the type of tracer injected into
different parts of each barrier 208. In the present disclosure,
"each" refers to each of multiple items or operations in a group,
and may include a subset of the items or operations in the group
and/or all of the items or operations in the group.
[0066] The injection system 211 may also include surface and
down-hole sensors (not shown) to measure pressure, rate,
temperature and/or other parameters of treatment and/or production.
The injection system 211 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 instrument trucks 222)
may communicate with such equipment to monitor and control the
injection treatment.
[0067] In one aspect of operation, the pump trucks 221 pump the
tracers 228 and the sealant material 226 down the well bore 203
through the working string 220. From the working string 220, the
tracers 228 and sealant material 226 are received by the flow
control device 223 and injected into the reservoir 205. After the
tracers 228 and sealant material 226 have been injected, the
sealant material 226 may become more viscous and/or solidify in the
reservoir 205. The sealant 226 may impede or prevent fluid flow in
the resulting barrier 208, which may alter fluid flow patterns in
the reservoir 205. The sealant mixture may be injected into the
reservoir 205 at a high pressure to fracture the reservoir during
the injection. The sealant mixture may be injected into the
reservoir 205 at a low pressure to fill an existing fracture. The
pressure may be controlled in a different manner to achieve a
desired result. The sealant mixture, which includes the tracers 228
and sealant material 226, may be mixed prior to injection, for
example, in the pump trucks 221, in the working string 220, in the
flow control device 223, in a different location, and/or in a
combination of these. The sealant mixture may be fully or partially
mixed when the tracers 228 and sealant 226 are injected into the
reservoir 205. The sealant 226 and tracers 228 may remain separate
from each other until they are combined in the reservoir 205, in
the annulus, in the flow control device 223, in the working string
220, in the pump trucks 221, and/or at any stage of forming the
barrier 208.
[0068] Additional barriers may be formed in the reservoir 205 using
the injection system 211. For example, the barriers 208 and/or
additional barriers can be placed as a remedial treatment after the
well has been producing for some time. As such, barriers can be
emplaced and/or modified at different times over the production
lifetime of the well system 200. Flow control devices 223 and
packers 224 may be positioned at different locations in the well
bore 203 to create additional barriers in the reservoir 205.
[0069] FIG. 3 is a diagram of an example treatment well 300 that
includes an injection system 330 injecting treatment fluid into a
subterranean reservoir 305 in a subterranean region 301. The
injection system 330 may be used with the treatment well 104 of
FIG. 1 to inject the treatment fluid 110 into the subterranean
reservoir 105. In some implementations, the injection system 330
injects treatment fluids 310 into a reservoir to displace or sweep
resident hydrocarbon resources through the reservoir to a
production well. A barrier in the reservoir may influence the flow
of the treatment fluids 310 and/or the displaced hydrocarbons
through the reservoir. In some cases, a barrier releases a tracer
into the reservoir when the barrier is contacted by the treatment
fluids 310 and/or the hydrocarbons. Movement of the tracer in the
reservoir may be detected and analyzed to identify flow patterns in
the reservoir.
[0070] The example treatment well 300 shown in FIG. 3 includes a
well bore 304 with a casing 334 cemented or otherwise secured to
the well bore wall. A treatment well may include an uncased well
bore. Perforations 336 may be formed in the casing 334 to allow
treatment fluids 310 and/or other materials to flow into the
reservoir 305. Perforations 336 may be formed using shape charges,
a perforating gun, and/or other tools.
[0071] The injection system 330 includes pump trucks 321,
instrument trucks 322, working string 332, flow control device 338,
packers 324, and other equipment. The injection system 330 may
include features of the injection system 211 shown in FIG. 2 and/or
other features. The pump trucks contain treatment fluid 310 to be
injected into the reservoir 305. The treatment fluid 310 may
include water, steam, and/or other types of compressible and/or
incompressible fluids that can promote migration of hydrocarbons
through the reservoir 305. The pump trucks 321 are coupled to the
working string 332 to communicate treatment fluid 310 into the well
bore 304. The working string 332 is coupled to the flow control
device 338, which communicates fluid from the working string 332
into the reservoir 305. Treatment fluid 310 may be injected without
use of a flow control device 338. For example, fluids may be
injected by an open end of the working string 332 without using a
flow control device 338. The packers 324 reside in an annulus
between the working string 332 and the casing 334, and isolate an
interval of the reservoir 305 that receives the treatment fluid 310
through the perforations 336.
[0072] The instrument trucks 322 control and/or monitor the
injection treatment. For example, the instrument trucks 322 may
include communication links 325 that allow the instrument trucks
322 to communicate with tools, sensors, and/or other devices
installed in the well bore 304; the instrument trucks 322 may
include communication links 325 that allow the instrument trucks
322 to communicate with the pump trucks 321 and/or other systems at
the surface. The instrument trucks 322 may include an injection
control system that control the flow of treatment fluid into the
reservoir 305 to achieve a desired reservoir sweep. For example,
the instrument trucks 322 may monitor and/or control the density,
volume, flow rate, flow pressure, location, and/or other
characteristics of the treatment fluid 310 injected into the
reservoir 305.
[0073] In one aspect of operation, the pump trucks 321 pump the
treatment fluid 310 down the well bore 304 through the working
string 332. From the working string 332, the treatment fluid 310
flows through the flow control device 338, through the perforations
336, and into the reservoir 305. The treatment fluid 310 may form a
fluid front in the reservoir 305. The fluid front may sweep through
the reservoir 305 to displace hydrocarbons toward a production
well. The treatment fluid 310 may contact a barrier in the
reservoir 305 and cause the barrier to release tracers. The tracers
may flow through the reservoir 305 with the treatment fluid 310
and/or other fluids. In some cases, the flow of the treatment fluid
310 through the reservoir may be analyzed based on the detection of
the tracers' movement through the reservoir 305. The injection of
the treatment fluid 310 may be modified based on the analysis. For
example, the location, pressure, flow rate, fluid composition,
and/or other parameters of the injection treatment may be modified
to improve sweep efficiency.
[0074] FIG. 4 is a diagram of an example production well system 400
detecting tracers 428a (circles), 428b (triangles) released into a
reservoir 405 from barriers 408. The production well system 400
includes a well bore 403 in a subterranean region 401 beneath the
surface 404. The subterranean region 401 includes the reservoir
405, which includes fractures 406 and barriers 408. The fractures
406 conduct fluids from the reservoir 405 into the well bore 403. A
completion string 420 installed in the well bore communicates the
fluids to the surface 404.
[0075] The well system 400 includes tracer detectors 442a and 442b
installed in the well bore 403, and a tracer detector 444 installed
at the surface 404. In some cases, tracer detectors may be
installed in additional, fewer, and/or different locations. For
example, the well system 400 may be implemented without down hole
tracer detectors 442a, 442b, without tracer detectors 444 at the
surface, and/or with tracer detectors installed at different
locations in the subterranean region 401. The tracer detectors
442a, 442b, and 444 may communicate with a computing subsystem 445
that stores and analyzes data generated by the tracer detectors.
For example, the computing subsystem 445 may identify properties of
fluid flow in the subterranean reservoir 405 based on data provided
by the tracer detectors 442a, 442b, and/or 444.
[0076] The tracer detectors 442a, 442b, and 444 may each be adapted
to detect one or more of the tracers 428a, 428b stored in the
barriers 408. For example, the detectors may be adapted to detect
chemical tracers, radioactive tracers, noble gas tracers, micro-
and nano-device tracers, other types of tracers, and/or
combinations of these. One or more of the detectors 442a, 442b, and
444 may detect chemical tracers by measuring chemical properties
(e.g., pH, resistivity, etc.) of fluids received by the detectors.
For example, a chemical tracer detector may include a pH sensor to
monitor a pH level of fluids in the reservoir 405, which may detect
an acid tracer. A chemical tracer detector may include an ohmmeter,
an ammeter, a voltmeter, or another device to monitor a resistivity
of fluids in the reservoir 405, which may detect a salt tracer, for
example. One or more of the detectors 442a, 442b, and 444 may
detect radioactive tracers based on radioactive properties (e.g.,
frequency, intensity of gamma rays emitted, and/or others) of
material near the detector. For example, a radioactive tracer
detector may include a scintillation crystal, a Geiger counter, or
another device that detects radiation emitted by nuclear decay. One
or more of the detectors 442a, 442b, and 444 may detect noble gas
tracers based on properties of fluids received by the detector. For
example, the detector may include sensor that detects helium, neon,
argon, krypton, xenon, and/or related gasses.
[0077] One or more of the detectors 442a, 442b, and 444 may detect
micro- and nano-device tracers. For example, the detectors may
include an active radio frequency beacon that interrogates a zone
around the detector for rf-device tracers. Rf-device tracers in the
interrogated zone may reflect and/or scatter the radio frequency
signal, and the detector may receive the reflected or scattered
signal. For example, the detectors may include an antenna that
receives reflected signals from the rf-device tracers. The detector
may monitor the movement of rf-device tracers through the reservoir
405. In some cases, a micro- or nano-tracer device may include an
active transmitter that transmits radio frequency signals that can
be detected by one or more of the detectors.
[0078] Tracer devices may be used to detect and record properties
of fluid flow. For example, tracer devices may detect and record
phase composition, flow velocity, location, and/or other data. One
or more of the detectors 442a, 442b, and 444 may receive the
information from the tracer devices. One or more of the detectors
442a, 442b, and 444 may include sensors and/or other features that
detect other example tracers, including dyes, organic materials,
pigments, metals, and/or others.
[0079] Each of the barriers 408 includes a sealant material 426 and
stores two different tracers 428a, 428b. The sealant material 426
is a low permeability material that inhibits fluid flow through the
barriers 408. In the example shown in FIG. 4, the tracers 428a,
428b are each stored in different portions of the barriers 408. A
first type of tracer 428a is stored in a portion of the barrier 408
farthest from the well bore 403; a second type of tracer 428b is
stored in a portion of the barrier 408 closest to the well bore
403. In some implementations, the different tracers can be
intermingled in the barrier rather than being stored in separate
portions of the barrier.
[0080] The flow arrows 445, 446, and 448 show examples of fluid
flow in the subterranean region 401. The flow arrows 445 indicate a
flow of fluids that contact the barriers 408. In the example shown,
the barriers 408 divert the flow of fluids away from the well bore
403. The fluids represented by the flow arrows 445 may include
treatment fluids injected into the reservoir through a treatment
well, other types of injected fluids, hydrocarbons, and/or other
types of fluids native to the reservoir 405. The fluids represented
by the flow arrows 445 do not include tracer materials before
contacting the barriers 408.
[0081] As the fluids contact the barriers 408, the barriers release
tracers 428a into the reservoir 405. Generally, any of the tracers
in a barrier may be released into the reservoir based on contact
and/or interaction with fluids in the reservoir. However, in some
implementations, only certain tracers are released. For example,
some tracers may only be released into the reservoir when contacted
by the treatment fluids, some tracers may only be released into the
reservoir when contacted by the hydrocarbon fluids, some tracers
may only be released after a specified amount of time, some tracers
may only be released when fluid contacts a certain portion of the
barriers 408, etc. In the example shown in FIG. 4, only one of the
tracers 428a is released into the reservoir 405, and the second
tracer 428b is not released into the reservoir 405 due to contact
with the fluids represented by the flow arrow 445. In some
instances, the second tracer 428b may alternatively or additionally
be released into the reservoir 405 due to contact with the fluids
represented by the flow arrow 445.
[0082] The flow arrows 446 indicate a flow path of fluids
containing tracers 428a that have been released by the barriers
408. In the example shown, the fluids represented by the flow
arrows 446 have been diverted by barriers 408; the fluids transport
the tracers 428a through the reservoir 405 into the fractures 406.
The fractures 406 conduct the fluids and the tracers 428a into the
well bore 403. In the well bore 403, the tracers 428a may be
detected by either of the detectors 442a and 442b. The flow arrow
448 indicates a flow path of fluids and tracers 428a through the
completion string 420 to the surface 404. At the surface, the
tracers 428a may be detected by the detector 444.
[0083] FIG. 5 is a diagram of an example production well system 500
detecting tracers 528a (circles), 528b (triangles) released into a
reservoir 505 from barriers 508a, 508b. The production well system
500 includes a well bore 503 in a subterranean region 501 beneath
the surface 504. The subterranean region includes a reservoir 505,
which includes fractures 506 and the barriers 508a, 508b. The
fractures 506 conduct fluids from the reservoir 505 into the well
bore 503. A completion string 520 installed in the well bore
communicates the fluids to the surface 504.
[0084] The well system 500 includes tracer detectors 542a and 542b
installed in the well bore 503, and a tracer detector 544 installed
at the surface 504. Each of the barriers 508a, 508b includes a
sealant material 526 and a tracer. The barriers 508a include a
first tracer 528a, and the barriers 508b include a second tracer
528b. The flow arrows 545, 546, 547, and 548 show an example of
fluid flow in the subterranean region 501. The flow arrows 545
indicate a flow path of fluids that contact the barriers 508b. The
barrier 508b divert the flow of fluids away from the well bore 503.
The fluids represented by the flow arrows 545 may include treatment
fluids injected into the reservoir through a treatment well, other
types of injected fluids, hydrocarbons, and/or other types of
fluids native to the reservoir 505. The fluids represented by the
flow arrows 545 do not include tracer materials before contacting
the barriers 508b.
[0085] As the fluids contact the barriers 508b, the barriers 508b
release tracers 528b into the reservoir 505. The flow arrows 546
indicate a flow path of fluids containing tracers 528b that have
been released by the barriers 508b. As the fluids subsequently
contact the barriers 508a, the barriers 508a release tracers 528a
into the reservoir 505. The flow arrows 547 indicate a flow path of
fluids containing tracers 528a and 528b that have been released by
the barriers 508a and 508b. In the example shown, the fluids
represented by the flow arrows 547 have been diverted by barriers
508a, 508b; the fluids transport the tracers 528a, 528b through the
reservoir 505 into the fractures 506. The fractures 506 conduct the
fluids and the tracers 528a, 528b into the well bore 503. In the
well bore 503, the tracers 528a, 528b may be detected by either of
the detectors 542a and 542b. The flow arrow 548 indicates a flow
path of fluids and tracers 528a, 528b through the completion string
520 to the surface 504. At the surface, the tracers 528a, 528b may
be detected by the detector 544.
[0086] One or more of the tracer detectors 542a, 542b, and 544 may
communicate with a computing subsystem 545 that stores and analyzes
data generated by the tracer detectors. For example, the computing
subsystem 545 may identify properties of fluid flow in the
subterranean reservoir 505 based on data provided by the tracer
detectors 542a, 542b, and/or 544.
[0087] FIG. 6 is a flow chart showing an example process 600 for
analyzing fluid flow in a reservoir. All or part of the example
process 600 may be implemented using the features and attributes of
the example well systems shown in FIGS. 1, 2, 3, 4, and 5. In some
cases, aspects of the example process 600 may be performed in a
single-well system, a multi-well system, a well system including
multiple interconnected well bores, and/or in another type of well
system, which may include any suitable well bore orientations. In
some implementations, the example process 600 is implemented to
analyze fluid flow in a hydrocarbon reservoir. The process 600 may
be implemented after the reservoir has been produced for days,
weeks, months, or years, or before the reservoir has produced
resources. In some cases, the process 600 is implemented during a
remedial production process that sweeps residual hydrocarbons from
a reservoir that has been producing for some time. The process 600,
individual operations of the process 600, and/or groups of
operations may be iterated to achieve a desired result. In some
cases, the process 600 may include the same, additional, fewer,
and/or different operations performed in the same or a different
order.
[0088] At 604, a sealant and a tracer are injected into a
subterranean reservoir to form a flow barrier in the reservoir. The
sealant and tracer may be injected into the reservoir through a
well bore in the reservoir. The sealant and tracer may be mixed to
form a sealant mixture before injection, during injection, and/or
after injection. Injecting the sealant mixture may fracture the
reservoir to form the flow barrier. The sealant mixture may be
injected into existing fractures. The sealant in the reservoir may
inhibit or reduce fluid flow in the flow barrier. In some cases,
forming the flow barrier in the reservoir modifies fluid flow paths
in the reservoir. For example, the flow barrier may divert flow in
one or more directions. Multiple tracers may be injected. For
example, a flow barrier may include multiple different types of
tracers and/or multiple different flow barriers may each include a
different type of tracer. In some cases, each of the multiple
tracers are stored in different portions of the flow barrier; in
some cases, each of the multiple tracers are stored together in the
same portion of the flow barrier.
[0089] The tracer may be stored in the flow barrier. For example,
the tracer may reside in the flow barrier for hours, days, weeks,
months, or years. The tracer may include a chemical tracer, a
radioactive tracer, a noble gas tracer, a radio frequency device
tracer, a water-soluble tracer, a hydrocarbon-soluble tracer, a
dye, a pigment, a metal, other types of tracers, and/or a
combination of these.
[0090] In some implementations, multiple flow barriers are formed
in the subterranean region and/or multiple tracers are stored in
one or more of the barriers. Each barrier may store multiple
different types of tracers, each tracer can be released into the
reservoir based on a different condition. For example, each barrier
can store a water-soluble tracer and a hydrocarbon-soluble tracer.
As another example, each barrier can store a short half-life
radioactive tracer and a long half-life radioactive tracer. The
combination of tracers can be used to glean more information from
the reservoir.
[0091] At 606, treatment fluid is injected into the reservoir. The
treatment fluid may be injected through a well bore to displace or
sweep hydrocarbons toward a production well. The treatment fluid
may be injected through a different well than the production well
used to form the flow barriers. The treatment fluid may include
compressible fluids such as steam, non-compressible fluids such as
water, heated treatment fluids, and/or other types of treatment
fluids that can induce movement of hydrocarbons through the
reservoir. The treatment fluids and/or the hydrocarbons displaced
by the treatment fluids may contact or otherwise interact with the
flow barrier in the subterranean reservoir. The contact or other
interaction between the flow barrier and fluids in the reservoir
may cause the tracer to be displaced from the barrier in the
reservoir. The tracer may be displaced to a production well and/or
to another part of the reservoir.
[0092] At 608, the tracer is detected outside of the barrier. The
tracer may be detected in fluids received into a well bore. The
tracer may be detected in fluids residing in the reservoir. A
tracer detector may detect movement of the tracer. The detector may
be installed in a well bore in the reservoir, at a ground surface
above the reservoir, and/or at another location to monitor movement
of tracers in the reservoir. The detector may detect the tracer
based on radio frequency signals scattered by the tracers. The
detector may detect the tracer based on monitoring the pH,
resistivity, and/or other properties of fluids in the reservoir.
The detector may detect the tracer based on radioactivity of the
tracers (e.g., emission of alpha, beta, and/or gamma rays). The
detector may detect the tracer based on detecting a noble gas in
fluids in the reservoir. The detector may detect the tracer based
on other types of measurements. Down hole tracer logs may indicate
a location where tracers, and hence certain types of fluids (e.g.,
treatment fluid) enters the well bore.
[0093] At 610, fluid flow patterns in the reservoir are analyzed
based on the detection of the tracer. For example, detecting the
tracer in hydrocarbons produced into a well bore may indicate that
the hydrocarbons contacted the barrier; detecting the tracer in
treatment fluid produced into a well bore may indicate that the
treatment fluid contacted the barrier. Based on the time and
location where the tracer is detected, properties of macroscopic
flow patterns in the reservoir may be identified.
[0094] In some implementations of the process 600, modifications to
the reservoir can be made based on the information provided by
detection of the tracer. Analysis may identify a breach in a flow
barrier, and the flow barrier can subsequently be reinforced or
supplemented to patch the breach. Analysis may identify a low
permeability zone, and fractures and/or additional flow barriers
may be formed in the reservoir to promote flow in the low
permeability zone. Other modifications may also be made, as
appropriate.
[0095] In some implementations of the process 600, modifications to
an injection treatment can be made based on information provided by
the detection of the tracer. Analysis may identify directions,
locations, rates and/or other properties of fluid flow in the
reservoir. An injection treatment may be designed and/or modified
based on the information on fluid flow in the reservoir. For
example, designing and/or modifying an injection treatment may
involve selecting a location to inject treatment fluid, selecting a
volume of treatment fluid to inject, and/or selecting other
injection parameters. The injection treatment may be designed
and/or modified to improve recovery of hydrocarbons from the
reservoir.
[0096] FIGS. 7A-7C are diagrams of subterranean reservoir
properties from an example numerical simulation of an injection
treatment. The numerical simulation was performed by a data
processing apparatus based on a model of a subterranean reservoir
705. The diagrams in FIGS. 7A-7D show an example scenario in which
tracers 728a and 728b stored in a flow barrier 708 can provide
information on properties of the reservoir 705. Generally,
numerical simulations may be performed in a variety of different
manners to provide a variety of different types information on
fluid flow, geological properties, and/or other information
relating to a subterranean reservoir. The example simulation shown
in FIGS. 7A-7D was performed using a numerical finite difference
representation of fluid flow through porous media, based on a
multi-phase Darcy law. The simulator used in the examples shown was
the QUIKLOOK.RTM. simulator of Halliburton Energy Services. The
simulator transforms input data describing initial subterranean
reservoir properties to generate output data describing subsequent
subterranean reservoir properties. The same and/or different types
computer software and/or hardware may be used to numerically
simulate these and/or other features of a subterranean
reservoir.
[0097] FIG. 7A shows a diagram 700a of permeability in the
reservoir 705. The shading of each rectangle in the diagram 700a
indicates an approximate magnitude of reservoir permeability in an
"x" direction in the region represented by the rectangle. The "x"
direction is indicated by the coordinate axes 752 in the diagram
700a. The range of permeability magnitudes represented by each type
of shading is shown in units of milliDarcy (mD) in the shading
legend 754a. For example, permeability values in the range of 0 mD
to 1 mD are represented in the diagram 700a by the shading type at
the top of the legend 754a, permeability values in the range of 1
mD to 100 mD are represented in the diagram 700a by the shading
type second from the top of the legend 754a, etc. In the example
numerical simulations, the reservoir 705 had an average
permeability of 40 mD, an average porosity of 0.24, and has an
initial oil saturation of 0.63; the reservoir 705 was approximately
1320 feet by 1320 feet in areal extent (in the xy-plane) and
approximately 450 feet thick (in the direction perpendicular to the
xy-plane). The values of porosity shown and described with respect
to the numerical simulations of FIGS. 7A-7D refer to the fraction
of the pore space available for fluid to saturate. As such, the
values of porosity are unitless values between zero and one. The
values of saturation shown and described with respect to the
numerical simulations of FIGS. 7A-7D refer to the fraction of the
pore space containing water (for water saturation) or oil (for oil
saturation). As such, the values of water saturation and oil
saturation are unitless values between zero and one.
[0098] The example reservoir 705 shown in FIGS. 7A-7D includes an
injection well 704, a production well 703, and a barrier 708
between the wells 704, 703. In the example simulation, the
injection well 704 injects water into the reservoir 705, and the
production well 703 receives fluids from the reservoir 705 and
communicates the received fluids to a surface. The reservoir 705
includes a high permeability channel 750. The high permeability
channel 750 transmits fluids in the x direction more readily than
the surrounding portions of reservoir 705 shown in the diagram
700a. In the example numerical simulation, the barrier 708 has a
permeability less than 1 mD in the x direction, the high
permeability channel 750 has a permeability of approximately 600
mD, and the remaining portions of the reservoir 705 have a
permeability between 1 and 100 mD.
[0099] The barrier 708 includes two types of tracers 728a, 728b,
each stored in a different portion of the barrier 708. The first
type of tracer 728a is stored in a first portion of the barrier 708
(in a first range of "y" coordinates), and the second type of
tracer 728b is stored in a second portion of the barrier 708 (in a
second range of "y" coordinates). The high permeability channel 750
intersects the barrier 708 at the second portion of the barrier 708
where the second type of tracer 728b resides. In the example shown,
the presence of the high permeability channel 750 intersecting the
second portion of the barrier 708 may result in detection of the
second type of tracer 728b at the production well 703 in greater
quantities than the first type of tracer 728a. As such, analysis of
tracer detection at the production well 703 may indicate properties
of the high permeability channel 750, such as locations where the
channel 750 intersects the barrier 708, directions of flow in the
channel 750, and/or other properties. As a result of such detection
and analysis, additional barriers may be formed, existing barriers
may be modified, operation of the production well 703, the
injection well 704, and/or another well may be modified, a new well
can be designed, and/or other changes can be made to improve
production.
[0100] FIG. 7B includes a diagram 700b showing oil saturation in
the reservoir 705 after approximately 16 years of production at the
production well 703. The shading of each rectangle in the diagram
700b indicates an approximate magnitude of oil saturation in the
region represented by the rectangle. The range of oil saturation
represented by each type of shading is shown in the shading legend
754b. FIG. 7C includes a diagram 700c showing water saturation in
the reservoir 705 after approximately 20 years of production at the
production well 703. The shading of each rectangle in the diagram
700c indicates an approximate magnitude of water saturation in the
region represented by the rectangle. The range of water saturation
represented by each type of shading is shown in the shading legend
754c. (In FIGS. 7B and 7C, the barrier 708 and the high
permeability channel 750 are present in the reservoir 705 but are
not shown in the diagrams 700b and 700c.)
[0101] FIG. 7D is a diagram 700d of water saturation from another
example numerical simulation of an injection treatment. The
numerical simulation represented in FIG. 7D was performed by a data
processing apparatus based on a model of a subterranean reservoir
805. The numerical simulation represented in FIG. 7D is identical
to the numerical simulation represented in FIG. 7C, except that the
subterranean reservoir 805 shown in FIG. 7D does not include the
barrier 708 or the tracers 728a, 728b that are included in the
subterranean reservoir 705 shown in FIGS. 7A-7C. The diagram 700d
shows water saturation in the reservoir 805 after approximately 20
years of production at the production well 703. The shading of each
rectangle in the diagram 700d indicates an approximate magnitude of
water saturation in the region represented by the rectangle. The
range of water saturation represented by each type of shading is
shown in the shading legend 754d.
[0102] The simulation represented in the diagram 700d of FIG. 7D
allows comparison with the simulation represented in diagram 700c
of FIG. 7C. In the reservoir 805 that does not include the barrier
708, water transits preferentially in the channel, resulting at
nine years in cumulative oil production of 5.6 million barrels
(bbl) and water production of 821 thousand bbl. By contrast, in the
reservoir 705 that does include the barrier 708, water transmission
in the reservoir is altered, and at nine years the cumulative oil
production is 6.4 million bbl and the cumulative water production
is 32 bbl. As such, in the example shown, numerical simulations
indicate that at nine years of production the presence of the
barrier 708 increases the volume of oil produced by the production
well 703 and reduces the volume of water produced by the production
well 703.
[0103] A number of embodiments of the invention 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.
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