CA2900158C - A flow control device and methods for thermal mobilization of hydrocarbons - Google Patents

Abstract

The present invention provides a flow control device that can be positioned within the injection wellbore of a SAGD wellbore pair. The flow control device regulates the distribution of steam that exits the device, from the injection wellbore, into the reservoir. The flow control device may comprise a mandrel with a flow port, a shroud, an inner sleeve and a flow diverter. The shroud is positioned about the mandrel and it defines an annular space therebetween. The inner sleeve moves between open and closed positions to regulate the fluid flow from the mandrel bore into the annular space, via the flow port. The flow diverter diverts a portion of the steam from the flow port towards one end of the mandrel. The present invention also provides methods of using the device in an injection wellbore of the SAGD wellbore pair.

Description

A FLOW CONTROL DEVICE AND METHODS FOR THERMAL MOBILIZATION OF
HYDROCARBONS
FIELD OF INVENTION:
[001] This disclosure generally relates to production of hydrocarbons. In particular, the disclosure relates to an apparatus and method for thermal mobilization of hydrocarbons.
BACKGROUND:

[002] Steam assisted gravity drainage (SAGD) delivers steam into underground geological reservoirs that contain highly viscous hydrocarbons. Heat from the steam is transferred into the reservoir for decreasing the hydrocarbons' viscosity. The heated, less viscous, hydrocarbons become mobilized and move under the influence of gravity. SAGD
utilizes paired wellbores, one wellbore for injecting the steam and the other wellbore for collecting the mobilized the hydrocarbons. The producer wellbore is positioned below the injection wellbore to collect the mobilized hydrocarbons. Typical SAGD wellbores have a vertical section that transitions into a horizontal section in a region referred to as the heel. The distance between the heel and the end of the horizontal section, which is referred to as the toe, is often many hundreds of meters long.

[003] As steam is injected into the injection wellbore, the steam moves from the surface along the vertical section of the wellbore through the heel section and towards the toe. Between the heel and toe of the injection wellbore steam may flow from the injection wellbore into the reservoir. A differential pressure between the injection wellbore pressure and the reservoir pressure is at least one factor that dictates how much of the steam will flow into the reservoir at a given point between the heel and toe. As the steam flows through the horizontal section of the injection wellbore friction causes the pressure of the steam within the injection wellbore to decrease from the heel towards the toe. The drop in pressure causes the differential pressure between the wellbore and the reservoir to decrease. Additionally, as steam flows out of the injection wellbore, there is smaller mass of steam available to flow into the reservoir towards the toe and therebetween. When steam is injected at surface at a constant pressure, the pressure differential is higher towards the heel than it is towards the toe and there is a larger mass of steam available towards the heel. The implication of which is that more steam tends to flow into the reservoir towards the heel in comparison to the toe.
This phenomenon may be referred to as uneven or unbalanced steam flow. Unbalanced steam flow can cause poor development of a steam chamber within the reservoir and even steam breakthrough towards the heel.
SUMMARY:

[004] One embodiment of the present invention provides a steam flow control device that can be positioned within the injection wellbore of a SAGD wellbore pair. The steam flow control device regulates the flow of steam from the injection wellbore into the reservoir. The flow control device comprises: a mandrel that is connectible to a tubing string and comprises:
i. an outer surface, two ends and a central bore that extends therebetween, and ii. a flow port that provides fluid communication between the central bore and the outer surface.

[005] The device also comprises:
a. a shroud that is securable in a position about the mandrel over top of the flow port, the shroud comprising at least two shoulders that each define one or more shroud flow ports, the at least two shoulders abut the outer surface of the mandrel on either side of the flow port and support the shroud above the outer surface for defining an annular space therebetween, the annular space is in fluid communication with the flow port and the shroud flow ports provide fluid communication between the annular space and outside of the shroud;
b. an inner sleeve that is positionable within the central bore, the inner sleeve is moveable between an open position and a closed position, when in the open position fluid communication between the flow port and the annular space is open, in the closed position fluid communication between the flow port and the annular space is closed; and c. a flow diverter that diverts a portion of the steam from the flow port through the annular space towards one end of the mandrel so as to divert between about 25%
to about 60% of a total steam mass at the one end of the mandrel.

[006] Another embodiment of the present invention provides a flow control device that comprises:
a. a mandrel that is connectible to a tubing string, the mandrel comprising:
i. an outer surface, two ends and a central bore that extends therebetween, and ii. a flow port that provides fluid communication between the central bore and the outer surface;
b. a shroud that is securable in a position about the mandrel over top of the flow port, the shroud comprising at least two shoulders that each define one or more shroud flow ports, the at least two shoulders abut the outer surface of the mandrel on either side of the flow port and support the shroud above the outer surface for defining an annular space therebetween, the annular space is in fluid communication with the flow port, the shroud flow ports provide fluid communication between the annular space and outside of the shroud and at least one of the shroud ports comprises a connection member for receiving a flow plug;
and c. an inner sleeve that is positionable within the central bore, the inner sleeve is moveable between an open position and a closed position, when in the open position fluid communication between the flow port and the annular space is open, in the closed position the fluid communication between the flow port and the annular space is closed.

[007] Another embodiment of the present invention provides a method of mobilizing hydrocarbons within an underground reservoir. The method comprises the steps of:
a. augmenting a cross-sectional flow area of a plurality of flow control devices so that a first portion of the plurality of flow control devices will have a greater cross-sectional flow area than a second portion;
b. providing the plurality of flow control devices within a wellbore that is positioned proximal to the underground reservoir, the first portion of the plurality of flow control devices is positioned proximal a toe section of the wellbore and the second portion of the plurality of flow control devices is positioned proximal a heel section of the wellbore;
c. actuating at least one of the plurality of flow control devices to an open position;
d. injecting steam into the plurality of flow control devices; and e. distributing the steam substantially equally among the first and second portions of the plurality of flow control devices so that the steam exits each of the open flow control devices and mobilize the viscous hydrocarbons.

[008] Another embodiment of the present invention provides another method of mobilizing hydrocarbons within an underground reservoir. This method comprises the steps of:
a. providing a plurality of flow control devices within a wellbore that is positioned proximal to the underground reservoir;
b. actuating at least one of the plurality of flow control devices to an open position;
c. injecting steam into the plurality of flow control devices;
d. diverting at least a portion of the steam towards an uphole section of each of the flow control devices; and e. distributing the steam among the plurality of flow control devices so that the steam exits each of the open flow control devices and mobilizes the viscous hydrocarbons.

[009] Controlling, or diverting, the flow of steam through the flow control device may provide at least one advantage of bi-directional steam that flows both uphole and downhole from a given flow control device. The bi-directional steam flow may provide a more even distribution of steam between the heel and toe of an injection wellbore.

[0010] The present invention also provides the ability to change the cross-sectional flow area by which steam flows through the flow control device into the reservoir. In one embodiment, flow ports within the flow control device can be blocked or unblocked to change the cross-sectional flow area through a given tool. For example, a first flow control device may be positioned towards the toe of the injection wellbore and a second flow control device may be positioned towards the heel of the injection wellbore. There may, or may not, be one or more flow control devices positioned between the first and second flow control devices. The cross-sectional flow area of the first flow control device may be greater than the cross-sectional flow area of the second flow control device. The different cross-sectional flow areas between the two flow control devices may be achieved by blocking more flow ports in the second flow control device in comparison to the first flow control device. Without being bound by any particular theory, decreasing the cross-sectional flow area in a flow control device that is positioned towards the heel of the injection wellbore may address uneven steam flow between the heel and toe of the injection wellbore.

[0011] The present invention may also address uneven steam flow that can occur within an individual flow control device by providing a flow diverter that diverts a portion of steam to exit one end of the flow control device rather than the downhole end. In one embodiment, the annular space of the flow control device includes flow resistance features that increase the resistance to flow through the downhole portion of the annular space. In another embodiment, the cross-sectional area of the uphole section of the annular space is greater than the downhole section of the annular space. The greater cross-section area may provide a path of lower resistance than the smaller cross-sectional area and, therefore, a greater mass of steam may flow through the uphole section of the annular space. The diversion of steam to exit the uphole end of the flow control device may provide a greater balance of steam flow through the flow control device, which without this balance one would expect the majority of steam to follow the path of least resistance and flow out the downhole end of the flow control device. Diverting a portion of the steam to exit the uphole end of an individual flow control device may also improve the distribution of steam injection into the reservoir between multiple flow control devices.
BRIEF DESCRIPTION OF DRAWINGS:

[0012] Various examples of the apparatus are described in detail below, with reference to the accompanying drawings. The drawings may not be to scale and some features or elements of the depicted examples may purposely be embellished for clarity. Similar reference numbers within the drawings refer to similar or identical elements. The drawings are provided only as examples and, therefore, the drawings should be considered illustrative of the present invention and its various aspects, embodiments and options. The drawings should not be considered limiting or restrictive as to the scope of the invention.

[0013] Figure 1 is schematic representation of a steam assisted gravity drainage thermal mobilization system positioned within an underground hydrocarbon reservoir.

[0014] Figure 2 is an isometric view of one embodiment of a steam injection apparatus for use with the system of Figure 1.

[0015] Figure 3 is a cross-sectional view of the steam injection apparatus in Figure 2 taken along line 3-3 in Figure 2.

[0016] Figure 4 is a mid-line cross-sectional view of the steam injection apparatus in Figure 2 taken along line 4-4 in Figure 3 with the apparatus depicted in a closed position.

[0017] Figure 5 is a cross-sectional view of the steam injection apparatus in Figure 2 taken along line 4-4 in Figure 3 with the apparatus depicted in an open position.

[0018] Figure 6 is a cross-sectional view of another embodiment of a steam injection apparatus for use with the system of Figure 1.

[0019] Figure 7 is a mid-line cross-sectional view of one embodiment of an inner sleeve for use with the apparatus of Figure 2 and Figure 6.

[0020] Figure 8 is a cross-sectional view of the inner sleeve in Figure 7 taken along line 8-8 in Figure 7.

[0021] Figure 9 is a cross-sectional view of the inner sleeve in Figure 7 taken along line 9-9 in Figure 7.

[0022] Figure 10 is a cross-sectional view of the inner sleeve in Figure 7 taken along line 10-10 in Figure 7.

[0023] Figure 11 is a magnified view of the area outlined by line 11 in Figure 7.
DETAILED DESCRIPTION:

[0024] Figure 1 is a schematic representation of a typical steam assisted gravity drainage (SAGD) system 100. The system comprises paired wellbores that are referred to as an injection wellbore 3 and a production wellbore 4. The paired wellbores 3, 4 extend from surface 1 close to, or into, an underground hydrocarbon reservoir 2. While Figure 1 depicts the paired wellbores 3, 4 as having both vertical and horizontal sections, the system 100 may be useful in a vertical-only wellbore.

[0025] The production wellbore 4 comprises a section of surface casing 4A, a section of production casing 4B, a production tubing string 4C and a production liner 7.
The casings 4A, 4B
may be cemented against the open hole of the production wellbore 4, or not.
The production liner 7 is supported by a production liner hanger 7A at a downhole end of the production casing 4B. Typically, the production liner 7 is not cemented and it resides in a portion of the production wellbore 4 that is open to the surrounding reservoir 2. The production liner 7 may comprise sand control means, such as metal wool, wire wrapped screen or slotted liners. The production well 4 may also comprise an artificial lift system, such as a submersible pump or gas lift system.

[0026] The injection wellbore 3 comprises a section of surface casing 3A, a section of injection casing 3B, an injection tubing string 3C and an injection liner 6. The surface casing 3A and the injection casing 3B may be cemented against the open hole of the injection wellbore 3, or not.
While depicted in Figure 1 as a single string of tubulars, in other embodiments the injection tubing string 3C may comprise more than one sting of injection tubulars. For example, the injection tubing string 3C may comprise a short injection string that terminates proximal to the heel and a long injection string that terminates proximal to the toe. The injection liner 6 is supported by an injection liner hanger 6A at a downhole end of the injection casing 38.
Typically the injection liner 6 is not cemented and it resides in a portion of the injection wellbore 3 that is open to the surrounding reservoir 2. The injection liner 6 may also comprise sand control means, such as metal wool, wire wrapped screen or slotted liners.

[0027] Figure 1, which is not intended to be limiting, depicts a plurality of flow control devices 10A, B, C, D that are positioned on the injection tubing string 3C. A flow control device 10 may also be referred to as a steam injection device and a steam splitter. While four flow control devices 10 are depicted, the injection wellbore 3 may comprise one or more individual flow control devices 10. The number of flow control devices 10 utilized may be dictated by a variety of factors, such as the length of the injection liner 6 and the amount of steam that is desired to be injected into the reservoir 2. As indicated by the downwardly facing arrows in Figure 1, steam is introduced into the injection tubing string 3C at the surface 1. The steam travels down the injection tubing string 3C it exits the injection wellbore 3, into the reservoir 2, by one or more of the flow control devices 10. In an alternative embodiment, the flow control devices 10 may comprise part of the injection liner 6 and the injection tubing 3C may not be used or, if used, the injection tubing 3C may not extend past the downhole end of the injection casing 3B.
In this alternative embodiment, centralizers and inflatable packers may also be incorporated into the injection liner 6 to centralize the injection liner 6 and the one or more flow control devices 10 within the open section of the injection wellbore 3. Centralizers and inflatable packers may facilitate a more even distribution of steam within the open section of the injection wellbore 3. Other embodiments where the flow control device 10 is incorporated into the injection tubing string 3C may also include centralizers and inflatables to isolate zones of an annular space between the injection tubing string 3C and the injection liner 6.

[0028] Injection of steam into the reservoir 2 creates a steam chamber 8 where the hot steam condenses into water and heats the reservoir 2. The hydrocarbons within the reservoir are typically highly viscous, such as bitumen, which may be trapped within sand, clay or sandstone.
The heat from the steam increases the hydrocarbons' mobility and produces a fluid mass that is a combination of steam, water, sand and oil. The fluid mass flows under gravity towards and into the production liner 7. The sand control means of the production liner 7 filter out some or all of the sand. The artificial lift system within the production wellbore 4 directs the filtered fluid mass up the production tubing string 4C to the surface 1.

[0029] Figures 2 and 3 depict one embodiment of the flow control device 10.
The apparatus 10 comprises a mandrel/shroud assembly 12 and an inner sleeve 18. The mandrel/shroud assembly 12 comprises a mandrel 14 and a shroud 16 that is positioned about the mandrel 14.
The apparatus 10 also comprises an inner sleeve 18 that is positionable within a central bore 110 of the mandrel 14.

[0030] Figure 4, which is not intended to be limiting, depicts the mandrel 14 as comprising an uphole end 14A and a downhole end 1413 both of which include threaded connections for threadably connecting the mandrel 14 to the injection tubing string 3C. The terms "uphole"
and "downhole" are used as a reference to a direction within a wellbore for both vertical and horizontal sections of the wellbore. Uphole refers to a direction towards surface and downhole refers to direction away from surface.

[0031] In one embodiment, the threaded connections are specifically designed to maintain a threaded connection in spite of being subjected to the high temperatures associated with the steam that flows through the injection tubing string 3C and the device 10. The threaded connections may be a box connection at the uphole end 14A and a pin connection at the downhole end 14B, or vice versa. Alternatively, both of the ends 14A, 14B may be pin connections that are threadably connected to the injection tubing string 3C by a coupling 20, such as a box-by-pin arrangement.

[0032] The mandrel 14 has an inner surface 14C and an outer surface 14D. The inner surface 14C defines an inner diameter of the mandrel 14 and the central bore 110 that extends between the two ends 14A, 14B. The central bore 110 is in fluid communication with a bore of the injection tubing string 3C for receiving steam that is delivered to the device 10 from the surface 1 via the injection tubing 3C. Fluids, including steam, can flow through the central bore 110 from the uphole end 14A towards the downhole end 14B, as indicated by line X in Figure 4.

[0033] The inner surface 14C also defines an uphole inner mandrel shoulder 26A
and a downhole inner mandrel shoulder 26B. The shoulders 26A, 26B extend away from the inner surface 14C into the central bore 110. The shoulders 26A, 26B may act as a stop feature for preventing displacement of the inner sleeve 18 past the shoulders 26A, 26B.

[0034] The outer surface 14D of the mandrel 14 defines an uphole outer mandrel shoulder 28A
and an uphole mandrel shoulder 28B. The shoulders 28A, 28B extend away from the outer surface 14D. The shoulders 28A, 28B may act as a bearing surface for a portion of the shroud 16.

[0035] The mandrel 14 has one or more mandrel flow ports 24 that extend between the inner surface 14C and the outer surface 14D to provide fluid communication between the central bore 110 and outside of the mandrel 14. The mandrel flow ports 24 are positioned between the shoulders 26A, 26B. The number of mandrel flow ports 24 may differ between 1 and about 10. In a preferred embodiment, the mandrel 14 has six mandrel flow ports 24 that are radially and evenly spaced apart about the mandrel 14.

[0036] The shroud 16 is positioned about the outer surface 14D of the mandrel 14 in top of and ' covering the mandrel flow ports 24. In one embodiment the shroud 16 comprises two sections, an uphole section 16A and a downhole section 16B. The two sections 16A, 16B
may be joined together, optionally in an overlapping fashion, to form the shroud 16.
Alternatively, the shroud 16 may be monolithic.

[0037] The shroud 16 also comprises an uphole internal shoulder 40A and a downhole internal shoulder 40B. In one embodiment, the internal shoulders 40A, B extend about the inner diameter of the shroud 16 and away from the inner surface 16C of the shroud 16. The height of the internal shoulders 40A, B space the inner surface 16C of the shroud 16 from the outer surface 14D of the mandrel 14 for defining an annular space 36 between the mandrel 14 and the shroud 16. The internal shoulders 40A, B abut the outer surface 14D of the mandrel 14 and the outer mandrel shoulders 28A, B, respectively. The annular space 36 is in fluid communication with the mandrel flow ports 24. The mandrel flow ports 24 may establish a divide of the annular space 36 between an uphole section 36A and a downhole section 36B.

[0038] The internal shoulders 40A, B comprise a plurality of shroud flow ports 42 that provide fluid communication between the annular space 36 and outside of the shroud 16.
In some embodiments of the shroud 16, the internal shoulders 40A, B may define between 1 and about 60 shroud flow ports 42. Figure 3 depicts a preferred embodiment of the shroud 16 with 32 shroud flow ports 42 that are radially and evenly spaced about the internal shoulders 40A, B.

[0039] In another embodiment of the shroud 16, one or more of the shroud flow ports 42 includes a connection member 44 for receiving and securing a flow plug 45 (see line Win Figure 3). For example, the connection member 44 may be one half of a threaded connection with the other half provided on the flow plug 45 so that the flow plug 45 can be threadably connected to the shroud 16 and prevent fluid communication through a given shroud flow port 42. As will be appreciated by one skilled in the art, other types of connection members 45 may be utilized to allow the flow plug 45 to be received and secured within a shroud flow port 42 in spite of the pressure and temperatures associated with steam injection through the flow control device 10.
In one embodiment of the shroud 16, each shroud flow port 42 comprises a connection member 44.

[0040] The inner sleeve 18 is positionable within the central bore 110 of the mandrel 14. The inner sleeve 18 has an uphole end 18A, a downhole end 18B and a sleeve bore 118 that extends therebetween. The sleeve bore 118 is in fluid communication with the central bore 110 of the mandrel 14. The inner sleeve 18 has an inner surface 18C and an outer surface 18D. The inner sleeve 18 may be positioned within the central bore 110 of the mandrel 14 with the outer surface 18D of the inner sleeve 18 adjacent the inner surface 14C of the mandrel 14. The inner sleeve 18 is dimensioned to be slidable between the inner mandrel shoulders 26A, B.

[0041] The inner sleeve 18 can slide between a closed position and an open position. In the closed position, the inner sleeve 18 blocks the mandrel flow ports 24 and prevents fluid communication from the central bore 110 to the annular space 36. In the open position, the inner sleeve 18 permits fluid communication between the central bore 110 and the annular space 36. For example, the inner sleeve 18 may slide to a position between the inner mandrel shoulders 26A, B where the mandrel flow ports 24 are no longer blocked.

[0042] In one embodiment of the flow control device 10, the inner sleeve 18 comprise one or more sleeve flow ports 48 that extend between the inner surface 18C and the outer surface 18D (see Figure 7). In this embodiment, when the inner sleeve 18 is in the open position, one or more sleeve flow ports 48 are substantially aligned with one or more mandrel flow ports 24.
This alignment permits fluid communication between the sleeve bore 118 and the annular chamber 36 via the sleeve flow ports 48 and the mandrel flow ports 24.

[0043] The inner surface 18C of the inner sleeve 18 may define an uphole shoulder 54A and a downhole shoulder 54B. The shoulders 54A, B extend around the inner diameter of the inner sleeve 18 and away from the inner surface 18C. The shoulders 54A, B may comprise a shaped profile that receives and releasably engages a shifting tool (not shown) that is actuated for moving the inner sleeve 18 between the open and closed positions. In one embodiment, the profile of the shoulders 54A, B may receive and engage an OTIS B shifting tool; however, other shifting tools may also be useful. In another embodiment of the inner sleeve 18, other mechanisms may be used to move the inner sleeve 18 between the open and closed positions.
Such other mechanisms may include, but are not limited to: balls, darts, augmenting the pressure within the injection wellbore 3 to actuate one or more hydraulic pistons that are coupled to the inner sleeve 18 or combinations thereof.

[0044] Another embodiment of the flow control device 10 comprises an alignment means for reducing or preventing rotation of the inner sleeve 18 within the mandrel 14.
Without intending to be limiting, one example of the alignment means comprises an alignment slot A
that is defined by the outer surface of the inner sleeve 18 and an alignment key 46B that extends from the inner surface 14C of the mandrel 14. The alignment key 46B is sized to fit within the alignment slot 46 to reduce or prevent rotation of the inner sleeve 18 within the mandrel 14. In another embodiment of the flow control device 10, the alignment slot 46A is defined by the inner surface 14C of the mandrel 14 and the alignment key 46B
extends from the outer surface 18D of the inner sleeve 18. The alignment means may be or comprise other anti-rotational mechanisms, as will be appreciated by those skilled in the art. Reducing or preventing rotation of the inner sleeve 18 relative to the mandrel 14 may help the substantial alignment of the sleeve flow ports 48 with the mandrel flow ports 24 when the inner sleeve 18 is moved to the open position.

[0045] Another embodiment of the flow control device 10 comprises a retaining means for retaining the inner sleeve 18 in either the open position or the closed position. The retaining means may be positioned towards either the uphole end 18A (see Figures 4, 5 or 6) or the downhole end 18B (see Figure 7) of the inner sleeve 18. The retaining means may comprise a protruding member 50, at least two retaining slots 51A, B and a deformable portion 52. Figure 7, which is not intended to be limiting, depicts the protruding member 50 extending away from the outer surface 18D of the inner sleeve 18 towards the inner surface 14C of the mandrel 14 where the at least two retaining slots 51A, B are located. The at least two retaining slots 51A, B
may be longitudinally positioned to hold the inner sleeve 18 in the closed position or the open position. Due to the tight tolerance between the inner sleeve 18 and the mandrel 14, the deformable portion 52 may deform slightly to accommodate moving the protruding member 50 between the two retaining slots 51A, B. In one embodiment, the deformable portion 52 may comprise a series of cut outs or slots 52'. The removal of material to create the slots 52' decreases the overall rigidity of the inner sleeve 18 material that remains between where the slots 52'are positioned. The slots 52' impart some flexibility in the section of the inner sleeve 18 where the deformable portion 52 is positioned, which allows inner sleeve 18 to, for example, deflect inwardly and accommodate the protruding member 50 when the inner sleeve 18 is moving between the open and closed positions.

[0046] In the embodiment depicted in Figure 10 the protruding member 50 may be a series of individual protruding members 50, each with an associated retaining slot 51A, B (see Figures 4, 5) on the mandrel 14. In this embodiment, each individual protruding member 50 may be positioned between two slots 52' of the deformable portion 52.

[0047] In one embodiment, the flow control device 10 comprises one or more sealing members 59 that are positioned between the outer surface 18D of the inner sleeve 18 and the inner surface 14C of the mandrel 14. In the embodiment depicted in Figures 4, 5 and 6, the sealing members 59 are positioned within glands that are defined on the inner surface 14C of the mandrel 14. The sealing members 59 may be positioned on either side of the flow ports 24 to direct the flow of fluids from the inner sleeve's conduit 118 through the flow ports 24 into the annular space 36. In one embodiment, the sealing members 59 may be o-rings or other types of seals that are suitable, as will be appreciated by one skilled in the art.

[0048] In other embodiments of the flow control device 10, the retaining means may be or comprise other mechanisms than those described above, as will be appreciated by those skilled in the art.

[0049] Another embodiment of the flow control device 10 comprises a flow diverter 33 that diverts steam from the mandrel flow port 24towards either of the uphole section 36A or the downhole section 36B of the annular space 36. In one embodiment, the outer surface 14D of the mandrel 14 includes the flow diverter 33 as a resistance feature 34 that is positioned within the annular space 36. The flow resistance feature 34 increases a resistance to fluid flow through the annular space 36. The flow resistance feature 34 may comprise a series of protrusions that extend into the annular space 36 and increase friction within the annular space 36. The protrusions may be formed by a series of lathe cuts in the outer surface 14D, the addition of material to the outer surface 36, for example by spot welding, or combinations thereof. The protrusions can be implemented with a specific number, pitch and height above the outer surface 14D to provide a desired friction factor within the annular space 36.
Providing the desired friction factor within the annular space 36 may provide enough flow resistance to influence how much steam flows through either or both of the sections of the annular space 36A, B. For example, providing the flow resistance feature 34 within the downhole section 36B (as depicted in Figure 4) may increase the percentage of the total of amount of steam that passes through the mandrel flow ports 24 to flow into the uphole section 36A and out the shroud flow ports 42 on the uphole end 16A of the shroud 16.
Alternatively, providing the flow resistance feature 34 in the uphole portion 36A may increase the fraction of steam that flows out the shroud flow ports 42 at the downhole end 16B of the shroud 16.

[0050] In another embodiment of the flow control device 10, the flow diverter 33 may be an inner shroud shoulder 38 that causes a cross-sectional area of the annular space 36 to be different between the uphole section 36A and the downhole section 36B. For example, the inner shroud shoulder 38 may form part of the inner surface 16C of the shroud 16 and the inner shroud shoulder 38 extends into the annular space 36 (See Figures 5 and 6).
The inner shroud shoulder 38 may form part of the uphole section 16A of the shroud 16, whether the shroud 16 is a multi-pieced construction or a monolithic construction. The inner shroud shoulder 38 may cause a restriction, or narrowing, of the annular space 36. In the embodiments depicted in Figures 4, 5 and 6, the uphole section 36A of the annular space 36 has a larger cross-sectional area than the downhole annular space 36B. The differential cross-sectional area may decrease the available flow area in the downhole section 36B, which may causes at least a portion of the steam from the mandrel flow port 24 to be diverted through to the uphole section 36A. In the embodiment depicted in Figures 4 and 5, the inner shroud shoulder 38 is positioned uphole of the mandrel flow ports 24. In an alternative embodiment, depicted in Figure 10, the inner shroud shoulder 38 may be positioned over top of the mandrel flow ports 24.
Without being bound by theory, the greater cross-section area may also provide a path of lower resistance than the smaller cross-sectional area. The larger cross-sectional area of the uphole section 36A

will receive a greater mass of steam in comparison to the downhole section 36B. The diversion of steam to exit the uphole end 16A of the shroud 16 may provide a greater balance of steam flow through the flow control device 10. Without this balance, one would expect the majority of steam to follow the path of least resistance and flow out the downhole end 16B of the shroud 16. Diverting a portion of the steam to exit the uphole end of an individual flow control device 10 may improve the distribution of injected steam into the reservoir 2 between multiple flow control devices. =

[0051] In one embodiment of the device 10, the outer surface 14D of the mandrel 14 may further include one or more steam deflectors 30 (see Figure 4). The steam deflectors 30 are protrusions that extend away from the outer surface 14D for deflecting steam that exits the shroud ports 42 away from collars or other features that may be part of the device 10 or the injection tubing string 3C that otherwise would be exposed to the steam and subject to erosion caused by the steam as it exits the flow control device 10.

[0052] The flow control device 10 can be made of a metal or metal alloy that is suitable for the high temperatures and pressures associated with a downhole SAGD injection wellbore. For example, ASTM A193 steel, 4140 steel alloy and P110 steel alloy may be suitable. However, certain regions of the flow control device 10 may be susceptible to erosion due to the angle that the high pressure, high temperature steam strikes that susceptible region. The steam may contain liquid droplets, debris and other contaminants that can exacerbate the erosion of the susceptible regions. Some of the susceptible regions include regions that are in a plane that is orthogonal to the direction of steam flow within the flow control device 10 and other regions of the flow control device 10 that cause large drops in pressure or flow of the steam. These regions may include any flow restrictions, bends or elbows. For example, at least a portion of the inner surface 18C of the shroud 16 that is directly opposite to the mandrel flow ports 24 and the portions of the internal shroud shoulders 40A, B that define the shroud flow ports 42 are susceptible regions. Other susceptible regions may include a 90 degree flow elbow where the mandrel flow port 25 is adjacent the annular space 36, the outer surface 14D of the mandrel 14 within the annular space 36, the inner shroud shoulder 38, the connection member 44 and the connections between the injection tubing string 3C and the flow control device 10.
In one embodiment of the flow control device 10, the susceptible regions are coated with an erosion mitigating coating 60 to protect the material that the flow control device 10 is made of and for prolonging the working life of the flow control device 10. The erosion mitigating coating 66 has a resistance to erosion that is many times greater than steel, for example, the erosion mitigating coating 60 may comprise tungsten carbide, boron carbide or combinations 'thereof. For clarity, Figure 6 depicts the erosion mitigating coating 60 as coating one region of the inner surface 16C of the shroud 16. As will be appreciated by the skilled person, the flow control device 10 may comprise other susceptible regions that are coated with the erosion mitigating coating 60

[0053] In use, the flow control device 10 may be included in a SAGD system for mobilizing viscous hydrocarbons from the reservoir 2. In particular, the flow control device 10 may be threadably connected to the injection tubing string 3C and deployed within a horizontal section of the injection wellbore 3. In one embodiment, one or more flow control device 10 may be deployed as part of the injection tubing string 3C.

[0054] The one or more flow control devices 10 may be actuated between an open position and a closed position by a shifting tool. For example, the shifting tool may engage the inner sleeve 18 of each of the one or more flow control devices 10 and move the inner sleeve 18 to the open position and allow fluid communication between the central bore 110 and the annular space 36. Following which, steam may be injected into the injection tubing string 3C, and the steam will be distributed substantially equally between the all of the open flow control devices 10.

[0055] In one embodiment, a warming phase may occur either before or after the one or more devices 10 are actuated into the open position. During the warming phase, steam is injected down the injection tubing 3C in order to pre-heat the reservoir 2 in preparation for the step that distributes steam between the open flow control devices 10.

[0056] In one embodiment, the cross-sectional flow area of each flow control device 10 may be augmented, either increased or decreased, to provide an desired distribution of steam to the flow control devices 10 that are positioned closer to the toe of the injection wellbore, in comparison to flow control devices 10 that are positioned closer to the injection wellbore's heel. The cross-sectional flow area may be augmented, at least in part, based upon a desired and pre-calculated difference in pressure between the central bore 110 and the reservoir 2 at each flow control device 10 in the SAG D system. In one embodiment, the cross-sectional flow area of the flow control devices 10 that are closer to the heel of the injection wellbore 3 is decreased to be lower than the cross-sectional flow area of the flow control devices 10 that are closer to the injection wellbore's toe. This step of augmenting may direct a greater mass of steam to the flow control devices 10 that are closer to the injection wellbore's toe, relative to those devices 10 that are closer to the injection wellbore's heel.

[0057] In another embodiment, each flow control device 10 may be subjected to a further step of diverting at least a portion of the mass of steam towards the uphole section 36A of the annular space 36. In one embodiment, the uphole section 36A receives between about 25 and 60% of the total mass of steam that enters the annular space 36 of a given flow control device 10. The downhole section 36B receives the remainder of the steam mass. In another embodiment, the uphole section 36B receives between about 40 and 50% of the total mass of steam. The steam within the annular space 36 will exit the flow control device 10 and the =
majority of that exited steam which will enter the reservoir 2 to contribute towards mobilizing the viscous hydrocarbons within the reservoir 2.

[0058] While the above disclosure describes certain examples of the present invention, various modifications to the described examples will also be apparent to those skilled in the art. The scope of the claims should not be limited by the examples provided above;
rather, the scope of the claims should be given the broadest interpretation that is consistent with the disclosure as a whole.

Claims (4)

What is claimed is:

1. A flow control device comprising:
a. a mandrel that is connectible to a tubing string, the mandrel comprising:
i. an outer surface, two ends and a central bore that extends therebetween, and ii. a flow port that provides fluid communication between the central bore and the outer surface;
b. a shroud that is securable in a position about the mandrel over top of the flow port, the shroud comprising at least two shoulders that each define one or more shroud flow ports, the at least two shoulders abut the outer surface of the mandrel on either side of the flow port and support the shroud above the outer surface for defining an annular space therebetween, the annular space is in fluid communication with the flow port and the shroud flow ports provide fluid communication between the annular space and outside of the shroud;
c. an inner sleeve that is positionable within the central bore, the inner sleeve is moveable between an open position and a closed position, when in the open position fluid communication between the flow port and the annular space is open, in the closed position fluid communication between the flow port and the annular space is closed; and d. a flow diverter that diverts a portion of steam received from the flow port through the annular space towards one end of the mandrel so as to divert between about 25%
to about 60% of a total steam mass at the one end of the mandrel.

2. A flow control device comprising:
a. a mandrel that is connectible to a tubing string, the mandrel comprising:
i. an outer surface, two ends and a central bore that extends therebetween, and REPLACEIVIENT SHEET
Date recue / Date received 2021-12-03 ii. a flow port that provides fluid communication between the central bore and the outer surface;
b. a shroud that is securable in a position about the mandrel over top of the flow port, the shroud comprising at least two shoulders that each define one or more shroud flow ports, the at least two shoulders abut the outer surface of the mandrel on either side of the flow port and support the shroud above the outer surface for defining an annular space therebetween, the annular space is in fluid communication with the flow port, the shroud flow ports provide fluid communication between the annular space and outside of the shroud and the shroud ports comprise a connection member for receiving a flow plug; and c. an inner sleeve that is positionable within the central bore, the inner sleeve is moveable between an open position and a closed position, when in the open position fluid communication between the flow port and the annular space is open, in the closed position the fluid communication between the flow port and the annular space is closed.

3. A method of mobilizing hydrocarbons within an underground reservoir, the method comprising steps of:
a. augmenting a cross-sectional flow area of a plurality of flow control devices so that a first portion of the plurality of flow control devices will have a greater cross-sectional flow area than a second portion;
b. providing the plurality of flow control devices within a wellbore that is positioned proximal to the underground reservoir, the first portion of the plurality of flow control devices is positioned proximal a toe section of the well bore and the second portion of the plurality of flow control devices is positioned proximal a heel section of the wellbore;
c. actuating at least one of the plurality of flow control devices to an open position;
d. injecting steam into the plurality of flow control devices; and REPLACEIVIENT SHEET
Date recue / Date received 2021-12-03 e. distributing the steam substantially equally among the first and second portions of the plurality of flow control devices so that the steam exits each of the open flow control devices and mobilize the viscous hydrocarbons.

4. A method of mobilizing hydrocarbons within an underground reservoir, the method comprising steps of:
a. providing a plurality of flow control devices within a wellbore that is positioned proximal to the underground reservoir;
b. actuating at least one of the plurality of flow control devices to an open position;
c. injecting steam into the plurality of flow control devices;
d. diverting at least a portion of the steam towards an uphole section of at least one of each of the plurality flow control devices; and e. distributing the steam among the plurality of flow control devices so that the steam exits each of the open flow control devices and mobilizes the viscous hydrocarbons.

REPLACEIVIENT SHEET
Date recue / Date received 2021-12-03