Patent Application
20190301272
The present disclosure relates to mitigating downhole pump gas interference during hydrocarbon production.
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.
In one aspect, there is provided a reservoir fluid production assembly for producing reservoir fluid from a subterranean formation via a wellbore that is lined with a wellbore string, wherein the wellbore includes a wellbore space, the wellbore space includes a downhole wellbore space and an uphole wellbore space, and the uphole wellbore space is disposed uphole relative to the downhole wellbore space, wherein the assembly includes:
In another aspect, there is provided parts for assembly of a reservoir fluid production assembly for producing reservoir fluid from a subterranean formation via a wellbore that is lined with a wellbore string, wherein the wellbore includes a wellbore space, the wellbore space includes a downhole wellbore space and an uphole wellbore space, and the uphole wellbore space is disposed uphole relative to the downhole wellbore space, wherein the assembly includes:
In another aspect, there is provided a process for producing reservoir fluid from a subterranean formation comprising:
In another aspect, there is provided a reservoir fluid production assembly for producing reservoir fluid from a subterranean formation via a wellbore that is lined with a wellbore string, wherein the wellbore includes a wellbore space, the wellbore space includes a downhole wellbore space and an uphole wellbore space, and the uphole wellbore space is disposed uphole relative to the downhole wellbore space, wherein the assembly includes:
In another aspect, there is provided parts for assembly of a reservoir fluid production assembly for producing reservoir fluid from a subterranean formation via a wellbore that is lined with a wellbore string, wherein the wellbore includes a wellbore space, the wellbore space includes a downhole wellbore space and an uphole wellbore space, and the uphole wellbore space is disposed uphole relative to the downhole wellbore space, wherein the assembly includes:
In another aspect, there is provided a method of deploying a reservoir fluid production assembly downhole within a wellbore;
The preferred embodiments will now be described with reference to the following accompanying drawings:
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.
Referring to
The wellbore 102 can be straight, curved, or branched. The wellbore 102 can have various wellbore portions. A wellbore portion is an axial length of a wellbore 102. A wellbore portion 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. The term “horizontal”, when used to describe a wellbore portion, refers to a horizontal or highly deviated wellbore portion as understood in the art, such as, for example, a wellbore portion having a longitudinal axis that is between about 70 and about 110 degrees from vertical. The term “vertical”, when used to describe a wellbore portion, refers to a vertical or highly deviated vertical portion as understood in the art, such as, for example, a wellbore portion having a longitudinal axis that is less than about 20 degrees from the vertical.
“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.
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.
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.
The fluid productive portion of the wellbore 102 may be completed either as a cased-hole completion or an open-hole completion.
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.
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.
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 oil reservoir.
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.
The cement is introduced to an annular region between the wellbore casing and the oil reservoir after the subject wellbore casing has been run into the wellbore. This operation is known as “cementing”.
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.
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 lofting more challenging.
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.
To facilitate flow communication between the reservoir and the wellbore, the wellbore casing may be perforated, or otherwise include per-existing ports (which may be selectively openable, such as, for example, by shifting a sleeve), to provide a fluid passage for enabling flow of reservoir fluid from the reservoir to the wellbore.
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.
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.
Referring to
In some embodiments, for example, a wellbore fluid conductor 113, such as, for example, the wellbore string 113 (such as, for example, the casing 113), is disposed within the wellbore 102. The assembly 10 is configured for disposition within the wellbore fluid conductor 113, such that an intermediate wellbore passage 112 is defined within the wellbore fluid conductor 113, between the assembly 10 and the wellbore fluid conductor 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.
The production assembly 10 includes a reservoir fluid-supplying conductor 12 and an uphole-disposed reservoir fluid-conducting assembly 14. In some embodiments, for example, the reservoir fluid-supplying conductor 12 is in the form of tubing, such as coiled tubing, or a substantial portion of the reservoir fluid-supplying conductor 12 is in the form of tubing, such as coiled tubing. In some embodiments, for example, the reservoir fluid-supplying conductor 12 is in the form of a hose, such as, for example, a braided hose, or a substantial portion of the reservoir fluid-supplying conductor 12 is in the form of a hose, such as, for example, a braided hose. In some embodiments, for example, the reservoir fluid-supplying conductor 12 is releasably retained relative to the reservoir fluid-supplying conductor 12. The uphole-disposed reservoir fluid-conducting assembly 14 defines a passage 14A.
The reservoir fluid-supplying conductor 12 is configured for receiving and conducting reservoir fluid, received within the wellbore 102 from the subterranean formation, to the uphole-disposed reservoir fluid-conducting assembly 14.
The uphole-disposed reservoir fluid-conducting assembly 14 includes a pump 300 for receiving reservoir fluid and, through mechanical action, pressurizing reservoir fluid such that the pressurized reservoir fluid is conducted uphole, via a reservoir fluid-producing conductor 210, to an outlet 208 disposed at the surface 106, and thereby effect production of the reservoir fluid. It is understood that the reservoir fluid being conducted uphole through the wellbore 102, via the assembly 10, may be additionally energized by supplemental means, including by gas-lift. In some embodiments, for example, the pump 300 is a sucker rod pump. Other suitable pumps 300 include screw pumps, electrical submersible pumps, and jet pumps.
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 reservoir 104. When disposed in flow communication with the reservoir 104, the wellbore 102 is disposed for receiving reservoir fluid flow from the reservoir 104.
It is preferable to remove at least a fraction of the gaseous material from the reservoir fluid received by the reservoir fluid-supplying conductor 12, prior to the pump suction 302, in order to mitigate gas interference or gas lock conditions during pump operation. In this respect, the uphole-disposed reservoir fluid-conducting assembly 14 includes a flow diverter 600 for receiving reservoir fluid flow from the reservoir fluid-supplying conductor 12, effecting removal of at least a fraction of the gaseous material from the received reservoir fluid such that a gas-depleted reservoir fluid is obtained, and conducting the gas-depleted reservoir fluid to the pump.
In this respect, the flow diverter 600 is disposed uphole relative to the reservoir fluid-supplying conductor 12 and is fluid coupled to the reservoir fluid-supplying conductor 12 for receiving reservoir fluid being conducted by the reservoir fluid-supplying conductor 12. The flow diverter is also disposed downhole relative to the pump 300 and is fluidly coupled to the pump suction 302 for supplying the pump 300 with the gas-depleted reservoir fluid. 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.
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 diverted reservoir fluid, received within the downhole wellbore space from the reservoir 104, 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 300.
In some embodiments, for example, the assembly counterpart 600C includes a fluid diverter body 600A.
In some embodiments, for example, the flow diverter body 600A is configured such that the depletion of gaseous material from the reservoir fluid material, that is effected while the assembly 10 is disposed within the wellbore 102, is effected externally of the flow diverter body 600A within the wellbore 102, such as, for example, within an uphole wellbore space 108 of the wellbore 102.
The flow diverter body 600A includes a reservoir fluid receiver 602 for receiving the reservoir fluid (such as, for example, in the form of a reservoir fluid flow) that is being conducted (e.g. flowed), via the reservoir fluid-supplying conductor 12 from its inlet 204. In some embodiments, for example, the reservoir fluid-supplying conductor 12 extends to the receiver 602. In this respect, the reservoir fluid-supplying conductor 12 is fluidly coupled to the inlet 204. In some embodiments, for example, the reservoir fluid receiver 602 includes one or more ports 602A for receiving reservoir fluid being conducted by the fluid-supplying conductor 12.
The flow diverter body 600A also includes a reservoir fluid discharge communicator 604 that is fluidly coupled to the reservoir fluid receiver 602 via a reservoir fluid-conductor 603. In this respect, the reservoir fluid conductor 603 defines at least a portion of the reservoir fluid-conducting passage 6002.
The reservoir fluid conductor 603 defines one or more reservoir fluid conductor passages 603A. In some of the embodiments described below, for example, the one or more reservoir fluid-conducting passages 603A.
The reservoir fluid discharge communicator 604 is configured for discharging reservoir fluid (such as, for example, in the form of a flow) that is received by the reservoir fluid receiver 602 and conducted to the reservoir fluid discharge communicator 604 via the reservoir fluid conductor 603. In some embodiments, for example, the reservoir fluid discharge communicator 604 is disposed at an opposite end of the flow diverter body 600A relative to the reservoir fluid receiver 602. In some embodiments, for example, the reservoir fluid discharge communicator 604 includes one or more ports 604A.
The flow diverter body 600A also includes a gas-depleted reservoir fluid receiver 608 for receiving a gas-depleted reservoir fluid (such as, for example, in the form of a flow), after gaseous material has been separated from the reservoir fluid (for example, a reservoir fluid flow), that has been discharged from the reservoir fluid discharge communicator 604, in response to at least buoyancy forces. In this respect, the gas-depleted reservoir fluid receiver 608 and the reservoir fluid discharge communicator 604 are co-operatively configured such that the gas-depleted reservoir fluid receiver 608 is disposed for receiving a gas-depleted reservoir fluid flow, after gaseous material has been separated from the received reservoir fluid flow that has been discharged from the reservoir fluid discharge communicator 604, in response to at least buoyancy forces. In some embodiments, for example, the reservoir fluid discharge communicator 604 is disposed at an opposite end of the flow diverter body 600A relative to the gas-depleted reservoir fluid receiver 608. In some embodiments, for example, the gas-depleted reservoir fluid receiver 608 includes one or more ports 608A.
The flow diverter body 600A also includes a gas-depleted reservoir fluid conductor 610 that defines a gas-depleted reservoir fluid-conducting passage 610A configured for conducting the gas-depleted reservoir fluid (for example, a gas-depleted reservoir fluid flow), received by the receiver 608, to the gas-depleted reservoir fluid discharge communicator 611. In some embodiments, for example, the gas-depleted reservoir fluid discharge communicator 611 is disposed at an opposite end of the flow diverter body 600A relative to the gas-depleted reservoir fluid receiver 608. The gas-depleted reservoir fluid discharge communicator 611 is configured for fluid coupling to the pump 300, wherein the fluid coupling is for supplying the pump 300 with the gas-depleted reservoir fluid received by the receiver 610 and conducted through at least the gas-depleted reservoir fluid conductor 610. In this respect, the gas-depleted reservoir fluid-conducting passage 610A defines at least a portion of the gas-depleted reservoir fluid-conducting passage 6004. In some embodiments, for example, the gas-depleted reservoir fluid discharge communicator includes one or more ports 611A.
Referring to
Again referring to
In some embodiments, for example, the flow diverter body 600A includes the reservoir fluid receiver 602, the reservoir fluid discharge communicator 604, and the reservoir fluid conductor 603 (such as, for example, in the form of a fluid passage or a network of fluid passages), for fluidly coupling the receiver 602 and the discharge communicator 604. The flow diverter body 600A also includes the gas-depleted reservoir fluid receiver 608, gas-depleted reservoir fluid discharge communicator 611, and the gas-depleted reservoir fluid conductor 610 (such as, for example, in the form of a fluid passage or a network of fluid passages) for fluidly coupling the receiver 608 to the discharge communicator 611.
The assembly counterpart 600C also includes a wellbore sealed interface effector 400 configured for interacting with a wellbore feature for defining a wellbore sealed interface 500 within the wellbore 102, between: (a) an uphole wellbore space 108 of the wellbore 102, and (b) a downhole wellbore space 110 of the wellbore 102, while the assembly 10 is disposed within 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 an uphole wellbore space 108 and a 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 such embodiments, for example, the disposition of the sealed interface 500 is effected by the combination of at least: (i) a sealed, or substantially sealed, disposition of the wellbore string 113 relative to a polished bore receptacle 114 (such as that effected by a packer 240A disposed between the wellbore string 113 and the polished bore receptacle 114), and (ii) a sealed, or substantially sealed, disposition of a flow diverter body portion 601 relative to the polished bore receptacle 114. In this respect, the sealed interface 500 functions to prevent, or substantially prevented, reservoir fluid flow, that is received within the wellbore 102 (that is lined with the wellbore string 113), from bypassing the reservoir fluid receiver 602, and, as a corollary, the reservoir fluid is directed to the reservoir fluid receiver 602 for receiving by the reservoir fluid receiver 602. As well, the sealed interface 500 functions to prevent, or substantially prevented, gas-depleted reservoir fluid flow, that has been separated from the reservoir fluid discharged into the wellbore 102 from the discharge communicator 604, from bypassing the gas-depleted reservoir fluid receiver 608 and, as a corollary, the gas-depleted reservoir fluid is directed to the gas-depleted reservoir fluid receiver 608 for receiving by the gas-depleted reservoir fluid receiver 608.
In some embodiments, for example, the sealed, or substantially sealed, disposition of the flow diverter body portion 601 relative to the polished bore receptacle 114 is effected by a latch seal assembly. A suitable latch seal assembly is a Weatherford' Thread-Latch Anchor Seal Assembly™.
In some embodiments, for example, the sealed, or substantially sealed, disposition of the flow diverter body portion 601 relative to the polished bore receptacle 114 is effected by one or more o-rings or seal-type Chevron rings. In this respect, the sealing interface effector 400 includes the o-rings, or includes the seal-type Chevron rings.
In some embodiments, for example, the sealed, or substantially sealed, disposition of the flow diverter body portion 601 relative to the polished bore receptacle 114 is disposed in an interference fit with the polished bore receptacle. In some of these embodiments, for example, the flow diverter body portion 601 is landed or engaged or “stung” within the polished bore receptacle 114.
In some embodiments, for example, the flow diverter body portion 601 defines a passage, and the reservoir fluid-supplying conductor 12 is disposed within the passage.
The above-described disposition of the wellbore sealed interface 500 provide for conditions which minimize solid debris accumulation in the joint between the flow diverter body portion 601 and the polished bore receptacle 114 or in the joint between the polished bore receptacle 114 and the wellbore string 113. By providing for conditions which minimize solid debris accumulation within the joint, interference to movement of the separator relative to the liner, or the casing, as the case may be, which could be effected by accumulated solid debris, is mitigated.
Referring to
Referring to
In this respect, in such embodiments, for example, at least a portion of the space within the intermediate wellbore space 112, between the reservoir fluid discharge communicator 604 and the gas-depleted reservoir fluid receiver 608, defines at least a portion of the gas-depleted reservoir fluid-conducting passage 6004.
Once received by the pump 300, the gas-depleted reservoir fluid is pressurized by the pump 300 and conducted to the surface via the reservoir fluid-producing conductor 210.
Also, 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 810 via the intermediate wellbore passage 112 that is disposed between the assembly 10 and the wellbore string 113 (see above).
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.
In some embodiments, for example, the flow diverter body 600A is configured such that the gas-depleted reservoir fluid receiver 608 is disposed downhole relative to (such as, for example, vertically below) the reservoir fluid discharge communicator 604, with effect that the separated gas-depleted reservoir fluid is conducted in a downhole direction to the gas-depleted reservoir fluid receiver 608.
In some embodiments, for example, separation of gaseous material, from the reservoir fluid that is being discharged from the reservoir fluid discharge communicator 604, is effected within an uphole-disposed space 1121X of the intermediate wellbore passage 112, the uphole-disposed space 1121X being disposed uphole relative to the reservoir fluid discharge communicator 604. In this respect, in some embodiments, for example, the reservoir fluid separation space 112X includes the uphole-disposed space 1121X.
In some embodiments, for example, a flow diverter body-defined intermediate wellbore passage portion 1121Y of the intermediate wellbore passage 112 is disposed within a space between the flow diverter body 600A and the wellbore string 113, and effects flow communication between the reservoir fluid discharge communicator 604 and the gas-depleted reservoir fluid receiver 608 for effecting conducting of the gas-depleted reservoir fluid to the gas-depleted reservoir fluid receiver 608. In this respect, in such embodiments, for example, the flow diverter body-defined intermediate wellbore passage portion 1121Y defines at least a portion of the gas-depleted reservoir fluid-conducting passage 6004.
In some embodiments, for example, the space between the flow diverter body 600A and the wellbore string 113, within which the flow diverter body-defined intermediate wellbore passage portion 1121Y is disposed, is an annular space. In some embodiments, for example, the flow diverter body-defined intermediate space 1121Y is defined by the entirety, or the substantial entirety, of the space between the flow diverter body 600A and the wellbore string 113. In some embodiments, for example, separation of gaseous material, from the reservoir fluid that is discharged from the reservoir fluid discharge communicator 604, is effected within the flow diverter body-defined intermediate wellbore passage portion 1121Y. In this respect, in some embodiments, for example, at least a portion of the reservoir fluid separation space 112X is co-located with at least a portion of the flow diverter body-defined intermediate wellbore passage portion 1121Y.
In some embodiments, for example, the separation of gaseous material, from the reservoir fluid that is being discharged from the reservoir fluid discharge communicator 604, is effected within both of the uphole-disposed space 1121X and the flow diverter body-defined intermediate wellbore passage portion 1121Y. In this respect, in some embodiments, for example, the reservoir fluid is discharged from the reservoir fluid discharge communicator 604 into the uphole wellbore space 1121X, and, in response to at least buoyancy forces, the gaseous material is separated from the discharged reservoir fluid, while the reservoir fluid is being conducted downhole, from the uphole-disposed space 1121X, through the flow diverter body-defined intermediate wellbore passage portion 1121Y, and to the gas-depleted reservoir fluid receiver 608. In this respect, in some embodiments, for example, the uphole-disposed space 1121X is merged with the flow diverter body-defined intermediate wellbore passage portion 1121Y
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.
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.
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.
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 12A defined by the reservoir fluid-supplying conductor 12 is at least about 1.5.
In some embodiments, for example, the flow diverter body 600A further includes a shroud 620 co-operatively disposed relative to the gas-depleted reservoir fluid receiver 608 such that the shroud 620 projects below the gas-depleted reservoir fluid receiver 608 and interferes with conduction of the gas-depleted reservoir fluid to the gas-depleted reservoir fluid receiver 608 The shroud 620 provides increased residence time for separation of gaseous material within the intermediate fluid passage 112.
In those embodiments where the gas-depleted reservoir fluid receiver 608 is disposed below the reservoir fluid discharge communicator 604, in some of these embodiments, for example, the shroud 620 projects below the gas-depleted reservoir fluid receiver 608, such that gas-depleted reservoir fluid being conducted downhole to the gas-depleted reservoir fluid receiver 608 is directed below the gas-depleted reservoir fluid receiver 608 by the shroud 620.
In some embodiments, for example, the space, between: (a) the gas-depleted reservoir fluid receiver 608 of the flow diverter body 600A, and (b) the sealed interface 500, defines a sump 700 for collection of solid particulate that is entrained within fluid being discharged from the reservoir fluid discharge communicator 604 of the flow diverter body 600A, and the sump 700 has a volume of at least 0.1 m3. In some embodiments, for example, the volume is at least 0.5 m3. In some embodiments, for example, the volume is at least 1.0 m3. In some embodiments, for example, the volume is at least 3.0 m3.
By providing for the sump 700 having the above-described volumetric space characteristic, and/or the above-described minimum separation distance characteristic, a suitable space is provided for collecting relative large volumes of solid debris, from the gas-depleted reservoir fluid being flowed downwardly to the gas-depleted reservoir fluid receiver 608, 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. As well, because the solid debris is deposited over a larger area, the propensity for the collected solid debris to interfere with movement of the flow diverter body 600A within the wellbore 102, such as during maintenance (for example, a workover) is reduced.
As above-described, the reservoir fluid-producing conductor 210 extends from the gas-depleted reservoir fluid discharge communicator 611 to the wellhead 116 for effecting flow communication between the discharge communicator 611 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 210A.
In some embodiments, for example, the length of the fluid-supplying conductor 12, as measured along the central longitudinal axis of the fluid-supplying conductor 12, is at least 500 feet, such as, for example, at least 750 feet, such as, for example at least 1000 feet.
In some embodiments, for example, the flow diverter 600 is disposed uphole of a horizontal section 102C of the wellbore 102, such as, in some embodiments, for example, within a vertical section 102A, or, in some embodiments, for example, within a transition section 102B.
In some embodiments, for example, the central longitudinal axis of the passage 102CC of the 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 the vertical section 102A is disposed along an axis that is less than about 20 degrees from the vertical “V”, and the transition section 102B is disposed between the sections 102A 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.
In some of these embodiments, for example, the reservoir fluid-supplying conductor 12 extends from the flow diverter 600, in a downhole direction, into the horizontal section 102C, such that the inlet 204 is disposed within the horizontal section 102C.
Referring to
In this respect, in some embodiments, for example, parts for assembly to obtain the production assembly 10 are provided, and the parts include first, second, third, and fourth assembly counterparts 10A, 10B, 10C, and 10D. The assembly-defined flow diverter counterpart 600C includes first and second assembly-defined flow diverter counterparts 6002, 6004. The first assembly counterpart 10A includes the first assembly-defined flow diverter counterpart 6002, and the second assembly counterpart 10B includes the second assembly-defined flow diverter counterpart 6004. The third assembly counterpart 10C includes a reservoir fluid-supplying conductor 12 that is a first reservoir fluid-supplying conductor 12, and the first reservoir fluid-supplying conductor 12 defines a fluid passage having a minimum cross-sectional flow area. The fourth assembly counterpart 10D includes a reservoir fluid-supplying conductor 12 that is a second reservoir fluid-supplying conductor 12, and the second reservoir fluid-supplying conductor 12 defines a fluid passage having a minimum cross-sectional flow area that is less than the minimum cross-sectional flow area of the fluid passage defined by the first reservoir fluid-supplying conductor 12.
Each one of the second, third, and fourth assembly counterparts 10B, 10C, and 10D is configured for releasable retention relative to the first assembly counterpart 10A
The first, second, third, and fourth assembly counterparts 10A, 10B, 10C, 10D are co-operatively configured such that:
In some embodiments, for example, the third assembly counterpart 10C is connected to the second assembly counterpart 10B, such that release of the third assembly counterpart 10C from retention relative to the first assembly counterpart 10A is effected by the release of the second assembly counterpart 10B relative to the first assembly counterpart 10A. In some of these embodiments, for example, in response to release of the second assembly counterpart 10B from retention relative to the first assembly counterpart 10A, both of the second and third assembly counterparts 10B, 10C become displaceable relative to the first assembly counterpart for defeating occlusion of a workstring-conducting passageway 626 such that the fourth assembly counterpart 10D is conductible through the workstring-conducting passageway 626 for releasable coupling to the first assembly counterpart 10A.
In some embodiments, for example, the releasable retention of the second assembly counterpart 10B relative to the first assembly counterpart 10A is independent of the releasable retention of the third assembly counterpart 10C relative to the first assembly counterpart 10A. In other words, each one of the first and second assembly counterparts 10B, 10C, independently, is configured for releasable retention relative to the first assembly counterpart 10A.
In this respect, the first, second, third, and fourth assembly counterparts 10A, 10B, 10C, 10D are co-operatively configured such that:
In some embodiments, for example, the preventing of the interchangeability of the third assembly counterpart 10C with the fourth assembly counterpart 10D includes preventing of release of the retention of the third assembly counterpart 10C relative to the first assembly counterpart 10A, and the defeating of the preventing of the interchangeability of the third assembly counterpart 10C with the fourth assembly counterpart 10D includes defeating of the preventing of release of the retention of the third assembly counterpart 10C relative to the first assembly counterpart 10A such that the third assembly counterpart 10C becomes releasable from the retention relative to the first assembly counterpart 10A for effecting displacement of the third assembly counterpart 10C relative to the first assembly counterpart such that occlusion to the workstring-conducting passageway 626 by the third assembly counterpart 10C is defeated with effect that the fourth assembly counterpart 10D is conductible through the workstring-conducting passageway 626 for effecting releasable coupling of the fourth assembly counterpart 10D to the first assembly counterpart 10A such that an assembly 10 is obtained that includes the second reservoir fluid-supplying conductor 12.
In some embodiments, for example, the minimum cross-sectional flow area of the fluid passage defined by second reservoir fluid-supplying conductor 12 is less than the minimum cross-sectional flow area of the fluid passage defined by the first reservoir fluid-supplying conductor 12. In some embodiments, for example, the ratio of the minimum cross-sectional flow area of the fluid passage defined by the second reservoir fluid-supplying conductor 12 to the minimum cross-sectional flow area of the fluid passage defined by the second reservoir fluid-supplying conductor 12 is less than about 0.9, such as, for example, less than about 0.8, such as, for example, less than 0.7.
Referring to
In some embodiments, for example, the second assembly-defined flow diverter counterpart 6004 includes a flow diverter-effecting insert 624 (see
The insert-receiving part 622 further defines both of the reservoir fluid discharge communicator 604 and the gas-depleted reservoir receiver 608. The reservoir fluid discharge communicator 604 is disposed in fluid communication with the passageway 626, and the gas-depleted reservoir receiver 608 is also disposed in fluid communication with the passageway 626.
In some embodiments, for example, the insert-receiving part 622 and the flow diverter-effecting insert 624 are co-operatively configured such that, while the assembly 10, having the flow diverter-effecting insert 624 disposed within the passageway 626 of the insert-receiving part 622, is disposed within the wellbore 102 such that the sealed interface 500 is defined, and the reservoir fluid-supplying conductor 12 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:
In some embodiments, for example, the gas-depleted reservoir fluid receiver 608 is disposed below the reservoir fluid discharge communicator 604, in which case, the receiving of the obtained gas-depleted reservoir fluid flow by the gas-depleted reservoir fluid receiver 608 is effected by conduction of the obtained gas-depleted reservoir fluid flow to the gas-depleted reservoir fluid receiver 608 in a downhole direction.
In some embodiments, for example, the insert-receiving part 622 and the flow diverter-effecting insert 624 are further co-operatively configured such that, while the assembly 10, having the flow diverter-effecting insert 624 disposed within the passageway 626 of the insert-receiving part 622, is disposed within the wellbore 102 such that the sealed interface 500 is defined, and the reservoir fluid-supplying conductor 12 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:
In some of these embodiments, for example, the flow diverter-effecting insert 624 is further configured for disposition relative to the passageway 626 such that a passageway sealed interface 628 is established. In this respect, the insert-receiving part 622 and the flow diverter-effecting insert 624 are further co-operatively configured such that a passageway sealed interface 628 is established while the flow diverter-effecting insert 624 is disposed within the passageway 626 of the insert-receiving part 622, with effect that:
In some embodiments, for example, the passageway sealed interface 628 is effected by sealing engagement, or substantially sealing engagement, of the flow diverter-effecting insert 624 with the insert-receiving part 622. In some embodiments, for example, the sealing engagement, or substantially sealing engagement, of the flow diverter-effecting insert 624 with the passageway 626 is effected by a sealing member 628A that is coupled to the flow diverter-effecting insert 624. In some embodiments, a sealing member 629 is also coupled to the flow diverter effecting insert 624 for protecting the sealing area (defined between sealing members 628A and 629) from erosion and corrosion.
Referring to
In some embodiments, for example, and referring to
In some embodiments, for example, the flow diverter-effecting insert 624 is disposed for becoming releasably retained relative to the insert-receiving part 622 via a coupler 804 incorporated in the reservoir fluid conducting assembly 14 such that the flow diverter-effecting insert is disposed within the passageway in the flow diverter-defining position. In some embodiments, for example, the releasable retention is effected with a lock mandrel 802 that has been integrated within the reservoir fluid conducting assembly 14. In this respect, while disposed in the flow diverter-defining position, the flow diverter-effecting insert 624 is releasably retained to the insert-receiving part 622 via a lock mandrel 802 that has been integrated within the reservoir fluid conducting assembly 14 uphole of the insert-receiving part 622, such that the flow diverter-effecting insert is disposed in the flow diverter-defining position, the flow diverter-effecting insert 624 while being releasably retained relative to the insert-receiving part 622. In some embodiments, for example, the flow diverter-effecting insert 624 is run downhole with the lock mandrel 802 with a running tool and set within the reservoir fluid conducting assembly 14 by coupling the lock mandrel 802 to a corresponding nipple 804 within the reservoir fluid conducting assembly 14. Exemplary lock mandrels 802 include the Otis XN™ lock mandrel that is available from Halliburton Company. The corresponding nipple for the Otis XN™ lock mandrel is the Otis XN™ nipple.
Upon release from retention relative to the insert-receiving part 622 with a suitable tool, the flow diverter-effecting insert 624 is displaceable, relative to the insert-receiving part 622 (such as, for example, in an uphole direction through the passage 14A such that the flow diverter-effecting insert 624 is removed from the assembly 10) such that occlusion of the passageway of the insert-receiving part, by the flow diverter-effecting insert 624, is defeated, or at least partially defeated (such as, for example, removed or at least partially removed), and such that the insert-receiving part 622 becomes disposed in a non-occluded condition.
In this respect, while the flow diverter-effecting insert 624 is releasably retained relative to the insert-receiving part 622, interchangeability of the first reservoir fluid-supplying conductor 12 with the second reservoir fluid-supplying conductor 12 is prevented. Upon release of the flow diverter-effecting insert 624 from the retention relative to the insert-receiving part 622, and displacement of the flow diverter-effecting insert 624, relative to the insert-receiving part 622 (such as, for example, in an uphole direction through the a reservoir fluid-producing conductor 210 such that the flow diverter-effecting insert 624 is removed from the assembly 10) such that occlusion of the passageway of the insert-receiving part, by the flow diverter-effecting insert 624, is defeated, or at least partially defeated (such as, for example, removed or at least partially removed), the insert-receiving part 622 becomes disposed in a non-occluded condition, and the preventing of the interchangeability of the first reservoir fluid-supplying conductor 12 with the second reservoir fluid-supplying conductor 12 is defeated. In some embodiments, for example, the displacing of the flow diverter-effecting insert 624 is effected via slickline.
In some embodiments, for example, the first reservoir fluid-supplying conductor 12 is releasably retained relative to the first assembly counterpart 10A, such as, for example, the diverter body portion 601, by coupling between a lock mandrel 806 and a corresponding nipple 808. In some embodiments, for example, the first reservoir fluid-supplying conductor 12 is run downhole with the lock mandrel with a running tool, through the passageway of the insert receiving part 622, and set within a passage defined within the diverter body portion 601 by coupling the lock mandrel to a corresponding nipple within the diverter body portion 601, such that the reservoir fluid-supplying conductor 12 is hung from the nipple. Exemplary lock mandrels include the Otis XN™ lock mandrel that is available from Halliburton Company. The corresponding nipple for the Otis XN™ lock mandrel is the Otis XN™ nipple. In this respect, in some embodiments, for example, the first assembly counterpart 10A further includes the wellbore sealed interface effector 400, and the reservoir fluid-supplying conductor 12 is removable from the assembly 10, without having to remove other components, such as the wellbore sealed interface effector 400.
In some embodiments, for example, to interchange the first reservoir fluid-supplying conductor 12 with the second reservoir fluid-supplying conductor 12, the first reservoir fluid-supplying conductor 12 is removed from the wellbore via the passageway of the insert-receiving part 622 and the reservoir fluid-producing conductor 210. In this respect, prior to the removal of the first reservoir fluid-supplying conductor 12 from the wellbore, the flow diverter-effecting insert 624 is removed from the wellbore, and prior to the removal of the insert 624 from the wellbore, the pump 300 is removed from the wellbore. In some embodiments, for example, the first reservoir fluid-supplying conductor 12 is removable via slickline. In some embodiments, for example, the first reservoir fluid-supplying conductor 12 is rod retrievable. After the first reservoir fluid-supplying conductor 12 has been removed from the wellbore 102, the second reservoir fluid-supplying conductor 12 is run-in-hole, via the passage 14A, including the passageway 626 of the insert-receiving part 622, and coupled to the same nipple used at which the first reservoir fluid-supplying conductor 12 had been releasably retained (using a corresponding lock mandrel) such that the second reservoir fluid-supplying conductor 12 is releasably retained relative to the insert-receiving part 622. Sequentially, the flow diverter-effecting insert 624, and then the pump 300, are conveyed downhole through the passage 14A and correspondingly re-deployed within the reservoir fluid conducting assembly 14 so as to enable production using the modified assembly 10 (now with a reservoir fluid-supplying conductor 12 having a narrower cross-sectional flow area).
In some of these embodiments, for example, it is advantageous to switch to a narrower reservoir fluid-supplying conductor 12 as the reservoir pressure is depleted and the bottomhole pressure is reduced, so as to maintain flow the produced reservoir fluid within the reservoir fluid-supplying conductor 12 at a suitable velocity and mitigate slugging.
In some embodiments, for example, the assembly 10 is emplaced within the wellbore, with effect that the assembly 10 is disposed within the wellbore. After the assembly 10 has been emplaced within the wellbore, the sealed interface effector 400 (e.g. packer) is actuated, thereby establishing the sealed interface 500.
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.
This application claims priority from U.S. Provisional Patent Application No. 62/626,357 filed on Feb. 5, 2018, the entire contents of which are hereby incorporated by reference.
| Number | Date | Country | |
|---|---|---|---|
| 62626357 | Feb 2018 | US |
