FIELD

[0001] The present disclosure relates to mitigating downhole pump gas interference, and the adverse effects of solid particulate matter entrainment, during hydrocarbon production.

BACKGROUND

[0002] Downhole pump gas interference is a problem encountered while producing wells, especially wells with horizontal sections. In producing reservoir fluids containing a significant fraction of gaseous material, the presence of such gaseous material hinders production by contributing to sluggish flow. Additionally, solid particulate material is entrained in reservoir fluids, and such solid particulate matter can adversely affect production operations.

BRIEF DESCRIPTION OF DRAWINGS

[0003] The preferred embodiments will now be described with reference to the following accompanying drawings:

[0004] Figure 1 is a schematic illustration of an embodiment of a system of the present disclosure;

[0005] Figure 2 is a schematic illustration of another embodiment of a system of the present disclosure;

[0006] Figure 3 is a sectional view of a pump intake of an embodiment of a system of the present disclosure;

[0007] Figure 4 is a perspective view of the pump intake illustrated in Figure 3;

[0008] Figure 5 is a perspective view of the pump intake illustrated in Figure 3 to which a clamp is connected; [0009] Figure 6 is a sectional view of the assembly illustrated in Figure 5;

[0010] Figure 7 is a perspective view of one of the two clamp sections of the clamp illustrated in Figures 5 and 6;

[0011] Figure 8 is a perspective view of the other one of the clamp sections of the clamp illustrated in Figures 5 and 6;

[0012] Figure 9 is a sectional view of a portion of a pump assembly, fluidly coupled to a gas- depleted reservoir fluid-producing conductor, disposed within a shroud of an embodiment of a system of the present disclosure;

[0013] Figure 10 is a section view of a first one of a series of connected shroud segments that form the shroud illustrated in Figure 9;

[0014] Figure 11 is a section view of an intermediate one of a series of connected shroud segments that form the shroud illustrated in Figure 10;

[0015] Figure 12 is a section view of a last one of a series of connected shroud segments that form the shroud illustrated in Figure 10;

[0016] Figure 13 is a section view of a retention ring of the shroud illustrated in Figure 10, with set screws extending radially inwards;

[0017] Figure 14 is a plan view of the retention ring illustrated in Figure 13, with set screws extending radially inwards;

[0018] Figure 15 is a side view of another embodiments of the pump motor, the seal section, the shroud and a portion of the gas-depleted reservoir fluid-producing conductor of the system of Figure 1;

[0019] Figure 16 is a side view of the assembly illustrated in Figure 15;

[0020] Figure 17 is a side view of assembly illustrated in Figure 16, with the shroud having been removed; [0021] Figure 18 is a sectional view taken along lines A-A in Figure 16; and

[0022] Figure 19 is an assembly of reinforcement members insertable within the shroud of the system of Figure 1.

PET ATT, ED DESCRIPTION

[0023] As used herein, the terms “up”, “upward”, “upper”, or “uphole”, mean, relativistically, in closer proximity to the surface 106 and further away from the bottom of the wellbore, when measured along the longitudinal axis of the wellbore 102. The terms“down”, “downward”,“lower”, or“downhole” mean, relativistically, further away from the surface 106 and in closer proximity to the bottom of the wellbore 102, when measured along the longitudinal axis of the wellbore 102.

[0024] Referring to Figures 1 and 2, there are provided systems 8, with associated apparatuses, for producing hydrocarbons from a reservoir, such as an oil reservoir, within a subterranean formation 100, when reservoir pressure within the oil reservoir is insufficient to conduct hydrocarbons to the surface 106 through a wellbore 102.

[0025] The wellbore 102 can be straight, curved, or branched. The wellbore 102 can have various wellbore sections. A wellbore section is an axial length of a wellbore 102. A wellbore section can be characterized as“vertical” or“horizontal” even though the actual axial orientation can vary from true vertical or true horizontal, and even though the axial path can tend to “corkscrew” or otherwise vary. In some embodiments, for example, the central longitudinal axis of the passage 102CC of a horizontal section 102C is disposed along an axis that is between about 70 and about 110 degrees relative to the vertical“V”, the central longitudinal axis of the passage 102AA of a vertical section 102A is disposed along an axis that is less than about 20 degrees from the vertical“V”, and a transition section 102B is disposed between the sections 102 A and 102C. In some embodiments, for example, the transition section 102B joins the sections 102A and 102C. In some embodiments, for example, the vertical section 102A extends from the transition section 102B to the surface 106. [0026] “Reservoir fluid” is fluid that is contained within an oil reservoir. Reservoir fluid may be liquid material, gaseous material, or a mixture of liquid material and gaseous material. In some embodiments, for example, the reservoir fluid includes water and hydrocarbons, such as oil, natural gas condensates, or any combination thereof.

[0027] Fluids may be injected into the oil reservoir through the wellbore to effect stimulation of the reservoir fluid. For example, such fluid injection is effected during hydraulic fracturing, water flooding, water disposal, gas floods, gas disposal (including carbon dioxide sequestration), steam-assisted gravity drainage (“SAGD”) or cyclic steam stimulation (“CSS”). In some embodiments, for example, the same wellbore is utilized for both stimulation and production operations, such as for hydraulically fractured formations or for formations subjected to CSS. In some embodiments, for example, different wellbores are used, such as for formations subjected to SAGD, or formations subjected to waterflooding.

[0028] A wellbore string 113 is employed within the wellbore 102 for stabilizing the subterranean formation 100. In some embodiments, for example, the wellbore string 113 also contributes to effecting fluidic isolation of one zone within the subterranean formation 100 from another zone within the subterranean formation 100.

[0029] The fluid productive portion of the wellbore 102 may be completed either as a cased- hole completion or an open-hole completion.

[0030] A cased-hole completion involves running wellbore casing down into the wellbore through the production zone. In this respect, in the cased-hole completion, the wellbore string 113 includes wellbore casing.

[0031] The annular region between the deployed wellbore casing and the oil reservoir may be filled with cement for effecting zonal isolation (see below). The cement is disposed between the wellbore casing and the oil reservoir for the purpose of effecting isolation, or substantial isolation, of one or more zones of the oil reservoir from fluids disposed in another zone of the oil reservoir. Such fluids include reservoir fluid being produced from another zone of the oil reservoir (in some embodiments, for example, such reservoir fluid being flowed through a production tubing string disposed within and extending through the wellbore casing to the surface), or injected fluids such as water, gas (including carbon dioxide), or stimulations fluids such as fracturing fluid or acid. In this respect, in some embodiments, for example, the cement is provided for effecting sealing, or substantial sealing, of flow communication between one or more zones of the oil reservoir and one or more others zones of the oil reservoir (for example, such as a zone that is being produced). By effecting the sealing, or substantial sealing, of such flow communication, isolation, or substantial isolation, of one or more zones of the oil reservoir, from another subterranean zone (such as a producing formation), is achieved. Such isolation or substantial isolation is desirable, for example, for mitigating contamination of a water table within the oil reservoir by the reservoir fluid (e.g. oil, gas, salt water, or combinations thereof) being produced, or the above-described injected fluids.

[0032] In some embodiments, for example, the cement is disposed as a sheath within an annular region between the wellbore casing and the oil reservoir. In some embodiments, for example, the cement is bonded to both of the production casing and the subterranean formation 100

[0033] In some embodiments, for example, the cement also provides one or more of the following functions: (a) strengthens and reinforces the structural integrity of the wellbore, (b) prevents, or substantially prevents, produced reservoir fluid of one zone from being diluted by water from other zones (c) mitigates corrosion of the wellbore casing, (d) at least contributes to the support of the wellbore casing, and e) allows for segmentation for stimulation and fluid inflow control purposes.

[0034] The cement is introduced to an annular region between the wellbore casing and the subterranean formation 100 after the subject wellbore casing has been run into the wellbore 102. This operation is known as“cementing”.

[0035] In some embodiments, for example, the wellbore casing includes one or more casing strings, each of which is positioned within the well bore, having one end extending from the well head. In some embodiments, for example, each casing string is defined by jointed segments of pipe. The jointed segments of pipe typically have threaded connections. [0036] Typically, a wellbore contains multiple intervals of concentric casing strings, successively deployed within the previously run casing. With the exception of a liner string, casing strings typically run back up to the surface 106. Typically, casing string sizes are intentionally minimized to minimize costs during well construction. Generally, smaller casing sizes make production and artificial lifting more challenging.

[0037] For wells that are used for producing reservoir fluid, few of these actually produce through wellbore casing. This is because producing fluids can corrode steel or form undesirable deposits (for example, scales, asphaltenes or paraffin waxes) and the larger diameter can make flow unstable. In this respect, a production string is usually installed inside the last casing string. The production string is provided to conduct reservoir fluid, received within the wellbore, to the wellhead 116. In some embodiments, for example the annular region between the last casing string and the production tubing string may be sealed at the bottom by a packer.

[0038] The wellbore 102 is disposed in flow communication (such as through perforations provided within the installed casing or liner, or by virtue of the open hole configuration of the completion), or is selectively disposable into flow communication (such as by perforating the installed casing, or by actuating a valve to effect opening of a port), with the subterranean formation 100. When disposed in flow communication with the subterranean formation 100, the wellbore 102 is disposed for receiving reservoir fluid flow from the subterranean formation 100, with effect that the system 8 receives the reservoir fluid.

[0039] In some embodiments, for example, the wellbore casing is set short of total depth. Hanging off from the bottom of the wellbore casing, with a liner hanger or packer, is a liner string. The liner string can be made from the same material as the casing string, but, unlike the casing string, the liner string does not extend back to the wellhead 116. Cement may be provided within the annular region between the liner string and the oil reservoir for effecting zonal isolation (see below), but is not in all cases. In some embodiments, for example, this liner is perforated to effect flow communication between the reservoir and the wellbore. In this respect, in some embodiments, for example, the liner string can also be a screen or is slotted. In some embodiments, for example, the production tubing string may be engaged or stung into the liner string, thereby providing a fluid passage for conducting the produced reservoir fluid to the wellhead 116. In some embodiments, for example, no cemented liner is installed, and this is called an open hole completion or uncemented casing completion.

[0040] An open-hole completion is effected by drilling down to the top of the producing formation, and then lining the wellbore (such as, for example, with a wellbore string 113). The wellbore is then drilled through the producing formation, and the bottom of the wellbore is left open (i.e. uncased), to effect flow communication between the reservoir and the wellbore. Open- hole completion techniques include bare foot completions, pre-drilled and pre-slotted liners, and open-hole sand control techniques such as stand-alone screens, open hole gravel packs and open hole expandable screens. Packers and casing can segment the open hole into separate intervals and ported subs can be used to effect flow communication between the reservoir and the wellbore.

[0041] The system 8 includes a pump 302 and a flow diverter 600. The flow diverter 600 is provided for, amongst other things, mitigating gas lock within the pump 302. In this respect, the flow diverter 600 is configured for receiving reservoir fluid, that has been received by the wellbore 102 from the subterranean formation 100, and separating gaseous material from the received reservoir fluid, in response to at least buoyancy forces, such that a gas-depleted reservoir fluid is obtained. In some embodiments, for example, the flow diverter 600 is disposed within a vertical portion of the wellbore 102 that extends to the surface 106. The flow diverter 600 is fluidly coupled to the pump 302 for effecting supply of the gas-depleted reservoir fluid to the pump 302.

[0042] The pump 302 is provided to, through mechanical action, pressurize and effect conduction of the gas-depleted reservoir fluid to the surface 106, and thereby effect production of the gas-depleted reservoir fluid. In some embodiments, for example, the pump 302 is a sucker rod pump. Other suitable pumps 302 include screw pumps, electrical submersible pumps, jet pumps, and plunger lift.

[0043] In some embodiments, for example, the system 8 includes an assembly 10. The assembly 10 is suspended within the wellbore 102 from the wellhead. The assembly includes the pump 302 and a gas-depleted reservoir fluid-producing conductor 204. The gas-depleted reservoir fluid-producing conductor 204 is fluidly coupled to the pump 302 for conducting the pressurized gas-depleted reservoir fluid to the surface 106.

[0044] The assembly 10 is disposed within the wellbore string 113, such that an intermediate wellbore passage 112 is defined within the wellbore string 113, between the assembly 10 and the wellbore string 113. In some embodiments, for example, the intermediate wellbore passage 112 is an annular space disposed between the assembly 10 and the wellbore string 113. In some embodiments, for example, the intermediate wellbore passage 112 is defined by the space that extends outwardly, relative to the central longitudinal axis of the assembly 10, from the assembly 10 to the wellbore fluid conductor 113. In some embodiments, for example, the intermediate wellbore passage 112 extends longitudinally to the wellhead 116, between the assembly 10 and the wellbore string 113.

[0045] In some embodiments, the flow diverter 600 includes a wellbore string counterpart 600B and an assembly counterpart 600C. The wellbore string 113 defines the wellbore string counterpart 600B, and the assembly 10 defines the assembly counterpart 600C. The flow diverter 600 defines: (i) a reservoir fluid-conducting passage 6002 for conducting reservoir fluid that is received within a downhole wellbore space from the subterranean formation 100, to a reservoir fluid separation space 112X of the wellbore 102, with effect that a gas-depleted reservoir fluid is separated from the reservoir fluid within the reservoir fluid separation space 112X in response to at least buoyancy forces; and (ii) a gas-depleted reservoir fluid-conducting passage 6004 for receiving the separated gas-depleted reservoir fluid while the separated gas- depleted reservoir fluid is flowing in a downhole direction, and diverting the flow of the received gas-depleted reservoir fluid such that the received gas-depleted reservoir fluid is conducted by the flow diverter 600 in the uphole direction to the pump 302.

[0046] In some embodiments, for example, the assembly counterpart 600C includes a flow diverter body 602, and the flow diverter body 602 includes a shroud 604. The gas-depleted reservoir fluid conducting passage 6004 is disposed within the shroud 604. In this respect, the shroud 604 is co-operatively disposed relative to the wellbore string counterpart 600B such that an intermediate reservoir fluid-conducting passage 608 (such as, for example, an annular fluid passage) is disposed between the shroud 604 and the wellbore string counterpart 600B. The intermediate reservoir fluid-conducting passage 608 forms part of the intermediate wellbore passage 112. In some embodiments, for example, the intermediate reservoir fluid-conducting passage 608 includes the reservoir fluid-conducting passage 6002 and is disposed for conducting the received reservoir fluid to the reservoir fluid separation space 112X.

[0047] In some embodiments, for example, the shroud 604 includes an opening 606 for receiving the separated gas-depleted reservoir fluid, such that the separated gas-depleted reservoir fluid is conducted via the gas-depleted reservoir fluid conducting passage 6004 to the pump 302. In this respect, the opening 606 defines a gas-depleted reservoir fluid receiver. In some embodiments, for example, the opening 606 is disposed at an uphole end 610 of the shroud, and the gas-depleted reservoir fluid conducting passage 6004 extends downhole from the uphole end 610 for conducting the received gas-depleted reservoir fluid in a downhole direction. The reservoir fluid separation space 112X is disposed uphole, such as vertically above, the opening 606.

[0048] In some embodiments, for example, there is provided a pump assembly 300, and the pump assembly includes the pump 302 and a pump intake 304. The pump intake 304 is disposed within the shroud 604 and includes a flow receiver 320 for receiving the gas-depleted reservoir fluid being conducted by the passage 6004, and conducting the gas-depleted reservoir fluid to the pump for pressurizing of the gas-depleted reservoir fluid by the pump 302. In some embodiments, for example, the flow diverter body 602 and the pump intake 304 are co- operatively configured such that bypassing of the flow receiver 320, by the gas-depleted reservoir fluid that is received and conducted by the passage 6004, is prevented or substantially prevented. In this respect, in some embodiments, for example, the flow diverter body 602 includes a downhole end 612 that is closed for preventing, or substantially preventing, such bypassing.

[0049] In some embodiments, for example, the wellbore string counterpart 600B is defined by 5-1/2” casing, the pump 302 is a 400 series pump, and the pump intake 304 is a 300 series pump intake. In this respect, in some embodiments, for example, in order for the shroud 604 to be sufficiently small such that the pump assembly 300, the shroud 604, and the wellbore string 113 co-operate to enable desirable operation of the system, the pump intake 304 is characterized by a series that is smaller than the series that is characteristic of the pump 302. In this respect, the pump assembly 300 includes a 300 series dummy pump 310 (i.e. a dummy pump that is characterized by a series that is equivalent to that of the series that is characteristic of the pump intake 304) that effects fluid coupling of the pump intake 304 to the pump 302. In some embodiments, for example, the pump 302 is connected to the dummy pump 310 via a cross-over such that the fluid coupling of the pump 302 to the dummy pump 310 is effected.

[0050] Referring to Figure 1, in some embodiments, for example, the pump 302 is disposed within the shroud 604. Referring to Figure 2, in some embodiments, for example, the pump 302 is disposed uphole relative to the shroud 604. In those embodiments where the reservoir fluid is relatively susceptible to slug flow, the pump 302 is disposed within the shroud 604.

[0051] In some embodiments, for example, the pump assembly 300 includes an electrical submersible pump 312, and the electrical submersible pump 312 includes the pump 302, a pump intake 304, a seal section 306, and a motor 308. The motor 308 is coupled to the pump 302, such as by a shaft, for driving the pump 302. The seal section 306 is disposed between the motor and the pump intake 304, for defining a sealed interface between the motor 308 and the shaft and a sealed interface between the pump 302 and the shaft. In some embodiments, for example, the seal section 306 is coupled to the pump intake 304 via a flange 305.

[0052] Referring to Figure 3 to 8, in some embodiments, for example, the shroud 604 is coupled to the pump assembly 300 via a connector 800, such as, for example, a clamp 802. In those embodiments where the pump assembly 300 includes an electrical submersible pump 312, in some of these embodiments, for example, the connector 800 is coupled to a neck 314 that is disposed between the seal section 306 and the pump intake 304. In this respect, in such embodiments, for example, both of the seal section 306 and the motor 308 are disposed externally of, and downhole relative to, the shroud 604. In this respect, by being disposed externally of the shroud 604, the motor 308 is disposed for cooling by the reservoir fluid that is being flowed past the motor 308 while the reservoir fluid is being conducted uphole to the reservoir fluid separation space 112X. [0053] In some embodiments, for example, the clamp 802 includes two clamp sections 804, 806, that are coupled together by set screws 808 which extend from one of the sections and are friction fitted into apertures provided in the other one of the sections. The interface between the clamp sections 804, 806 is sealed with a bead of room temperature vulcanization (“RTV”) silicone sealant. The clamp sections 804, 806 are co-operatively configured such that, while the neck 314, that is joining the motor 308 to the pump intake 304, is disposed between the clamp sections 80 4, 806 and the clamp sections 804, 806 are drawn together for effecting coupling of the sections 804, 806 upon coupling of the clamp sections 804, 806 to obtain the clamp 802, the neck 314 becomes clamped between the clamp sections 804, 806.

[0054] In some embodiments, for example, the neck 314 and the clamp 802 are co- operatively configured such that, upon clamping of the neck 314 between the clamp sections 804, 806, a sealed interface is established between the neck 314 and the clamp 802. In this respect, in some embodiments, for example, the sealed interface is established by sealing members 814, 815 (such as, for example, an o-ring) that are retained within grooves defined within inner surfaces of the clamp sections 804, 806.

[0055] In some embodiments, for example, a spacer 322 is also disposed about the neck 314 and in abutting relationship with the clamp 802 such that the clamp 802 is fixed, or substantially fixed, axially relative to the pump assembly 300.

[0056] In order to effect operation of the pump 302, the motor 308 is electrically coupled to a power and voltage source disposed at the surface 106 via an electrical conductor 900, such as, for example, an electrical cable. In some embodiments, for example, the electrical conductor 900 extends through the clamp 802 for effecting electrical connection to the motor 308. In this respect, in some embodiments, for example, the clamp 802 includes electrical conductor apertures 812 through which the electrical conductor 900 extends. In some embodiments, for example, a sealed interface is defined between the electrical conductor 900 and the clamp 802, with effect that flow communication through the apertures 812, between the electrical conductor 900 and the clamp 802, is sealed or substantially sealed. In this respect, in some embodiments, for example, the sealed interface is effected by a sealing member (such as, for example, an o- ring, suitably retained within a groove defined within an inner surface of the clamp 802 that is defining the aperture 812) disposed between the electrical conductor 900 and the clamp 802). In some embodiments, for example, the sealed interface is defined by a bead of RTV silicone sealant.

[0057] The shroud 604 is coupled to the connector 800 (such as, for example, the clamp 802) via fasteners (such as, for example, bolts) that are threaded into receiving apertures defined within outer surfaces of the clamp sections 804, 806. A sealed interface is established between the shroud 604 and the connector 800, for preventing, or substantially preventing, flow communication between the shroud 604 and the wellbore via the space between the shroud 604 and the connector 800. The sealed interface is established by a sealing member 811 (such as, for example, an o-ring), that is retained within grooves disposed within the outer surfaces of the clamp sections 804, 806, and disposed in sealing engagement, or substantially sealing engagement, with the shroud 604.

[0058] Referring to Figures 9 to 22, in some embodiments, for example, the shroud 604 is assembled from a plurality of thin-walled segments 6041. The plurality of segments 6041 are arranged in series. The plurality of segments includes a first one 6042 of the segments in the series, and the first segment 6042 is fastened to the connector 800 (such as, for example, the clamp 802) by fasteners (e.g. bolts) via receiving apertures 6046, and each one of the subsequent segments in the series, independently, is disposed in an interference fit relationship with a previous one of the segments in the series. In some embodiments, for example, the last one 6043 of the segments in the series is disposed in an interference fit relationship with a relatively thicker-walled retention ring 6044, and a plurality of set screws 6045 are fastened to the retention ring 6044, and extend radially, about a central longitudinal axis 2041 of the gas-depleted reservoir fluid-producing conductor, from the retention ring 6044 and towards the gas-depleted reservoir fluid-producing conductor 204, for centralizing the shroud 604 relative to the gas- depleted reservoir fluid-producing conductor 204. Referring to Figures 20 to 22, in some embodiments, for example, the set screws 6045 are distributed about the shroud 604, and the set screws 6045, or at least some of the set screws 6045, are offset, relative to one another. In this respect, in some embodiments, for example, the set screws 6045 and the gas-depleted reservoir fluid-producing conductor are co-operatively configured such that, the set screws 6045, or at least a some of the set screws 6045, are distributed: (i) about the central longitudinal axis 2041, and (ii) along spaced apart orthogonal planes traversing the central longitudinal axis 2041. In some embodiments, for example, such configuration optimizes fluid flow conditions.

[0059] In some embodiments, for example, the portion of the retention ring 6044, to which the last one 6043 of the segments is disposed in an interference fit relationship, has a minimum thickness that is greater than the maximum thickness of the last one 6043 of the segments. In some embodiments, for example, the ratio of the minimum thickness of the portion of the retention ring 6044, to which the last one 6043 of the segments is disposed in an interference fit relationship, to the maximum thickness of the last one 6043 of the segments is at least two (2). In some embodiments, for example, each one of the segments, independently, is in the form of a tubular. In some embodiments, for example, each one of the segments, independently, has a maximum thickness of less than 0.25 inches, such as, for example, less than 0.1 inches, such as, for example, less than 0.85 inches. By providing a shroud 604 with reduced wall thickness, a larger pump assembly 300 could be used within the same casing size. In some embodiments, for example, the material of construction of the segments 6041, comprising the shroud 604, is titanium.

[0060] In some embodiments, for example, relative to the first one 6042 of the segments in the series, each one of the subsequent segments, independently, is disposed within a previous one of the segments, in the series, in an interference fit relationship. In some embodiments, for example, relative to the last one 6043 of the segments in the series, each one of the previous segments, independently, includes an uphole end 6041A that is flared outwardly for receiving a subsequent one of the segments in the series for effecting the interference fit relationship. In some embodiments, for example, relative to the first one 6042 of the segments in the series, each one of the subsequent segments, independently, includes a downhole end that is flared outwardly for receiving a previous one of the segments in the series for effecting the interference fit relationship. In some embodiments, for example, the coupling of each pair of segments is reinforced by an adhesive, such as, for example, 3M™ Scotch-Weld™ Urethane Adhesive 604.

[0061] Referring to Figures 15 to 19, in some embodiments, for example, a plurality of spaced-apart elongated reinforcement members 6047 are disposed within the space between the thin-walled shroud (such as the above-described shroud 604 comprising of the plurality of thin- walled segments 6041) and the pump assembly 300. In some embodiments, for example, the reinforcement members 6047 reinforce the strength of the shroud 604, thereby mitigating versus, amongst other things, deformation of the shroud 604, such as the deformation which may be caused by a pressure differential that has been established between a space outside of the shroud 604 (e.g. the intermediate reservoir fluid-conducting passage 608, disposed between the shroud 604 and the wellbore string counterpart 600B) and a space inside the shroud 604 (e.g. the gas- depleted reservoir fluid conducting passage 6004). In some embodiments, for example, the reinforcement members 6047 (or at least some of the reinforcement members 6047) extend along axes that are parallel to a central longitudinal axis 6049 of the pump assembly 300.

[0062] In some embodiments, for example, the reinforcement members 6047 (or at least some of the reinforcement members 6047), are joined together with bracing struts 6048. In some embodiments, for example, the bracing struts 6048 (or at least some of the bracing struts 6048, are offset, relative to one another. In this respect, in some embodiments, for example, the the reinforcement members 6047, the bracing struts 6048, and the pump assembly 300 are co operatively configured such that the reinforcement members 6047 (or at least some of the reinforcement members) extend along axes that are parallel to a central longitudinal axis 6049 of the pump assembly 300, and the bracing struts 6048 (or at least some of the bracing struts 6048) are distributed: (i) about the central longitudinal axis 6049, and (ii) along spaced apart orthogonal planes traversing the central longitudinal axis 6049. In some embodiments, for example, such configuration optimizes fluid flow conditions.

[0063] In some embodiments, for example, the reinforcement, provided by the reinforcement members 6047, is provided along the entire length of the shroud 604, such as, for example, from the connector 800 to the retention ring 6044. In some embodiments, for example, reinforcement is provided by separate assemblies of reinforcement members 6047 that are co-operatively positioned to provide the desired reinforcement.

[0064] In some embodiments, for example, the shroud 604, the pump assembly 300, and the reinforcement members 6047 are co-operatively configured such that: (i) for each one of the reinforcement members 6047, independently, a first side of the reinforcement member 6047 is disposed in contact engagement with the shroud 604 and a second opposite side of the reinforcement member 6047 is disposed in contact engagement with the pump assembly 300; and

(ii) a space is defined within the shroud, between the shroud 604, the pump assembly 300, and the reinforcement members, for defining the gas-depleted reservoir fluid conducting passage 6004.

[0065] In some embodiments, for example, the pump assembly 300 is eccentrically disposed relative to the shroud 604, such that the contact engagement between the second opposite side of the reinforcement member 6047 and the pump assembly 300 is between the second opposite side of the reinforcement member 6047 and a first side of the pump assembly 300, and a second opposite side of the pump assembly 300 is disposed in contact engagement with the shroud 604.

[0066] The system 8 receives, via the wellbore 102, the reservoir fluid flow from the reservoir 100. As discussed above, the wellbore 102 is disposed in flow communication (such as through perforations provided within the installed casing or liner, or by virtue of the open hole configuration of the completion), or is selectively disposable into flow communication (such as by perforating the installed casing, or by actuating a valve to effect opening of a port), with the subterranean formation 100. When disposed in flow communication with the subterranean formation 100, the wellbore 102 is disposed for receiving reservoir fluid flow from the subterranean formation 100, with effect that the system 8 receives the reservoir fluid.

[0067] The system 8 also includes a reservoir fluid- supplying conductor 202 for conducting the reservoir fluid that is received within a downhole-disposed wellbore space 110 of the wellbore 102, from the downhole-disposed wellbore space 110 and uphole to the reservoir fluid separation space 112X. The conducting to the reservoir fluid separation space 112X is via the reservoir fluid conducting passage 6002, such that the reservoir fluid-supplying conductor 202 includes the reservoir fluid conducting passage 602.

[0068] In some embodiments, for example, the reservoir fluid-supplying conductor 202 and the reservoir fluid separation space 112X are co-operatively configured such that, in operation, while the reservoir fluid is being supplied to the reservoir fluid separation space 112X via the reservoir fluid-supplying conductor 202, the velocity of the gaseous portion of the reservoir fluid being conducted via the reservoir fluid-supplying conductor is greater than the critical liquid lifting velocity, and while the reservoir fluid is disposed within the reservoir fluid separation space 112X, the velocity of the gaseous portion of the reservoir fluid is sufficiently low such that the above-described separation is effected.

[0069] In some embodiments, for example, the reservoir fluid-supplying conductor 202 includes a downhole-disposed conductor 2022 and an uphole-disposed conductor 2024.

[0070] The downhole-disposed conductor 2022 is configured for receiving reservoir fluid, which has been conducted into a downhole wellbore space 110 of the wellbore 102, and conducting the reservoir fluid uphole for supplying an uphole wellbore space 108. In some embodiments, for example, the length of the downhole-disposed conductor 2022, as measured along the central longitudinal axis of the downhole-disposed conductor 2022, is at least 500 feet, such as, for example, at least 750 feet, such as, for example at least 1000 feet. In some of these embodiments, for example, the downhole-disposed conductor 2022 includes a receiver 206 (e.g. an inlet port) for receiving the reservoir fluid from the downhole wellbore space 110, and the receiver 206 is disposed within the horizontal section 102C of the wellbore 102.

[0071] The uphole-disposed conductor 2024 receives the reservoir fluid supplied to the uphole wellbore space 108 and conducts the reservoir fluid to the reservoir fluid separation space 112X. In this respect, the uphole-disposed conductor 2024 includes the reservoir fluid conducting passage 6002.

[0072] The system 8 also includes a sealed interface 500 for preventing, or substantially preventing, bypassing of the reservoir fluid separation space 112X by the reservoir fluid that is supplied to the uphole wellbore space 108 by the downhole-disposed conductor 2022. In some embodiments, for example, the sealed interface 500 is defined by a sealed interface effector 502, such as, for example, a packer.

[0073] In some embodiments, for example, the sealed interface 500 is defined within the wellbore 102, between: (a) the uphole wellbore space 108 of the wellbore 102, and (b) the downhole wellbore space 110 of the wellbore 102. In some embodiments, for example, the disposition of the sealed interface 500 is such that flow communication, via the intermediate wellbore passage 112, between the uphole wellbore space 108 and the downhole wellbore space 110 (and across the sealed interface 500), is prevented, or substantially prevented. In some embodiments, for example, the disposition of the sealed interface 500 is such that fluid flow, across the sealed interface 500, in a downhole direction, from the uphole wellbore space 108 to the downhole wellbore space 110, is prevented, or substantially prevented. In this respect, the sealed interface 500 functions to prevent, or substantially prevent, reservoir fluid flow, that is received within the uphole wellbore space 108, from bypassing the reservoir fluid separation space 112X, and, as a corollary, the reservoir fluid is directed to the reservoir fluid separation space 112X, via the uphole-disposed conductor 2024, for facilitating separation of gaseous material from the reservoir fluid in response to at least buoyancy forces.

[0074] Referring to Figures 1 and 2, in some embodiments, for example, the sealed interface 500 is disposed within a section of the wellbore 102 whose axis 14A is disposed at an angle“a” of at least 60 degrees relative to the vertical“V”. In some of these embodiments, for example, the sealed interface 500 is disposed within a section of the wellbore whose axis is disposed at an angle“a” of at least 85 degrees relative to the vertical“V”. In this respect, disposing the sealed interface 500 within a wellbore section having such wellbore inclinations minimizes solid debris accumulation at the sealed interface 500.

[0075] In some embodiments, for example, the downhole-disposed conductor 2022, the uphole-disposed conductor 2024, the sealed interface 500, and the flow diverter 600 are co- operatively configured such that, while the downhole-disposed conductor 2022 is receiving reservoir fluid, from the downhole wellbore space 110, that has been received within the downhole wellbore space 110 from the subterranean formation 100: the reservoir fluid is supplied to the uphole wellbore space 108 by the downhole-disposed conductor 2022; bypassing of the reservoir fluid separation space 112X by the reservoir fluid, being supplied to the uphole wellbore space 108 by the downhole-disposed conductor 2022, is prevented, or substantially prevented, such that the reservoir fluid is supplied to the reservoir fluid separation space 112X by the uphole-disposed conductor 2024 via the reservoir fluid conducting passage 6002; within the reservoir fluid separation space 112X, a gas-depleted reservoir fluid is separated from the discharged reservoir fluid, in response to at least buoyancy forces, such that the gas-depleted reservoir fluid is obtained; and the separated gas-depleted reservoir fluid is received by the gas depleted reservoir fluid receiver of the flow diverter (e.g. the opening 606 of the shroud 604) and conducted to the flow receiver 320 of the pump 302 via the gas-depleted reservoir fluid-conducting passage 6004.

[0076] Once received by the pump 302, the gas-depleted reservoir fluid is pressurized by the pump 302 and conducted as a flow 402 to the surface via the gas-depleted reservoir fluid- producing conductor 204.

[0077] In parallel, the separation of gaseous material from the reservoir fluid is with effect that a liquid-depleted reservoir fluid is obtained and is conducted uphole (in the gaseous phase, or at least primarily in the gaseous phase with relatively small amounts of entrained liquid) as a flow 404 via the intermediate wellbore passage 112 that is disposed between the assembly 10 and the wellbore string 113 (see above).

[0078] The reservoir fluid produced from the subterranean formation 100, via the wellbore 102, including the gas-depleted reservoir fluid, the liquid-depleted reservoir material, or both, may be discharged through the wellhead 116 to a collection facility, such as a storage tank within a battery.

[0079] In some embodiments, for example, the reservoir fluid separation space 112X spans a continuous space extending from the assembly to the wellbore string 113, and the continuous space extends outwardly relative to the central longitudinal axis of the assembly 10. [0080] In some embodiments, for example, the reservoir fluid separation space 112X spans a continuous space extending from the assembly to the wellbore string 113, and the continuous space extends outwardly relative to the central longitudinal axis of the wellbore 102.

[0081] In some embodiments, for example, the reservoir fluid separation space 112X is disposed within a vertical portion of the wellbore 102 that extends to the surface 106.

[0082] In some embodiments, for example, the ratio of the minimum cross-sectional flow area of the reservoir fluid separation space 112X to the maximum cross-sectional flow area of the fluid passage defined by the reservoir fluid-supplying conductor 202 is at least about 1.5.

[0083] In some embodiments, for example, the uphole-disposed wellbore space 108 includes a sump space 700, and the sump space 700 is disposed: (i) downhole relative to the reservoir fluid separation space 112X (such as, for example, downhole relative to the reservoir fluid conducting passage 6002), and (ii) uphole relative to the sealed interface 500. The sump space 700 is provided for collecting solid particulate material that gravity separates from the reservoir fluid that is supplied to the uphole wellbore space 108 by the downhole-disposed conductor 2022. In some embodiments, for example, the downhole-disposed conductor 2022 includes a flow communicator 212 (e.g. an outlet port) for discharging the conducted reservoir fluid into the uphole wellbore space 108, and the flow communicator 212 is disposed uphole relative to the sump space 700 and oriented for discharging the conducted reservoir fluid in a downhole direction towards the sump space 700. In this respect, as reservoir fluid is discharged from the flow communicator 212, the reservoir fluid flows in the downhole direction towards the sump space 700, and after having flowed in the downhole direction, reverses direction and flows in an uphole direction to the reservoir fluid separation space 112X via the uphole-disposed conductor 2024, including the reservoir fluid-conducting passage 6002. During the flow reversal, at least a fraction of solid particulate material, that is entrained within the reservoir fluid, that is discharged into the uphole wellbore space 108 from the downhole-disposed conductor 2024, becomes separated from the reservoir fluid and gravity settles within the sump space 700.

[0084] In this respect in some embodiments, for example, the downhole-disposed conductor 2022 extends into the uphole wellbore space 208 such that an uphole wellbore space-disposed section 214 of the downhole-disposed conductor 2022 is defined and includes the flow communicator 212. In some embodiments, for example, the flow communicator 212 is disposed downhole relative to the motor 308. In some embodiments, for example, the uphole wellbore space-disposed section 214 defines a tortuous flow path.

[0085] In some embodiments, for example, the uphole wellbore space-disposed section 214 is defined within a second shroud 216, and, in some of these embodiments, for example, the second shroud is disposed downhole relative to the motor 308. In this respect, in some embodiments, for example, the downhole-disposed conductor 2022 includes a conduit 218 that extends into a space 220 defined within the second shroud 216 such that an outlet port 222 of the conduit 218 is disposed for discharging the conducted reservoir fluid into the space 220, and such that fluid passages 224, 226 are defined within the shroud 216 for receiving and conducting the reservoir fluid discharged from the outlet port 222 such that the above-described flow reversal is effected and the reservoir fluid is discharged in a downhole direction from the shroud 216 and towards the sump space 700. In some embodiments, for example, the shroud 216 is suspended from a sensor 316 disposed at a terminus of the assembly 10.

[0086] In some embodiments, for example, the conduit 218 is supported by a sealed interface-effector 502, such as the packer. In some embodiments, for example, there is an absence, or substantial absence, of supporting of the conduit 218 by the assembly 10. In this respect, decoupling of the reservoir fluid-supplying conductor 202 from the assembly 10 such that stress, that would otherwise be experienced by the pump assembly 300, during movement of the reservoir fluid-supplying conductor 202, is relieved.

[0087] In some embodiments, for example, the conduit 218 defines a velocity string 228, and, in some embodiments, for example, the entirety, or the substantial entirety of the downhole- disposed conductor 2022 is a velocity string 228. In some embodiments, for example, at least 25% of the length of the downhole-disposed conductor 2022, as measured along the central longitudinal axis of the downhole-disposed conductor 2022, is a velocity string 228. In some embodiments, for example, at least 50% of the length of the downhole-disposed conductor 2022, as measured along the central longitudinal axis of the downhole-disposed conductor 2022, is a velocity string 228. In some embodiments, for example, at least 75% of the length of the downhole-disposed conductor 2022, as measured along the central longitudinal axis of the downhole-disposed conductor 2022, is a velocity string 228. In some embodiments, for example, the length of the velocity string 228, measured along the central longitudinal axis of the velocity string, is at least 20 feet, such as, for example, at least 50 feet, such as, for example, at least 100 feet. In some embodiments, for example, the velocity string 228 defines a fluid passage 234, and the maximum cross-sectional area of the fluid passage 234 is less than the minimum cross-sectional area of the fluid passage 230 of the gas-depleted reservoir fluid- producing conductor 204.

[0088] In some embodiments, for example, at least a fraction of the sump space 700 is disposed within the vertical section 102A of the wellbore 102. In some embodiments, for example, at least a majority of the sump space 700 is disposed within the vertical section 102A of the wellbore 102. In some embodiments, for example, the sump space 700 has a volume of at least 0.1 m ³ . In some embodiments, for example, the volume is at least 0.5 m ³ . In some embodiments, for example, the volume is at least 1.0 m ³ . In some embodiments, for example, the volume is at least 3.0 m ³ . By providing for the sump space 700, a suitable space is provided for collecting relative large volumes of solid debris, that has separated from the reservoir fluid, such that interference by the accumulated solid debris with the production of oil through the system is mitigated. This increases the run-time of the system before any maintenance is required.

[0089] As above-described, the gas-depleted reservoir fluid-producing conductor 204 is fluidly coupled to the pump 302 for conducting the pressurized gas-depleted reservoir fluid to the surface 106. In this respect, the gas-depleted reservoir fluid-producing conductor 204 extends from the pump 302 to the wellhead 116 for effecting flow communication between the pump 302 and the earth’s surface 106, such as, for example, a collection facility located at the earth’s surface 106, and defines a fluid passage 230. In some embodiments, for example, the minimum cross-sectional flow area of the fluid passage 230 is greater than the maximum cross-sectional flow area of the fluid passage 232 of the velocity string 228. In some embodiments, for example, the ratio of the cross-sectional flow area of the fluid passage 230 to the cross-sectional flow area of the fluid passage 232 is at least 1.1, such as, for example, at least 1.25, such as, for example, at least 1.5.

[0090] In the above description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the present disclosure. However, it will be apparent to one skilled in the art that these specific details are not required in order to practice the present disclosure. Although certain dimensions and materials are described for implementing the disclosed example embodiments, other suitable dimensions and/or materials may be used within the scope of this disclosure. All such modifications and variations, including all suitable current and future changes in technology, are believed to be within the sphere and scope of the present disclosure. All references mentioned are hereby incorporated by reference in their entirety.