EP3559405B1 - Wellbore pumps in series, including device to separate gas from produced reservoir fluids - Google Patents

Wellbore pumps in series, including device to separate gas from produced reservoir fluids Download PDF

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Publication number
EP3559405B1
EP3559405B1 EP17817162.5A EP17817162A EP3559405B1 EP 3559405 B1 EP3559405 B1 EP 3559405B1 EP 17817162 A EP17817162 A EP 17817162A EP 3559405 B1 EP3559405 B1 EP 3559405B1
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EP
European Patent Office
Prior art keywords
pumps
production tubing
fluid
wellbore
pump
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Active
Application number
EP17817162.5A
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German (de)
English (en)
French (fr)
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EP3559405A1 (en
Inventor
Henning Hansen
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Hansen Downhole Pump Solutions AS
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Hansen Downhole Pump Solutions AS
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Publication of EP3559405A1 publication Critical patent/EP3559405A1/en
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Classifications

    • 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
    • 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

Definitions

  • This disclosure relates to the field of producing fluids from underground wellbores, where the fluids need artificial assistance to be transported to the surface.
  • ESP electrical submersible pump
  • the length and dimension of the pump determines the fluid flow rate to surface that may be obtained.
  • ESP fluid lift flow rates typically are related to the outer diameter and length of the ESP. Smaller diameter and smaller length corresponds to lower possible flow rates; larger outer diameter and longer pumps may have higher possible flow rates.
  • wellbores include a conduit called a "casing" that has a less than optimum internal diameter for an artificial lift system to be installed, which frequently means that a pump (e.g., an ESP) of smaller outer dimension than may be desirable must be used, and correspondingly results in insufficient fluid lift rates to the surface.
  • a pump e.g., an ESP
  • wellbores are often deviated (inclined from vertical), which results in a length restriction for the pump(s); pumps generally cannot be exposed to large bending as would be required to install such pumps in a wellbore that has high change in deviation per unit length ("dog leg severity").
  • the productive reservoirs in the Barents Sea located north of Norway are at very shallow depths below the seafloor.
  • pumps in subsea wells can be replaced by light intervention, as for example by wireline or similar, a less costly vessel can be used. Such vessels will most likely also have much less mobilization time than marine drilling units, which may substantially reduce lost production in case of pump failures.
  • ESPs may suffer from lack of reliability, and therefore it is an advantage to install several pumps as redundancy in a wellbore, so that production is not completely stopped in case of failure of one pump.
  • An alternative, as described in U.S. Patent No. 9,166,352 issued to Hansen is to equip a pump with an electrical wet connect system, so that a pump can be retrieved and installed without having to retrieve the entire well completion system.
  • a pump system for a wellbore.
  • a pump system according to this aspect of the disclosure includes a production tubing nested within a casing in a wellbore or disposed within an open wellbore.
  • At least two pumps are disposed in the production tubing and axially spaced apart from each other. At least one of the at least two pumps is removable from the production tubing while the production tubing remains in place in the wellbore.
  • At least one fluid intake conduit is disposed outside the production tubing and inside the wellbore. The at least one fluid intake conduit is in fluid communication with an interior of the production tubing below a lower one of the at least two pumps and at a position of an intake of an upper one of the at least two pumps.
  • At least one fluid discharge conduit is disposed outside the tubing and inside the wellbore.
  • the at least one fluid discharge conduit in fluid communication with the interior of the production tubing proximate a discharge of the lower one of the at least two pumps and above the upper one of the at least two pumps.
  • a method for pumping fluid from a wellbore includes operating at least one of at least two pumps disposed in a production tubing disposed in the wellbore. At least one of the at least two pumps is removable from the production tubing while the production tubing remains in place in the wellbore, at least one fluid intake conduit disposed outside the production tubing and inside the wellbore, the at least one fluid intake conduit in communication with an interior of the production tubing below a lower one of the at least two pumps and at a position of an intake of an upper one of the at least two pumps, at least one fluid discharge conduit disposed outside the tubing and inside the wellbore, the at least one fluid discharge conduit in fluid communication with the interior of the production tubing proximate a discharge of the lower one of the at least two pumps and either proximate an intake of or above the upper one of the at least two pumps.
  • the present disclosure describes structures wherein a plurality of wellbore fluid pumps can be installed in a wellbore as individual units, where each pump below an uppermost pump transfers fluids to a location above the uppermost pump, or to an area below the uppermost pump, if the uppermost pump is capable of pumping the combined volume delivered from the pumps below.
  • Bypass (flow) conduits may be provided for transporting reservoir fluids from below the lowermost pump to one or more pumps mounted above the lowermost pump, as well as transporting fluids from the various pumps to a location below and/or above the uppermost pump.
  • One or several fluid transport tubes may be disposed between each required pump location may be provided in some embodiments to obtain increased fluid transport rate to surface.
  • the axial distance along the wellbore between the various pumps may be different.
  • wet connect coupler(s) as for example the coupler described in patent U.S. Patent No. 9,166,352 issued to Hansen , the pumps can be replaced by light wellbore intervention instead of having to mobilize and use a much more costly drilling rig.
  • a production packer annular seal between a wellbore casing and a nested production tubing
  • a production packer annular seal between a wellbore casing and a nested production tubing
  • the latter method is more complex, because the packer will need to have bypass devices to enable pass through of the electrical cable.
  • pump packers with annular bypass is a commonly available technology today.
  • a well completion may consist of a larger outer diameter, permanently installed ESP capable of lifting total required fluid flow rate amount of fluid per combined with one or several retrievable ESPs (e.g., wireline or coiled tubing retrievable ESPs.
  • the retrievable ESPs may function as a back-up to the permanently mounted pump, and may also be sized to together be able to provide the total required fluid flow rate
  • a gas separator may be installed below the ESPs, where gas may be discharged to an area above the ESPs.
  • the gas separation system may be retrievable by wireline, coiled tubing or the like, or may also be permanently mounted as part of the production tubing.
  • Fig. 1 illustrates an example wellbore having a casing 14 disposed in the wellbore (not shown separately) to hydraulically isolate formations disposed outside the casing 14 and to maintain mechanical integrity of the wellbore.
  • the casing 14 may comprise a nested production tubing 12 inside, where the production tubing 12 includes a plurality of pumps, for example, electrical submersible pumps (ESPs).
  • ESPs electrical submersible pumps
  • the tubing 12 comprises three axially spaced apart pumps, shown at 10A, 10B and 10C, respectively.
  • An annular seal 16, often referred to as a packer, production packer or a tie-back seal stem, may be located proximate the lower end of the production tubing 12 in the annular space between the production tubing 12 and the casing 14.
  • the pumps 10A, 10B, 10C may be disposed in the production tubing 12 above the annular seal 16. Each pump 10A, 10B, 10C has a dedicated fluid path from the wellbore below the annular seal 16 to the respective intake of each pump 10A, 10B, 10C.
  • the lowermost pump 10C may have its intake path through the part of the production tubing 12 disposed below the lowermost pump 10C.
  • the middle 10B and upper 10A pumps may have corresponding intake flow lines 22B, 22A that are fluidly connected, at 22B1 and 22A1, respectively to the interior of the production tubing 12 below the lowermost pump 10C.
  • the lowermost pump 10C and middle pump 10B may each have as well a respective fluid discharge conduit 24C, 24B above each pump 10C, 10B
  • Such fluid discharge conduits 24C, 24B may be fluidly connected to the interior of the production tubing 12 above the uppermost pump 10A at connections 24C1, 24B1, respectively.
  • Each fluid intake flow line 22A, 22B as well as each fluid discharge conduit 24B, 24C may consist of a plurality of individual conduits disposed in the annular space between the casing 14 an the production tubing 12 lines to obtain high fluid flow capability with as small outer total diameter of the pumps 10A, 10B, 10C and lines 22A, 22B, 24A, 24B as practical when the components are assembled and inserted into the casing 14.
  • each pump 10A, 10B, 10C may have one or several fluid flow conduits to and/or from each respective intake and discharge locations described above. Intake and discharge locations for the respective fluid flow conduits will depend on the configuration of and the number of pumps used in any particular embodiment.
  • the production tubing 12 may comprise a wet mateable electrical and mechanical coupler 18A, 18B, 18C for seating each respective pump 10A, 10B, 10C and making electrical connection to each respective pump 10A, 10B, 10C.
  • the lines 22A, 22B, 24A, 24B may be affixed to the production tubing 12 prior to or during insertion of the production tubing 12 into the casing 14.
  • the wet mateable electrical and mechanical couplers 18A, 18B, 18C may be substantially as described in U.S. Patent No. 9,166,352 issued to Hansen .
  • the pumps 10A, 10B, 10C may be inserted into and seated in their respective positions within the production tubing 12 by means of conveyance such as wireline (armored electrical cable), coiled tubing or jointed tubing.
  • conveyance such as wireline (armored electrical cable), coiled tubing or jointed tubing.
  • the pumps 10A, 10B 10C may be likewise removed from the production tubing if and as necessary. It will be appreciated by those skilled in the art that using wireline conveyance for the pumps 10A, 10B, 10C may provide operational advantages such as lower transportation cost and lower operating cost.
  • Figs. 2A, 2B and 2C illustrate a known configuration for installing multiple ESPs 10A, 10B in tandem.
  • the pumps 10A, 10 are disposed outside the production tubing 12 and have their respective intakes in fluid communication with the interior of the casing (14 in Fig. 1 ).
  • Discharge from each pump 10A, 10B is connected to the interior of the production tubing using a Y-connector 28 coupled within the production tubing 12 along one leg of the Y-connector 28 and having a coupling to the discharge of each pump 10A, 10B through the other leg of the Y connector 28.
  • the drawback of the configuration shown in Figs. 2A, 2B and 2C is that the casing (14 in Fig.
  • each Y-connector 28 needs to be large enough to allow installation and retrieval of a blanking plug 27, which reduces the amount of room available for the pumps 10A, 10B.
  • Another typical method is to mount an outer shroud on a ESP assembly, as an alternative to the bypass tube approach described in this patent application. Using bypass tubes will allow more room for the ESP, and therefore has an advantage to using a shroud. Also, using a shroud prevents the ability to utilize retrievable ESP's.
  • Fig. 3 illustrates a production tubing with several retrievable pumps 10A. 10B, 10C placed within the production tubing 12 at various axial positions along the interior of the production tubing 12.
  • the retrievable pumps 10A, 10B, 10C can be pulled to surface from within the production tubing 12, as well as installed through same, without having to pull the production tubing 12 to the surface.
  • a respective electrical wet mateable coupler 18A, 18B, 18C for each pump 10A, 10B, 10C is preinstalled in the production tubing 12, being for example the type as described in U.S. Patent No. 9,166,352 issued Hansen .
  • Fluid intake and discharge tubes may be similar to those as explained with reference to Fig. 1 .
  • Being retrievable pumps a sealing system on each pump is required to eliminate any unwanted cross flow and leakages.
  • Fig. 4 illustrates a production tubing 12 with several non-retrievable pumps 110A, 110B, 110C placed within the production tubing 12 at various axial positions.
  • the production tubing 12 will need to be pulled to the surface for replacement of any of the pumps.
  • the fluid intake and discharge tubes may be substantially as explained with reference to Fig. 1 .
  • Fig. 5 illustrates that a combination of a permanently 110C and one or more retrievable 10A, 10B pumps are also possible, combining what is illustrated in Fig. 3 and Fig. 4 .
  • the permanently mounted pump 110C can be capable of lifting the total required fluid flow rate to the surface, where back-up is provided by one or several retrievable pumps 10A, 10B that would also be able to in combination lift the total required fluid flow rate to the surface.
  • the back-up pumps 10A, 10B can be engaged. If one or several of the back-up pumps 10A, 10B fail also, it is possible to replace them without having to remove the production tubing 12.
  • Flow lines for intake and discharge of the pumps 10A. 10B, 110C may be substantially as explained with reference to FIG. 1 .
  • each of the retrievable pumps 10A, 10B may be seated in a respective wet mateable connector 18A, 18B also as explained with reference to Fig. 1 .
  • Fig. 6 illustrates a cross section of the wellbore with one of the pumps, for example pump 10B in Fig. 1 including a wet mateable electrical/mechanical coupler 18B, an electrical cable 30 and several fluid transport conduits 22A, 22B, 24A, 24B as explained with reference to Fig. 1 .
  • Fig. 7A and 7B illustrate the difference in depth to which a pump may be moved through production tubing 12 if the pump has a length and/or diameter according to the present disclosure.
  • a conventional, large diameter pump 110 is shown being inserted into the production tubing 12 and being unable to pass a point 32 in the wellbore where the dog leg severity is sufficient to prevent further passage of the pump 110.
  • Fig. 7B by using a pump 10 with a smaller outer diameter and/or less length, the pump 10 may be able to pass the point 32 where dog leg severity stops a larger diameter and/or longer pump (as shown in Fig. 7A ).
  • Fig. 8 illustrates a cross section of a casing 14 where an ESP 10, a wet mateable electrical/mechanical connector 18, ESP cable 30 and flow conduits 22, 24 are shown.
  • the example shown in Fig. 8 is based on an ESP manufactured by Baker Hughes, Incorporated, Houston, Texas, under model designation PASS Slimline 3.38. Similar ESPs may be available from other manufacturers. This type of ESP has a relatively small outer diameter, but is still able to lift 397,47 m 3 (2,500 barrels) of wellbore fluid per day to the surface.
  • ESPs may be installed in a production tubing substantially as explained with reference to Figs. 1 and 3 .
  • the installation may also include light intervention replaceable ESPs, where each ESP would include a wet mateable electrical/mechanical connector, for example, as explained with reference to Figs. 1 and 3 .
  • Fig. 9 illustrates how an ESP assembly 10A, equivalent to the uppermost pump shown in Fig. 1 may be removably placed within a segment (joint) of the production tubing 12.
  • the ESP assembly 10A may be of types known in the art and may comprise a sensor module 10A7 (having e.g., pressure, temperature and capacitance sensors), a motor section 10A6, a seal (protector) section 108A, a pump section (e.g., a centrifugal or progressive cavity pump), a locking module section 10A3 to axially lock the pump assembly 10A in the production tubing 12 and a fluid discharge section 10A2.
  • a sensor module 10A7 having e.g., pressure, temperature and capacitance sensors
  • a motor section 10A6 having e.g., a motor section 10A6, a seal (protector) section 108A
  • a pump section e.g., a centrifugal or progressive cavity pump
  • Some embodiments of the ESP assembly 10A may comprise a fishing head 10A1 to enable retrieval of the ESP assembly 10A using a wireline "fishing" head attached to the end of an armored electrical cable.
  • the production tubing 12 may be configured, including the wet mateable electrical/mechanical connector 18, substantially as described with reference to Fig. 1 and Fig. 3 . Fluid from the wellbore will be delivered to the pump intake through the flow line(s) 22A mounted externally on the production tubing 12.
  • the pump section 10A5 will deliver fluid upwardly to the surface through the discharge section 10A2 of the ESP system 10A. Even though the locking module 10A3 is illustrated in Fig.
  • the locking module 10A3 may be disposed at any axial location along the ESP assembly 10A.
  • the wet mateable connector 18 routes electrical power to the ESP system 10A.
  • the discharge section 10A2 may also be on the side of the ESP assembly 10A, discharging fluids into one or several fluid discharge lines (see Fig. 1 ) mounted externally on the production tubing 12.
  • the wet mateable connector 18 may comprise male connector contacts 18-1 on the ESP system 10A and female connector contacts 18-2 on the connector portion disposed in the production tubing 12.
  • a seal section 10A-8 may stop fluid movement axially within the production tubing 12 along the exterior of the ESP system 10A, so that all fluid discharged by the ESP system 10A may be moved into the production tubing 12 in a direction toward the surface.
  • Fig. 10 illustrates a system similar to the system shown in and explained with reference to Fig. 1 with the inclusion of a gas separator 34 in the production tubing 12 below the intake of the lowermost pump 10C.
  • the gas separator 34 device may be of a retrievable type landed within the production tubing 12, or it may be a permanent component as part of the production tubing 12. Gas is discharged from the gas separator 34 to one or more gas discharge tubes 36 mounted externally on the production tubing 12, extending to a location axially above the pumps 10A, 10B, 10C. Having the gas separator 34 may increase the operating efficiency of the pumps 10A, 10B, 10C by reducing cavitation or gas locking of the pumps 10A, 10B, 10C.
  • Fig. 11 illustrates a booster system 38 receiving gas at an inlet thereof from one or several gas feeding conduit(s) 36, for example as explained with reference to Fig. 10 , and then discharging the gas into the produced fluids from one or several wellbore pumps, e.g., 10A in Fig. 11 .
  • the booster system 38 may be powered by an electrical cable, e.g., 30, by hydraulic power fluid supplied from the surface through one or several hydraulic control lines, or by the fluid discharged from one or several wellbore pumps located below the booster 38.
  • Fig. 11 omits possible fluid discharge and intake flow lines from wellbore pumps that can be located in the wellbore below the illustrated pump 10A for clarity of the illustration.
  • the booster's function is to draw in gas from below the pump(s) and then pressurize the gas enough for the gas to be discharged into the production tubing 12 above the pump(s).
  • Fig. 12 illustrates an example embodiment of a gas separator such as shown in Fig. 10 in more detail.
  • the gas separator 34 may seal externally against the interior of the casing 14. Fluids and gas 46 from a reservoir flows into the gas separator 36 through suitable openings 116A in a lower packer 116 to an area between an inner tube 34A and an outer tube 34B of the gas separator 34. Thereafter the fluids and gas 46 exit in the upper section into the area outside the gas separator 34, followed by traveling to intake ports in the lower side of the separator 34.
  • gas 40 separating and rising to the upper section of the gas separator 34, and then entering through an upper packer 216 to, for example, one or several gas discharge tubes 36 extending to the surface, or coupled to an area above the wellbore pump(s) as described and explained with reference to Figs. 10 and 11 .
  • the fluids and gas may also be contained within an outer concentric housing, or within one or several tubes mounted externally.

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  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Jet Pumps And Other Pumps (AREA)
EP17817162.5A 2016-12-29 2017-11-29 Wellbore pumps in series, including device to separate gas from produced reservoir fluids Active EP3559405B1 (en)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201662440060P 2016-12-29 2016-12-29
PCT/IB2017/057503 WO2018122647A1 (en) 2016-12-29 2017-11-29 Wellbore pumps in series, including device to separate gas from produced reservoir fluids

Publications (2)

Publication Number Publication Date
EP3559405A1 EP3559405A1 (en) 2019-10-30
EP3559405B1 true EP3559405B1 (en) 2022-10-19

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ID=60702899

Family Applications (1)

Application Number Title Priority Date Filing Date
EP17817162.5A Active EP3559405B1 (en) 2016-12-29 2017-11-29 Wellbore pumps in series, including device to separate gas from produced reservoir fluids

Country Status (6)

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US (1) US20190292889A1 (da)
EP (1) EP3559405B1 (da)
BR (1) BR112019013413B1 (da)
CA (1) CA3045411C (da)
DK (1) DK3559405T3 (da)
WO (1) WO2018122647A1 (da)

Families Citing this family (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP3615770A1 (en) * 2017-04-25 2020-03-04 Hansen Downhole Pump Solutions A.S. Systems and methods for killing wells equipped with jet pumps
US11441363B2 (en) * 2019-11-07 2022-09-13 Baker Hughes Oilfield Operations Llc ESP tubing wet connect tool
US20210246771A1 (en) * 2020-02-07 2021-08-12 Saudi Arabian Oil Company Simultaneous operation of dual electric submersible pumps using single power cable
WO2024097335A1 (en) * 2022-11-02 2024-05-10 Moog Inc. Assisted lift electrical subsurface pump system

Family Cites Families (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB0504664D0 (en) * 2005-03-05 2005-04-13 Inflow Control Solutions Ltd Method, device and apparatus
GB0801156D0 (en) 2008-01-23 2008-02-27 Pump Tools Ltd Apparatus and method
US9166352B2 (en) 2010-05-10 2015-10-20 Hansen Energy Solutions Llc Downhole electrical coupler for electrically operated wellbore pumps and the like
KR101883425B1 (ko) 2011-08-01 2018-07-31 삼성전자주식회사 휴대 단말기를 이용하는 위폐 감별법
WO2015017810A1 (en) * 2013-08-01 2015-02-05 Chevron U.S.A. Inc. Electric submersible pump having a plurality of motors operatively coupled thereto and methods of using
US9657535B2 (en) * 2013-08-29 2017-05-23 General Electric Company Flexible electrical submersible pump and pump assembly

Also Published As

Publication number Publication date
US20190292889A1 (en) 2019-09-26
EP3559405A1 (en) 2019-10-30
CA3045411A1 (en) 2018-07-05
DK3559405T3 (da) 2022-11-21
BR112019013413A2 (pt) 2020-03-03
WO2018122647A1 (en) 2018-07-05
BR112019013413B1 (pt) 2023-04-18
CA3045411C (en) 2021-05-18

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