Note: Descriptions are shown in the official language in which they were submitted.
PAT 104331-1
SYSTEM AND METHOD FOR FLUID FLOW CONTROL
IN A HYDROCARBON RECOVERY OPERATION
Technical Field
[0001] The present invention relates to control of fluid flow in a well
utilized
in a hydrocarbon recovery operation.
Background
[0002] Extensive deposits of viscous hydrocarbons exist around the world,
including large deposits in the northern Alberta oil sands that are not
susceptible
to standard oil well production technologies. The hydrocarbons in reservoirs
of
such deposits are too viscous to flow at commercially relevant rates at the
temperatures and pressures present in the reservoir. For such reservoirs,
thermal techniques may be utilized to heat the reservoir to mobilize the
hydrocarbons and produce the heated, mobilized hydrocarbons from wells. For
example, a displacing fluid such as steam, water, gas, solvent, or a
combination
thereof, may be utilized to heat and mobilize the hydrocarbons. One technique
for utilizing a horizontal well for injecting heated fluids and producing
hydrocarbons is described in U.S. Patent No. 4,116,275, which also describes
some of the problems associated with the production of mobilized viscous
hydrocarbons from horizontal wells.
[0003] One thermal method of recovering viscous hydrocarbons utilizing
spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). In
the SAGD process, pressurized steam is delivered through an upper, horizontal,
injection well (injector), into a viscous hydrocarbon reservoir while
hydrocarbons
are produced from a lower, parallel, horizontal, production well (producer)
that is
near the injection well and is vertically spaced from the injection well. The
injection and production wells are situated in the lower portion of the
reservoir,
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with the producer located close to the base of the hydrocarbon deposit to
collect
the hydrocarbons that flow toward the base of the deposit.
[0004] The SAGD process is believed to work as follows. The injected
steam initially mobilizes the hydrocarbons to create a steam chamber in the
reservoir around and above the horizontal injection well. The term steam
chamber is utilized to refer to the volume of the reservoir that is saturated
with
injected steam and from which mobilized oil has at least partially drained. As
the
steam chamber expands, viscous hydrocarbons in the reservoir and water
originally present in the reservoir are heated and mobilized and move with
aqueous condensate, under the effect of gravity, toward the bottom of the
steam
chamber. The hydrocarbons, the water originally present, and the aqueous
condensate are typically referred to collectively as emulsion. The emulsion
accumulates such that the liquid / vapor interface is located below the steam
injector and above the producer. The emulsion is collected and produced from
the production well. The produced emulsion is separated into dry oil for sales
and produced water, comprising the water originally present and the aqueous
condensate.
[0005] Due to differences in viscosity between the displacing fluid and
the
oil, as well as the heterogeneous nature of most reservoirs, heating of the
viscous hydrocarbons and displacement of hydrocarbons is non-uniform along
the length of the injection or production wells. The control of the displacing
fluid
distribution along the length of the injection well is thus desirable. Fluid
control
and distribution devices are therefore utilized along the length of the
injection
well.
[0006] Downhole flow control devices that are openable and closable are
beneficial for delivery of steam, water, gas and solvent injection to targeted
locations and for reducing delivery of such fluids to other locations. Such
devices
are electronically or mechanically manipulated to open and close. Electronic
manipulation requires downhole connections and equipment that is expensive
and easily damaged. Mechanical manipulation may be difficult in small diameter
wells, which are desirable for ease of installation and cost reasons, and in
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relatively long well lengths or depths. Reaching such devices utilizing coiled
tubing units is difficult, and generating the mechanical force sufficient to
open or
close the devices may be difficult. In addition, such mechanical manipulations
require opening of the well head for the mechanical intervention, resulting in
down time for the associated wells and requiring safety precautions when
intervening in wells that have hot fluids therein.
[0007] Improvements in control of fluid flow in wells utilized in
hydrocarbon
recovery are desirable.
Summary
[0008] According to an aspect of an embodiment, there is provided a flow
control system for use in a well of a hydrocarbon recovery operation. The
system includes a tube disposed in the well for flow of fluid therethrough,
the
tube including a tube port disposed in a sidewall thereof, a sleeve disposed
within the tube, the sleeve being moveable within the tube between a closed
position in which the tube port is covered to inhibit the flow of fluid
therethrough,
and an open position in which the tube port is uncovered to facilitate the
flow of
fluid therethrough. A first valve seat is disposed in the tube and for
cooperating
with a first releasable valve member for creating differential pressure across
the
first releasable valve member to move the sleeve within the tube, in a first
direction toward the open position or the closed position. A second valve seat
is
disposed in the tube for cooperating with a second releasable valve member for
creating differential pressure across the second releasable valve member to
move the sleeve within the tube, in a second direction, opposite to the first
direction. The first valve seat and second valve seat differing in size for
selectively cooperating with the first releasable valve member and the second
releasable valve member, respectively.
[0009] According to another aspect, a method of controlling fluid flow in
a
well of a hydrocarbon recovery operation is provided. The method includes:
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disposing a fluid flow control system in the well, the fluid flow control
system
including a tube having a tube port therein, a sleeve disposed within the tube
and moveable within the tube between a closed position in which the tube port
is
covered to inhibit the flow of fluid therethrough, and an open position in
which
the tube port is exposed to facilitate the flow of fluid therethrough, a first
valve
seat disposed in the tube for cooperating with a first releasable valve
member,
and a second valve seat disposed in the tube for cooperating with a second
releasable valve member, the first valve seat and second valve seat differing
in
size for selectively cooperating with the first releasable valve member and
the
second releasable valve member, respectively;
introducing a first releasable valve member into the well, the first
releasable
valve member cooperating with the first valve seat;
directing pressurized fluid down the well to create a first differential
pressure
across the first releasable valve member to move the sleeve in a first
direction
along the tube;
introducing a second releasable valve member into the well, the second
releasable valve member cooperating with the second valve seat; and
directing pressurized fluid down the well to create a second differential
pressure
across the second releasable valve member to move the sleeve in a second
direction along the tube, opposite to the first direction.
[0010] According to another aspect, there is provided a method for
improving steam chamber conformance in a hydrocarbon recovery operation
having an injection well extending into a hydrocarbon-bearing formation, the
injection well including fluid flow control systems disposed therein, each of
the
fluid flow control systems including a tube having a tube port therein, a
sleeve
disposed within the tube and moveable within the tube between a closed
position
in which the tube port is covered to inhibit the flow of fluid therethrough,
and an
open position in which the tube port is exposed to facilitate the flow of
fluid
therethrough, the method comprising:
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PAT 104331-1
identifying one fluid flow control system of the fluid flow control systems
for
opening to facilitate the flow of fluid through the tube port of the one fluid
flow
control system;
selecting a first releasable valve member sized to cooperate with the one
fluid
flow control system;
introducing the first releasable valve member into the injection well, the
first
releasable valve member cooperating with a first valve seat of the one fluid
flow
control system;
injecting steam into the injection well to create a first differential
pressure across
the first releasable valve member to move the sleeve of the one fluid flow
control
system in a first direction along the tube to thereby open the one fluid flow
control system;
injecting further steam into the hydrocarbon-bearing formation, via the tube
port
of the one fluid control system; and
producing fluids including at least some of the hydrocarbons from the
hydrocarbon-bearing formation.
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Brief Description of the Drawings
[0011] Embodiments of the present invention will be described, by way of
example, with reference to the drawings and to the following description, in
which:
[0012] FIG. 1 is a sectional view through a reservoir, illustrating a
SAGD
well pair;
[0013] FIG. 2 is a sectional side view illustrating a SAGD well pair
including
an injection well and a production well;
[0014] FIG. 3 is a sectional side view illustrating an example of an
injection
well including flow control systems therein;
[0015] FIG. 4A through FIG. 4H illustrate an example of controlling fluid
flow utilizing a flow control system in accordance with an aspect of an
embodiment;
[0016] FIG. 5 is a flowchart illustrating a method of controlling fluid
flow in
a well of a hydrocarbon recovery operation;
[0017] FIG. 6A through FIG. 6D illustrate another example of controlling
fluid flow utilizing a flow control system in accordance with an aspect of
another
embodiment;
[0018] FIG. 6E illustrates a particular example of an application of the
flow
control system illustrated in FIG. 6A through FIG. 6D;
[0019] FIG. 7A through FIG. 7G illustrate another example of controlling
fluid flow utilizing a flow control system in accordance with an aspect of
another
embodiment;
[0020] FIG. 8A through FIG. 8D illustrate another example of controlling
fluid flow utilizing a flow control system in accordance with an aspect of yet
another embodiment.
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Detailed Description
[0021] For simplicity and clarity of illustration, reference numerals may
be
repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples
described herein. The examples may be practiced without these details. In
other instances, well-known methods, procedures, and components are not
described in detail to avoid obscuring the examples described. The description
is
not to be considered as limited to the scope of the examples described herein.
[0022] The disclosure generally relates to a flow control system for use
in a
well of a hydrocarbon recovery operation. The system includes a tube disposed
in the well for flow of fluid therethrough, the tube including a tube port
disposed
in a sidewall thereof. A sleeve is disposed within the tube, the sleeve being
moveable within the tube between a closed position in which the tube port is
covered to inhibit the flow of fluid therethrough, and an open position in
which
the tube port is uncovered to facilitate the flow of fluid therethrough. Valve
seats are disposed in the tube for cooperating with releasable valve members
to
create differential pressures along the tube and thereby move the sleeve from
the closed position to the open position and from the open position to the
closed
position.
[0023] Thus, releasable valve members are utilized for downhole flow
control by creating differential pressures to selectively open and close ports
rather than utilizing mechanical tools or complex electronic communication
systems.
[0024] As noted above, the present disclosure relates to flow control
systems for controlling the flow of fluids, such as steam. In the present
example, the process is described in relation to SAGD. The present process may
be successfully implemented with other processes, however.
[0025] Reference is made herein to an injection well and a production
well.
The injection well and the production well may be physically separate wells.
Alternatively, the production well and the injection well may be housed, at
least
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partially, in a single physical wellbore. The production well and the
injection well
may be functionally independent components that are hydraulically isolated
from
each other, and housed within a single physical wellbore.
[0026] As referred to above, a steam-assisted gravity drainage (SAGD)
process may be utilized for mobilizing viscous hydrocarbons. In the SAGD
process, a well pair, including a hydrocarbon production well and a steam
injection well are utilized. One example of a well pair is illustrated in FIG.
1 and
an example of a hydrocarbon production well 100 and injection well 108 is
illustrated in FIG. 2. The hydrocarbon production well 100 includes a
generally
horizontal segment 102 that extends near the base or bottom 104 of the
hydrocarbon reservoir 106. The injection well 108 also includes a generally
horizontal segment 110 that is disposed generally parallel to and is spaced
generally vertically above the horizontal segment 102 of the hydrocarbon
production well 100.
[0027] During SAGD, steam is injected into the injection well 108 to
mobilize the hydrocarbons and create a steam chamber 112 in the reservoir 106,
around and above the generally horizontal segment 110. In addition to steam
injection into the injection well 108, light hydrocarbons, such as the C3
through
C10 alkanes, either individually or in combination, may optionally be injected
with the steam such that the light hydrocarbons function as solvents in aiding
the
mobilization of the hydrocarbons. In one embodiment, the volume of light
hydrocarbons that are injected is relatively small compared to the volume of
steam injected. The addition of light hydrocarbons is referred to as a solvent
aided process (SAP). Alternatively, or in addition to the light hydrocarbons,
various non-condensing gases, such as methane or carbon dioxide, may be
injected. Viscous hydrocarbons in the reservoir are heated and mobilized and
the
mobilized hydrocarbons drain under the effect of gravity. Fluids, including
the
mobilized hydrocarbons along with connate water and condensed steam
(aqueous condensate), are collected in the generally horizontal segment 102.
The fluids may also include gases such as steam and production gases (e.g.,
methane, hydrogen sulfide) from the SAGD process.
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[0028] A simplified sectional side view of one example of a well
including a
plurality of flow control systems is illustrated in FIG. 3. For the purpose of
the
present example, the well may be an injection well 108 and includes 4 flow
control systems 300 for controlling the flow of mobilizing fluid, such as
steam, in
a tubing string 304 along the horizontal segment of the injection well 108.
The
flow control systems 300 are spaced along the horizontal segment 110 of the
injection well 108 to facilitate the control of flow of the mobilizing fluid
at the
spaced apart locations along the injection well 108. Each of the flow control
systems is operable to selectively divert mobilizing fluid out of the
horizontal
segment 110 of the injection well 108 and in a direction generally transverse
thereto. Alternatively, the well may be a production well 100 that includes 4
flow
control systems 300 for controlling the flow of hydrocarbons in a tubing
string
304 along the horizontal segment of the production well 100.
[0029] The term uphole is generally utilized to refer to elements along a
generally horizontal segment that are closer to a wellhead along the length of
the
well. The term downhole is generally utilized to refer to elements along a
generally horizontal segment that are farther from the wellhead along the
length
of the well.
[0030] Reference is now made to FIG. 4A through FIG. 4H, which show
partial sectional side views of controlling fluid flow utilizing a flow
control system
300 according to an example.
[0031] The flow control system 300 includes a tube 402 that is
coupleable,
for example, along a tubing string such as a string utilized for water or
steam
injection. The flow control system 300 may be utilized to selectively divert
steam
injected down the tubing string, generally radially outwardly from the tube
402.
The tube 402 includes tube ports 404 extending through a sidewall of the tube
402 for the flow of fluid therethrough. In the example shown in FIG. 4, the
tube
402 includes four tube ports 404, generally equally spaced around a
circumference of the tube 402 for the flow of fluid from inside the tube 402,
through the tube ports 404, out of the tube 402. Alternatively, the tube 402
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may be coupled along a tubing string utilized for production of gas or
hydrocarbons.
[0032] A portion 416 of the tube 402 is constructed of multiple
sidewalls,
including an inner sidewall 406, a middle sidewall 408, and an outer sidewall
410. The middle sidewall 408 is sized and shaped to encircle the inner
sidewall
406, leaving spaces therebetween, and the outer sidewall 410 is sized and
shaped to encircle the middle sidewall 408, leaving spaces therebetween, to
form
piston conduits 412 and fluid channels 414 between the sidewalls.
[0033] The piston conduits 412 are disposed between the inner sidewall
406 and the middle sidewall 408 and are sized and shaped for movement of
pistons along the piston conduits 412. For the purpose of the present example,
each piston conduit 412 is generally cylindrically shaped for receiving
generally
cylindrical pistons therein. Thus, the inner sidewall 406 and the middle
sidewall
408 are sized and shaped to provide the generally cylindrical piston conduits
412
therebetween.
[0034] Alternatively, a single sleeve-shaped piston may be utilized such
that the piston conduit extends around or encircles an inner wall of the tube
402.
In this alternative example, an inner diameter of the middle sidewall 408 is
greater than an outer diameter of the inner sidewall 406, to form a space
between the inner sidewall 406 and the middle sidewall 408 in which the single
sleeve-shaped piston resides.
[0035] The portion 416 of the tube 402 that includes the piston conduits
412 and fluid channels 414, is located uphole, i.e., closer to the wellhead,
of the
tube ports 404.
[0036] The flow control system 300 also includes a sleeve 420 that is
moveable within the tube 402 to selectively open and close the tube ports 404.
The sleeve 420 is generally cylindrically shaped and includes sleeve ports 422
extending through the sleeve sidewall 424 for the flow of fluid therethrough.
In
the example shown in FIG. 4A through FIG. 4H, the sleeve 420 includes four
sleeve ports 422, generally equally spaced around a circumference of the
sleeve
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420. The sleeve ports 422 are sized, shaped, and disposed at locations to
align
with the tube ports 404 when the sleeve 420 is in an open position, as
illustrated
in FIG. 4E.
[0037] The sleeve 420 is coupled to the pistons 426 by webs (not shown)
that extend radially outwardly from the sleeve sidewall 424 and connect to the
pistons 426 that are disposed in the piston conduits 412, in spaces between
the
inner sidewall 406 and the middle sidewall 408. Each web passes through a thin
slot in the inner sidewall 406 of the tube 402 to connect the pistons 426 to
the
sleeve 420.
[0038] The pistons 426 in the present example are solid cylindrical rods
that are moveable along the piston conduits 412. The fluid channels 414
include
first fluid channels 430 and second fluid channels 432. Each first fluid
channel
430 is defined by the outer sidewall 410 of the portion 416 of the tube 402
and
the middle sidewall 408 of the portion 416 of the tube 402, and extends from a
location uphole of the sleeve 420, to a downhole end 434 of a respective
piston
426. Thus, the first fluid channels 430 provide fluid communication between
the
interior of the tube 402 and the downhole ends 434 of the pistons 426.
[0039] Each second fluid channel 432 is defined by the middle sidewall
408
and the inner sidewall 406 of the portion 416 of the tube 402, and extends
from
a location uphole of the sleeve 420, to an uphole end 436 of a respective
piston
426. Thus, the second fluid channels 432 provide fluid communication between
the interior of the tube 402 and the uphole ends 436 of the pistons 426. The
second fluid channels 432 are fluidly coupled to the interior of the tube 402
at
locations that are downhole of the locations at which the first fluid channels
430
are fluidly coupled to the interior of the tube 402. Thus, the second fluid
channels 432 start downhole of the first fluid channels 430.
[0040] A first valve seat 440 is coupled to and extends inwardly into the
tube 402 from a location between the locations at which the first fluid
channels
430 fluidly couple to the interior of the tube 402 and the locations at which
the
second fluid channels 432 fluidly couple to the interior of the tube 402.
Thus,
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the first valve seat 440 is disposed uphole of the sleeve 420. The first valve
seat
440 is sized to receive a first releasable valve member, which in the present
example is a first ball 444, as shown in FIG. 4F.
[0041] A second valve seat 442 is coupled to and extends inwardly from
the sleeve 420, at a location along the sleeve 420 that is uphole from the
sleeve
ports 422, i.e., between the sleeve ports 422 and an uphole end of the sleeve
420. The second valve seat 442 is connected to and moves with the sleeve 420
and the pistons 426. The second valve seat 442 is sized to receive a second
releasable valve member, which in the present example is a second ball 446, as
shown in FIG. 48. The second valve seat 442 is smaller than the first valve
seat
440 such that the second ball 446 is sized to pass through the first valve
seat
440 and land on the second valve seat 442.
[0042] In one embodiment, both the first ball 444 and the second ball 446
are dissolvable such that the first ball 444 and the second ball 446 are
releasable
from their respective valve seats by dissolving in the fluids in the tube 402.
[0043] Continued reference is made to FIG. 4A through FIG. 4H along with
reference to FIG. 5 to describe the control of fluid flow in a well of a
hydrocarbon
recovery operation in accordance with one example. At 502, a fluid flow
control
system 300 is disposed in a horizontal segment of a well, such as the
injection
well 108 during well completion. The fluid flow control system 300 may be
utilized in any vertically oriented well or portion of a well. The fluid flow
control
system 300 may also be utilized in a horizontal or vertical segment of a
production well.
[0044] As illustrated in FIG. 4A, the sleeve is in a closed position in
which
the sleeve ports 422 are not aligned with the tube ports 404. As a result,
fluid
flow out of the tube ports 404 and into the reservoir is inhibited as fluid
flows
into an uphole end 450 of the tube 402 and out a downhole end 552 of the tube
402.
[0045] To move the sleeve 420 to an open position in which the sleeve
ports 422 are aligned with the tube ports 404, to facilitate the diversion of
fluid
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flow through the tube ports 404, the releasable valve member, which in this
example is the second ball 446 is introduced into the tubing string 304 (shown
in
FIG. 3) at 504. The second ball 446 enters the tube 402 and is smaller than
the
first valve seat 440 and sized to seat on the second valve seat 442. Thus, the
second ball 446 passes through the first valve seat 440 and seats on the
second
valve seat 442, as illustrated in FIG. 48. Fluid, such as water, is injected,
under
pressure, into the tubing string 304 at 506, as illustrated in FIG. 4C. With
the
second ball 446 seated on the second valve seat 442, a differential pressure
is
created along the tube 402, across the second ball 446 and second valve seat
442. As the pressure differential increases, the force on the uphole side of
the
second ball 446 and second valve seat 442 increases and pushes the second ball
446 and second valve seat 442 in the downhole direction. The sleeve 420 and
sleeve pistons 426 are moved in the downhole direction, thereby sliding the
sleeve 420 into the open position, as illustrated in FIG. 4D. The second ball
446
is dissolved and is released from the second valve seat 442 facilitating fluid
flow
through the tube 402. With the sleeve 420 in the open position, the sleeve
ports
422 are aligned with the tube ports 404 to facilitate the diversion of fluid
flow
through the tube ports 404, as illustrated in FIG. 4E and into the reservoir.
[0046] To
return the sleeve 420 to the closed position, in which the sleeve
ports 422 are not aligned with the tube ports 404 and therefore fluid flow out
of
the tube ports 404 is inhibited, the first releasable valve member, which in
this
example is the first ball 444, is introduced into the tubing string 304
(illustrated
in FIG. 3) at 508. The first ball 444 is larger than the second ball 446 and
is
sized to seat on the first valve seat 440, as illustrated in FIG. 4F. At 510,
fluid,
such as water, is injected, under pressure, into the tubing string 304, as
illustrated in FIG. 4G. With the first ball 444 seated on the first valve seat
440, a
differential pressure is created along the tube 402, across the first ball 444
and
first valve seat 440. As the pressure differential increases, the force on the
uphole side of the first ball 444 and first valve seat 440 increases. The
injected
water is inhibited from passing the first ball 444 and the first valve seat
440 and
the water utilized to create the differential pressure, travels through the
first fluid
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channels 430, applying a force at the downhole ends 434 of the pistons 426.
With sufficient pressure, the pistons 426 are forced in the uphole direction,
causing the sleeve 420 to move into the closed position, as illustrated in
FIG. 4H,
thereby moving the sleeve ports 422 out of alignment with the tube ports 404.
The pressure behind the first ball 444 and the first valve seat 440 is
reduced.
[0047] The first ball 444 is dissolved and is released from the first
valve
seat 440 facilitating fluid flow through the tube 402. The pressure in the
well
may be decreased to reduce the pressure differential in the event that the
first
ball 444 engages the second valve seat 442, after dissolving a sufficient
amount
to be released from the first valve seat. Thus, any pressure differential
across
the first ball 444 is insufficient to cause the sleeve 420 to move back into
the
open position. For example, in the case of an injection well, the injection
well
may be temporarily shut in to reduce the pressure to a pressure that is
insufficient to cause the sleeve 420 to move. The pressure differential and
thus
the injection pressure to move the sleeve 420 may vary from well to well
depending on a number of factors including well depth.
[0048] The valve members, which in this example are the first ball 444
and
the second ball 446, may be configured to dissolve within a period of time,
such
as 1 hour or 2 hours to ensure that the valve members are dissolved before
injection commences again. Optionally, a fluid may be injected to dissolve a
valve member in the event that the valve member remains in the valve seat
longer than desired.
[0049] As illustrated in FIG. 3, a plurality of flow control systems 300
for
controlling the flow of fluid in a tubing string along the horizontal segment
of a
well may be utilized. The flow control systems 300 are spaced along the
horizontal segment of the well to facilitate the control of flow of fluid at
the
spaced apart locations along the well. Each successive flow control system in
the
downhole direction includes first and second valve seats 440, 442 that are
sized
to cooperate with successively smaller valve members such that valve members
are selectable, based on size, to control any one of the flow control systems.
For
example, a flow control system further downhole includes valve seats that are
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sized to cooperate with smaller valve members than those utilized to control
an
uphole flow control system. Thus, a valve member may be inserted to pass
through the uphole flow control system and to seat on one of the valve seats
of
the downhole flow control system.
[0050] Utilizing the flow control system 300, ports are selectively
openable
and closable. Fluids, such as water or steam, may be selectively diverted
through the ports to deliver the fluids to locations at which the fluids are
utilized
to mobilize the hydrocarbons. Thus, fluid distribution along the length of the
injection well is controllable to improve uniformity of heating and
displacement of
hydrocarbons along the length of the injection well. Alternatively, the ports
may
be utilized to allow fluid to flow into the tubing at selected intervals to
improve
production of displacement or depletion of hydrocarbons along the length of
the
production well.
[0051] As indicated, the flow control systems described herein may be
utilized in a production well, for controlling the flow of hydrocarbons in a
tubing
string along a horizontal segment of the production well. A pump and
associated
tubing string may be utilized in the production well. The valve members, which
may be balls, for example, may be delivered to the appropriate valve seat by
passing the pump and associated tubing string utilized in the production well.
[0052] FIG. 6A through FIG. 6D show a partial sectional side view of
another example of control of flow utilizing a flow control system 600. The
flow
control system 600 is similar to the flow control system 300 described above
with reference to FIG. 4A through FIG. 4H. In the present example, however,
the locations of the elements differ from the locations of similar elements in
the
example described with reference to FIG. 4A through FIG. 4H. For example, the
locations of the sleeve ports 622, the first valve seat 640, the second valve
seat
642, the pistons 626, and the fluid channels 630, 632 differ. In particular,
the
second valve seat 642, is coupled to an extends inwardly from the sleeve 620
at
a location along the sleeve 620 that is uphole from the sleeve ports 622 and
uphole of the first valve seat 640.
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[0053] The first valve seat 640 is coupled to and extends inwardly into
the
tube 602 from a location that is downhole of the downhole end of the sleeve
620.
The second valve seat 642 is coupled to and extends inwardly from the sleeve
620, at a location along the sleeve that is uphole from the sleeve ports 622.
The
second valve seat 642 is connected to and moves with the sleeve 620 and the
pistons 626. The second valve seat 642 is sized to receive a second releasable
valve member, which in the present example is a second ball 646, as shown in
FIG. 6A. In the present example, the second valve seat 642 is sized to receive
a
larger ball, i.e., the second ball 646, than the first valve seat 640.
[0054] The pistons 626 move along the piston conduits. The fluid
channels, however, include first fluid channels 630, each defined by the outer
sidewall 610 and the inner sidewall 606 of the tube 602 and the first fluid
channel 630 and extending from a location downhole of the sleeve 620 and
uphole of the first valve seat 640, i.e., between the sleeve 620 and the first
valve seat 640, to a downhole end 634 of a respective piston 626. Thus, each
first fluid channel 630 provides fluid communication between the interior of
the
tube 602 and a downhole end 434 of the respective piston 626. Each second
fluid channel 632 is also defined by the outer sidewall 610 and the inner
sidewall
606 of the tube 602 and extends from an uphole end 636 of the respective
piston
626 to an exterior or outside of the tube 602. Thus, each second fluid channel
632 provides fluid communication between an uphole end of the respective
piston 626 and the formation in which the tube 602 is disposed.
[0055] In the example illustrated in FIG. 6A through FIG. 6D, the flow
control system 600 may be utilized in a production well or in an injection
well. In
FIG. 6A, the sleeve 620 is shown in the closed position in which the sleeve
ports
622 are not aligned with the tube ports 604 and therefore fluid flow through
the
tube ports 604 is inhibited. To move the sleeve 620 to the open position, the
first releasable valve member, which in this example is the first ball 644 is
introduced into the tubing string. The first ball 644 is smaller than the
second
ball 646, passes through the second valve seat 642, and seats on the first
valve
seat 640, as illustrated in FIG. 6A. Fluid, such as water, is injected under
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pressure, into the tubing string, as illustrated in FIG. 6B. The fluid enters
the
first fluid channels 632 and applies force to the downhole ends of the pistons
634. With sufficient pressure, the pistons 626 are forced in the uphole
direction,
causing the sleeve 620 to move into the open position shown in FIG. 6B in
which
the sleeve ports 622 are aligned with the tube ports 604, facilitating fluid
flow
through the tube ports 604. The first ball 644 is dissolved and released from
the
first valve seat 640.
[0056] To return the sleeve 620 to the closed position, a second
releasable
valve member, which is the second ball 646 is introduced into the tubing
string
646 and is sized to seat on the second valve seat 642, as illustrated in FIG.
6C.
The fluid, such as water, is injected, under pressure, into the tubing string
and
creates a pressure differential along the tube 402, across the second ball 646
and the second valve seat 642. As the pressure differential increases, the
force
on the uphole side of the second ball 646 and second valve seat 642 increases
and pushes the second ball 646, second valve seat 646, and the sleeve 620 in
the downhole direction, thus moving the sleeve 620 into the closed position,
as
illustrated in FIG. 6D. The second ball 646 is dissolved and released from the
second valve seat 642.
[0057] FIG. 6E shows a partial sectional side view illustrating one
example
of an application of the flow control system 600. Although one flow control
system 600 is shown further flow control systems 600 may be utilized and
disposed in succession in a tubing string. The flow control system described
herein may be utilized in an open hole completion, for example, in a ?racking
application or a sand control application.
[0058] For example, such flow control systems may be utilized in
controlling the injection of fracking fluid. The example of FIG. 6E is a
simplified
illustration of the use of the flow control system 600 in a production well,
in a
sand control application in which sand is inserted into the formation, also
referred to as gravel packing. Although numerous details and elements of the
method are not illustrated herein for the purpose of simplicity, it will be
appreciated that the flow control systems of the present application may be
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utilized. Thus, the flow control systems utilized in the example shown in FIG.
6E,
are utilized for sand control applications in order to control sand insertion
along a
horizontal segment of a production well. Each of the flow control systems is
operable to selectively divert fluid, including sand, out of the horizontal
segment
of the production well and in a direction generally transverse thereto.
[0059] For flow control systems, such as the flow control system 600,
utilized in succession, the smaller balls are utilized and cooperate with the
valve
seats of the downhole flow control system 600 than those that are utilized and
cooperate with the valve seats of the uphole flow control system 600. Thus,
the
sizes of the valve seats and valve members of the down hole flow control
system
600 differ from that of the valve seats and valve members of the uphole flow
control system 600 to facilitate selective movement of the respective sleeves.
[0060] The flow control systems may be selectively opened and closed to
facilitate the injection of fluidized sand, i.e., sand suspended in a fluid or
gel,
under pressure. The sand is diverted through the tube ports 604 of the flow
control system 600.
[0061] Utilizing the flow control systems 600, tube ports are selectively
openable and closable. Sand may be selectively diverted through the tube ports
in a sand control application, referred to as gravel packing for the control
or
reduced production of finer grain sands around the production well.
[0062] FIG. 7A through FIG. 7G show partial sectional side views of
another
example of controlling flow utilizing a flow control system 700. The flow
control
system 700 is similar to the flow control system 300 described above with
reference to FIG. 4A through FIG. 4H. In the present example, however, the
second valve member is a dart 746, rather than the second ball 446. The dart
746 cooperates with the second valve seat 742, which is sized and shaped for
the dart 746 to releasably seat on the second valve seat 742. In addition, the
portion of the tube 716 in the present example, includes only an inner
sidewall
706 and an outer sidewall 710. The first fluid channels 730 and the second
fluid
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channels 732 are defined by the shape of the inner sidewall 706 and the outer
sidewall 710.
[0063] The remaining elements are similar to those described with
reference to FIG. 4A through FIG. 411 and the description of such elements is
not
repeated herein. Those elements are referred to herein utilizing similar
reference
numerals, raised by 300 with reference to FIG. 7A through FIG. 7G for the
purpose of clarity.
[0064] In the example illustrated in FIG. 7A through FIG. 7G, the flow
control system 700 may be utilized in a production well or in an injection
well. In
FIG. 7A, the sleeve 720 is shown in the closed position in which the sleeve
ports
722 are not aligned with the tube ports 704. To move the sleeve 720 to an open
position in which the sleeve ports 722 are aligned with the tube ports 704,
for
example, to facilitate the diversion of fluid flow out of the tube ports 704,
the
releasable valve member, which in this example is the dart 746, is introduced
into the tubing string. The dart 746 enters the tube 702 and is smaller than
the
first valve seat 740 and sized and shaped to seat on the second valve seat
742.
Thus, the dart 746 passes through the first valve seat 740 and seats on the
second valve seat 742, as illustrated in FIG. 7B. Fluid, such as water, is
injected,
under pressure, into the tubing string, as illustrated in FIG. 7C. With the
dart
746 seated on the second valve seat 742, a differential pressure is created
along
the tube 702, across the dart 746 and second valve seat 742. As the pressure
differential increases, the force on the uphole side of the dart 746 and
second
valve seat 742 increases and pushes the dart 746 and second valve seat 742 in
the downhole direction. The sleeve 720 and sleeve pistons 726 are moved in the
downhole direction, thereby sliding the sleeve 720 into the open position, as
illustrated in FIG. 7C and 7D. The dart 746 is dissolved and is released from
the
second valve seat 742, facilitating fluid flow through the tube 702. With the
sleeve 720 in the open position, the sleeve ports 722 are aligned with the
tube
ports 704 to facilitate the diversion of fluid flow out of the tube ports 704.
[0065] To return the sleeve 720 to the closed position, in which the
sleeve
ports 722 are not aligned with the tube ports 704 and therefore fluid flow out
of
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PAT 104331-1
the tube ports 704 is inhibited, the first releasable valve member, which in
this
example is the first ball 744, is introduced into the tubing string. The first
ball
744 is sized to seat on the first valve seat 740, as illustrated in FIG. 7E.
Fluid,
such as water, is injected, under pressure, into the tubing string as
illustrated in
FIG. 7F. With the first ball 744 seated on the first valve seat 740, a
differential
pressure is created along the tube 702, across the first ball 744 and the
first
valve seat 740. As the pressure differential increases, the force on the
uphole
side of the first ball 744 and first valve seat 740 increases. The injected
water is
inhibited from passing the first ball 744 and the first valve seat 740 and the
water utilized to create the differential pressure, travels through the first
fluid
channels 730, applying a force at the downhole ends 734 of the pistons 726.
With sufficient pressure, the pistons 726 are forced in the uphole direction,
causing the sleeve 720 to move into the closed position, as illustrated in
FIG. 7F,
thereby moving the sleeve ports 722 out of alignment with the tube ports 704.
The pressure behind the first ball 744 and the first valve seat 740 is
reduced.
The first ball 744 is dissolved and is released from the first valve seat 740
facilitating fluid flow through the tube 702 shown in FIG. 7G.
[0066] FIG. 8A through FIG. 8D show a partial sectional side view of yet
another example of control of flow utilizing a flow control system 800. The
flow
control system 800 is similar to the flow control system 600 described above
with reference to FIG. 6A through FIG. 6D. In the present example, however,
the fluid channels 814 include first fluid channels 830, each defined by an
inner
sidewall 806 and a middle sidewall 808 of the tube 802. Each first fluid
channel
830 extends from a location downhole of the sleeve 820 and uphole of the first
valve seat 840, i.e., between the sleeve 820 and the first valve seat 840, to
a
downhole end 834 of a respective piston 826. Thus, each first fluid channel
830
provides fluid communication between the interior of the tube 802 and a
downhole end 834 of the respective piston 826. Each second fluid channel 832
is
defined by the middle sidewall 808 and an outer sidewall 810 of the tube 802
and extends from an uphole end 836 of the respective piston 826 to an inside
of
the tube 802.
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[0067] The remaining elements are similar to those described with
reference to FIG. 6A through FIG. 6D and the description of such elements is
not
repeated herein. Those elements are referred to herein utilizing similar
reference
numerals, raised by 200 with reference to FIG. 8A through FIG. 8D for the
purpose of clarity.
[0068] In the example illustrated in FIG. 8A through FIG. 8D, the flow
control system 800 may be utilized in a production well or in an injection
well. In
FIG. 8A, the sleeve 820 is shown in the closed position in which the sleeve
ports
822 are not aligned with the tube ports 804 and therefore fluid flow through
the
tube ports 804 is inhibited. To move the sleeve 820 to the open position, the
first releasable valve member, which in this example is the first ball 844 is
introduced into the tubing string. The first ball 844 is smaller than the
second
ball 846, passes through the second valve seat 842, and seats on the first
valve
seat 840, as illustrated in FIG. 8A. Fluid, such as water, is injected under
pressure, into the tubing string, as illustrated in FIG. 8B. The fluid enters
the
first fluid channels 832 and applies force to the downhole ends of the pistons
834. With sufficient pressure, the pistons 826 are forced in the uphole
direction,
causing the sleeve 820 to move into the open position, as shown in FIG. 8B in
which the sleeve ports 822 are aligned with the tube ports 804, facilitating
fluid
flow through the tube ports 804. The first ball 844 is dissolved and released
from the first valve seat 840.
[0069] To return the sleeve 820 to the closed position, a second
releasable
valve member, which is the second ball 846, is introduced into the tubing
string
846 and is sized to seat on the second valve seat 842, as illustrated in FIG.
8C.
The fluid, such as water, is injected, under pressure, into the tubing string
and
creates a pressure differential along the tube 402, across the second ball 846
and the second valve seat 842. As the pressure differential increases, the
force
on the uphole side of the second ball 846 and second valve seat 842 increases
and pushes the second ball 846, second valve seat 846, and the sleeve 820 in
the downhole direction, thus moving the sleeve 820 into the closed position,
as
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illustrated in FIG. 8D. The second ball 846 is dissolved and released from the
second valve seat 842.
[0070] Advantageously, the above-described systems may be utilized in a
method for improving steam chamber conformance in a hydrocarbon recovery
operation. In such a method, an injection well may include many fluid flow
control systems spaced apart along the injection well. Any one of the fluid
flow
control systems may be identified for opening to facilitate the flow of fluid
through the tube port of the fluid flow control system. A releasable valve
member that is sized to cooperate with the identified fluid flow control
system is
selected and introduced into the injection well for cooperating with an
associated
valve seat. Steam is then injected to create a differential pressure across
the
releasable valve member seated on the valve seat to open the fluid flow
control
system. Further steam is then injected into the hydrocarbon-bearing formation,
via the tube port and fluids care produced including hydrocarbons from the
hydrocarbon-bearing formation.
[0071] Other ones of the fluid flow control systems are also openable by
selecting an appropriately sized releasable valve member to selectively
cooperate
with an identified one of the fluid flow control systems. Thus, a second fluid
flow
control system is then openable. Similarly, a third fluid flow control system
is
openable. The releasable valve members differ in size for cooperating with a
selected one of the valve members.
[0072] Any of the valve members is also closable by selecting a
releasable
valve member sized to cooperate with the fluid flow control system identified
for
closing and introducing the selected releasable valve member into the
injection
well to cooperate with a closing valve seat of the identified fluid flow
control
system. Steam is injected to create a differential pressure across the
releasable
valve member to move the sleeve of the one fluid flow control system in a
second direction along the tube, opposite to the first direction, to thereby
close
the fluid flow control system.
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[0073]
The described embodiments are to be considered in all respects only
as illustrative and not restrictive. The scope of the claims should not be
limited
by the preferred embodiments set forth in the examples, but should be given
the
broadest interpretation consistent with the description as a whole. All
changes
that come with meaning and range of equivalency of the claims are to be
embraced within their scope.
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