DOWNHOLE FLUID FLOW CONTROL SYSTEM AND METHOD HAVING
DYNAMIC RESPONSE TO LOCAL WELL CONDITIONS
TECHNICAL FIELD OF THE INVENTION
[0001] This invention relates, in general, to equipment utilized in conjunction with
operations performed in subterranean wells and, in particular, to a downhole fluid flow
control system and method having dynamic response to local well conditions to control the
inflow of formation fluids and the outflow of injection fluids.
BACKGROUND OF THE INVENTION
[0002] Without limiting the scope of the present invention, its background will be
described with reference to producing fluid from a hydrocarbon bearing subterranean
formation, as an example.
[0003] During the completion of a well that traverses a hydrocarbon bearing subterranean
formation, production tubing and various completion equipment are installed in the well to
enable safe and efficient production of the formation fluids. For example, to control the
inflow of production fluids, it is common practice to install one or more flow control devices
within the tubing string. The flow control devices may include one or more flow control
components such as flow tubes, nozzles, labyrinths or the like. Typically, the production
flowrate through these flow control devices is fixed prior to installation by the number and
design of the flow control components.
[0004] It has been found, however, that due to changes in formation pressure and changes
in formation fluid composition over the life of the well, it may be desirable to adjust the flow
control characteristics of the flow control devices. In addition, for certain completions, such
as long horizontal completions having numerous production intervals, it may be desirable to
independently control the inflow of production fluids into each of the production intervals.
Further, in some completions, it would be desirable to adjust the flow control characteristics
of the flow control devices without the requirement for well intervention.
[0005] Accordingly, a need has arisen for an improved flow control system that is
operable to control the inflow of formation fluids. A need has also arisen for such a flow
control system that is operable to independently control the inflow of production fluids from
multiple production intervals and operable to control the inflow of production fluids without
the requirement for well intervention as formation pressure or fluid composition changes over
time.
SUMMARY OF THE INVENTION
[0006] The present invention disclosed herein comprises a downhole fluid flow control
system and method having dynamic response to local well conditions to control the inflow of
formation fluids and the outflow of injection fluids. In addition, the downhole fluid flow
control system and method of the present invention are operable to independently control the
inflow of production fluids into multiple production intervals without the requirement for
well intervention as formation pressure or the composition of the fluids produced into
specific intervals changes over time.
[0007] In one aspect, the present invention is directed to a downhole fluid flow control
system. The downhole fluid flow control system includes a tubing string operably
positionable in a wellbore. Annular barriers are positioned between the tubing string and the
wellbore to isolate first and second zones. A fluid flow control device is positioned within
each zone. A flow tube operably associated with the fluid flow control device of the first
zone operable to establish fluid communication between the second zone and the fluid flow
control device in the first zone such that a differential pressure between the first zone and the
second zone is operable to actuate the fluid flow control device of the first zone from a first
operating configuration to a second operating configuration.
[0008] In one embodiment, the first operating configuration is an open position and the
second operating configuration is a closed position. In another embodiment, the first
operating configuration is a closed position and the second operating configuration is an open
position. In a further embodiment, the first operating configuration is an open position and
the second operating configuration is a restricted position. In certain embodiments, the flow
tube extends through at least one of the annular barriers. In some embodiments, a flow tube
operably associated with the fluid flow control device of the second zone extends through at
least one of the annular barriers to establish fluid communication between the first zone and
the fluid flow control device in the second zone such that a differential pressure between the
first zone and the second zone is operable to actuate the fluid flow control device of the
second zone from a first operating configuration to a second operating configuration.
[0009] In another aspect, the present invention is directed to a downhole fluid flow
control method. The method includes isolating first and second zones in a wellbore, each
zone having a fluid flow control device positioned therein, establishing fluid communication
between the first zone and the fluid flow control device in the second zone, flowing fluid
through the fluid flow control device of the first zone, generating a differential pressure
between the first zone and the second zone and actuating the fluid flow control device of the
second zone from a first operating configuration to a second operating configuration
responsive to the differential pressure.
[0010] The method may also include installing annular barriers between the tubing string
and the wellbore, extending a flow tube through at least one of the annular barriers, injecting
a fluid from an interior of the tubing string into the formation through the first zone,
performing an acid stimulation of the first zone, performing a fracture operation in the
formation, changing the viscosity of the fluid or actuating the fluid flow control device of the
second zone from a closed position to an open position.
[0011] In another aspect, the present invention is directed to a downhole fluid flow
control method. The method includes isolating first and second zones in a wellbore, each
zone having a fluid flow control device positioned therein, establishing fluid communication
between the second zone and the fluid flow control device in the first zone, flowing fluid
through the fluid flow control devices of the first zone and the second zone, generating a
differential pressure between the first zone and the second zone and actuating the fluid flow
control device of the first zone from a first operating configuration to a second operating
configuration responsive to the differential pressure.
[0012] The method may also include installing annular barriers between the tubing string
and the wellbore, extending a flow tube through at least one of the annular barriers,
producing fluid from the formation into an interior of the tubing string through the first zone
and the second zone, transitioning from production of a desired fluid to production of an
undesired fluid in the first zone, increasing the flowrate of the fluid produced through the first
zone, changing the viscosity of the fluid produced through the first zone, actuating the fluid
flow control device of the first zone from an open position to a restricted position or actuating
the fluid flow control device of the first zone from an open position to a closed position.
[0013] In another aspect, the present invention is directed to a downhole fluid flow
control method. The method includes isolating first and second zones in a wellbore, each
zone having a fluid flow control device positioned therein, establishing fluid communication
between the second zone and the fluid flow control device in the first zone, establishing fluid
communication between the first zone and the fluid flow control device in the second zone,
injecting fluid from a tubing string through the fluid flow control device of the first zone into
a formation, generating a differential pressure between the first zone and the second zone and
responsive to the differential pressure, opening the fluid flow control device in the second
zone and closing the fluid flow control device in the first zone.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] For a more complete understanding of the features and advantages of the present
invention, reference is now made to the detailed description of the invention along with the
accompanying figures in which corresponding numerals in the different figures refer to
corresponding parts and in which:
[0015] Figure 1 is a schematic illustration of a well system operating a fluid flow control
system according to an embodiment of the present invention during a first phase of a
treatment operation;
[0016] Figure 2 is a schematic illustration of a well system operating a fluid flow control
system according to an embodiment of the present invention during a second phase of a
treatment operation;
[0017] Figure 3 is a schematic illustration of a well system operating a fluid flow control
system according to an embodiment of the present invention during a third phase of a
treatment operation;
[0018] Figure 4 is a schematic illustration of a well system operating a fluid flow control
system according to an embodiment of the present invention during a final phase of a
treatment operation;
[0019] Figure 5 is a schematic illustration of a well system operating a fluid flow control
system according to an embodiment of the present invention during a production operation;
and
[0020] Figure 6 is a schematic illustration of a well system operating a fluid flow control
system according to an embodiment of the present invention during a later phase of the
production operation.
DETAILED DESCRIPTION OF THE INVENTION
[0021] While the making and using of various embodiments of the present invention are
discussed in detail below, it should be appreciated that the present invention provides many
applicable inventive concepts which can be embodied in a wide variety of specific contexts.
The specific embodiments discussed herein are merely illustrative of specific ways to make
and use the invention, and do not delimit the scope of the present invention.
[0022] Referring initially to figure 1, therein is depicted a well system including a
downhole fluid flow control system embodying principles of the present invention that is
schematically illustrated and generally designated 10. In the illustrated embodiment, a
wellbore 1 extends through the various earth strata. Wellbore 12 has a substantially vertical
section 14, the upper portion of which has cemented therein a casing string 16. Wellbore 12
also has a substantially horizontal section 18 that extends through a hydrocarbon bearing
subterranean formation 20. As illustrated, substantially horizontal section 18 of wellbore 12
is open hole.
[0023] Positioned within wellbore 12 and extending from the surface is a tubing string
22. Tubing string 22 provides a conduit for formation fluids to travel from formation 20 to
the surface and for injection fluids to travel from the surface to formation 20. At its lower
end, tubing string 22 is coupled to a completions string 24 that has been installed in wellbore
12 and divides the completion interval into various production intervals identified as zone 1,
zone 2, zone 3 ... zone N-l and zone N. Completion string 24 includes a plurality of flow
control devices identified as FCD 1, FCD 2, FCD 3, FCD N-l and FCD N, wherein FCD 1
corresponds with zone 1, FCD 2 corresponds to zone 2 and so forth. Each of the flow control
devices is depicted as being positioned between a pair of annular barriers 26 that extend
between completion string 24 and wellbore 12, thereby isolating the production intervals. As
used herein, the term annular barrier may refer to any suitable pressure barrier known to those
skilled in the art including, but not limited to, production packers, inflatable packer, swellable
packer or the like as well as materials such as gravel packs or other wellbore filler materials
that are operable to provide a pressure differential thereacross, thereby isolating zones in the
wellbore. The annular barriers may or may not provide a complete seal between the tubing
string and the wellbore.
[0024] In the illustrated embodiment, the flow control devices may serve numerous
functions. For example, the flow control devices may function as filter media such as a wire
wrap screen, a woven wire mesh screen, a prepacked screen or the like, with or without an
outer shroud positioned therearound, designed to allow fluids to flow therethrough but
prevent particulate matter of a predetermined size from flowing therethrough. In addition,
the flow control devices may function as inflow control devices to regulate the flow of a
production fluid stream during the production phase of well operations or as outflow control
devices to control the flow of an injection fluid stream during a treatment phase of well
operations or both. The inflow and outflow control may be accomplished using the same or
different components within the flow control devices such that the desired flowrates are
achieved. For example, it may be desirable to have a higher injection rate than the intended
production rate through the flow control devices in which case different injection valves and
production valves may be used or more injection valves than production valves may be used.
As explained in greater detail below, when operated in the system and according to the
methods of the present invention, the flow control devices are also operable to dynamically
respond to local well conditions to control the inflow of formation fluids or the outflow of
injection fluids through the various zones of the wellbore. It is noted that the function of
inflow or outflow control during production or injection operations and the function of
dynamic response to wellbore conditions may be performed by the same or different
components within the flow control devices.
[0025] For example, inflow or outflow control during production or injection operations
may be achieved using fluid flow resistors such as nozzles, flow tubes, labyrinths or other
tortuous path flow resistors, as well as vortex chambers or other fluidic diodes, matrix
chambers containing fluid flow resisting filler material such as bead or fluid selector
materials that swell when in contact with hydrocarbons, water or other stimulants such as pH,
ionic concentration or the like. The function of dynamic response to wellbore conditions may
be achieved using valves such as sliding sleeves, piston operated valves, velocity valves or
the like. Alternatively, both inflow or outflow control during production or injection
operations and dynamic response to wellbore conditions could be performed by the same
component such as a choke or other infinitely variable valving assembly.
[0026] Still referring to figure 1, each of the flow control devices is in communication
with one or more adjacent zones, for example, fluid communication, fluid pressure
communication or the like. Specifically, FCD 1 is operably associated with a flow tube 28
proving upstream communication with zone 2 through one of the annular barriers 26. As
used herein, the term flow tube shall mean any medium capable of providing a
communication path, such as a fluid or pressure communication path, between a flow control
device and another zone. For example, the flow tubes may be control lines or other tubing in
the annulus between the tubing string and the wellbore that extend through one or more
annular barriers. Alternatively, the flow tubes could be concentric tubulars around the tubing
string that extend through and are preferably positioned interiorly of one or more annular
barriers. The flow tubes may provide an unencumbered communication path between a flow
control device and another zone or the flow tubes may include valving, pistons or other flow
control or pressure operated devices. In the illustrated embodiment, FCD 2 is operably
associated with a flow tube 30 proving downstream communication with zone 1 through one
of the annular barriers 26. Also, FCD 2 is operably associated with a flow tube 32 proving
upstream communication with zone 3 through one of the annular barriers 26. FCD 3 is
operably associated with a flow tube 34 proving downstream communication with zone 2
through one of the annular barriers 26. Also, FCD 3 is operably associated with a flow tube
36 proving upstream communication through one of the annular barriers 26. FCD N-l is
operably associated with a flow tube 38 proving downstream communication through one of
the annular barriers 26. Also, FCD N-l is operably associated with a flow tube 40 proving
upstream communication with zone N through one of the annular barriers 26. FCD N is
operably associated with a flow tube 42 proving downstream communication with zone N-l
through one of the annular barriers 26. Even though figure 1 depicts each flow control device
in communication with one or more adjacent zones via the flow tubes, it is to be understood
by those skilled in the art that the flow control devices in the present invention could
alternatively or additionally be in communication with one or more remote zones that are not
adjacent to the zone in which that flow control device operates.
[0027] Even though figure 1 depicts the flow control system of the present invention in
an open hole environment, it should be understood by those skilled in the art that the present
invention is equally well suited for use in cased wells. Also, even though figure 1 depicts one
flow control device in each production interval, it should be understood by those skilled in
the art that any number of flow control devices may be deployed within a production interval
without departing from the principles of the present invention. In addition, even though
figure 1 depicts the flow control system of the present invention in a horizontal section of the
wellbore, it should be understood by those skilled in the art that the present invention is
equally well suited for use in wells having other directional configurations including vertical
wells, deviated wells, slanted wells, multilateral wells and the like. Accordingly, it should be
understood by those skilled in the art that the use of directional terms such as above, below,
upper, lower, upward, downward, left, right, uphole, downhole and the like are used in
relation to the illustrative embodiments as they are depicted in the figures, the upward
direction being toward the top of the corresponding figure and the downward direction being
toward the bottom of the corresponding figure, the uphole direction being toward the surface
of the well and the downhole direction being toward the toe of the well.
[0028] The operation of the downhole fluid flow control system having dynamic response
to local well conditions will now be described with reference to figures 1-4. In figure 1, a
tubing string depicted as completion string 24 has been located in wellbore 12. A plurality of
annular barriers 26 has been deployed which isolate a plurality of zones; namely, zone 1 -
zone N. Each zone includes a fluid flow control device FCD 1 - FCD N that is in fluid
communication with one or more other zones via flow tubes 28-42. Figure 1 depicts a first
stage of a treatment operation wherein FCD 1 is in the open position and FCD 2 - FCD N are
all in the closed position such that the treatment fluid, indicated by the arrows, is directed out
of completions string 24 into formation 20 through FCD 1 and zone 1. The treatment
operation depicted may be an acid treatment, a hydraulic fracturing operation or other
operation that requires pumping fluid down the tubing string into a production zone or the
formation.
[0029] As the treatment fluid is pumped into formation 20 through zone 1, the pressure
PI in zone 1 will change as local well conditions change. For example, during an acid
treatment, the pressure PI in zone 1 will initially be at a high pressure that is above reservoir
pressure as the filter cake or other wellbore damage will create resistance to the flow of the
treatment fluid into the formation at the surface of the wellbore. As the acid treatment
removes the filter cake in zone 1, the pressure PI will decrease as the resistance to flow into
the formation decreases. As another example, during certain fracture operations, the pressure
PI in zone 1 will initially be at a high pressure that is above reservoir pressure as a large
volume of treatment fluid is pumped into the formation to create and prop open the hydraulic
fractures. When the fractures cease to propagate or a sand out occurs, the pressure PI will
increase. Similarly, in other fracture operations, the pressure PI in zone 1 will initially be at
a high pressure that is above reservoir pressure as a large volume of treatment fluid is
pumped into the formation to create and prop open the hydraulic fractures. As the
composition of the treatment fluid changes from a high viscosity gel to a lower viscosity
fluid, for example, the pressure PI will decrease as the resistance to flow into the formation
decreases. In each of these treatment scenarios, the pressure PI changes over time and has an
expected pressure signature.
[0030] In the illustrated embodiment, these pressure changes in zone 1 are seen by FCD 2
in zone 2 due to fluid communication through annular barrier 26 via flow tube 30.
Depending on the expected pressure signature during the treatment operation, the fluid
pressure PI can be routed to the appropriate side of a piston, sliding sleeve or other operation
mechanism within FCD 2. The other side of the piston, sliding sleeve or other operation
mechanism within FCD 2 may see the pressure P2 from zone 2, which is initially reservoir
pressure. The differential pressure between PI and P2 thus provides an energy source to
operate FCD 2 from a first operating configuration to a second operating configuration.
Depending upon the operation being performed and the routing of pressures PI and P2 into
FCD 2, when PI experiences the desired pressure increase or decrease, a differential pressure
is created between PI and P2 such that, in the illustrated embodiment, FCD 2 is shifted from
the closed to the open position, as best seen in figure 2.
[0031] Depending upon the desired outcome of the treatment operation, once FCD 2 is
open, FCD 1 can remain open or preferably, FCD 1 can be closed. In the illustrated
embodiment, the pressure P2 in zone 2 is seen by FCD 1 in zone 1 due to fluid
communication through annular barrier 26 via flow tube 28. Depending on the expected
pressure signature during the treatment operation, the fluid pressure P2 can be routed to an
appropriate side of the operation mechanism within FCD 1, the other side of which preferably
sees the pressure PI from zone 1. The differential pressure between PI and P2 thus provides
an energy source to operate FCD 1 from a first operating configuration to a second operating
configuration which in this case is shifting FCD 1 from the open to the closed position, as
best seen in figure 2. Preferably, FCD 2 is opened prior to closing FCD 1. This can be
accomplished using a time delay circuit such as a metering fluid to regulate the closing speed
of FCD 1. Once FCD 1 is closed, it may be mechanically biased or locked in the closed
position using springs, collets or other locking assemblies or it may be biased in the closed
position by pressure in the system, such as tubing pressure.
[0032] The treatment operation then continues in zone 2 with the pressure P2 changing
over time with an expected pressure signature that depends on the treatment operation being
performed. These pressure changes in zone 2 are seen by FCD 3 in zone 3 due to fluid
communication through annular barrier 26 via flow tube 34. Depending on the expected
pressure signature during the treatment operation, the fluid pressure P2 can be routed to the
appropriate side of the operation mechanism within FCD 3 with the other side preferably
seeing the pressure P3 from zone 3, which is initially reservoir pressure. The differential
pressure between P2 and P3 thus provides an energy source to operate FCD 3 from its closed
position to its open position, as best seen in figure 3.
[0033] Depending upon the desired outcome of the treatment operation, once FCD 3 is
open, FCD 2 can remain open or preferably, FCD 2 can be closed. In the illustrated
embodiment, the pressure P3 in zone 3 is seen by FCD 2 in zone 2 due to fluid
communication through annular barrier 26 via flow tube 32. Depending on the expected
pressure signature during the treatment operation, the fluid pressure P3 can be routed to an
appropriate side of the operation mechanism within FCD 2, the other side of which preferably
sees the pressure P2 from zone 2. The differential pressure between P2 and P3 thus provides
an energy source to operate FCD 2 from its open to its closed position, as best seen in figure
3. Preferably, FCD 3 is opened prior to closing FCD 2 and FCD 2 is secured in the closed
position.
[0034] This process may proceed uphole in a stepwise fashion to accomplish the desired
treatment goals until the last zone of wellbore 12 is treated, as best seen in figure 4, wherein
FCD N is open to allow treatment fluid to enter zone N as indicated by the arrows and all
other flow control devices are closed. After the treatment operation has been completed, each
of the previously closed flow control devices may be operated to the open position based
upon sequential differential pressure changes in the zones. For example, as fluid is produced
into zone N, the pressure PN falls below reservoir pressure. This pressure change in zone N
is seen by FCD N-l in zone N-l due to fluid communication through annular barrier 26 via
flow tube 40. The fluid pressure PN can be routed to the appropriate side of the operation
mechanism within FCD N-l, the other side of which preferably sees the pressure PN-1 from
zone N-l, which is initially reservoir pressure. The differential pressure between PN and PN-
1 can be use as an energy source to operate FCD N-l from its closed position to its open
position. This process may proceed downhole in a stepwise fashion until all zones are open
to production.
[0035] Another operation of the downhole fluid flow control system having dynamic
response to local well conditions will now be described with reference to figures 5-6. In
figure 5, a tubing string depicted as completion string 24 has been located in wellbore 12. A
plurality of annular barriers 26 has been deployed which isolate a plurality of zones; namely,
zone 1 - zone N. Each zone includes a fluid flow control device FCD 1 - FCD N that is in
fluid communication with one or more other zones via flow tubes 28-42. Figure 5 depicts a
production operation wherein each of the flow control devices is in the open position such
that the production fluid, indicated by the arrows, flows into completion string 24 through
each of the flow control devices and each of the zones.
[0036] During the production operation, the inflow control components within FCD 1 -
FCD N will attempt to regulate and balance production rates through each zone. Under
certain conditions, however, the inflow control components may be unable to regulate and
balance production rates or it may be desirable to shut-in or highly restrict production from
one or more zones due to changes in flowrate through a zone or changes in the composition
of a fluid being produced into a zone. For example, if the desired fluid to be produced in the
well system is oil and one or more zones begin to produce an undesired fluid such as gas or
water, the fluid flow control system of the present invention can dynamically respond to this
local well condition. As the viscosity of the oil is generally higher than the viscosity of the
gas or water, there is a greater pressure drop experienced by the oil as it migrates through the
formation to the wellbore than that experienced by water or gas. As such, when water or gas
is produced into a zone, the pressure in that zone is greater than the pressure in a zone
producing oil. Likewise, if the flowrate into a zone increases due to, for example, a fissure in
the formation, this low resistance region in the formation could lead to early water or gas
production. As such, when oil is produced into a zone from a high permeability region in the
formation, the pressure in that zone is greater than the pressure in a zone producing oil
through a normal permeability region of the formation. In each of these production scenarios,
the pressure difference in various zones can be used to control production.
[0037] In the illustrated embodiment, if a change in flowrate or fluid composition has
resulted in a higher pressure in zone 2 than in zone 1 or zone 3 or both, these pressure
differences are seen by FCD 2 in zone 2 due to fluid communication through annular barrier
26 via flow tubes 30, 32. The fluid pressure PI or P3 can be routed to the appropriate side of
a piston, sliding sleeve or other operation mechanism within FCD 2 with the other side of the
piston, sliding sleeve or other operation mechanism within FCD 2 seeing the pressure P2
from zone 2. The differential pressure between PI and P2 or P3 and P2 thus provides an
energy source to operate FCD 2 from a first operating configuration to a second operating
configuration. For example, when the differential pressure reaches a predetermined level,
FCD 2 could be operated from its open position to a choked position or FCD 2 could be
operation from its open position to a closed position, as best seen in figure 6. Preferably,
FCD 2 is then secured in the closed position. The process will continue interventionlessly
throughout the wellbore system as production fluid flowrates or compositions change in the
various zones, with differential pressures providing the energy for the closure of the desired
flow control devices. It should be noted that the required differential pressure needed to
operate the various flow control devices may be different in different zones and may be
preselected or predetermined.
[0038] While this invention has been described with reference to illustrative
embodiments, this description is not intended to be construed in a limiting sense. Various
modifications and combinations of the illustrative embodiments as well as other
embodiments of the invention will be apparent to persons skilled in the art upon reference to
the description. It is, therefore, intended that the appended claims encompass any such
modifications or embodiments.
What is claimed is:
1. A downhole fluid flow control method comprising:
isolating first and second zones in a wellbore, each zone having a fluid flow control
device positioned therein;
establishing communication between the first zone and the fluid flow control device
in the second zone;
flowing fluid through the fluid flow control device of the first zone;
generating a differential pressure between the first zone and the second zone; and
actuating the fluid flow control device of the second zone from a first operating
configuration to a second operating configuration responsive to the differential pressure.
2. The downhole fluid flow control method as recited in claim 1 wherein
isolating first and second zones in the wellbore further comprises installing annular barriers
between a tubing string and the wellbore.
3. The downhole fluid flow control method as recited in claim 2 wherein
establishing communication between the first zone and the fluid flow control device in the
second zone further comprises extending a flow tube through at least one of the annular
barriers.
4. The downhole fluid flow control method as recited in claim 1 wherein flowing
fluid through the fluid flow control device of the first zone further comprises injecting a fluid
from an interior of a tubing string into a formation through the first zone.
5. The downhole fluid flow control method as recited in claim 1 wherein flowing
fluid through the fluid flow control device of the first zone further comprises performing an
acid stimulation of the first zone.
6. The downhole fluid flow control method as recited in claim 1 wherein flowing
fluid through the fluid flow control device of the first zone further comprises performing a
fracture operation in the formation.
7. The downhole fluid flow control method as recited in claim 1 wherein
generating the differential pressure between the first zone and the second zone further
comprises changing the viscosity of the fluid.
8. The downhole fluid flow control method as recited in claim 1 wherein
actuating the fluid flow control device of the second zone from the first operating
configuration to the second operating configuration further comprises actuating the fluid flow
control device of the second zone from a closed position to an open position.
9. A downhole fluid flow control method comprising:
isolating first and second zones in a wellbore, each zone having a fluid flow control
device positioned therein;
establishing communication between the second zone and the fluid flow control
device in the first zone;
flowing fluid through the fluid flow control devices of the first zone and the second
zone;
generating a differential pressure between the first zone and the second zone; and
actuating the fluid flow control device of the first zone from a first operating
configuration to a second operating configuration responsive to the differential pressure.
10. The downhole fluid flow control method as recited in claim 9 wherein
isolating first and second zones in the wellbore further comprises installing annular barriers
between a tubing string and the wellbore.
11. The downhole fluid flow control method as recited in claim 10 wherein
establishing communication between the second zone and the fluid flow control device in the
first zone further comprises extending a flow tube through at least one of the annular barriers.
12. The downhole fluid flow control method as recited in claim 9 wherein flowing
fluid through the fluid flow control devices of the first zone and the second zone further
comprises producing fluid from a formation into an interior of a tubing string through the first
zone and the second zone.
13. The downhole fluid flow control method as recited in claim 12 wherein
generating the differential pressure between the first zone and the second zone further
comprises transitioning from production of a desired fluid to production of an undesired fluid
in the first zone.
14. The downhole fluid flow control method as recited in claim 12 wherein
generating the differential pressure between the first zone and the second zone further
comprises increasing the flowrate of the fluid produced through the first zone.
15. The downhole fluid flow control method as recited in claim 12 wherein
generating the differential pressure between the first zone and the second zone further
comprises changing the viscosity of the fluid produced through the first zone.
16. The downhole fluid flow control method as recited in claim 9 wherein
actuating the f uid flow control device of the first zone from the first operating configuration
to the second operating configuration further comprises actuating the fluid flow control
device of the first zone from an open position to a restricted position.
17. The downhole fluid flow control method as recited in claim 9 wherein
actuating the f uid flow control device of the first zone from the first operating configuration
to the second operating configuration further comprises actuating the fluid flow control
device of the first zone from an open position to a closed position.
18. A downhole fluid flow control method comprising:
isolating first and second zones in a wellbore, each zone having a fluid flow control
device positioned therein;
establishing communication between the second zone and the fluid flow control
device in the first zone;
establishing communication between the first zone and the fluid flow control device
in the second zone;
injecting fluid from a tubing string through the fluid flow control device of the first
zone into a formation;
generating a differential pressure between the first zone and the second zone; and
responsive to the differential pressure, opening the fluid flow control device in the
second zone and closing the fluid flow control device in the first zone.
19. The downhole fluid flow control method as recited in claim 18 wherein
isolating first and second zones in the wellbore further comprises installing annular barriers
between a tubing string and the wellbore.
20. The downhole fluid flow control method as recited in claim 18 wherein
injecting fluid from the tubing string through the fluid flow control device of the first zone
into the formation further comprises performing an acid stimulation of the first zone.
21. The downhole fluid flow control method as recited in claim 18 wherein
injecting fluid from the tubing string through the fluid flow control device of the first zone
into the formation further comprises performing a fracture operation in the formation.
22. A downhole fluid flow control system comprising:
a tubing string operably positionable in a wellbore;
a plurality of annular barriers positionable between the tubing string and the wellbore
to isolate first and second zones;
a fluid flow control device positioned within each zone; and
a flow tube operably associated with the fluid flow control device of the first zone, the
flow tube establishing communication between the second zone and the fluid flow control
device in the first zone such that a differential pressure between the first zone and the second
zone is operable to actuate the fluid flow control device of the first zone from a first operating
configuration to a second operating configuration.
23. The downhole fluid flow control system as recited in claim 22 wherein the
flow tube extends through at least one of the annular barriers.
24. The downhole fluid flow control system as recited in claim 22 wherein the
first operating configuration is an open position and the second operating configuration is a
closed position.
25. The downhole fluid flow control system as recited in claim 22 wherein the
first operating configuration is a closed position and the second operating configuration is an
open position.
26. The downhole fluid flow control system as recited in claim 22 wherein the
first operating configuration is an open position and the second operating configuration is a
restricted position.
27. The downhole fluid flow control system as recited in claim 22 further
comprising a flow tube operably associated with the fluid flow control device of the second
zone and extending through at least one of the annular barriers to establish communication
between the first zone and the fluid flow control device in the second zone such that a
differential pressure between the first zone and the second zone is operable to actuate the
fluid flow control device of the second zone from a first operating configuration to a second
operating configuration.