U.S. patent application number 13/785524 was filed with the patent office on 2013-07-18 for technique of fracturing with selective stream injection.
This patent application is currently assigned to Schlumberger Technology Corporation. The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Diana Paola Olarte Caro, Renny Yeguez Gomez.
Application Number | 20130180722 13/785524 |
Document ID | / |
Family ID | 48779179 |
Filed Date | 2013-07-18 |
United States Patent
Application |
20130180722 |
Kind Code |
A1 |
Olarte Caro; Diana Paola ;
et al. |
July 18, 2013 |
TECHNIQUE OF FRACTURING WITH SELECTIVE STREAM INJECTION
Abstract
A technique facilitates enhanced hydrocarbon recovery through
selective stream injection. The technique employs a system and
methodology for combining a fracturing technique and application of
selective injection streams. The selective injection streams are
delivered to select, individual subterranean layers until a
plurality of unique subterranean layers are fractured to enhance
hydrocarbon recovery.
Inventors: |
Olarte Caro; Diana Paola;
(Greenwood Village, CO) ; Yeguez Gomez; Renny;
(Villahermosa, MX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation; |
Sugar Land |
TX |
US |
|
|
Assignee: |
Schlumberger Technology
Corporation
Sugar Land
TX
|
Family ID: |
48779179 |
Appl. No.: |
13/785524 |
Filed: |
March 5, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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12848690 |
Aug 2, 2010 |
|
|
|
13785524 |
|
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|
61266659 |
Dec 4, 2009 |
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Current U.S.
Class: |
166/308.1 ;
166/177.5 |
Current CPC
Class: |
E21B 43/162 20130101;
E21B 33/124 20130101; E21B 43/26 20130101; E21B 34/06 20130101;
E21B 49/008 20130101; E21B 43/14 20130101 |
Class at
Publication: |
166/308.1 ;
166/177.5 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A method for fracturing, comprising: isolating a formation layer
of a plurality of formation layers from one or more others of the
plurality of formation layers; delivering a fluid a first time to
the formation layer at least until a pressure of the fluid is equal
to an opening pressure of the formation layer; allowing the
formation layer to close after delivering the fluid the first time;
delivering the fluid a second time to the formation layer at least
until the pressure of the fluid is equal to a reopening pressure of
the formation layer, wherein the reopening pressure is less than
the opening pressure; and determining that the reopening pressure
is less than a maximum injection pressure.
2. The method of claim 1, further comprising: determining, after
delivering fluid the second time, that the reopening pressure of
the formation layer is greater than the maximum injection pressure;
and delivering fluid one or more third times to the formation
layer, at least until the reopening pressure of the formation layer
is reached each of the one or more third times, wherein the
reopening pressure decreases for each sequential one of the one or
more third times, and wherein determining that the reopening
pressure is less than the maximum injection pressure occurs after
delivering the fluid the one or more third times.
3. The method of claim 2, further comprising allowing the formation
layer to close after delivering the fluid each of the one or more
third times.
4. The method of claim 1, wherein allowing the formation to close
comprises flowing back the fluid from the formation layer.
5. The method of claim 1, further comprising: determining, after
delivering the fluid the second time, that the reopening pressure
of the formation layer is greater than the maximum injection
pressure; and delivering a complementary chemical to improve the
fracturing, duration of the fracture, or both.
6. The method of claim 1, further comprising substantially matching
a flow rate of the fluid versus time while delivering the fluid the
second time to a flow rate of the fluid versus time when the fluid
was delivered the first time.
7. The method of claim 6, wherein the flow rate of the fluid
increases over time during at least a portion of delivering the
fluid the first time.
8. The method of claim 1, further comprising selecting the
formation layer from among the plurality of formation layers
independently of whether any others of the plurality of formation
layers have been fractured.
9. The method of claim 1, further comprising determining the
maximum injection pressure based on one or more capabilities of
well equipment.
10. A computer system, comprising: one or more processors; a memory
system comprising one or more computer-readable media storing
instructions that, when executed by at least one of the one or more
processors, are configured to cause the computer system to perform
operations, the operations comprising: causing a pump to pump a
fluid a first time to a formation layer; determining that the
pressure in the fluid proximal to the formation layer is at least
equal to a fracture pressure of the formation layer; causing the
pump to pump fluid to the formation layer a second time, after the
first time; determining that the pressure in the fluid proximal to
the formation layer at least equals a reopening pressure of the
formation layer, wherein the reopening pressure is less than the
fracture pressure; and determining that the reopening pressure is
less than a maximum injection pressure.
11. The system of claim 10, wherein causing the pump to pump the
fluid the first time comprises causing the pump to pump the fluid
at successively higher fluid flow rates.
12. The system of claim 11, wherein causing the pump to pump fluid
the second time comprises substantially matching a flow rate of the
fluid versus time while pumping the first time to a flow rate of
the fluid versus time while pumping the first time.
13. The system of claim 10, wherein the operations further
comprise: determining that the reopening pressure after the second
time is higher than a threshold; causing a complementary chemical
to be delivered to the formation layer after the second time;
causing the pump to pump the fluid to the formation layer one or
more third times; and for each of the one or more third times,
determining that the pressure of the fluid proximal to the
formation layer is at least equal to the reopening pressure,
wherein the reopening pressure is reduced after each of the one or
more third times.
14. The system of claim 10, further comprising causing the fluid to
flowback, to allow the formation layer to close between the first
and second times.
15. The system of claim 10, wherein the operations further
comprise: selecting the formation layer from a plurality of
formation layers along a wellbore; and isolating the formation
layer from each other of the plurality of formation layers,
independently of whether any other of the plurality of formation
layers has been fractured.
16. The system of claim 10, wherein the operations further comprise
determining the maximum injection pressure using data related to
one or more capabilities of well equipment.
17. A computer-readable medium storing instructions that, when
executed by one or more processors of a computing system, are
configured to cause the computing system to perform operations, the
operations comprising: causing a selected formation layer of a
plurality of formation layers to be isolated from each of a
remainder of the plurality of formation layers, wherein the
selected formation layer is selected independently of whether any
other of the plurality of formation layers have been fractured;
causing fluid to be pumped to the formation layer at successively
higher fluid flow rates; determining that the pressure in the fluid
meets or exceeds a fracture pressure of the formation layer while
the fluid is being pumped the first time; causing the fluid to be
pumped to the formation layer a second time at successively higher
flow rates; determining that the pressure in the fluid meets or
exceeds a reopening pressure of the formation layer while the fluid
is being pumped the second time, wherein the reopening pressure is
less than the fracture pressure; and determining that the formation
reopening pressure is less than a maximum injection pressure.
18. The medium of claim 17, wherein a maximum value of the pressure
of the fluid during the first time is greater than a maximum value
of the pressure of the fluid during the second time.
19. The medium of claim 17, wherein the operations further
comprise: determining that the reopening pressure at the second
time is higher than a threshold; causing a complementary chemical
to be delivered to the formation layer after the second time;
causing the pump to pump fluid to the formation layer one or more
third times; and for each of the one or more third times,
determining that the pressure in the fluid meets or exceeds the
formation reopening pressure, wherein the formation reopening
pressure is reduced after each of the one or more third times.
20. The medium of claim 17, further comprising causing the fluid to
flowback, to allow the formation to close between the first and
second times.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation-in-part of U.S. patent
application Ser. No. 12/848,690, filed on Aug. 2, 2010, which
claims priority to U.S. Provisional Application Ser. No.
61/266,659, filed Dec. 4, 2009. The entirety of both of these
priority applications is incorporated herein by reference.
BACKGROUND
[0002] In certain well applications, recovery of hydrocarbon based
fluids can decline over time to uneconomical levels. Sometimes, the
recovery of hydrocarbons may be enhanced through the injection of
fluids, and such techniques are referred to as secondary recovery
or enhanced recovery methods. In one technique known as
waterflooding, water is injected to displace oil toward a producer
well. However, hydrocarbon gases, CO2, air, steam, and other fluids
may be injected to enhance recovery of the desired hydrocarbons.
Various fracturing techniques, including proppantless fracturing
techniques, also have been employed to facilitate recovery of
hydrocarbons from certain subterranean formations. Because the
composition of subterranean formations often is layered, adequate
control over fracturing and/or injection of the fluids is difficult
due to the many unique layers holding the hydrocarbon based
fluids.
SUMMARY
[0003] In general, embodiments of the present disclosure provide a
system and methodology which combine a well stimulation technique,
e.g. a proppantless fracturing technique, and application of
selective injection streams at multiple unique subterranean layers
to enhance hydrocarbon recovery.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] Certain embodiments will hereafter be described with
reference to the accompanying drawings, wherein, where convenient,
like reference numerals are generally employed to denote like
elements. In the figures:
[0005] FIG. 1 is an illustration of a system for enhancing a fluid
injection profile to multiple levels along a wellbore, according to
an embodiment.
[0006] FIG. 2 is a graph illustrating one technique for
screening/fracturing a formation layer to improve fluid injection
rate which enhances hydrocarbon production, according to an
embodiment.
[0007] FIG. 3 is a schematic illustration showing the sequential
fracturing of multiple formation layers, according to an
embodiment.
[0008] FIG. 4 is a graphical illustration of the efficiency
improvements following a multi-level fracturing technique,
according to an embodiment.
[0009] FIG. 5 is a flowchart illustrating an operational procedure
related to stimulation pumping which is employed to facilitate
sequential fracturing of a plurality of formation levels, according
to an embodiment.
[0010] FIG. 6 is a flowchart illustrating a fracturing pumping
technique employed to facilitate sequential fracturing of a
plurality of formation levels, according to an embodiment.
[0011] FIG. 7 is a flowchart illustrating fluid flushing with
chemicals, e.g. acids or solvents, which may be employed to
facilitate sequential fracturing of a plurality of formation
levels, according to an embodiment.
[0012] FIG. 8 is a schematic view of a computer system, according
to an embodiment.
DETAILED DESCRIPTION
[0013] In the following description, numerous details are set forth
to provide an understanding of embodiments of the present
disclosure. However, it will be understood by those of ordinary
skill in the art that embodiments of the present disclosure may be
practiced without these details and that numerous variations or
modifications from the described embodiments may be possible.
[0014] Embodiments of the present disclosure generally relate to a
system and methodology for improving a fluid injection profile in
fluid injector wells to thereby induce enhanced recovery of
hydrocarbons, e.g. oil, from subterranean regions. The technique is
useful in increasing the percentage of hydrocarbon based fluids
recovered from a plurality of formation layers formed through a
given subterranean region. According to one embodiment, selective
injection streams (SIS) are used to regulate the injection of
fluids, e.g. liquids, gases, steam, into formation layers through
flow regulators positioned between isolating devices. Use of the
selective injection streams also distributes the injected fluids
more efficiently through the formation layers which increases the
vertical efficiency and increases the recovery of hydrocarbons.
[0015] As described in greater detail below, the technique improves
injection of fluids and enhances hydrocarbon recovery which, as a
consequence, increases hydrocarbon production. Various aspects of
the present technique include the injection of fluids into
specific, selected subterranean layers to create individual
fractures in those layers. The selective injection stream technique
is employed to increase the number of unique formation layers which
are fractured. In some applications, complementary chemicals, e.g.
acids or solvents, are delivered to each formation layer to improve
the fracturing process and/or the duration of the created
fractures. Additionally, various analyses may be performed prior
to, during, and/or after the fracturing operation. The selective
stream injection also increases the number of formation/reservoir
layers which may be fractured in a single downhole operation.
[0016] According to one embodiment, the technique may be used to
improve the effectiveness of fluid injected, e.g. waterflooding
methods, to enhance hydrocarbon recovery. In this embodiment,
fluid, e.g. water or another suitable fluid, is introduced into a
subterranean region to create different, individual fractures using
a selective fluid injection stream. The selective fluid injection
stream is sequentially directed into each isolated layer or at
least into some of the isolated layers of a plurality of formation
layers to cause enhanced fracturing along the entire subterranean
region. The fracturing is accomplished through one or more downhole
flow control devices, e.g. regulator valves, associated with each
individual layer or each specific group of selected layers.
[0017] In many applications, the deepest layer is initially
fractured using the deepest associated mandrel (with or without a
flow control device, e.g. flow regulator valves, installed
therein), while blocking the upper regulator valves with "dummy" or
"blind" valves (or other no-flow valves) to guarantee injection of
fluid through the selected mandrel and into the selected formation
layer. For example, the technique can be applied with free mandrels
(if high wellhead pressure limitations are presented) or with flow
regulator valves or other suitable flow devices disposed in the
mandrel. The operation can be repeated through other mandrels to
selectively and sequentially fracture each of the subsequent
formation layers while the other layers are isolated. In some
cases, a device may be installed into the mandrel for the purpose
of protecting the mandrel integrity from the effects of pressure
and/or corrosion during the fracturing process.
[0018] In some applications, complementary chemicals are injected
or otherwise delivered into the individual layers prior to or after
fracturing pumping. For example, acids, e.g. hydrochloric acid
(HCl), mutual solvents, diesel, paraffin or asphalten solvents may
be delivered to the desired formation layer followed by or preceded
by the fracturing pumping. The complementary chemicals improve the
fracturing process and/or the duration of the fracture. However,
use of complementary chemicals may not be required in all
applications.
[0019] The technique also may include employing an analysis process
to evaluate and monitor aspects of the hydrocarbon production
enhancement. The analysis may be performed prior to, during, and/or
after the operation, and various monitoring techniques may be
continued following the operation. For example, the analysis may be
performed prior to the fracturing operation by screening criteria
to facilitate selection of well candidates for which the present
technique is suitable. The pre-operation analysis may include
evaluating well parameters, including mechanical integrity,
injection and fracture pressure, geological correlations,
petrophysics, reserves calculations, production profiles,
operational aspects, risk evaluation, planning of the operation,
and economics of the operation.
[0020] The analysis also may include operational aspects, including
definition of the fracture pressure which may be obtained through,
for example, "step rate tests" as described below. Other
operational aspects may include defining the pressure increment
employed during the fracture operation, and implementing the
operation (or contingency plan if necessary). The analysis also may
include ongoing monitoring techniques which include monitoring of
well parameters, e.g. flow rates, pressures, and water/fluid
quality. Monitoring may be achieved with a variety of technologies,
including tracers, spinners, distributed temperature sensing fiber
optic systems, and/or other technologies designed to measure
injection rates at each formation layer, e.g. injection rates
through specific regulator valves at each formation layer. The
monitoring techniques also may include the use of mathematical
models to reproduce dynamic aspects of the reservoirs, formation
layers, and overall well performance. The injection rates for a
given layer or layers may be modified according to the results of
the modeling.
[0021] Referring generally to FIG. 1, a well system 20 is
illustrated as deployed in a well 22, having at least one wellbore
24, to facilitate individual fracturing of a plurality of formation
layers by improving the fluid injection profile and therefore
enhancing hydrocarbon recovery. The well system 20 includes a
selective injection completion 26 designed to improve the vertical
sweeping by enabling the controlled injection of fluid into
individual, selected formation layers 28 of a plurality of
formation layers 28. The completion 26 provides control over the
injection flow, e.g. water injection flow, to individual formation
layers 28 via corresponding mandrels/flow control devices 30. By
way of example, the mandrels/flow control devices 30 may include
flow regulators, e.g. water flow regulators (WFR), such as flow
regulator valves. The mandrels/flow regulators 30 provide better
control over the injection profile throughout the reservoir and the
individual formation layers 28 of that reservoir.
[0022] In the specific example illustrated in FIG. 1, the selective
injection completion 26 includes a tubing string 32 having
isolation devices 34, e.g. packers. In the specific embodiment
illustrated, the mandrels/flow control devices 30 may include flow
regulator valves disposed in side pocket mandrels 36. In some
applications, the flow regulators 30 include dummy valves.
Additionally, the side pocket mandrels 36 are independently
isolated between packers 34, thus allowing separate injection, e.g.
water injection, into specific, selected formation layers 28
according to a specific pattern profile design. This ability
substantially enhances the fracturing operation via the selective
injection while isolating the other well zones/formation layers
from the fracturing pressure. It also should be noted that in the
embodiment illustrated, tubing string 32 is deployed within a
surrounding casing 38 having perforations 40 associated with each
formation layer 28 to enable flow of injection fluid from the
tubing string 32, through the appropriate flow control device 30,
through the corresponding perforations 40, and into the selected,
surrounding formation layer 28.
[0023] Depending on the injection/fracturing application and on the
surrounding environment, well system 20 may include a variety of
other components to facilitate injection and/or monitoring of the
procedure. For example, a sensor system 42 may be deployed downhole
with tubing string 32 to monitor the fracturing of each formation
layer 28. The sensor system 42 may be deployed within tubing string
32, along the exterior of tubing string 32, or at a location
separated from tubing string, such as along casing 38.
Additionally, the sensor system 42 may include a variety of sensors
44, e.g. distributed sensors or discrete sensors, designed to
measure desired parameters, such as pressure, temperature, flow
rate, porosity, or other parameters related to the stimulation
procedure and/or surrounding reservoir. The sensor system 42 is
useful for collecting data to enable various analyses prior to,
during, and/or after fracturing of individual layers 28.
[0024] To better recognize candidate wells (e.g. a well screening
process) and/or to better respond to low injection rates detected
in some formation layers, a detailed review of possible problems
affecting injection water restriction may be performed. A screening
process of problems and their possible associated solutions may be
conducted to determine the more appropriate stimulation system to
be employed with the present technique. In some applications, the
screening process may be based on the principle of
formation/perforations breakdown and the creation of conductor
channels within the formation by proppantless fluid, such as
water.
[0025] Referring generally to FIG. 2, the fracturing process may
involve pumping the injection fluid, e.g. water or another suitable
fluid, in a "step rate test" procedure followed by the flow back.
It should be noted a pump cycle includes both of the previously
mentioned stages (pumping the injection fluid and flow back). The
step rate test procedure includes a series of successively higher
injection rates for which pressure values are read and recorded at
each rate and time step 46, as illustrated in FIG. 2. In FIG. 2, a
plot of injection rates and the corresponding stabilized pressure
values are graphically represented as a constant slope straight
line 48 to a point 50 at which the formation fracture, or
"breakdown", pressure is exceeded (FIP) in a first pump cycle 52.
The flow back stage is then performed to allow the transition
between pump cycles and to increase the formation perturbations. A
second pump cycle 54 is performed and a fracture re-opening
pressure (FRP) 56 effectively becomes the parameter for evaluating
the effectiveness of the stimulation process and also for ranking
the success of the treatment. The success ranking depends on the
differential pressure achieved when the fracture re-opening
pressure 56 is compared with the injection pressure of fluid from
the fluid injection plant, e.g. water injection plant. The
re-opening fracture pressure could be affected every time the
pumping cycle is done, reducing the effective re-opening pressure.
The cycles may be repeated until the reduction in such pressure is
considered profitable. Performing several cycles increases
formation perturbations which induces fatigue and makes the
formation weaker. This is demonstrated by a decrease in the
reopening pressure due to reduction in the tensile strength and
Young's Modulus of the formation.
[0026] In the present technique for enhancing hydrocarbon recovery,
vertical sweeping efficiency is an important factor, and that
factor is addressed by the selective stream completion 26 when used
for fracture stimulation. Furthermore, the fracture stimulation via
selective stream completion 26 provides a technique directly
focused on improving vertical efficiency at a low cost and low
risk. Another attribute of the technique is maintaining selectivity
in the injection because the fractures are selectively performed in
accordance with the selective string arrangement. The fracturing
technique is designed to avoid communication between formations
while substantially enhancing conductivity of flow along a selected
or determined formation. In the embodiment of FIG. 3, the
sequential stimulation, e.g. fracturing, of individual formation
layers 28 is illustrated. In this example, the selective injection
completion 26 is used to fracture individual layers 28 or specific
groups of layers through the empty mandrel (or using flow control
devices) 30 having "dummy" or "blind" valves 58 to block injection
of fluid into other layers of the subterranean region. In that way,
injection of fluid is concentrated through a selected control
device(s) 30 and into the specific layer or group of layers 28 to
be fractured.
[0027] As illustrated in the embodiment of FIG. 3, the injection
sequence is repeated for each layer or group of layers of the
subterranean region. Initially, the dummy valves 58 are used to
block flow into the upper formation layers 28, while the lowermost
formation layer 28 is fractured or otherwise stimulated. In the
specific example illustrated, a well stimulation fluid 60, e.g. a
water-based fracturing fluid, is first delivered down through
tubing string 32. In this example, the fracturing fluid is flowed
outwardly through the lowermost mandrel 30 and into the lowermost
formation zone 28 to create the desired fractures 62, as
illustrated in the left portion of FIG. 3.
[0028] After fracturing the lowermost formation layer 28, it is
blocked by dummy valve 58, as illustrated in the middle portion of
FIG. 3. The flow control device 30 of the next sequential formation
layer 28 to be stimulated, e.g. fractured, is then opened to allow
the outflow of fluid 60, as illustrated. While a given formation
layer 28 is fractured (or otherwise stimulated), the other
formation layers 28 are isolated from the pressure of the
fracturing fluid via packers 34 and the closed flow control devices
30 in those other well zones. This process of introducing an
injection fluid into a selected formation layer 28 while isolating
the other formation layers is repeated for each sequential
formation layer, as further illustrated in the rightmost portion of
FIG. 3. To obtain desired isolation or inclusion, different options
may be employed, e.g. selective dummy or blind valve installation
and retrieval.
[0029] The flow control devices 30 may be actuated between open and
closed positions via a variety of actuators depending on the design
of the flow control device. With certain flow regulator valves,
including dummy valves 58, a shifting tool may be moved downhole to
manipulate the appropriate valve. For example, injection into
specific layers 28 may be achieved by moving/actuating/retrieving
the regulator valves 30/58 via a low-cost slickline operation. As
result, it is not necessary to pull out the selective string to
make individual fractures, thus avoiding substantial costs
associated with the rig rate and required replacement tools.
[0030] The selective stream injection technique substantially
increases the efficiency of hydrocarbon recovery from a variety of
wells. Improvements are provided with respect to not only vertical
efficiency but also with respect to areal efficiency and total
efficiency or recovery factor. Referring generally to FIG. 4, a
graphical illustration is provided to illustrate the substantial
improvements in various efficiency measurements when the present
"fracturing with selective stream injection technique" is employed
to recover hydrocarbons from a subterranean region.
[0031] As illustrated in the example of FIG. 4, areal efficiency is
substantially improved, as illustrated by upper portion 66 of the
graphical representation in FIG. 4. In this particular example, the
areal efficiency is based on a well configuration in which four
injector wells are employed in the corners of a pattern of wells,
and a producer well is located in the center of the pattern. Over
time, the injected fluid flows into the porous media displacing oil
to the producer well. The ratio between the area flooded with water
and the area of the pattern (a rectangle in this case) is referred
to as areal efficiency. It should be noted that a variety of
patterns of the injector wells and producer wells may be employed
depending on the characteristics of the application and reservoir
environment. As additional formation layers are reached by the
injected fluids, the areal efficiency increases in these particular
formation layers, thus improving the overall areal efficiency.
[0032] Vertical efficiency is illustrated in a lower portion 68 of
the graphical representation in FIG. 4 by a schematic
cross-sectional view of formation layers 28 at three different
times. In this example, five different formation layers 28 are
flooded with water 60. The injected water 60 is distributed in the
different formation layers according to the petrophysical
properties, e.g. permeability and thickness of the layers;
formation damage during the well completion; and/or pore pressure.
In this example, the vertical efficiency is the ratio between the
volume of the layers flooded and the total volume of the layers.
The vertical efficiency, in particular, can be substantially
improved through the use of the technique described herein which
employs fracturing with selective stream injection of individual
formation layers 28. However, the total efficiency or recovery
factor, ER, also is improved and is the product of three
efficiencies, namely displacement efficiency, areal efficiency, and
vertical efficiency.
[0033] The fracturing with selective injection stream technique may
be employed in a variety of environments with many types of wells.
However, one embodiment of the methodology for carrying out this
technique includes initially preparing a well for intervention. At
this initial stage, each layer 28 to be individually treated is
properly prepared to ensure the integrity of the selective
injection completion 26 and to verify each formation layer 28 has
treatment isolation/independency with respect to the other layers
28. In some applications, an optional "pickling" job is performed
at this stage by delivering a complementary chemical into one or
more individual formation layers. For example, HCl may be delivered
downhole to clean the injection string or tubing 32 by eliminating
residual components in the walls of the tubing which could
otherwise block the flow control devices/valves 30 or damage the
formation layers 28.
[0034] The initial segments of one embodiment of the procedure are
illustrated in the flowchart of FIG. 5. In this specific example, a
slickline may be used to isolate formation layers with dummy valves
58, as illustrated by block 70. The system is then flow tested by a
pressure test, as represented by decision block 72. If the flow is
zero, an optional pickling operation may be performed by directing
a complementary chemical, e.g. HCl, downhole, as represented by
block 74, prior to inclusion of the selective group to be
fractured, as represented by block 76. If, on the other hand, flow
is detected as an indication of lack of isolation, a tracer log may
be run and the dummy valves 58 may be readjusted and/or the
equipment may be re-run downhole, as represented by block 78.
[0035] In a subsequent stage of the technique, the injection fluid
60, e.g. water or another suitable fluid, is delivered downhole and
introduced into a specific layer or group of layers 28 between
packers 34 to create individual fractures 62 in the specific
layer(s), as discussed above with reference to FIG. 3. The
selective fluid injection stream 60 can be used sequentially on
individual, isolated formation layers 28 to increase the number of
formation layers 28 that may be independently fractured.
Consequently, the selective stream technique enables independent
treatments on specific layers and optimizes the effective
channeling creation throughout the overall formation. In many
applications, brine may be used as a fracture fluid when formation
layers are sensitive to untreated water.
[0036] Referring generally to FIG. 6, a flow chart is provided to
illustrate one procedure for carrying out the fracturing process
discussed above with reference to FIG. 2. Initially, several
fracturing pump cycles may be performed, as represented by block
80. The fracturing pump cycles may be performed through two
different stages, the first of which is a step rate test or the
fluid injection stage when fluid 60 is injected into a desired,
selected formation layer to be fractured. The second stage is a
flow back stage (not a fluid injection stage) which allows the pump
cycles to transition and increase the perturbation effect to the
formation. In operational conditions, the fluid injection wells
work under a specific injection pressure established by the pumping
capacity of the surface facilities of the hydrocarbon field as
provided for retaining injection operations. However, this specific
injection pressure is not related to any injection pressure
obtained during the fracturing process application. This specific
injection pressure could be measured for any formation through
dynamic pressure profiling when fluid injection is performed in a
particular well at normal operating conditions.
[0037] Accordingly, the required injection pressure must be
available/obtained before performing the fracturing process
described herein. The number of fracturing pump cycles may be
determined according to, for example, detailed analysis related to
formation characteristics and a cost-benefit analysis of the
operation. Upon ending the fracturing pumping cycles, the last
fracture reopening pressure obtained is compared to the injection
pressure previously defined, as represented by decision block 82.
If the fracture reopening pressure is above the injection pressure
value, then a chemical flushing may be performed, as represented by
block 84. Subsequently, several fracturing pumping cycles may again
be carried out, as represented by block 86, until the fracture
reopening pressure is less than the injection pressure, as
represented by decision block 88. If the fracture reopening
pressure is less than the injection pressure, the fracturing
pumping is stopped and the fracturing is ended, as represented by
blocks 90 and 92. If there is difficulty in achieving a fracturing
reopening pressure which is less than the injection pressure,
additional testing and/or other techniques may be employed, as
represented by block 94.
[0038] As discussed above, chemicals may be directed downhole with
and/or in addition to the injection stream 60 to facilitate or
enhance the fracturing process. If, for example, a limitation in
injection rate occurs due to near wellbore restrictions,
complementary chemicals (e.g. hydrochloric acid (HCl), mutual
solvents, diesel, paraffin or asphalten solvents) may be added to
improve the fracturing process and the duration of the fracture. In
some applications, the complementary chemicals may be added during
the step rate test.
[0039] Referring generally to the flowchart of FIG. 7, one example
of the addition of complementary chemicals pumping is illustrated.
During an initial step rate test, the injection rate is compared to
the injection pressure, as illustrated by block 96. The injection
rate is compared to a predetermined value Y, as represented by
decision block 98. If the injection rate is above the value Y, then
a pre-flush is employed in which a complementary chemical, e.g.
HCl, is delivered downhole to the desired well zone/formation
layer, as represented by block 100.
[0040] Subsequently, a flush procedure is delivered downhole with
an additional, or stronger, complementary chemical, as represented
by block 102. The flush procedure may be followed with a
displacement fluid procedure, as represented by block 104.
[0041] Referring again to the decision block 98. If the injection
rate is below the value Y, then an appropriate tool on coiled
tubing may be run in hole, as represented by block 106. The coiled
tubing is used to conduct and supplement the pre-flush procedure,
as represented by block 100. Subsequently, the flush and
displacement procedures may be conducted, as represented by blocks
102, 104.
[0042] The technique of fracturing with selective stream injection
may be employed in a variety of wells formed in many types of
subterranean regions. The number of formation layers independently
treated in fluid injector wells to improve hydrocarbon recovery in
producers, as well as the number and type of packers, regulator
valves and other components of the injection completion, may be
adjusted according to the specific environment and application.
Similarly, the injection fluid and any complementary chemicals used
to facilitate fracturing may be selected according to the
parameters of the specific application and/or environment in which
the technique is employed. The procedural stages of the methodology
also may be adjusted to accommodate specific parameters of a given
application employing the selective stream injection technique.
Various candidate well screening techniques also may be employed to
determine wells best suited for improved production through
selective fracturing.
[0043] Embodiments of the disclosure may also include one or more
systems for implementing one or more embodiments of the processes
and techniques shown in and described above with reference to FIGS.
1-7. Accordingly, FIG. 8 illustrates a schematic view of such a
computer or processor system 800, according to an embodiment. The
processor system 800 may include one or more processors 802 of
varying core (including multiple cores) configurations and clock
frequencies. The one or more processors 802 may be operable to
execute instructions, apply logic, etc., for example, to flatten
the seismic image 300, identify packages, determine spatially any
areas of contamination, compare results, verify results, etc.,
according to one or more of the embodiments of the method 200
described above. It will be appreciated that these functions may be
provided by multiple processors or multiple cores on a single chip
operating in parallel and/or communicably linked together.
[0044] The processor system 800 may also include a memory system,
which may be or include one or more memory devices and/or
computer-readable media 804 of varying physical dimensions,
accessibility, storage capacities, etc. such as flash drives, hard
drives, disks, random access memory, etc., for storing data, such
as images, files, and program instructions for execution by the
processor 802. In an embodiment, the computer-readable media 804
may store instructions that, when executed by the processor 802,
are configured to cause the processor system 800 to perform
operations. For example, execution of such instructions may cause
the processor system 800 to implement one or more portions and/or
embodiments of the method described above.
[0045] The processor system 800 may also include one or more
network interfaces 806. The network interfaces 806 may include any
hardware, applications, and/or other software. Accordingly, the
network interfaces 106 may include Ethernet adapters, wireless
transceivers, PCI interfaces, and/or serial network components, for
communicating over wired or wireless media using protocols, such as
Ethernet, wireless Ethernet, etc.
[0046] The processor system 800 may further include one or more
peripheral interfaces 108, for communication with a display screen,
projector, keyboards, mice, touchpads, sensors, other types of
input and/or output peripherals, and/or the like. In some
implementations, the components of processor system 800 may not be
enclosed within a single enclosure or even located in close
proximity to one another, but in other implementations, the
components and/or others may be provided in a single enclosure.
[0047] The memory device 804 may be physically or logically
arranged or configured to store data on one or more storage devices
810. The storage device 810 may include one or more file systems or
databases in any suitable format. The storage device 810 may also
include one or more software programs 812, which may contain
interpretable or executable instructions for performing one or more
of the disclosed processes. When requested by the processor 802,
one or more of the software programs 812, or a portion thereof, may
be loaded from the storage devices 810 to the memory devices 804
for execution by the processor 802.
[0048] Those skilled in the art will appreciate that the
above-described componentry is merely one example of a hardware
configuration, as the processor system 800 may include any type of
hardware components, including any necessary accompanying firmware
or software, for performing the disclosed implementations. The
processor system 800 may also be implemented in part or in whole by
electronic circuit components or processors, such as
application-specific integrated circuits (ASICs) or
field-programmable gate arrays (FPGAs).
[0049] Although only a few embodiments have been described in
detail above, those of ordinary skill in the art will readily
appreciate that many modifications are possible without materially
departing from the present disclosure. Accordingly, such
modifications are intended to be included within the scope of this
present disclosure, as defined in the claims.
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