CA3036738A1 - System and method for fluid flow control in a hydrocarbon recovery operation - Google Patents

Abstract

A flow control system for use in a hydrocarbon recovery operation well, includes a tube in the well for fluid flow therethrough, including a tube port in a sidewall thereof, a sleeve within the tube, moveable between a closed position in which the tube port is covered to inhibit fluid flow, and an open position in which the tube port is uncovered to facilitate fluid flow. A first valve seat in the tube cooperates with a first releasable valve member for creating differential pressure across the first releasable valve member to move the sleeve in a first direction toward the open or the closed position. A second valve seat in the tube cooperates with a second releasable valve member for creating differential pressure across the second releasable valve member to move the sleeve in an opposite direction. The first and second valve seats differ in size for selectively cooperating with the first and second releasable valve members, respectively.

Description

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, 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 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:

CA 303.6738 2019-03-13 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:

CA 303.6738 2019-03-13 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.

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.

CA 3031'6738 2019-03-13 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 CA 303.6738 2019-03-13 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.

CA 303.6738 2019-03-13

[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 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 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 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 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 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, 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 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 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 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 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.

CA 303.6738 2019-03-13

[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 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 CA 303'6738 2019-03-13 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 CA 303'6738 2019-03-13 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 CA 303'6738 2019-03-13 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 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.

CA 303'6738 2019-03-13

[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 CA 303'6738 2019-03-13 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.

CA 303'6738 2019-03-13

[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.

Claims (26)

Claims

1. A flow control system for use in a well of a hydrocarbon recovery operation, the system comprising:
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 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; and a second valve seat 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.

2. The flow control system according to claim 1, wherein a downhole one of the first valve seat and the second valve seat is sized to cooperate with a smaller one of the first releasable valve member and the second releasable valve member.

3. The flow control system according to claim 1, comprising a piston coupled to the sleeve and disposed in a piston conduit extending within sidewalls of the tube, generally parallel with the sleeve, wherein a downhole end of the piston conduit is coupled to a downhole end fluid channel that fluidly connects the downhole end of the piston conduit to an interior of the tube.

4. The flow control system according to claim 3, wherein the downhole end fluid channel fluidly connects to the interior of the tube at an uphole side of the first valve seat.

5. The flow control system according to claim 3, wherein an uphole end of the piston conduit is coupled to an uphole end fluid channel that fluidly connects the uphole end of the piston conduit to the interior of the tube.

6. The flow control system according to claim 5, wherein the downhole end fluid channel fluidly connects to the interior of the tube at one of an uphole side or downhole side of the first valve seat and the uphole end fluid channel fluidly connects to the interior of the tube at an other of the uphole side or downhole side of the first valve seat.

7. The flow control system according to claim 3, wherein the piston is coupled to the sleeve by a web.

8. The flow control system according to claim 1, wherein the second valve seat is connected to the sleeve for cooperating with the second releasable valve member to move the sleeve downhole within the tube.

9. The flow control system according to claim 1, wherein the first valve seat is connected to the tube at a location spaced from the sleeve, for cooperating with the first releasable valve member to move the sleeve uphole within the tube.

10. The flow control system according to claim 3, wherein the first valve seat is connected to the tube at a location spaced from the sleeve, for cooperating with the first releasable valve member to move the sleeve uphole within the tube.

11. The flow control system according to claim 10, wherein the downhole end fluid channel is fluidly connected to the tube at a location uphole of the first valve seat.

12. The flow control system according to claim 1, wherein the first valve seat and the second valve seat comprise ball valve seats for cooperating with the first and second releasable valve members comprising dissolvable balls.

13. The flow control system according to claim 1, wherein at least one of the first valve seat and the second valve seat comprises a dart valve seat for cooperating with a dissolvable dart.

14. A method of controlling fluid flow in a well of a hydrocarbon recovery operation, the method comprising:
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.

15. The method according to claim 14, wherein a downhole one of the first valve seat and the second valve seat is sized to selectively cooperate with a smaller one of the first releasable valve member and the second releasable valve member.

16. The method according to claim 14, wherein directing pressurized fluid down the well to create a first differential pressure comprises injecting steam into the well.

17. The method according to claim 16, wherein directing pressurized fluid down the well to create a second differential pressure comprises injecting steam into the well.

18. The method according to claim 14, wherein introducing a first releasable valve member into the well, comprises introducing a first dissolvable ball or a first dart sized to seat on the first valve seat.

19. The method according to claim 18, wherein introducing a second releasable valve member into the well, comprises introducing a second dissolvable ball or second dart sized to seat on the second valve seat.

20. The method according to claim 14, wherein one of the first differential pressure and the second differential pressure applies a force, via fluid channels in the tube walls, across a piston connected to the releasable valve member such that a high pressure side is applied on a downhole side of the piston, to move the piston in an uphole direction.

21. The method according to claim 14, comprising injecting mobilizing fluid into the well after directing pressurized fluid down the well to create a first differential pressure, and moving the sleeve in the first direction along the tube.

22. The method according to claim 21, comprising injection mobilizing fluid into the well after directing pressurized fluid down the well to create a second differential pressure, and moving the sleeve in the second direction along the tube.

23. 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:
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.

24. The method according to claim 23, comprising:
identifying a second fluid flow control system of the fluid flow control systems for opening to facilitate the flow of the fluid through the tube port of the second fluid flow control system;
selecting a second releasable valve member sized to cooperate with the second fluid flow control system;
introducing the second releasable valve member into the injection well, the second releasable valve member cooperating with a second fluid flow control system valve seat;
injecting steam into the injection well to create a second differential pressure across the second releasable valve member to move the sleeve of the second fluid flow control system in the first direction along the tube to thereby open the second fluid flow control system;
injecting further steam into the hydrocarbon-bearing formation, via the tube port of the second fluid control system; and producing fluids including at least some of the hydrocarbons from the hydrocarbon-bearing formation, wherein a size of the second releasable valve member differs from a size of the first releasable valve member for selectively cooperating with the second fluid flow control system.

25. The method according to claim 24, comprising:
identifying a third fluid flow control system of the fluid flow control systems for closing to inhibit the flow of fluid through the tube port of the third fluid flow control system;
selecting a third releasable valve member sized to cooperate with the third fluid flow control system;
introducing the third releasable valve member into the injection well, the third releasable valve member cooperating with a third valve seat of the fluid flow control system;
injecting steam into the injection well to create a third differential pressure across the third releasable valve member to move the sleeve of the third fluid flow control system in a second direction along the tube, opposite to the first direction, to thereby close the third fluid flow control system; and producing fluids including at least some of the hydrocarbons from the hydrocarbon-bearing formation, wherein a size of the third releasable valve member differs from a size of the first releasable valve member and a size of the second releasable valve member for selectively cooperating with the third fluid flow control system.

26. The method according to claim 24, comprising:
selecting a third releasable valve member sized to cooperate with the one fluid flow control system;
introducing the third releasable valve member into the injection well, the third releasable valve member cooperating with a closing valve seat of the one fluid flow control system;
injecting steam into the injection well to create a third differential pressure across the third 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 one fluid flow control system;
injecting further steam into the injection well; and producing fluids including at least some of the hydrocarbons from the hydrocarbon-bearing formation, wherein a size of the third releasable valve member differs from a size of the first releasable valve member and a size of the second releasable valve member for selectively cooperating with the closing valve seat of the second fluid flow control system.