US20190085667A1 - Electric submersible pump configuration - Google Patents

Electric submersible pump configuration Download PDF

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Publication number
US20190085667A1
US20190085667A1 US15/707,367 US201715707367A US2019085667A1 US 20190085667 A1 US20190085667 A1 US 20190085667A1 US 201715707367 A US201715707367 A US 201715707367A US 2019085667 A1 US2019085667 A1 US 2019085667A1
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US
United States
Prior art keywords
pump
diffuser
threaded end
uphole
threaded
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Abandoned
Application number
US15/707,367
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English (en)
Inventor
Jinjiang Xiao
Chidirim Enoch Ejim
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Saudi Arabian Oil Co
Original Assignee
Saudi Arabian Oil Co
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Saudi Arabian Oil Co filed Critical Saudi Arabian Oil Co
Priority to US15/707,367 priority Critical patent/US20190085667A1/en
Assigned to SAUDI ARABIAN OIL COMPANY reassignment SAUDI ARABIAN OIL COMPANY ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: EJIM, CHIDIRIM ENOCH, XIAO, JINJIANG
Priority to JP2020516418A priority patent/JP2020534472A/ja
Priority to CN201880060610.7A priority patent/CN111094696A/zh
Priority to CA3075850A priority patent/CA3075850A1/en
Priority to PCT/US2018/049863 priority patent/WO2019055295A1/en
Priority to EP18778752.8A priority patent/EP3685009A1/en
Publication of US20190085667A1 publication Critical patent/US20190085667A1/en
Abandoned legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121—Lifting well fluids
    • E21B43/128—Adaptation of pump systems with down-hole electric drives
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121—Lifting well fluids
    • E21B43/126—Adaptations of down-hole pump systems powered by drives outside the borehole, e.g. by a rotary or oscillating drive
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
    • F04D—NON-POSITIVE-DISPLACEMENT PUMPS
    • F04D1/00—Radial-flow pumps, e.g. centrifugal pumps; Helico-centrifugal pumps
    • F04D1/06—Multi-stage pumps
    • F04D1/063—Multi-stage pumps of the vertically split casing type
    • F04D1/066—Multi-stage pumps of the vertically split casing type the casing consisting of a plurality of annuli bolted together
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
    • F04D—NON-POSITIVE-DISPLACEMENT PUMPS
    • F04D13/00—Pumping installations or systems
    • F04D13/02—Units comprising pumps and their driving means
    • F04D13/06—Units comprising pumps and their driving means the pump being electrically driven
    • F04D13/08—Units comprising pumps and their driving means the pump being electrically driven for submerged use
    • F04D13/10—Units comprising pumps and their driving means the pump being electrically driven for submerged use adapted for use in mining bore holes
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
    • F04D—NON-POSITIVE-DISPLACEMENT PUMPS
    • F04D29/00—Details, component parts, or accessories
    • F04D29/40—Casings; Connections of working fluid
    • F04D29/52—Casings; Connections of working fluid for axial pumps
    • F04D29/54—Fluid-guiding means, e.g. diffusers
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F05—INDEXING SCHEMES RELATING TO ENGINES OR PUMPS IN VARIOUS SUBCLASSES OF CLASSES F01-F04
    • F05D—INDEXING SCHEME FOR ASPECTS RELATING TO NON-POSITIVE-DISPLACEMENT MACHINES OR ENGINES, GAS-TURBINES OR JET-PROPULSION PLANTS
    • F05D2230/00—Manufacture
    • F05D2230/50—Building or constructing in particular ways
    • F05D2230/51—Building or constructing in particular ways in a modular way, e.g. using several identical or complementary parts or features

Definitions

  • This specification relates to electric submersible pumps (ESPs) for oilfield applications.
  • ESPs electric submersible pumps
  • Some oil and gas wells contain enough pressure for hydrocarbons to rise to the surface without stimulation.
  • the natural drive energy of the reservoir is not strong enough to push the hydrocarbons to the surface. Consequently, such wells require artificial lift to increase the flow of hydrocarbons from the wells.
  • Even in the wells that initially possessed enough pressure for the hydrocarbons to flow to the surface the pressure depletes over time and may require artificial lift. Therefore, artificial lift is typically used on most wells at some point during their production life. Artificial lift can be performed by the use of a mechanical device positioned inside the well.
  • the electric submersible pump (ESP) is an example of an artificial lift method for lifting volumes of fluids from wellbores.
  • the threads of the uphole threaded end can be formed on an inner surface of the diffuser, and the threads of the downhole threaded end can be formed on an outer surface of the diffuser.
  • the threads of the uphole threaded end can be formed on an outer surface of the diffuser, and the threads of the downhole threaded end can be formed on an inner surface of the diffuser.
  • the pump assembly can include a first seal positioned between the uphole threaded end and the downhole threaded end of the other, uphole-positioned pump stage and a second seal positioned between the downhole threaded end and the uphole threaded end of the other, downhole-positioned pump stage.
  • the pump assembly can include a pump base including a threaded end threadedly coupled to a downhole threaded end of a downhole-most pump stage. Threads of the threaded end of the pump base and the downhole threaded end of the downhole-most pump stage can be formed in directions opposite to the rotational direction of the impeller.
  • the pump assembly can include a seal positioned between the threaded end of the pump base and the downhole threaded end of the downhole-most pump stage.
  • the downhole-most pump stage can include a diffuser spacer including threaded ends to threadedly couple to the threaded end of the pump base and the downhole threaded end of the downhole-most pump stage.
  • the threads of the diffuser spacer can be formed in directions opposite to the rotational direction of the impeller.
  • the pump assembly can include a pump head including a threaded end threadedly coupled to an uphole threaded end of an uphole-most pump stage. Threads of the threaded end of the pump head and the uphole threaded end of the uphole-most pump stage can be formed in directions opposite to the rotational direction of the impeller.
  • the pump assembly can include a seal positioned between the threaded end of the pump head and the uphole threaded end of the uphole-most pump stage.
  • the pump assembly can include a diffuser spacer positioned between the diffuser and the pump base.
  • the diffuser spacer can include threaded ends connected with the threaded end of the pump base and the downhole threaded end of the diffuser by respective threaded couplings.
  • the threads of the threaded ends of the diffuser spacer, pump base, and diffuser are formed in directions opposite to the rotational direction of the impeller.
  • the threaded coupling between the other of the threaded ends of the diffuser spacer and the downhole threaded end of the diffuser can include a seal to block fluid flowing through the pump base and the pump stage from leaking outside the pump stage.
  • the pump stage can be a first pump.
  • the impeller can be a first impeller.
  • the diffuser can be a first diffuser.
  • the threaded coupling can be a first threaded coupling.
  • the pump assembly can include a second pump stage uphole of the first pump stage.
  • the second pump stage can include a second rotating impeller to rotate to provide kinetic energy to flow the fluid received from the first pump stage through the second pump stage in the uphole direction and a second stationary diffuser within which the second rotating impeller is positioned.
  • the second diffuser can convert the kinetic energy received from the second impeller to head to flow the fluid through the second pump stage.
  • the second diffuser can include a downhole threaded end connected with an uphole threaded end of the first diffuser by a second threaded coupling. The threads of the threaded ends of the first and second diffusers are formed in directions opposite to a rotational direction of the impellers.
  • the pump assembly can include a pump head including a threaded end.
  • An uphole threaded end of the second diffuser can be connected with the threaded end of the pump head by a third threaded coupling.
  • the threads of the threaded ends of the second diffuser and the pump head are formed in directions opposite to the rotational direction of the impellers.
  • the threaded coupling between the uphole end of the second diffuser and the threaded end of the pump head can include a seal to block fluid flowing through the pump head and the second pump stage from leaking outside the second pump stage.
  • FIG. 1 is a diagram of an electric submersible pump (ESP), according to an implementation.
  • ESP electric submersible pump
  • FIGS. 2A & 2B are views of an example of a threaded coupling between diffusers of the ESP of FIG. 1 .
  • FIGS. 3A & 3B are views of an example of assembling components of the ESP of FIG. 1 .
  • FIGS. 4A & 4B are views of an example of assembling components of the ESP of FIG. 1 .
  • the diffusers can have threaded ends that tighten in a direction opposite of the rotation of the impellers to mitigate the potential of unthreading and improve assembly integrity of the pump. Based on this assembly, a compression tube may not be necessary because the torque from the threaded connections can provide the resistance to prevent the diffusers from rotating during pump operation. Static seals, such as O-rings can be inserted within grooves between diffusers for additional sealing capability.
  • Downhole ESPs operate in environments where space is limited radially, and increasing impeller diameters is desirable to increase lift provided to well fluids to be produced to the surface.
  • keeping ESP length short is typically desirable to mitigate bending stress on the pump, especially in the case that a severe dog leg is present.
  • short pump lengths are also desirable for tandem pumps installed through a lubricator, which can have a fixed length and height.
  • the pump is housing-less, and larger impellers can be used to generate more lift.
  • the pump can have a shorter length in comparison to a conventional pump that provides the same amount of lift.
  • the mitigation of bending stress can reduce potential rubbing between pump stages and can prevent heat generation and undesirable increases in power usage. Therefore, ESP operational life can be extended, and reliability can be improved, thereby reducing field operating costs and likelihood of deferred production.
  • FIG. 1 illustrates an example of a housing-less wellbore pump assembly 100 .
  • the pump assembly 100 can include a pump head 101 (not to be confused with hydraulic head, which is related to differential pressure), a pump base 103 , a pump shaft 151 , a head bearing 153 , an upper ring 155 , a compression nut 157 , a lower ring 165 , a base bearing 167 , and multiple pump stages, for example, three pump stages ( 180 A, 180 B, 180 C) connected end-to-end axially, which can pump well fluid in an uphole direction.
  • a pump head 101 not to be confused with hydraulic head, which is related to differential pressure
  • a pump base 103 can include a pump shaft 151 , a head bearing 153 , an upper ring 155 , a compression nut 157 , a lower ring 165 , a base bearing 167 , and multiple pump stages, for example, three pump stages ( 180 A, 180 B, 180 C) connected end
  • the pump stage ( 180 A, 180 B, 180 C) can include a rotating impeller ( 161 A, 161 B, 161 C) to rotate to provide kinetic energy to flow fluid through the assembly 100 and a stationary diffuser ( 105 A, 105 B, 105 C), within which the impeller ( 161 A, 161 B, 161 C) is positioned.
  • the pump assembly 100 can include a diffuser spacer 107 that can be positioned between the diffuser (for example, 105 A of the pump stage 180 A) and the pump base 103 .
  • the diffuser spacer 107 can include threaded ends ( 131 A, 141 B) to threadedly couple to the threaded end 141 A of the pump base 103 and the downhole threaded end of a diffuser, such as the threaded end 131 B of the downhole-most diffuser 105 A of pump stage 180 A.
  • the pump base 103 can include a threaded end 141 A threadedly coupled to a downhole threaded end of a downhole-most pump stage (for example, the threaded end 131 B of pump stage 180 A).
  • the pump assembly 100 can include additional diffusers apart from those that are a component of a pump stage ( 180 A, 180 B, 180 C), such as the diffuser 105 D.
  • the pump assembly 100 can include an adapter 109 that can be positioned between the pump head 101 and a diffuser, such as the diffuser 105 D.
  • the pump head 101 can include a threaded end 131 G threadedly coupled to an uphole threaded end of an uphole-most pump stage.
  • the pump assembly 100 can include additional components, such as diffuser internals or bearings, but have not been shown in FIG. 1 .
  • the components of the pump assembly 100 can be categorized as inner components or outer components.
  • the outer components of the pump assembly 100 include components that share a surface with the outer surface 111 of the assembly 100 and can be in contact with fluids outside of the pump assembly 100 , that is, the fluids that do not enter and get pressurized by the pump assembly 100 .
  • the outer components of the pump assembly 100 can include, for example, the pump head 101 , the pump base 103 , the diffuser spacer 107 , the adapter 109 , and the diffusers 105 A, 105 B, 105 C, 105 D.
  • the pump assembly 100 can include seals between the outer components—for example, 121 A between pump base 103 and diffuser spacer 107 ; 121 B between diffuser spacer 107 and diffuser 105 A; 121 C between diffusers 105 A and 105 B; 121 D between diffusers 105 B and 105 C; 121 E between diffusers 105 C and 105 D; 121 F between diffuser 105 D and adapter 109 ; and 121 G between adapter 109 and pump head 101 .
  • seals between the outer components for example, 121 A between pump base 103 and diffuser spacer 107 ; 121 B between diffuser spacer 107 and diffuser 105 A; 121 C between diffusers 105 A and 105 B; 121 D between diffusers 105 B and 105 C; 121 E between diffusers 105 C and 105 D; 121 F between diffuser 105 D and adapter 109 ; and 121 G between adapter 109 and pump head 101 .
  • the impellers ( 161 A, 161 B, 161 C) of the pump assembly 100 can be mechanically coupled to the pump shaft 151 .
  • the pump shaft 151 can be connected to and rotated by a motor (refer to FIG. 5 ), thereby causing the impellers ( 161 A, 161 B, 161 C) to rotate.
  • the diffuser ( 105 A, 105 B, 105 C) can convert the kinetic energy received from the corresponding rotating impeller ( 161 A, 161 B, 161 C) to head (that is, hydraulic head) to flow the fluid through the pump stage ( 180 A, 180 B, 180 C) and the assembly 100 .
  • the rotating impeller ( 161 A, 161 B, 161 C) of the pump stage ( 180 A, 180 B, 180 C) can rotate to provide kinetic energy to flow fluid through the pump stage ( 180 A, 180 B, 180 C) and the pump base 103 in an uphole direction through a wellbore.
  • the pump assembly 100 can include an impeller spacer ( 163 A, 163 B, 163 C) uphole of each impeller ( 161 A, 161 B, 161 C).
  • the compression nut 157 can connect the last, uphole impeller spacer (for example, 163 C) to the pump shaft 151 .
  • the upper ring 155 and lower ring 165 can join the rotating components of the assembly 100 to the pump shaft 151 to transmit power and axial thrust.
  • the head bearing 153 and the base bearing 167 constrains the relative motion of the shaft 151 to only the desired motion, for example, free rotation around the axis of the shaft 151 .
  • the two-piece rings ( 155 , 165 ) can ensure that the assembled impellers ( 161 A, 161 B, 161 C), impeller spacers ( 163 A, 163 B, 163 C), and compression nut ( 157 ) are locked onto the pump shaft 151 and can prevent axial movement along the shaft 151 .
  • the two-piece rings ( 155 , 165 ) can prevent the assembled components from sliding along the pump shaft 151 .
  • Preventing axial movement of the components along the pump shaft 151 can ensure that any axial thrust is transmitted through the pump shaft 151 . Additional friction can cause heat generation and can even result in potential pump failure.
  • Preventing axial movement of the components along the pump shaft 151 can also prevent potential rubbing contact (axially) between the rotating components.
  • the incremental space available for the tip of the impeller ( 161 A, 161 B, 161 C) of each pump stage ( 180 A, 180 B, 180 C) to occupy can increase, in some examples, by substantially 0.5′′.
  • An increase in impeller diameter can result in a higher developed head (that is, increased pressure differential between the inlet and outlet of the ESP).
  • a difference between the outer diameter of each pump stage ( 180 A, 180 B, 180 C), and the diameter of the tip of the impeller 161 A, 161 B, 161 C) of each pump stage ( 180 A, 180 B, 180 C) can be between 0.2′′ and 0.4′′.
  • the generated head for a housing-less pump described here can increase by approximately 23% attributable to the possible increase in impeller diameter by approximately 0.5′′.
  • the threaded ends can be connected with each other by threaded couplings.
  • the threads of the threaded ends can be formed in directions opposite to a rotational direction of the impellers.
  • the threaded coupling between the diffuser spacer 107 and the pump base 103 can prevent the components ( 107 and 103 ) from disassembling because the threads of the threaded couplings are formed in an opposite direction from the rotation of the impeller 161 A.
  • the threaded coupling between the diffuser spacer 107 and the diffuser 105 A can prevent the components ( 107 and 105 A) from disassembling.
  • the diffuser spacer 107 includes threaded ends ( 131 A, 141 B) connected with the threaded end 141 A of the pump base 103 and the downhole threaded end 131 B of the diffuser 105 A by respective threaded couplings.
  • the threads of the threaded ends ( 131 A, 131 B, 141 B) can be formed in an opposite direction from the direction of the impeller 161 A rotating to provide the kinetic energy to flow the fluid through the pump stage 180 A.
  • the pump assembly 100 can optionally include an additional diffuser 105 D (which is not directly associated with a pump stage) between the adapter 109 and the uphole-most pump stage ( 180 C).
  • the pump head 101 , the adapter 109 , and the diffuser 105 D can include threaded ends and can be threadedly coupled to each other.
  • the threads of the threaded ends of the components of the pump assembly 100 can be formed in an opposite direction of the impellers (such as 161 A, 161 B, 161 C) rotating to provide the kinetic energy to flow the fluid through the pump assembly 100 .
  • the threads of the threaded end 131 G of the pump head 101 and the uphole threaded end 141 E of the uphole-most pump stage 180 C can be formed in directions opposite to the rotational direction of the impeller, such as 161 C.
  • the pump assembly 100 includes an adapter 109 in between and threadedly coupled to the pump head 101 and the uphole-most diffuser 105 D, the threads of the threaded ends ( 131 F, 141 G) of the adapter 109 can be formed in directions opposite to the rotational direction of the impellers, such as 161 C.
  • the threads of the uphole threaded end of a diffuser are formed on the inner surface of the diffuser (for example, threaded end 141 D of diffuser 105 B), and the threads of the downhole threaded end of a diffuser are formed on the outer surface of the diffuser (for example, threaded end 131 D of diffuser 105 C).
  • a second seal can be positioned between the downhole threaded end of a pump stage and the uphole threaded end of another pump stage positioned downhole.
  • the seal 121 C is positioned between the downhole threaded end 131 C of pump stage 180 B and the uphole threaded end 141 C of pump stage 180 A.
  • the pump assembly 100 can include seals, such as O-rings, between other components, as well.
  • the threaded end of a component (such as 141 A of 103 ) can include one or more grooves, and the grooves can be located uphole relative to the threading ( FIGS. 3A and 3B ), downhole relative to the threading ( FIGS. 4A and 4B ), or both (if there are multiple grooves on one threaded end).
  • one of the components that are threadedly coupled together can include a groove on an inner surface for a seal to be installed between them (for example, 121 B between 131 B and 141 B as shown in FIGS. 3A and 3B ).
  • one of the components that are threadedly coupled together can include a groove on an outer surface for a seal to be installed between them (not shown).
  • the seal for example, O-ring
  • the two components such as two diffusers
  • the threaded coupling between one of the threaded ends ( 131 A) of the diffuser spacer 107 and the threaded end 141 A of the pump base 103 can include a seal, such as the seal 121 A, that can block fluid flowing through the pump base 103 and the pump stage 180 A from leaking outside the pump stage 180 A.
  • the threaded coupling between the other of the threaded ends ( 141 B) of the diffuser spacer 107 and the downhole threaded end 131 B of the diffuser 105 A can include a seal, such as the seal 121 B, that can block fluid flowing through the pump base 103 and the pump stage 180 A from leaking outside the pump stage 180 A.
  • the threaded coupling between the uphole end 141 D of the diffuser 105 B and the threaded end 131 G of the pump head 101 can include a seal, such as the seal 121 G, that can block fluid flowing through the pump head and the pump stage 180 B from leaking outside the second pump stage 180 B.
  • the threaded coupling between the uphole threaded end 141 G of the adapter 109 and the downhole threaded end 131 G of the pump head 101 can include a seal, such as seal 121 G, that can block fluid flowing through the pump assembly 100 from leaking outside the pump assembly 100 .
  • FIG. 5 illustrates an example of a production system 500 within a wellbore.
  • the production system 500 can include a casing 502 , a motor 503 , a protector 504 , a pump intake 505 , a packer 506 , production tubing 507 , and a pump assembly, such as the housing-less pump assembly 100 shown in FIG. 1 .
  • the various components of the production system 500 can have substantially the same outer diameter with a variation as described earlier.
  • the components of the production system 500 can have different diameters, but all components can be designed to handle a desired flow of well fluid 501 .
  • the pump assembly 100 lifts well fluid 501 in an uphole direction, that is, toward a surface of the wellbore.
  • the motor 503 can be positioned downhole relative to the pump assembly 100 .
  • the order of components of a wellbore production system can vary, but the intake 505 is located downhole of the pump assembly 100 , and the protector 504 is typically located adjacent to the motor 503 .
  • the protector 504 can be positioned between the pump assembly 100 and the motor 503 and can absorb a portion of axial loads from the pump assembly 100 pressurizing the well fluid 501 .
  • the packer 506 can be positioned uphole relative to the pump assembly 100 and can fluidically isolate a portion of the wellbore downhole relative to the pump assembly 100 from a remainder of the wellbore uphole relative to the pump assembly 100 .
  • the packer 506 can be positioned to isolate the reservoir, such that any fluid from the reservoir first flows through the pump assembly 100 before entering the production tubing 507 and traveling further uphole.
  • the pump intake 505 can include a screen to filter debris before fluid enters the pump assembly 100 .
  • the motor 503 can be a center-tandem (CT) motor or other suitable motor.
  • the production system 500 can include additional components, such as downhole sensors, for example, for pressure, temperature, flow rate, or vibration; additional packers; wellheads; centralizers or protectorlizers; check valves; motor shroud or recirculation systems; additional screens or filters; or a bypass, for example, a Y-tool.
  • additional components such as downhole sensors, for example, for pressure, temperature, flow rate, or vibration; additional packers; wellheads; centralizers or protectorlizers; check valves; motor shroud or recirculation systems; additional screens or filters; or a bypass, for example, a Y-tool.

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  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Structures Of Non-Positive Displacement Pumps (AREA)
US15/707,367 2017-09-18 2017-09-18 Electric submersible pump configuration Abandoned US20190085667A1 (en)

Priority Applications (6)

Application Number Priority Date Filing Date Title
US15/707,367 US20190085667A1 (en) 2017-09-18 2017-09-18 Electric submersible pump configuration
JP2020516418A JP2020534472A (ja) 2017-09-18 2018-09-07 電動水中ポンプの構成
CN201880060610.7A CN111094696A (zh) 2017-09-18 2018-09-07 电潜泵配置
CA3075850A CA3075850A1 (en) 2017-09-18 2018-09-07 Electric submersible pump configuration
PCT/US2018/049863 WO2019055295A1 (en) 2017-09-18 2018-09-07 CONFIGURATION OF ELECTRIC SUBMERSIBLE PUMP
EP18778752.8A EP3685009A1 (en) 2017-09-18 2018-09-07 Electric submersible pump configuration

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US15/707,367 US20190085667A1 (en) 2017-09-18 2017-09-18 Electric submersible pump configuration

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US20190085667A1 true US20190085667A1 (en) 2019-03-21

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US15/707,367 Abandoned US20190085667A1 (en) 2017-09-18 2017-09-18 Electric submersible pump configuration

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US (1) US20190085667A1 (ja)
EP (1) EP3685009A1 (ja)
JP (1) JP2020534472A (ja)
CN (1) CN111094696A (ja)
CA (1) CA3075850A1 (ja)
WO (1) WO2019055295A1 (ja)

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WO2021148649A1 (en) * 2020-01-23 2021-07-29 Zilift Holdings Limited Centrifugal well pump with threadedly coupled diffusers
US11174872B2 (en) * 2018-05-15 2021-11-16 Halliburton Energy Services, Inc. Anti-spin pump diffuser
US20220243569A1 (en) * 2018-02-23 2022-08-04 Extract Management Company, Llc Upthrust protection in electric submersible pumps

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US11940064B2 (en) 2022-06-17 2024-03-26 Saudi Arabian Oil Company Threaded tubular connection

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US20220243569A1 (en) * 2018-02-23 2022-08-04 Extract Management Company, Llc Upthrust protection in electric submersible pumps
US11624270B2 (en) * 2018-02-23 2023-04-11 Extract Management Company, Llc Upthrust protection in electric submersible pumps
US11174872B2 (en) * 2018-05-15 2021-11-16 Halliburton Energy Services, Inc. Anti-spin pump diffuser
WO2021148649A1 (en) * 2020-01-23 2021-07-29 Zilift Holdings Limited Centrifugal well pump with threadedly coupled diffusers
GB2606116A (en) * 2020-01-23 2022-10-26 Zilift Holdings Ltd Centrifugal well pump with threadedly coupled diffusers
US20230012388A1 (en) * 2020-01-23 2023-01-12 Zilift Holdings Limited Centrifugal well pump with threadedly coupled diffusers

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CA3075850A1 (en) 2019-03-21
JP2020534472A (ja) 2020-11-26
EP3685009A1 (en) 2020-07-29
WO2019055295A1 (en) 2019-03-21

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