WO2022261629A1 - Séparateur de gaz de fond de trou - Google Patents

Séparateur de gaz de fond de trou Download PDF

Info

Publication number
WO2022261629A1
WO2022261629A1 PCT/US2022/072795 US2022072795W WO2022261629A1 WO 2022261629 A1 WO2022261629 A1 WO 2022261629A1 US 2022072795 W US2022072795 W US 2022072795W WO 2022261629 A1 WO2022261629 A1 WO 2022261629A1
Authority
WO
WIPO (PCT)
Prior art keywords
tubular member
inner tubular
outer tubular
opening
annulus
Prior art date
Application number
PCT/US2022/072795
Other languages
English (en)
Inventor
Daniel J. SNYDER
Original Assignee
Snyder Daniel J
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 Snyder Daniel J filed Critical Snyder Daniel J
Publication of WO2022261629A1 publication Critical patent/WO2022261629A1/fr

Links

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
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/38—Arrangements for separating materials produced by the well in the well
    • 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
    • E21B43/127—Adaptations of walking-beam pump systems

Definitions

  • Sucker rod pumps are often used when the natural pressure of an oil and gas formation is not sufficient to lift the oil to the surface of the earth.
  • Sucker rod pumps operate by admitting fluid from the formation into a tubing and then lifting the fluid to the surface.
  • the sucker rod pump contains, among others, four elements: a pump or working barrel, a plunger which travels in an up and down motion inside the pump barrel, a standing valve positioned near the lower end of the pump barrel, and a traveling valve that is attached to and travels with the plunger.
  • a chamber is formed inside the pump barrel between the standing valve and the traveling valve.
  • the standing valve allows fluid to flow into the chamber but does not allow fluid to flow out of the chamber.
  • the traveling valve allows fluid to flow out of the chamber, but not into the chamber.
  • the plunger When the fluid that the sucker rod pump is pumping is substantially all liquids, the plunger is mechanically made to move up and down in a reciprocating motion. On the upstroke of a pumping cycle, where the plunger is moved upward, the hydrostatic pressure of the fluid above the traveling valve causes the traveling valve to close. The upward motion of the plunger also causes a negative fluid pressure to develop inside the chamber thereby causing the standing valve to open and to admit fluid from the formation into the chamber.
  • the chamber is filled with liquid from the formation.
  • the pressure in the chamber becomes positive which causes the standing valve to close. Because liquids are substantially incompressible, the pressure in the chamber rapidly increases to a pressure greater than the fluid column pressure above the traveling valve.
  • the traveling valve opens and fluid passes by the traveling valve where it is able to be lifted by the sucker rod pump on the upstroke.
  • both liquids and gases may be produced from the same well.
  • Gases that may be entrained or evolved from hydrocarbon liquids when such liquids are pumped to the surface may interfere or reduce the efficiency of the pumping operations, decreasing or slowing production.
  • One such separator device includes an inner tube with an open lower end positioned within and connected to the sucker rod pump so the inner tube is in fluid communication with the sucker rod pump.
  • An outer tube is connected at an upper end to the sucker rod pump, but is not in direct fluid communication with the sucker rod pump.
  • the outer tube may be provided with ports or slots at the upper end to allow liquids and gases in the annulus of the well to pass into the outer tube. The change in direction of the flow causes a portion of the gas to separate from the liquid. The liquid continues to pass down the outer tube, into the inner tube via the open lower end, and into the sucker rod pump.
  • the inventive concepts disclosed and claimed herein generally relate to a downhole gas separator.
  • the downhole gas separator includes a first separator section and a second separator section.
  • the first separator section including a first outer tubular member and a first inner tubular member.
  • the first outer tubular member has an upper end, a lower end, and a sidewall extending between the upper end and the lower end.
  • the sidewall has at least one opening extending therethrough adjacent the upper end, and the upper end of the first outer tubular member is connectable to a lower end of a tubing string positionable in a wellbore.
  • the first inner tubular member has an upper end, a lower end, and a sidewall extending between the upper end and the lower end.
  • the first inner tubular member is positioned in the first outer tubular member to define a first annulus between the first outer tubular member and the first inner tubular member.
  • the upper end of the first inner tubular member is connected to the upper end of the first outer tubular member so the first annulus is fluidically sealed from the tubing string and the first inner tubular member is in fluid communication with the tubing string when the first inner tubular member is connected to the tubing string.
  • the lower end of the first inner tubular member is connected to the lower end of the second outer tubular member.
  • the second separator section includes a second outer tubular member and a second inner tubular member.
  • the second outer tubular member has an upper end, a lower end, and a sidewall extending between the upper end and the lower end.
  • the sidewall has at least one opening extending therethrough adjacent the upper end.
  • the upper end of the second outer tubular member is connected to the lower end of the first outer tubular member, and the lower end of the second outer tubular member is being fluidically sealed.
  • the second inner tubular member has an upper end, a lower end, and a sidewall extending between the upper end and the lower end, and the second inner tubular member is positioned in the second outer tubular member to define a second annulus between the second outer tubular member and the second inner tubular member.
  • the upper end of the second inner tubular member is connected to the lower end of the first inner tubular member so the second annulus is fluidically sealed from the first annulus and the second inner tubular member is in fluid communication with the first inner tubular member.
  • the lower end of the second inner tubular member is open to define a lower open end having a flow area
  • the sidewall of the first inner tubular member has at least one opening extending therethrough adjacent the lower end thereof.
  • the opening has a flow area less than the flow area of the lower open end.
  • FIG. 1 is a schematic view of a sucker rod pump assembly with a downhole gas separator constructed in accordance with the inventive concepts disclosed herein incorporated with the sucker rod pump assembly.
  • FIG. 2 is cross-sectional view of the downhole gas separator.
  • FIG. 3 is a cross-sectional view of a first separator section of the downhole gas separator.
  • FIG. 4 is cross-sectional view of a portion of the first separator section.
  • qualifiers like “substantially,” “about,” “approximately,” and combinations and variations thereof, are intended to include not only the exact amount or value that they qualify, but also some slight deviations therefrom, which may be due to manufacturing tolerances, measurement error, wear and tear, stresses exerted on various parts, and combinations thereof, for example.
  • any reference to "one embodiment” or “an embodiment” means that a particular element, feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment.
  • the appearances of the phrase “in one embodiment” in various places in the specification are not necessarily all referring to the same embodiment.
  • FIG. 1 a downhole pump assembly 10 is shown in a wellbore 11 of a well.
  • the wellbore 11 may be provided with a casing 13 that may be perforated at one or more positions along its length. The perforations allow fluids from the surrounding formation to enter the casing 13.
  • the fluids may include liquids and gases.
  • the downhole pump assembly 10 is secured within in a tubing string 12 and used with a pump jack unit 15 and a sucker rod string 14 for elevating fluids, such as hydrocarbons, to the earth's surface.
  • the downhole pump assembly 10 may include a pump barrel 20, a standing valve 22, a plunger 24, and a traveling valve 26.
  • the pump barrel 24 supports the standing valve 22 in a lower end thereof.
  • the standing valve 22 is illustrated as being a conventional ball check valve.
  • the plunger 24 is disposed in the pump barrel 20 and is adapted for reciprocating movement through pump barrel 20.
  • the traveling valve 26 is located in a lower end of the plunger 24 to permit one way flow of fluid into the plunger 24.
  • the traveling valve 26 is shown to be a ball check valve and a seat.
  • the plunger 24 is moved in an upward direction.
  • the hydrostatic pressure of the fluid above the traveling valve 26 causes the traveling valve 26 to close.
  • the upward motion of the plunger 24 further causes a negative pressure to develop inside a chamber 28 below the plunger 24 thereby causing the standing valve 22 to open and admit fluid from the formation into the chamber 28.
  • the traveling valve 26 will not open until the pressure below the traveling valve 26 becomes greater than the hydrostatic pressure above the traveling valve 26, if the fluid contains a significant amount of gas, the traveling valve 26 may not open at all, resulting in the condition known as “gas lock.”
  • the plunger 24 may compress the gas thereby resulting in the plunger 24 colliding with the liquid. The collision between the plunger 24 and the liquid generates a shockwave and is referred to as “gas pound.”
  • the shockwave causes the traveling valve 26 to open quickly which can result in damage to the traveling valve 26 and to the other components of the downhole pump assembly 10.
  • a gas separator 50 constructed in accordance with inventive concepts disclosed herein is shown connected to a lower end of the downhole pump assembly 10 to reduce the amount of gas entering the downhole pump assembly 10.
  • the gas separator 50 is particularly suited for use in a downhole wellbore for separation of gas and liquids from a multi-phase fluid.
  • the gas separator 50 includes a first separator section 52 and a second gas separator section 54.
  • the second gas separator section 54 is a conventional gas separator that may include an outer tubular member 56 and an inner tubular member 58.
  • the outer tubular member 56 has an upper end 60, a lower end 62, and a sidewall 64 extending between the upper end 60 and the lower end 62.
  • the sidewall 64 has at least one inlet opening 66 extending therethrough adjacent the upper end 60 thereof.
  • the upper end 60 of the outer tubular member 56 is connected to the lower end of the pump assembly 10.
  • the lower end 62 of the outer tubular member 56 is capped so fluid only enters the second separator section 52 via the inlet opening 66.
  • the inner tubular member 58 has an upper end 68, a lower end 70, and a sidewall 72 extending between the upper end 68 and the lower end 70.
  • the inner tubular member 58 is positioned in the outer tubular member 56 to define an annulus 74 between the outer tubular member 56 and the inner tubular member 58.
  • the upper assembly 10 so the annulus 74 is fluidically sealed from the pump assembly 10 and the inner tubular member 58 is in fluid communication with the pump assembly 10.
  • the second gas separator section 54 may include a connector 67.
  • the connector 67 connects the upper end 60 of the outer tubular member 56 to the pump assembly 10 and the upper end 68 of the inner tubular member 58 is connected to the lower end of the pump assembly 10 so the annulus 74 is fluidically sealed from the pump assembly 10 and the inner tubular member 58 is in fluid communication with the pump assembly 10.
  • the lower connector 67 may be formed from a single, unitary piece of material, as shown, or it may be formed in two or more pieces.
  • the connector 67 may have a tubular wall with an upper end provided with a female threaded portion 69 for coupling with the pump assembly 10 or the first gas separator section 52 as discussed below.
  • the lower end of the connector 67 may be provided with a male threaded portion 71 for coupling to the upper end 60 of the outer tubular member 56 and a female threaded portion 73 for coupling to the upper end 68 of the inner tubular member 58 of the second separator section 54.
  • the lower end 70 of the inner tubular member 58 is open to define a lower open end 76 having a flow area.
  • the reservoir fluids flow into the inlet opening 66 of the outer tubular member 56 and pass down the annulus 74.
  • the change of direction causes a portion of the gas in the reservoir fluid to separate from the liquid and travel up an annulus 77 between the outer tubular member 56 and the casing 13.
  • Another portion of the gas separates from the fluid within the annulus 74. This gas travel upwards through the annulus 74 and exits through the inlet opening 66.
  • the liquid passes into the inner tubular member 58 via the lower open end 76 and up to the pump assembly 10.
  • the first separator section 52 includes an outer tubular member 80 and an inner tubular member 82.
  • the outer tubular member 80 has an upper end 84, a lower end 86, and a sidewall 88 extending between the upper end 84 and the lower end 86.
  • the sidewall 88 has at least one inlet opening 90 extending therethrough adjacent the upper end 84.
  • the upper end 84 of the outer tubular member 80 is connectable to the lower end of the pump assembly 10.
  • the inner tubular member 82 has an upper end 92, a lower end 94, and a sidewall 96 extending between the upper end 92 and the lower end 94.
  • the inner tubular member 82 is positioned in the outer tubular member 80 to define an annulus 97 between the outer tubular 80 member and the inner tubular member 82.
  • the upper end 92 of the inner tubular member 82 is connected to the upper end 84 of the outer tubular member 80 so the annulus 97 is fluidically sealed from the pump assembly 10 and the inner tubular member 82 is in fluid communication with the pump assembly 10 when the inner tubular member 82 is connected to the pump assembly 10.
  • the sidewall 88 of the first inner tubular member 82 has at least one opening 98 extending therethrough adjacent the lower end thereof.
  • the opening 98 has a flow area less than the flow area of the lower open end 76 of the inner tubular member 58 of the second separator section 52.
  • the opening 98 may be defined by a nozzle 99 (FIG. 4).
  • the nozzle 99 may be formed of a hardened material, such as carbide.
  • the nozzle 99 may have a diameter of approximately 1 ⁇ 4 inch, by way of example. However, it will be appreciated that the diameter of the opening 98 may be varied.
  • the first gas separator section 52 may be provided with a screen 101 (FIG. 3) secured over the opening 98.
  • the inlet opening 90 of the outer tubular member 80 of the first separator section 52 is arranged to be less restrictive than the opening 98 such that fluid may readily enter through the inlet opening 90; however, gas can also escape from the first separator section 52 back into the annulus 97 through the inlet opening 90.
  • the inlet opening 66 and the inlet opening 90 may be configured as slots with dimensions of approximately one to two inches in width and approximately eight inches in length. The inlet opening 66 and the inlet opening 90 may be of similar dimension or different.
  • the first separator section 52 may have an upper connector 100 and a lower connector 102.
  • the upper connector 100 connects the upper end 84 of the outer tubular member 80 to upper end 92 of the inner tubular member 82.
  • the upper connector 100 also enables the first separator section 52 to be connected to the lower end of the pump assembly 10.
  • the lower connector member 102 connects the lower end 86 of the outer tubular member 80 to the lower end 94 of the inner tubular 82.
  • the upper connector 100 and the lower connector 102 connect the inner tubular member 82 to the outer tubular member 80 so the annulus 97 is fluidically sealed from the pump assembly 10 and the annulus 74 of the second separator section 54 except via the opening 98. As such, fluid in the annulus 97 must pass through the opening 98.
  • the lower connector 102 also enables the first separator section 52 to be connected to the second separator section 54.
  • the upper connector 100 may be formed from a single, unitary piece of material, as shown, or it may be formed in two or more pieces.
  • the upper connector 100 may have a tubular wall with an upper end portion configured with a female thread portion 120 for coupling to the tubing string 12.
  • the lower end of the upper connector 100 may be provided with a male threaded portion 122 for coupling to the outer tubular member 80 and a female threaded portion 124 for coupling to the upper end of the inner tubular member 82.
  • the lower connector 102 may be formed from a single, unitary piece of material, as shown, or it may be formed in two or more pieces.
  • the lower connector 102 may have a tubular wall with an upper end provided with a male threaded portion 126 for coupling to the lower end 86 of the outer tubular member 80 and a female portion 128 (including a sealing member, such as an O-ring) for coupling to the lower end 94 of the inner tubular member 82.
  • the lower end of the lower connector 102 may be provided with a male threaded portion 130 for sealingly coupling to the female threaded portion 69 of the connector 67 of the second gas separator section 54 so the inner tubular member 58 is in fluid communication with the inner tubular member 82.
  • the gas separator 50 may be implemented with more than one of the first separator sections 52 connected to one another in series.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Jet Pumps And Other Pumps (AREA)
  • Reciprocating Pumps (AREA)

Abstract

L'invention concerne un séparateur de gaz comprenant une première section de séparateur et une seconde section de séparateur. La première section de séparateur et la seconde section de séparateur comprennent chacune un élément tubulaire externe à travers lequel s'étend au moins une ouverture à proximité d'une extrémité supérieure et un élément tubulaire interne positionné dans l'élément tubulaire externe pour définir un espace annulaire. L'espace annulaire de la première section de séparateur est hermétiquement scellé à partir d'une colonne de production. Une extrémité inférieure de l'élément tubulaire interne de la seconde section de séparateur est ouverte pour définir une extrémité ouverte inférieure ayant une zone d'écoulement et l'extrémité inférieure de l'élément tubulaire externe est hermétiquement scellée. L'élément tubulaire interne de la première section de séparateur comporte au moins une ouverture s'étendant à travers celui-ci à proximité de l'extrémité inférieure de celui-ci. L'ouverture présente une zone d'écoulement inférieure à la zone d'écoulement de l'extrémité ouverte inférieure.
PCT/US2022/072795 2021-06-07 2022-06-07 Séparateur de gaz de fond de trou WO2022261629A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US202163197696P 2021-06-07 2021-06-07
US63/197,696 2021-06-07

Publications (1)

Publication Number Publication Date
WO2022261629A1 true WO2022261629A1 (fr) 2022-12-15

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ID=84284969

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2022/072795 WO2022261629A1 (fr) 2021-06-07 2022-06-07 Séparateur de gaz de fond de trou

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US (1) US20220389806A1 (fr)
WO (1) WO2022261629A1 (fr)

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20040020638A1 (en) * 2002-05-28 2004-02-05 Williams Benny J. Mechanically actuated gas separator for downhole pump
WO2015196287A1 (fr) * 2014-06-25 2015-12-30 Raise Production Inc. Système de pompe à tige
US20190085677A1 (en) * 2017-09-18 2019-03-21 Gary V. Marshall Down-hole gas separator
US20200208506A1 (en) * 2018-12-26 2020-07-02 Odessa Separator, Inc. Above packer gas separation
US20200284134A1 (en) * 2019-03-05 2020-09-10 Wellworx Energy Solutions Llc Gas Bypass Separator

Family Cites Families (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6182751B1 (en) * 1996-12-25 2001-02-06 Konstantin Ivanovich Koshkin Borehole sucker-rod pumping plant for pumping out gas liquid mixtures
US6039121A (en) * 1997-02-20 2000-03-21 Rangewest Technologies Ltd. Enhanced lift method and apparatus for the production of hydrocarbons
US7462225B1 (en) * 2004-09-15 2008-12-09 Wood Group Esp, Inc. Gas separator agitator assembly
US9004166B2 (en) * 2011-08-01 2015-04-14 Spirit Global Energy Solutions, Inc. Down-hole gas separator
MX2017009006A (es) * 2015-01-09 2018-03-15 Modicum Llc Sistema de separacion de gas de fondo de pozo.
US20170151510A1 (en) * 2015-12-01 2017-06-01 Delwin E. Cobb Downhole liquid / gas separator
CA3132046A1 (fr) * 2019-03-11 2020-09-17 Blackjack Production Tools, Llc Separateur de gaz de fond de trou a entree limitee et a etages multiples
US11028683B1 (en) * 2020-12-03 2021-06-08 Stoneview Solutions LLC Downhole pump gas eliminating seating nipple system
US11536126B2 (en) * 2021-02-11 2022-12-27 Delwin E. Cobb Downhole gas-liquid separator

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20040020638A1 (en) * 2002-05-28 2004-02-05 Williams Benny J. Mechanically actuated gas separator for downhole pump
WO2015196287A1 (fr) * 2014-06-25 2015-12-30 Raise Production Inc. Système de pompe à tige
US20190085677A1 (en) * 2017-09-18 2019-03-21 Gary V. Marshall Down-hole gas separator
US20200208506A1 (en) * 2018-12-26 2020-07-02 Odessa Separator, Inc. Above packer gas separation
US20200284134A1 (en) * 2019-03-05 2020-09-10 Wellworx Energy Solutions Llc Gas Bypass Separator

Also Published As

Publication number Publication date
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