Patent Application
20200256179
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 conducting assembly for disposition within a wellbore string of a wellbore that extends into a subterranean formation, wherein the assembly comprises:
while the assembly is disposed within the wellbore, there is an absence, or substantial absence, of tensile force being applied to the pump by the assembly-defined flow diverter counterpart.
In another aspect, there is provided a reservoir fluid conducting assembly for disposition within a wellbore string of a wellbore that extends into a subterranean formation, wherein the assembly comprises:
the gas-depleted reservoir fluid-conducting passage is disposed in fluid communication with the accumulator for supplying the separated gas-depleted reservoir fluid to the accumulator, such that the separated gas-depleted reservoir fluid is accumulated within the accumulator;
the pump is disposed within the accumulator and configured for receiving and pressurizing the gas-depleted reservoir fluid that has accumulated within the accumulator; and
the gas-depleted reservoir fluid-producing conductor is disposed in fluid communication with the pump for receiving the pressurized gas-depleted reservoir fluid and conducting the pressurized gas-depleted reservoir fluid to the surface.
In another aspect, there is provided a reservoir fluid production system disposed within a wellbore that extends into a subterranean formation, wherein the system comprises:
there is an absence, or substantial absence, of tensile force being applied to the pump by the flow diverter.
the gas-depleted reservoir fluid-conducting passage is disposed in fluid communication with the accumulator for supplying the separated gas-depleted reservoir fluid to the accumulator, such that the separated gas-depleted reservoir fluid is accumulated within the accumulator;
In another aspect, there is provided a reservoir fluid production system disposed within a wellbore that extends into a subterranean formation, wherein the system comprises:
the gas-depleted reservoir fluid-conducting passage is disposed in fluid communication with the accumulator for supplying the separated gas-depleted reservoir fluid to the accumulator, such that the separated gas-depleted reservoir fluid is accumulated within the accumulator;
the pump is disposed within the accumulator and configured for receiving and pressurizing the gas-depleted reservoir fluid that has accumulated within the accumulator; and
the gas-depleted reservoir fluid-producing conductor is disposed in fluid communication with the pump for receiving the pressurized gas-depleted reservoir fluid and conducting the pressurized gas-depleted reservoir fluid to the surface.
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 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 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.
“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 emplaced 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 subterranean formation 100.
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 subterranean formation 100 after the subject wellbore casing has been run into the wellbore 102. 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 lifting 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.
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.
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.
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.
The system 8 includes a flow diverter 600, a pump 302, and a gas-depleted reservoir fluid-producing conductor 400.
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, 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. The flow diverter 600 is fluidly coupled to the pump 302 for effecting supply of the gas-depleted reservoir fluid to the pump 302.
In some embodiments, for example, the flow diverter 600 defines: (i) a reservoir fluid-conducting passage 6002 for conducting reservoir fluid, that is received within a downhole wellbore space 110 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 that 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.
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 pump 302 is configured to receive the gas-depleted reservoir fluid at its suction, pressurize the gas-depleted reservoir fluid, through mechanical action, to obtain a pressurized gas-depleted reservoir fluid, and discharge the pressurized gas-depleted reservoir fluid to the gas-depleted reservoir fluid-producing conductor 400. The gas-depleted reservoir fluid-producing conductor 400 is fluidly coupled to the pump 302 for conducting the discharged pressurized gas-depleted reservoir fluid to the surface 106, with effect that the gas-depleted reservoir fluid is thereby produced.
In some embodiments, for example, the pump 302 is an electrical submersible pump (“ESP”).
In some embodiments, for example, the flow diverter 600 and the pump 302 are co-operatively configured such that, while the reservoir fluid-conducting passage 6002 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:
Once received by the pump 302, the gas-depleted reservoir fluid is pressurized by the pump 302 to obtain a pressurized gas-depleted reservoir fluid, and the pressurized gas-depleted reservoir fluid is discharged from the pump and conducted as a flow 402 to the surface via the gas-depleted reservoir fluid-producing conductor 400.
In some embodiments, for example, the system 8 includes an assembly 10 disposed within the wellbore 102. The assembly 10 is suspended within the wellbore 102 from the wellhead, and includes the pump 302 and the gas-depleted reservoir fluid-producing conductor 400.
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.
In those embodiments where the system 8 includes an assembly 10 disposed within the wellbore 102, the flow diverter 600 includes a wellbore string-defined counterpart 600B and an assembly-defined counterpart 600C. The wellbore string 113 defines the wellbore string-defined counterpart 600B, and the assembly 10 defines the assembly-defined counterpart 600C. In this respect, the assembly 10 further includes the assembly-defined counterpart 600C.
In some embodiments, for example, the assembly-defined counterpart 600C of the flow diverter 600 includes a reservoir fluid-supplying conductor 202 for receiving the reservoir fluid from the downhole-disposed wellbore space 110 and conducting the received reservoir fluid, uphole, from the downhole-disposed wellbore space 110 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 defines the reservoir fluid conducting passage 6002 of the flow diverter 600. 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 202 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.
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 10 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 reservoir fluid-supplying conductor 202 defines a fluid passage 202X, and 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 202X of the reservoir fluid-supplying conductor 202 is at least about 1.5.
In some embodiments, for example, the flow diverter 600 is further configured such that bypassing of the gas-depleted reservoir fluid-conducting passage 6004, by the separated gas-depleted reservoir fluid (for example, separated gas-depleted reservoir fluid being conducted in the downhole direction), is prevented, or substantially prevented. In this respect, in some embodiments, for example, the assembly-defined counterpart 600C of the flow diverter 600 further includes a sealed interface effector 502.
The sealed interface effector 502 and the wellbore string-defined counterpart 600C co-operate to define a sealed interface 500. The sealed interface 500 is configured for preventing, or substantially preventing, bypassing, of the gas-depleted reservoir fluid-supplying conductor 400, by the separated gas-depleted reservoir fluid. In some embodiments, for example, the sealed interface effector 502 includes a packer. In some embodiments, for example, the sealed interface 500 is defined within the wellbore 102, between: (a) an uphole wellbore space 108 (which includes the reservoir fluid separation space 112X) of the wellbore 102, and (b) a 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, the separated gas-depleted reservoir fluid from bypassing the gas-depleted reservoir fluid-supplying conductor 400, and, as a corollary, the gas-depleted reservoir fluid is directed to the gas-depleted reservoir fluid-supplying conductor 400 (for conducting to the pump 302).
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 of at least 60 degrees relative to the vertical. 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 of at least 85 degrees relative to the vertical. 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.
In some embodiments, for example, the sealed interface 500 is effected by sealing, or substantially sealing, disposition of the sealed interface effector 502 relative to the wellbore string 113. In this respect, in some embodiments, for example, the sealed interface effector 502 is configured for becoming disposed in sealing, or substantially sealing, disposition relative to the wellbore string 113, for effecting definition of the sealed interface 500.
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 reservoir fluid-supplying conductor 202.
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 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 space 700, a suitable space is provided for collecting relative large volumes of solid debris, which 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.
In some embodiments, for example, the flow diverter 600 and the pump 302 are co-operatively configured such that, while the reservoir fluid-supplying conductor 202 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:
As described above, once received by the pump 302, the gas-depleted reservoir fluid is pressurized by the pump 302 to obtain a pressurized gas-depleted reservoir fluid, and the pressurized gas-depleted reservoir fluid is discharged from the pump and conducted as a flow 402 to the surface via the gas-depleted reservoir fluid-producing conductor 400. In some embodiments, for example, the gas-depleted reservoir fluid-producing conductor 400 defines a fluid passage 401, and the minimum cross-sectional flow area of the fluid passage 401 of the gas-depleted reservoir fluid-producing conductor 400 is greater than the maximum cross-sectional flow area of the fluid passage 202X of the reservoir fluid-supplying conductor 202. In some embodiments, for example, the ratio of the cross-sectional flow area of the fluid passage 401 of the gas-depleted reservoir fluid-producing conductor 400 to the cross-sectional flow area of the fluid passage 202X of the reservoir fluid-supplying conductor 202 is at least 1.1, such as, for example, at least 1.25, such as, for example, at least 1.5.
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).
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 assembly-defined counterpart 600C further includes the gas-depleted reservoir fluid supplying conductor 301. The gas-depleted reservoir fluid supplying conductor 301 is configured for receiving gas-depleted reservoir fluid, separated from the reservoir fluid within the reservoir fluid separation space 112X, and conducting the gas-depleted reservoir fluid to the pump 302.
In some embodiments, for example, the co-operation between the assembly defined counterpart 600C (such as, for example, the reservoir fluid-supplying conductor 202) and the wellbore string-defined counterpart 600C is with effect that an intermediate gas-depleted reservoir fluid-conducting passage 112Y is defined, and the intermediate gas-depleted reservoir fluid- conducting passage 112Y forms a portion of the intermediate wellbore passage 112. The separated gas-depleted reservoir fluid is conducted, in response to at least buoyancy forces, between the reservoir fluid separation space 112X and the gas-depleted reservoir fluid-supplying conductor 400, via the intermediate gas-depleted reservoir fluid-conducting passage 112Y.
In this respect, the gas-depleted reservoir fluid conducting passage 6004, defined by the flow diverter 600, includes the intermediate gas-depleted reservoir fluid-conducting passage 112Y and the gas-depleted reservoir fluid-supplying conductor 301.
In some embodiments, for example, the assembly-defined counterpart 600C defines a diverter body-supplying fluid conductor 604, a flow diverter body 602, and a pump-supplying fluid conductor 606.
The diverter body-supplying fluid conductor 604 is configured for receiving reservoir fluid, conducted into a downhole wellbore space 110 of the wellbore 102 from the subterranean formation, and conducting the received reservoir fluid to the flow diverter body 602. In some embodiments, for example, the length of the diverter body-supplying fluid conductor 604, as measured along the central longitudinal axis of the diverter body-supplying fluid conductor 604, 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 diverter body-supplying fluid conductor 604 includes a receiver 605 (e.g. an inlet port) for receiving the reservoir fluid from the downhole wellbore space 110, and the receiver 605 is disposed within the horizontal section 102C of the wellbore 102.
Referring to
The fluid communication established by the diverter body-defined fluid conductor 612 is with effect that reservoir fluid received by the reservoir fluid receiver 608 is conducted uphole to the reservoir fluid discharge communicator 610 and discharged from the reservoir fluid discharge communicator 610 and into the reservoir fluid separation space 112X.
In this respect, in some embodiments, for example, the reservoir fluid conducting passage 6002 includes the combination of the diverter body-supplying fluid conductor 604 and the diverter body-defined fluid conductor 612.
In some embodiments, for example, the diverter body-supplying fluid conductor 604 defines a velocity string 228, and, in some embodiments, for example, the entirety, or the substantial entirety of the conductor 604 is a velocity string 228. In some embodiments, for example, at least 25% of the length of the conductor 604, as measured along the central longitudinal axis of the conductor 604, is a velocity string 228. In some embodiments, for example, at least 50% of the length of the conductor 604, as measured along the central longitudinal axis of the conductor 604, is a velocity string 228. In some embodiments, for example, at least 75% of the length of the conductor 604, as measured along the central longitudinal axis of the conductor 604, is a velocity string 228. In some embodiments, for example, the conductor 604 is defined by 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 228A, and 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 228A of the velocity string 228 is at least about 1.5.
In some embodiments, for example, the gas-depleted reservoir fluid-producing conductor 400 defines a fluid passage 400A, and the minimum cross-sectional flow area of the fluid passage 400A of the gas-depleted reservoir fluid-producing conductor 400 is greater than the maximum cross-sectional flow area of the fluid passage 228A of the velocity string 228. In some embodiments, for example, the ratio of the cross-sectional flow area of the fluid passage 400A of the gas-depleted reservoir fluid-producing conductor 400 to the cross-sectional flow area of the fluid passage 228A of the velocity string 228 is at least 1.1, such as, for example, at least 1.25, such as, for example, at least 1.5.
The flow diverter body 602 further includes a gas-depleted reservoir fluid receiver 614 (defined by, for example, one or more ports defined within the body) for receiving the gas-depleted reservoir fluid that has separated from the reservoir fluid within the reservoir fluid separation space 112X, a gas-depleted reservoir fluid discharge communicator 616 (defined by, for example, one or more ports defined within the body 602) discharging the received gas-depleted reservoir fluid for supplying to the pump 302, and a diverter body-defined gas-depleted reservoir fluid conductor 618 (defined by, for example, one or more passages defined within the body 602) for effecting fluid communication between the gas-depleted reservoir fluid receiver 608 and the gas-depleted reservoir fluid discharge communicator 610.
In some embodiments, for example, the flow diverter body 602 co-operates with the wellbore string-defined counterpart 600C to define the gas-depleted reservoir fluid-conducting passage 112Y. The gas-depleted reservoir fluid-conducting passage 112Y functions to effect fluid communication between the reservoir fluid separation space 112X and the gas-depleted reservoir fluid receiver 608, and thereby conduct the separated gas-depleted reservoir fluid from the reservoir fluid separation space 112X to the gas-depleted reservoir fluid receiver 614.
In some embodiments, for example, for effecting definition of the sealed interface 500, the sealed interface effector 502 (e.g. packer) extends laterally outwardly relative to the longitudinal axis of the diverter body-supplying fluid conductor 604. In some of these embodiments, for example, the sealed interface effector 502 is disposed about a downhole end of the diverter body-supplying fluid conductor 604.
The fluid communication, established by the diverter body-defined gas-depleted reservoir fluid conductor 618, is with effect that gas-depleted reservoir fluid, received by the gas-depleted reservoir fluid receiver 614, is conducted uphole to the gas-depleted reservoir fluid discharge communicator 616 and discharged from the gas-depleted reservoir fluid discharge communicator 616 for supplying to the pump 302.
In some embodiments, for example, the discharging of the gas-depleted reservoir fluid from the gas-depleted reservoir fluid discharge communicator 616 is into the pump-supplying fluid conductor 606. The pump-supplying fluid conductor 606 is disposed relative to the gas-depleted reservoir fluid discharge communicator 616 and the pump 302 such that gas-depleted reservoir fluid, discharged from the gas-depleted reservoir fluid discharge communicator 616, is conducted to the pump via the pump-supplying fluid conductor 606.
In some embodiments, for example, the gas-depleted reservoir fluid-conducting passage 6004 includes the diverter body-defined gas-depleted reservoir fluid conductor 618 and the pump-supplying fluid conductor 606.
Referring to
In some embodiments, for example, the pump 302 is an electrical submersible pump 302, and the electrical submersible pump 302 includes the 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 308 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. 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 motor 308 is also disposed within the accumulator space 622. By being disposed within the accumulator space 622, the motor 308 is disposed for cooling by the gas-depleted reservoir fluid that is being flowed past the motor 308 while the gas-depleted reservoir fluid is being conducted to the pump 302, via the pump intake 304, from the gas-depleted reservoir fluid discharge communicator 616
In some embodiments, for example, the pump-supplying fluid conductor 606 further includes an intermediate conductor 607, extending between the gas-depleted reservoir fluid discharge communicator 616 and the accumulator 620, for conducting gas-depleted reservoir fluid from the gas-depleted reservoir fluid discharge communicator to the accumulator 620. In some embodiments, for example, the maximum cross-sectional flow area of the intermediate conductor is less than the minimum cross-sectional flow area of the accumulator 620. In some embodiments, for example, the intermediate conductor 607 is connected to the flow diverter body 602 and communicates with the gas-depleted reservoir fluid discharge communicator 616. In some embodiments, for example, the intermediate conductor 607 is connected to the accumulator 620 and communicates with the space within the accumulator space 622 (and, therefore, the pump intake 304) via an accumulator receiver 624 (defined by, for example, one or more ports). In some embodiments, for example, the intermediate conductor 607 is suspended from the accumulator 620, such that the flow diverter body 602 and the diverter body-supplying fluid conductor 604 are also suspended from the accumulator 620. In this respect, there is an absence, or substantial absence, of suspension of the assembly-defined counterpart 600C of the flow diverter 600 from the pump 302. Also in this respect, there is an absence, or substantial absence, of tensile force being applied to the pump 302 by the assembly-defined counterpart 600C of the flow diverter 600.
Referring to
The shroud 628 is connected to (and thereby suspended from) the hanger 626 via fasteners (such as, for example, bolts) that are threaded into the hanger 626 via corresponding receiving apertures within the shroud 628. A sealed interface is established between the shroud 628 and the hanger 626, for preventing, or substantially preventing, flow communication between the space 622 of the accumulator 620 and the wellbore 102 via the space between the shroud 628 and the hanger 626. The sealed interface is established by one or more sealing members (e.g. o-rings), which are retained within corresponding grooves defined within the hanger 626, and disposed in sealing engagement, or substantially sealing engagement, with the shroud 628.
In some embodiments, for example, the electrical conductor 900 extends through the hanger 626 for effecting electrical connection of the power and voltage source to the motor 308. In this respect, in some embodiments, for example, the hanger 626 defines one or more electrical conductor passages through which the electrical conductor 900 extends. In some embodiments, for example, a sealed interface is defined between the electrical conductor 900 and the hanger, with effect that flow communication through the passages, between the electrical conductor 900 and the hanger 626, is sealed or substantially sealed. In this respect, in some embodiments, for example, the sealed interface is effected by sealing material disposed between the electrical conductor 900 and the hanger 626. In some embodiments, for example, the hanger 626 includes a main body 626A and a cover 626B that is releasably connected to the main body 626A, and the cover 626B is secured to the main body 626A after the sealing material has been emplaced for effecting the sealed interface between the electrical conductor 900 and the hanger 626.
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 under 35 U.S.C. § 120 from U.S. Provisional Patent Application No. 62/798,771 filed on Jan. 30, 2019, and the entire content is incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 62798771 | Jan 2019 | US |
