WO2023057597A1 - Production d'hydrocarbures - Google Patents

Production d'hydrocarbures Download PDF

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Publication number
WO2023057597A1
WO2023057597A1 PCT/EP2022/077863 EP2022077863W WO2023057597A1 WO 2023057597 A1 WO2023057597 A1 WO 2023057597A1 EP 2022077863 W EP2022077863 W EP 2022077863W WO 2023057597 A1 WO2023057597 A1 WO 2023057597A1
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WO
WIPO (PCT)
Prior art keywords
fluid
produced
pressure
hydrocarbon
subsea
Prior art date
Application number
PCT/EP2022/077863
Other languages
English (en)
Inventor
Cecilie Gotaas Johnsen
Arild SAMUELSBERG
Original Assignee
Equinor Energy As
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 Equinor Energy As filed Critical Equinor Energy As
Publication of WO2023057597A1 publication Critical patent/WO2023057597A1/fr

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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
    • 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
    • E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
    • 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
    • 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
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • 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
    • E21B43/36—Underwater separating arrangements

Definitions

  • the present invention relates to a method of hydrocarbon production. More specifically, the present invention relates to a method of producing hydrocarbon fluid from a subsea hydrocarbon reserve.
  • injection of water and/or gas is used to maintain pressure within the reserve/well and thereby maintain the pressure of the wellhead. This in turn maintains a high production rate of fluid being removed from the production well and further ensures that the produced fluid can be conveyed topside.
  • US 9181786 B1 discloses a method of production in which gas injection is used to maintain reserve and wellhead pressure.
  • Artificial lift in the form of pumping or otherwise, may be present at a particular production site and may be used in support of the injection to aid in conveying the produced fluid topside.
  • a constant degree of artificial lift is used where it is known from the outset of production at the given reserve that injection in itself will not be sufficient to convey the fluid topside.
  • US 10774622 B2 discloses a production system in which a topside (i.e. surface) pump is used to help convey hydrocarbon fluid to a surface production facility.
  • a topside (i.e. surface) pump is used to help convey hydrocarbon fluid to a surface production facility.
  • Injection is energy-intensive and is associated with a large ‘carbon footprint’ which in turn results in the overall production process having a large ‘carbon footprint’.
  • the pressure of injection is limited to a maximum pressure above which cracks would form in the reserve.
  • reserve pressure is maintained below this level when using injection.
  • the production rates that can be achieved by virtue of the use of injection are also limited since conventionally production rates are directly dependent on injection. There is thus a desire for production process that enables increased production rates.
  • a method of hydrocarbon production at an offshore production facility comprising: a) producing hydrocarbon fluid from a subsea wellhead in communication with a subsea hydrocarbon reserve; b) conveying the produced hydrocarbon fluid to a topside structure by means of the pressure of the produced hydrocarbon fluid; c) allowing the pressure of the produced hydrocarbon fluid at the wellhead to decline during step a) as a result of a declining hydrocarbon reserve pressure due to production of hydrocarbon fluid therefrom; and d) whilst allowing the pressure of the produced hydrocarbon fluid at the wellhead to decline, compensating for the declining pressure of the produced hydrocarbon fluid by introducing or increasing pumping of the produced hydrocarbon fluid (i.e. the produced fluid that has emanated from the wellhead) using a subsea pump to ensure that the produced fluid is conveyed to the topside structure.
  • the first aspect of the invention allows, and in fact requires, the pressure of the produced fluid at the wellhead and at the reserve to decline.
  • a high pressure necessarily has to be maintained, by virtue of fluid injection into the reserve, to ensure a high production rate of produced fluid and to ensure that the produced fluid was conveyed to the topside structure (perhaps with supporting artificial lift).
  • the inventors have realised that by allowing the wellhead pressure to drop, and thereby avoiding or at least minimising the reliance on injection, significant and advantageous energy savings can be made and thereby significant and advantageous reductions in the carbon footprint of the production process can be made.
  • Fluid (e.g. gas or water) injection is an energy intensive process and thus, by virtue of the hydrocarbons utilised in the production of the energy, is associated with a large carbon footprint.
  • desired hydrocarbons e.g. oil and/or heavier gas phases
  • the proportion of desired hydrocarbons in the fluid produced from the reserve similarly declines over the production lifetime of the reserve until such a point in time where injection fluid is effectively being cycled into and out of the reserve with little useful hydrocarbons being produced.
  • step c) of the method injection to the hydrocarbon reserve is avoided, reduced and/or minimised, which in turn allows for the declining hydrocarbon reserve pressure due to production of hydrocarbon fluid therefrom to be realised. If injection were not avoided, reduced and/or minimised when producing hydrocarbons then a declining hydrocarbon reserve pressure could not be realised since the injected fluid would necessarily maintain (or even increase) the pressure of the first. Given the absence or at least reduction/minimisation of injection, the method of production is made significantly less energy intensive and has a greatly reduced carbon footprint.
  • subsea pumping Pumping using a subsea pump (herein also termed subsea pumping) is in itself not a new measure; however, in the prior art subsea pumping is typically used as a constant support to provide lift to produced fluid and is typically used from the outset of production at a given reserve. There is no disclosure in the prior art of introducing subsea pumping after production at a given reserve has already commenced or increasing the degree of subsea pumping in response to declining pressure of the produced fluid at the wellhead.
  • the inventors have realised that by introducing/increasing the degree of subsea pumping to compensate for a declining pressure of the produced fluid at the wellhead (which is allowed to occur) the produced fluid can still be conveyed topside whilst still making significant energy savings (and thereby reducing the carbon footprint of the production process).
  • the energy associated with the subsea pumping that is introduced/increased and which is required to convey the produced fluid topside is significantly reduced as compared to the energy associated with the injection that would otherwise (and conventionally) be required for conveying the fluid topside.
  • the invention of the first aspect therefore resides in the realisation that by allowing for pressure of the produced fluid at the wellhead to decline and by compensating for the decline in this wellhead pressure by introducing or increasing subsea pumping of the produced fluid to the degree necessary to ensure the fluid is conveyed topside as required, that the production process can be carried out with a significantly reduced reliance on injection and thereby a significantly reduced carbon footprint.
  • the maximum pressure which limits injection based production methods is not a concern for the method of the first aspect.
  • the method of the fist aspect may optionally be used to withdraw produced fluid from the well at a rate greater than would be achievable via injection alone.
  • the subsea pumping is introduced/increased only (or substantially only) to the extent that ensures the produced fluid is conveyed topside as required.
  • the pumping of the produced hydrocarbon fluid using a subsea pump provides the produced fluid with the necessary impetus such that it is conveyed to the topside structure.
  • a surplus of subsea pumping above that which is required to ensure that the produced fluid is conveyed topside may be utilised. For example, where it is desired to maximise production rates. However, even in such a scenario, the energy input associated with the subsea pumping would necessarily be significantly reduced as compared to the injection that would otherwise be used for this purpose.
  • the method may comprise e) injecting fluid (e.g. gas and/or water) into the hydrocarbon reserve (and/or a well connected to the reserve) during step a) to lessen the decline in hydrocarbon reserve pressure and thereby lessen the decline in the pressure of the produced hydrocarbon fluid at the wellhead, but whilst still allowing a decline to take place.
  • fluid e.g. gas and/or water
  • the method of the first aspect may utilise injection, but to a lesser extent than with conventional arrangements.
  • injection may only be used to the extent that is absolutely necessary to ensure the produced fluid can be conveyed to the topside structure. That is to say, the method may comprise minimising injection of fluid in step e) whilst still ensuring that the produced fluid is conveyed to the topside structure.
  • Injection would certainly not be used to completely prevent the decline in pressure at the reserve as a result of hydrocarbon fluid being produced therefrom. If injection is used, it would only be used to reduce the degree of decline of pressure, with compensation for the rest of the decline in pressure being provided for by subsea pumping, which as above is far less energy intensive than injection.
  • the subsea pump may be installed before production commences, i.e. before step a). However, the method may alternatively comprise installing the subsea pump prior to step d) of the method but after step a) of the method.
  • the method of the first aspect may comprise a step f) of separating the produced fluid using a subsea separator once the pressure of the produced fluid falls below a first predetermined level.
  • step c The pressure of the fluid produced at the wellhead declines in step c). Whilst this is advantageous since it results from the avoidance (or reduction) of energy intensive injection, it can also be problematic if the pressure of the produced fluid decreases to a large enough degree.
  • the produced hydrocarbon fluid will typically comprise a mix of constituents including oil phases, hydrocarbon gas phases and water.
  • a fluid comprising both hydrocarbon gas phases and water is susceptible to hydrate formation, particularly when the pressure of said fluid is sufficiently low. Hydrates are ice-like crystalline solids which, when formed in hydrocarbon production equipment and associated conduits/piping, can cause blockages and damage that are/is undesirable.
  • the method of the first aspect of the invention can optionally deal with these issues by, as above, introducing subsea separation, optionally at least once the pressure of the produced fluid falls below a first predetermined level.
  • This first predetermined level may be selected to avoid hydrate formation and/or to avoid vaporisation (i.e. boiling off) of phases from the produced fluid.
  • the method may comprise drawing down the pressure of the subsea separator in response to the declining pressure of the produced fluid at the wellhead. In that way, separation is enabled for the produced hydrocarbon fluid despite its declining pressure.
  • the separation in step f) may comprise separating water from the produced hydrocarbon fluid.
  • step f) of the method may comprise separating the produced hydrocarbon fluid into a gas phase and an oil phase. This may occur in addition to, or as an alternative to, the separation of water as discussed above.
  • the separation of the gas phases from the oil phases may occur in a two phase separator or, where water separation also occurs, may occur in a three phase separator. If water and gas separation are optionally employed, they need not occur within a three phase separator but may instead occur in a series of sequential, two phase separation processes.
  • the subsea pump may pump the (separated) oil phase to the topside structure after separation thereof.
  • the gas phase may not require artificial lift (e.g. pumping and/or compression) to convey it to the topside structure after separation thereof.
  • artificial lift e.g. pumping and/or compression
  • the inherent pressure of the separated gas may be sufficient to convey itself topside.
  • the gas phase may require artificial lift to convey it to the topside structure or to convey it to the topside structure at the desired rate, or it may not initially require artificial lift to convey it to the topside structure but may require artificial lift over time as the pressure of the separated gas phase reduces, for example, as a result of the decreasing pressure in the separator.
  • the method may comprise, when the pressure of the gas phase drops below a second predetermined level, introducing a subsea compressor to provide artificial lift to the gas phase.
  • Step c) of the method may be controlled by controlling the degree of opening of a choke valve associated with the subsea wellhead.
  • the topside structure of the invention may be any structure that is conventionally situated topside (i.e. above or at sea level) within a production facility and that would receive produced hydrocarbon fluid therefrom.
  • the topside structure may be an offshore platform, for instance a production platform or vessel (e.g. a floating, production storing and offloading (FPSO) vessel).
  • FPSO floating, production storing and offloading
  • the topside structure may be an offshore structure.
  • the topside structure may be an unmanned structure, for example an unmanned production platform (UPP).
  • UPF unmanned production platform
  • unmanned may require at least one of: no permanent personnel at the topside structure; no provision of facilities for personnel to stay on the structure, for example there may be no shelters for personnel, no toilet facilities, no drinking water, no personnel operated communications equipment and/or no lifeboat; and/or that personnel be present for fewer than 10,000 maintenance hours per year at the structure.
  • An unmanned structure may have no permanent personnel and may only be occupied for particular operations such as maintenance and/or installation of equipment.
  • the unmanned structure may be a structure where no personnel are required to be present for the structure to carry out its normal function, for example day-to-day functions relating to handling of oil and/or gas products at the structure.
  • An unmanned structure may alternatively or additionally be defined as unmanned based on the relative amount of time that personnel are needed to be present on the structure during operation. This relative amount of time may be defined as maintenance hours needed per annum, for example, an unmanned structure may be a structure requiring fewer than 10,000 maintenance hours per year, optionally fewer than 5000 maintenance hours per year, perhaps fewer than 3000 maintenance hours per year.
  • the topside structure may be a low-manned structure, for example a low- manned production platform.
  • a low-manned structure comprises some permanent crew/personnel (which distinguishes it from an unmanned structure)
  • the low-manned structure has a relatively small number of personnel (i.e. a skeleton crew) and thus it is distinguished from a ‘manned’ or ‘fully-manned’ structure.
  • Figure 1 is a schematic of an offshore production facility carrying out a method of hydrocarbon production in accordance with an embodiment of the invention.
  • Figure 1 depicts an offshore production facility 1 situated at an offshore hydrocarbon reserve.
  • the production facility 1 comprises a plurality of production wells 3, each associated with a respective wellhead 5.
  • the wellheads 5 are each connect to a common header 7, which in turn is connected to a two-phase subsea separator 9.
  • the subsea separator 9 has a first outlet connected to a gas riser 11 and a second outlet connected to a subsea pump 13, which itself has an outlet connected to a liquid riser 15.
  • the gas riser 11 and liquid riser 15 extend from the subsea separator 9 and pump 13, respectively, to an offshore production platform 17 that is situated topside and represented by a dashed line in Figure 1.
  • the production platform 17 comprises two sequential separators 19a, 19b.
  • a pump 25 is connected to a second outlet of the second separator 19b.
  • a conduit links the liquid riser 15 to the inlet of the first sequential separator 19a.
  • the production platform 17 further comprises five sequential compressors 21a- 21e, with a dehydration unit 23 situated between the fourth 21d and fifth 21e sequential compressors.
  • a conduit links the gas riser 11 with the inlet of the fourth compressor 21 d.
  • a first outlet of the first separator 19a feeds a conduit that leads to the inlet of the third compressor 21c, whilst a second outlet of the first separator 19b feeds a conduit leading to the inlet of the second separator 19b.
  • a first outlet of the second separator 19b feeds a conduit that leads to the inlet of the first compressor 21a.
  • fluid is produced at the hydrocarbon production facility 1 from the plurality of production wells 3.
  • the fluid flows to the wellheads 5, and in turn passes to the header 7.
  • the produced hydrocarbon fluid passes into the subsea separator 9.
  • the subsea separator 9 is a two phase separator, and separates the fluid into a hydrocarbon gas phase and a liquid phase comprising oil phases.
  • separators 19a, 19b On the production platform, a number of sequential separation processes of the liquid phase occur using separators 19a, 19b. Gas is drawn off during these separation processes and is fed into third 21c and first 21a compressors, dependent on the stage at which the gas has been separated.
  • the liquid product, including oil phases, is outlet from the second outlet of the second separator 19b and is transferred to a pump 25 for pressurisation such that it can be conveyed as desired.
  • compressors 21a-21d Prior to reaching the final, fifth compressor 21e the gas is dehydrated by passing through the dehydration unit 23. The gas is then passed to the final compressor 21 d, and is then conveyed for use elsewhere (e.g. for use as an injection fluid in an injection well).
  • the degree of pumping by the subsea pump 13 is increased. In that way, the decreased pressure liquid phase output from the subsea separator 9 can be provided with sufficient impetus to convey it topside to the offshore platform 17.
  • the subsea separator 9 pressure can also be decreased to match the declining pressure of the wellheads 5 and thereby continue to enable separation of the fluid therein.

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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)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)

Abstract

Procédé de production d'hydrocarbures au niveau d'une installation de production en mer (1). Le procédé comprend les étapes consistant à : a) produire un fluide hydrocarbure à partir d'une tête de puits sous-marine (5) en communication avec une réserve d'hydrocarbures sous-marine ; b) transporter le fluide hydrocarbure produit vers une structure supérieure (17) au moyen de la pression du fluide hydrocarbure produit au niveau de la tête de puits ; c) permettre à la pression du fluide hydrocarbure produit au niveau de la tête de puits de diminuer pendant l'étape a) à la suite d'une baisse de la pression de la réserve d'hydrocarbures en raison de la production d'un fluide hydrocarbure à partir de celle-ci ; et d) tout en permettant à la pression du fluide hydrocarbure produit au niveau de la tête de puits de diminuer, compenser la baisse de la pression du fluide hydrocarbure produit par l'introduction ou l'augmentation du pompage du fluide hydrocarbure produit à l'aide d'une pompe sous-marine afin de garantir le transport du fluide produit vers la structure supérieure.
PCT/EP2022/077863 2021-10-06 2022-10-06 Production d'hydrocarbures WO2023057597A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB2114304.5A GB2611539A (en) 2021-10-06 2021-10-06 Hydrocarbon production
GB2114304.5 2021-10-06

Publications (1)

Publication Number Publication Date
WO2023057597A1 true WO2023057597A1 (fr) 2023-04-13

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PCT/EP2022/077863 WO2023057597A1 (fr) 2021-10-06 2022-10-06 Production d'hydrocarbures

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WO (1) WO2023057597A1 (fr)

Citations (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6267182B1 (en) * 1996-06-12 2001-07-31 Petroleo Brasileiro S. A. - Petrobras Method and equipment for offshore oil production with primary gas separation and flow using the injection of high pressure gas
US20050072574A1 (en) * 2001-10-12 2005-04-07 Appleford David Eric System and method for injecting gas into a hydrocarbon reservoir
US20050189116A1 (en) * 2004-02-26 2005-09-01 Vetco Gray Inc. Submersible well pump installation procedure
US20110042093A1 (en) * 2007-10-10 2011-02-24 Petroleo Brasileiro S A - Petrobras Pumping module and system
US20110168399A1 (en) * 2008-05-02 2011-07-14 Jean Francois Saint-Marcoux Mid water gas lift
US20130220434A1 (en) * 2012-02-28 2013-08-29 Jeff (Jianfeng) Zhang Systems And Methods For Pressure Boosting Of Liquids Of A Hydrocarbon Gas-Liquid Separator Using One Or More Pumps On Seabed
US9140106B2 (en) * 2010-06-30 2015-09-22 Chevron U.S.A. Inc. System and method for producing hydrocarbons from a well
US9181786B1 (en) 2014-09-19 2015-11-10 Baker Hughes Incorporated Sea floor boost pump and gas lift system and method for producing a subsea well
US10774622B2 (en) 2016-09-27 2020-09-15 David C. Wright Pipeline booster pump system for promoting fluid flow

Family Cites Families (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
NO312978B1 (no) * 2000-10-20 2002-07-22 Kvaerner Oilfield Prod As Fremgangsmåter og anlegg for å produsere reservoarfluid

Patent Citations (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6267182B1 (en) * 1996-06-12 2001-07-31 Petroleo Brasileiro S. A. - Petrobras Method and equipment for offshore oil production with primary gas separation and flow using the injection of high pressure gas
US20050072574A1 (en) * 2001-10-12 2005-04-07 Appleford David Eric System and method for injecting gas into a hydrocarbon reservoir
US20050189116A1 (en) * 2004-02-26 2005-09-01 Vetco Gray Inc. Submersible well pump installation procedure
US20110042093A1 (en) * 2007-10-10 2011-02-24 Petroleo Brasileiro S A - Petrobras Pumping module and system
US20110168399A1 (en) * 2008-05-02 2011-07-14 Jean Francois Saint-Marcoux Mid water gas lift
US9140106B2 (en) * 2010-06-30 2015-09-22 Chevron U.S.A. Inc. System and method for producing hydrocarbons from a well
US20130220434A1 (en) * 2012-02-28 2013-08-29 Jeff (Jianfeng) Zhang Systems And Methods For Pressure Boosting Of Liquids Of A Hydrocarbon Gas-Liquid Separator Using One Or More Pumps On Seabed
US9181786B1 (en) 2014-09-19 2015-11-10 Baker Hughes Incorporated Sea floor boost pump and gas lift system and method for producing a subsea well
US10774622B2 (en) 2016-09-27 2020-09-15 David C. Wright Pipeline booster pump system for promoting fluid flow

Non-Patent Citations (3)

* Cited by examiner, † Cited by third party
Title
DARVISH SARVESTANI A ET AL: "artificial lift method selection for mature oil fields: A case study", SOCIETY OF PETROLEUM ENGINEERS - SPE ANNUAL CASPIAN TECHNICAL CONFERENCE 2019, CTC 2019 - SOCIETY OF PETROLEUM ENGINEERS - SPE ANNUAL CASPIAN TECHNICAL CONFERENCE 2019, CTC 2019 2019 SOCIETY OF PETROLEUM ENGINEERS USA, 2019, DOI: 10.2118/198424-MS *
DARVISH SARVESTANI A ET AL: "artificial lift method selection for mature oil fields: A case study", SOCIETY OF PETROLEUM ENGINEERS - SPE ANNUAL CASPIAN TECHNICAL CONFERENCE 2019, CTC 2019, 2019, SOCIETY OF PETROLEUM ENGINEERS USA, XP002806505, DOI: 10.2118/198424-MS *
DATABASE COMPENDEX [online] ENGINEERING INFORMATION, INC., NEW YORK, NY, US; 2019, DARVISH SARVESTANI A ET AL: "artificial lift method selection for mature oil fields: A case study", XP002808120, Database accession no. E20200808192569 *

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GB202114304D0 (en) 2021-11-17
GB2611539A (en) 2023-04-12

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