Patent Application
20220403727
The present disclosure relates to mitigating downhole pump gas interference during hydrocarbon production.
Reservoir fluids often contain entrained gases and solids. In producing reservoir fluids containing a relatively substantial fraction of gaseous material, the presence of such gaseous material hinders production by contributing to sluggish flow, and interfering with pump operation. As well, the presence of solids interferes with pump operation, including contributing to erosion of mechanical components.
Separators are provided help remedy or mitigate downhole pump gas interference during hydrocarbon production. However, separators often occupy relatively significant amounts of space within a wellbore, rendering efficient separation of gaseous material that is entrained within the reservoir fluid difficult. Some separators are complex structures and are associated with increased material and manufacturing costs. Accordingly, efficient and cost effective separation of gaseous material that is entrained within the reservoir fluid is desirable.
In one aspect there is provided a reservoir production system, disposed within a wellbore that is lined with a wellbore string, comprising:
a gas separator;
a pump; and
a gas-depleted reservoir fluid conductor;
wherein:
In another aspect there is provided a reservoir production system, disposed within a wellbore that is lined with a wellbore string, comprising:
a gas separator;
a pump; and
a gas-depleted reservoir fluid conductor;
wherein:
In another aspect there is provided a downhole-deployable reservoir production system precursor, deployable within a wellbore lined with a wellbore string for establishing a reservoir production system within the wellbore, comprising:
an uphole counterpart including:
and
a downhole counterpart including:
and
degradable material;
wherein:
In another aspect there is provided a reservoir production system, disposed within a wellbore that is lined with a wellbore string, comprising:
a gas separator;
a pump; and
a gas-depleted reservoir fluid conductor;
wherein:
In another aspect there is provided a top hold down pump comprising:
a barrel;
wherein:
Reference will now be made, by way of example, to the accompanying drawings which show example embodiments of the present application, and in which:
Similar reference numerals may have been used in different figures to denote similar components.
Referring to
A wellbore 102 of a subterranean formation can be straight, curved or branched. The wellbore 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 of a horizontal section is disposed along an axis that is between about 70 and about 110 degrees relative to the vertical, while the central longitudinal axis of the passage of a vertical section is disposed along an axis that is less than about 20 degrees from the vertical “V”, and a transition section is disposed between the horizontal and vertical sections.
“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. Reservoir fluid may also include fluids injected into the reservoir for effecting stimulation of resident fluids within the reservoir.
A wellbore string 200 is emplaced within the wellbore 102 for stabilizing the subterranean formation 100. In some embodiments, for example, the wellbore string 200 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.
With respect to a cased-hole completion, in some embodiments, for example, a wellbore string 200, in the form of a wellbore casing that includes one or more casing strings, each of which is positioned within the wellbore 102, having one end extending from the wellhead 106, is provided. 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 102 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 104. 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 the 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 106. 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 10 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 106. 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 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 106.
An open-hole completion is established by drilling down to the producing formation, and then lining the wellbore (such as, for example, with a wellbore string 200). 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.
The system 10 receives, via the wellbore 102, the reservoir fluid flow from the subterranean formation 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, a reservoir fluid-receiving zone 402 of the wellbore 102 is disposed for receiving reservoir fluid flow from the subterranean formation 100, with effect that the system 10 receives the reservoir fluid.
In some embodiments, for example, the system 10 includes a production system 300 disposed within the wellbore 102.
The production system 300 includes a gas-depleted reservoir fluid production system 400, a pump 600, and a gas-depleted reservoir fluid conductor 500. The gas-depleted reservoir fluid conductor 500 is suspended within the wellbore 102 from the wellhead 106 disposed at the surface 104. The gas-depleted reservoir fluid production system 400 is fluidly coupled to the pump 600 for supplying a gas-depleted reservoir fluid to the gas-depleted reservoir fluid pump 600. The pump 600 is configured for pressurizing the gas-depleted reservoir fluid received from the gas-depleted reservoir fluid production system 400, with effected that pressurized gas-depleted reservoir fluid is conducted to the surface 104 via the gas-depleted reservoir fluid conductor 500.
In some embodiments, for example, the pump 600 is a rod pump. In some embodiments, for example, the rod pump is a top hold down rod pump. In some embodiments, for example, the rod pump is a bottom hold down rod pump.
Referring to
In some embodiments, for example, the reinforcing layer 606 and the outer surface 604B are co-operatively configured such that the coupling of the reinforcing layer 606 to the outer surface 604B includes adsorption of the reinforcing layer 606 to the outer surface 604B. In some embodiments, for example, the adsorption includes adhesion. In some embodiments, for example, the coupling of the reinforcing layer 606 to the outer surface 604B includes chemical bonding between the reinforcing layer 606 and the outer surface 604B.
In some embodiments, for example, the material of construction of the flow passage-defining portion 604 includes polymeric material, such as, for example, polypropylene. In some embodiments, for example, the flow passage-defining portion 604 is formed from polymeric material, such as, for example, polypropylene.
In some embodiments, for example, the reinforcing layer 606 includes a plurality of continuous fibers. Suitable continuous fibers include glass fibers, carbon fibers, and aramid fibers. In some embodiments, for example, the continuous fibers are helically wound about the flow passage-defining portion 604 with respect to a longitudinal axis 604X of the flow passage-defining portion 604. In some embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees. In some embodiments, for example, the continuous fibers are embedded within a matrix, such as, for example, a polymeric matrix.
In some embodiments, for example, the reinforcing layer 606 includes continuous fiber reinforced thermoplastic (“CFRT”) material. In some embodiments, for example, the reinforcing layer 606 is formed from CFRT material. Suitable continuous fibers include glass fibers, carbon fibers, and aramid fibers. Suitable thermoplastic materials include polyethylene, polypropylene, nylon, and acrylonitrile butadiene styrene (“ABS”).
In some embodiments, for example, the reinforcing layer 606 is in the form of a tape of CFRT material. In some embodiments, for example, the tape is helically wound about the flow passage-defining portion 604 with respect to a longitudinal axis 604X of the flow passage-defining portion 604. In some embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees.
In some embodiments, for example, the reinforcing layer 606 is a first reinforcing layer 606 which includes an outer surface 606A, and the barrel 602 further includes a second reinforcing layer 608. The second reinforcing layer 608 is coupled to the first reinforcing layer 606 such that the second reinforcing layer 608 overlies at least a portion of the outer surface 606A of the first reinforcing layer 606. In some embodiments, for example, the first reinforcing layer 606 has a perimeter defined by the outer surface 606A, and the overlying is with effect that the second reinforcing layer 608 extends about the entirety of the perimeter of the first reinforcing layer 606. The second reinforcing layer 608 functions to further reinforce the strength of the flow passage-defining portion 604.
In some embodiments, for example, the second reinforcing layer 608 and the outer surface 606A are co-operatively configured such that the coupling of the second reinforcing layer 608 to the outer surface 606A includes adsorption of the second reinforcing layer 608 to the outer surface 606A. In some embodiments, for example, the adsorption includes adhesion. In some embodiments, for example, the coupling of the second reinforcing layer 608 to the outer surface 606A includes chemical bonding between the second reinforcing layer 608 and the outer surface 606A.
In some embodiments, for example, the second reinforcing layer 608 includes a plurality of continuous fibers. Suitable continuous fibers include glass fibers, carbon fibers, and aramid fibers. In some embodiments, for example, the continuous fibers are helically wound about the flow passage-defining portion 604 with respect to a longitudinal axis 604X of the flow passage-defining portion 604. In some embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees. In some embodiments, for example, the continuous fibers are embedded within a matrix, such as, for example, a polymeric matrix.
In some embodiments, for example, the second reinforcing layer 608 includes continuous fiber reinforced thermoplastic (“CFRT”) material. In some embodiments, for example, the second reinforcing layer 608 is formed from CFRT material. Suitable continuous fibers include glass fibers, carbon fibers, and aramid fibers. Suitable thermoplastic materials include polyethylene, polypropylene, nylon, and acrylonitrile butadiene styrene (“ABS”).
In some embodiments, for example, the second reinforcing layer 608 is in the form of a tape of CFRT material. In some embodiments, for example, the tape is helically wound about the flow passage-defining portion 604 with respect to a longitudinal axis 604X of the flow passage-defining portion 604. In some embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees.
In some embodiments, for example, the first reinforcing layer 606 is in the form of a tape of CFRT material, and the second reinforcing layer 608 is in the form of a tape of CFRT material. In some embodiments, for example, the tape of the first reinforcing layer 606 is helically wound about the flow passage-defining portion 605 with respect to the longitudinal axis 604X of the flow passage-defining portion 604, and, in some of these embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees. In some embodiments, for example, the tape of the second reinforcing layer 608 is helically wound about the first reinforcing layer 606 with respect to the longitudinal axis 604X of the flow passage-defining portion 604, and, in some of these embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees. In some embodiments, for example, the winding of the tape of the first reinforcing layer 606 is in a direction that is opposite to the direction of the winding of the tape of the second reinforcing layer 608. In some embodiments, for example, the winding of the tape of the first reinforcing layer 606 is in one of a clockwise or counterclockwise direction, and the winding of the tape of the second reinforcing layer 608 is in the other one of a clockwise or counterclockwise direction.
In some embodiments, for example, an outer sheath 610 overlies the one or more reinforcing layers 606, 608 for enclosing the one or more reinforcing layers 606, 608 and the flow passage-defining portion 604. In this respect, in some embodiments, for example, the outer sheath 610 protects the enclosed materials from degradation, such as, for example, degradation in response to abrasion, chemical conversion, or dissolution. In some embodiments, for example, the outer sheath 610 functions to hold the enclosed materials in place.
The system 10 is configured for producing reservoir fluid while, amongst other things, mitigating gas lock within the pump 600.
In this respect, the gas-depleted reservoir fluid production system 400 co-operates with the wellbore string 200 to define a flow diverter 400A.
The flow diverter 400A defines a reservoir fluid flow passage configuration 404, a separation zone 406, a downwardly-conducting flow passage configuration 422, and an upwardly-conducting flow passage configuration 407. In some embodiments, for example, the separation zone 406 is disposed within a vertical portion of the wellbore 102. The separation zone 406 is disposed vertically above (and uphole relative to) the reservoir fluid-receiving zone 402, and vertically below (and downhole relative to) the wellhead 106.
The reservoir fluid-receiving zone 402, the reservoir fluid flow passage configuration 404, the separation zone 406, the downwardly-conducting flow passage configuration 422, and the upwardly-conducting flow passage configuration 407 are co-operatively configured such that:
In some embodiments, for example, the gas-depleted reservoir fluid production system 400 includes a reservoir fluid flow conductor 416, defining a reservoir fluid flow conducting passage 441 and a sealed interface effector 418 (such as, for example, a packer). At least a portion of the reservoir fluid flow passage configuration 404 is defined by the reservoir fluid flow conducting passage 416A. The sealed interface effector 418 is mounted to the reservoir fluid flow conductor 416 such that the reservoir fluid flow conductor 416 is sealingly engaged to the wellbore string 200 via the sealed interface effector 418.
In some embodiments, for example, at least a portion of the reservoir fluid flow conductor 416 is a velocity string 420. In some embodiments, for example, the at least a portion of the reservoir fluid flow conductor 416 is the entirety of the reservoir fluid flow conductor 416, such that, in such embodiments, the velocity string is the reservoir fluid flow conductor 416. In some embodiments, for example, the sealing engagement of the reservoir fluid flow conductor 416 to the wellbore string 200 is a sealing engagement of the velocity string 420 to the wellbore string. In this respect, in some embodiments, for example, the sealed interface effector 418 is mounted to the velocity string 420.
In those embodiments where at least a portion of the reservoir fluid flow conductor 416 is a velocity string 420, in some of these embodiments, for example, the velocity string 420 is characterized by a maximum cross-sectional flow area, and the maximum cross-sectional flow area is smaller than the minimum cross-sectional flow area of the reservoir fluid-receiving space 402. In some of these embodiments, for example, the ratio of the minimum cross-sectional flow area of the reservoir fluid-receiving space 402 to the maximum cross-sectional flow area of the reservoir fluid flow passage configuration 404, defined by the velocity string 420, is at least 1.5.
In those embodiments where at least a portion of the reservoir fluid flow conductor 416 is a velocity string 420, in some of these embodiments, for example, at least a portion of the velocity string 420 is disposed within a heel portion 108 of the wellbore 102. In some embodiments, for example, the velocity string 420 extends through the heel portion 108.
In some embodiments, for example, the material of construction of the reservoir fluid conductor 416 includes polymeric material, such as, for example, polypropylene. In some embodiments, for example, the reservoir fluid conductor 416 is formed from polymeric material, such as, for example, polypropylene.
Referring to
In some embodiments, for example, the reinforcing layer 4162 and the outer surface 4161B are co-operatively configured such that the coupling of the reinforcing layer 4162 to the outer surface 4161B includes adsorption of the reinforcing layer 4162 to the outer surface 4161B. In some embodiments, for example, the adsorption includes adhesion. In some embodiments, for example, the coupling of the reinforcing layer 4162 to the outer surface 4161B includes chemical bonding between the reinforcing layer 4162 and the outer surface 4161B.
In some embodiments, for example, the material of construction of the flow passage-defining portion 4161 includes polymeric material, such as, for example, polypropylene. In some embodiments, for example, the flow passage-defining portion 4161 is formed from polymeric material, such as, for example, polypropylene.
In some embodiments, for example, the reinforcing layer 4162 includes a plurality of continuous fibers. Suitable continuous fibers include glass fibers, carbon fibers, and aramid fibers. In some embodiments, for example, the continuous fibers are helically wound about the flow passage-defining portion 4161 with respect to a longitudinal axis 4161X of the flow passage-defining portion 4161. In some embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees. In some embodiments, for example, the continuous fibers are embedded within a matrix, such as, for example, a polymeric matrix.
In some embodiments, for example, the reinforcing layer 4162 includes continuous fiber reinforced thermoplastic (“CFRT”) material. In some embodiments, for example, the reinforcing layer 4162 is formed from CFRT material. Suitable continuous fibers include glass fibers, carbon fibers, and aramid fibers. Suitable thermoplastic materials include polyethylene, polypropylene, nylon, and acrylonitrile butadiene styrene (“ABS”).
In some embodiments, for example, the reinforcing layer 4162 is in the form of a tape of CFRT material. In some embodiments, for example, the tape is helically wound about the flow passage-defining portion 4161 with respect to a longitudinal axis 4161X of the flow passage-defining portion 4161. In some embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees.
In some embodiments, for example, the reinforcing layer 4162 is a first reinforcing layer 4162 which includes an outer surface 4162A, and the reservoir fluid conductor 416 further includes a second reinforcing layer 4164. The second reinforcing layer 4164 is coupled to the first reinforcing layer 4162 such that the second reinforcing layer 4164 overlies at least a portion of the outer surface 4162A of the first reinforcing layer 4162. In some embodiments, for example, the first reinforcing layer 4162 has a perimeter defined by the outer surface 4162A, and the overlying is with effect that the second reinforcing layer 4164 extends about the entirety of the perimeter of the first reinforcing layer 4162. The reinforcing layer 4164 functions to further reinforce the strength of the flow passage-defining portion 4161.
In some embodiments, for example, the second reinforcing layer 4164 and the outer surface 4162A are co-operatively configured such that the coupling of the second reinforcing layer 4164 to the outer surface 4162A includes adsorption of the second reinforcing layer 4164 to the outer surface 4162A. In some embodiments, for example, the adsorption includes adhesion. In some embodiments, for example, the coupling of the second reinforcing layer 4164 to the outer surface 4162A includes chemical bonding between the second reinforcing layer 4162 and the outer surface 4162A.
In some embodiments, for example, the second reinforcing layer 4164 includes a plurality of continuous fibers. Suitable continuous fibers include glass fibers, carbon fibers, and aramid fibers. In some embodiments, for example, the continuous fibers are helically wound about the flow passage-defining portion 4161 with respect to a longitudinal axis 4161X of the flow passage-defining portion 4161. In some embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees. In some embodiments, for example, the continuous fibers are embedded within a matrix, such as, for example, a polymeric matrix.
In some embodiments, for example, the second reinforcing layer 4164 includes continuous fiber reinforced thermoplastic (“CFRT”) material. In some embodiments, for example, the second reinforcing layer 4164 is formed from CFRT material. Suitable continuous fibers include glass fibers, carbon fibers, and aramid fibers. Suitable thermoplastic materials include polyethylene, polypropylene, nylon, and acrylonitrile butadiene styrene (“ABS”).
In some embodiments, for example, the second reinforcing layer 4164 is in the form of a tape of CFRT material. In some embodiments, for example, the tape is helically wound about the flow passage-defining portion 4161 with respect to a longitudinal axis 4161X of the flow passage-defining portion 4161. In some embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees.
In some embodiments, for example, the first reinforcing layer 4162 is in the form of a tape of CFRT material, and the second reinforcing layer 4164 is in the form of a tape of CFRT material. In some embodiments, for example, the tape of the first reinforcing layer 4162 is helically wound about the flow passage-defining portion 4161 with respect to the longitudinal axis 4161X of the flow passage-defining portion 4161, and, in some of these embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees. In some embodiments, for example, the tape of the second reinforcing layer 4164 is helically wound about the first reinforcing layer 4162 with respect to the longitudinal axis 4161X of the flow passage-defining portion 4161, and, in some of these embodiments, for example, helical winding is at a winding angle of from 40 degrees to 60 degrees. In some embodiments, for example, the winding of the tape of the first reinforcing layer 4162 is in a direction that is opposite to the direction of the winding of the tape of the second reinforcing layer 4164. In some embodiments, for example, the winding of the tape of the first reinforcing layer 4162 is in one of a clockwise or counterclockwise direction, and the winding of the tape of the second reinforcing layer 4164 is in the other one of a clockwise or counterclockwise direction.
In some embodiments, for example, an outer sheath 4166 overlies the one or more reinforcing layers 4162, 4164 for enclosing the one or more reinforcing layers 4162, 4164 and the flow passage-defining portion 4161. In this respect, in some embodiments, for example, the outer sheath 4166 protects the enclosed materials from degradation, such as, for example, degradation in response to abrasion, chemical conversion, or dissolution. In some embodiments, for example, the outer sheath 4166 functions to hold the enclosed materials in place.
In those embodiments where the material of construction of the reservoir fluid flow conductor 416 includes polymeric material (including, for example, those embodiments where the reservoir fluid flow conductor 416 includes a flow passage-defining portion 4161 and a reinforcing layer 4162), in some of these embodiments, for example, the sealed interface effector 418 includes a swellable packer.
In some embodiments, for example, gas-depleted reservoir fluid production system 400 further includes a gas separator 408, and the gas separator 400 defines the downwardly-conducting flow passage configuration 422 and the upwardly-conducting flow passage configuration 407. The gas separator 408 and the wellbore string 200 are co-operatively configured such that an intermediate passage 426 is defined between the gas separator 408 and the wellbore string 200.
Co-operatively, the reservoir fluid flow conductor 416 includes a flow receiving communicator 440 (such as, for example, an inlet port), a flow discharging communicator 442 (such as, for example, an outlet port), and a reservoir fluid flow conducting passage 441. At least a portion of the reservoir fluid flow passage configuration 404 is defined by the reservoir fluid flow conducting passage 441. The flow receiving communicator 440 is disposed for receiving the reservoir fluid from the reservoir fluid-receiving zone 402 such that the conducting of the reservoir fluid, by the reservoir fluid flow conducting passage 441, is effected while the reservoir fluid is being received by the flow receiving communicator 440 from the reservoir fluid-receiving zone 402. The reservoir fluid flow conducting passage 441 is effective for conducting the reservoir fluid received by the flow receiving communicator 440 to the flow discharging communicator 442. The flow discharging communicator 442 is effective for discharging the reservoir fluid from the reservoir fluid flow conductor 416. The flow discharging communicator 442 is disposed in flow communication with the separation zone 406 via the intermediate passage 426 such that the discharging reservoir fluid is conducted to the separation zone 406 via the intermediate flow passage 426.
The reservoir fluid flow conductor 416, the sealed interface 418, and the intermediate passage 426 are co-operatively configured such that, while the reservoir fluid flow is being received within the reservoir fluid flow receiving zone 402, the reservoir fluid flow is conducted from the reservoir fluid flow receiving zone 402 to the separation zone 406 via at least the reservoir fluid flow conducting passage 441 and the intermediate passage 426, such that the reservoir fluid flow passage configuration 404 includes the reservoir fluid flow conducting passage 441 and the intermediate passage 426.
In some embodiments, for example, the gas separator 408 defines a gas-depleted reservoir fluid collector 411. The collector 411 defines a shroud 424, and the downwardly-conducting flow passage configuration 422 and the upwardly-conducting flow passage configuration 407 are disposed within the shroud 424. The shroud 424 separates the downwardly-conducting flow passage configuration 422 and the upwardly-conducting flow passage configuration 407 from the intermediate passage 426.
In some of these embodiments, for example, the shroud 424 is defined by a vertically extending wall 428 projecting from a base 430, such that an opening 432 is defined by an upper edge 434 of the wall 428, for receiving the downwardly flow of the separated gas-depleted reservoir fluid, and the wall 428 and the base 430 co-operate to define a gas-depleted reservoir fluid collection space 436, which defines the downwardly-conducting flow conductor configuration 422, for receiving the downwardly-flowing gas-depleted reservoir fluid flow, and diverting such downwardly-flowing gas-depleted reservoir fluid flow such that the upwardly-flowing gas-depleted reservoir fluid flow is obtained and conducted via the upwardly-conducting flow conductor configuration 407, which is defined by a conduit 407A, to the pump 600.
In some of these embodiments, for example, the gas separator 408 is disposed above the flow discharging communicator 442, such that a bubble coalescent zone 444 is defined between the flow discharging communicator 442 and the flow diverter 400A. In some embodiments, for example, the minimum spacing distance from the flow discharging communicator 442 to the gas separator 408 is at least five (5) feet, such as, for example, at least ten (10) feet, such as, for example, at least 20 feet, such as, for example, at least 30 feet. In some embodiments, for example, the minimum spacing distance from the flow discharging communicator 442 to the intermediate passage is at least five (5) feet, such as, for example, at least ten (10) feet, such as, for example, at least 20 feet, such as, for example, at least 30 feet. The minimum cross-sectional flow area of the bubble coalescent zone 444 is greater than the maximum cross-sectional flow area of the reservoir fluid conducting passage portion 404A of the reservoir fluid conductor 416 (such as, for example, the velocity string 420). In some embodiments, for example, the ratio, of the minimum cross-sectional flow area of the bubble coalescent zone 444 to the maximum cross-sectional flow area of the reservoir fluid conducting passage portion 404A of the reservoir fluid conductor 416 (such as, for example, the velocity string 420), is at least 1.5. The bubble coalescent zone 444 is configured to reduce the velocity of the reservoir fluid flow being discharged from the reservoir fluid conductor 416, and mitigate turbulent flow conditions, so as to promote bubble coalescence, which facilitates the separation within the separation zone 404. In this respect, the conducting of the reservoir fluid from the reservoir fluid-receiving space 402 to the separation zone 406 is effected via at least the reservoir fluid flow conducting passage 441 of the reservoir fluid conductor 416 (such as, for example, the velocity string 420), the bubble coalescent zone 444, and the intermediate space 426.
Referring to
The uphole counterpart 401A, the downhole counterpart 401B, and the degradable material 401C are co-operatively configured such that the uphole counterpart 401A is connected to the downhole counterpart 401B via a connection, and, while the gas-depleted reservoir fluid production system precursor 401 is disposed within the wellbore 100, the connection is defeatable in response to degradation of the degradable material, with effect that the gas-depleted reservoir fluid production system 400 is obtained within the wellbore. In some embodiments, for example, the connection is via degradable pins. In some embodiments, for example, the connection, via which the uphole counterpart 401A is connected to the downhole counterpart 401B, is a connection between the gas separator 408 and the reservoir fluid flow conductor 416.
In some embodiments, for example, the degradable material is degradable in response to chemical conversion of at least a portion of the degradable material, such as, for example, chemical conversion stimulated in response to interaction with a chemical agent. In some embodiments, for example, the degradable material is degradable in response to dissolution of at least a portion of the degradable material, such as, for example, dissolution stimulated in response to interaction with a dissolution agent. In some embodiments, for example, the degradable material is degradable in response to disintegration of at least a portion of the degradable material, such as, for example, disintegration stimulated in response to application of a stimulus, such as one or more of a mechanical stimulus, a sonic stimulus, or a light stimulus. In some embodiments, for example, the degradable material is degradable in response to contacting with wellbore fluids.
In the above description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of 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. Therefore, it will be understood that certain adaptations and modifications of the described embodiments can be made and that the above discussed embodiments are considered to be illustrative and not restrictive. All references mentioned are hereby incorporated by reference in their entirety.
| Number | Date | Country | |
|---|---|---|---|
| 63213028 | Jun 2021 | US |
