WO2019109080A1 - Installation centrale de traitement, optimisation de génération de vapeur par contact direct - Google Patents

Installation centrale de traitement, optimisation de génération de vapeur par contact direct Download PDF

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Publication number
WO2019109080A1
WO2019109080A1 PCT/US2018/063627 US2018063627W WO2019109080A1 WO 2019109080 A1 WO2019109080 A1 WO 2019109080A1 US 2018063627 W US2018063627 W US 2018063627W WO 2019109080 A1 WO2019109080 A1 WO 2019109080A1
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WO
WIPO (PCT)
Prior art keywords
dcsg
cpf
feedwater
steam
production site
Prior art date
Application number
PCT/US2018/063627
Other languages
English (en)
Inventor
James C. Juranitch
Original Assignee
XDI Holdings, LLC
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 XDI Holdings, LLC filed Critical XDI Holdings, LLC
Priority to CA3083918A priority Critical patent/CA3083918A1/fr
Priority to US16/768,161 priority patent/US20200370403A1/en
Publication of WO2019109080A1 publication Critical patent/WO2019109080A1/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
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2406—Steam assisted gravity drainage [SAGD]
    • E21B43/2408—SAGD in combination with other methods
    • 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
    • E21B43/40—Separation associated with re-injection of separated materials
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B1/00—Methods of steam generation characterised by form of heating method
    • F22B1/02—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers
    • F22B1/18—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers the heat carrier being a hot gas, e.g. waste gas such as exhaust gas of internal-combustion engines
    • F22B1/1853—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers the heat carrier being a hot gas, e.g. waste gas such as exhaust gas of internal-combustion engines coming in direct contact with water in bulk or in sprays
    • 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
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2401—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection by means of electricity
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P80/00—Climate change mitigation technologies for sector-wide applications
    • Y02P80/10—Efficient use of energy, e.g. using compressed air or pressurized fluid as energy carrier
    • Y02P80/15—On-site combined power, heat or cool generation or distribution, e.g. combined heat and power [CHP] supply

Definitions

  • Embodiments of the present disclosure relate generally to a method, apparatus and system for the optimization of an unconventional oil recovery Central Processing Facility (CPF) for the cost effective and efficient implementation of a Direct Contact Steam Generation (DCSG) system which is preferably located at the well pad.
  • CPF Central Processing Facility
  • DCSG Direct Contact Steam Generation
  • DCSGs Direct Contact Steam Generators
  • SAGD steam assist gravity drain
  • SF Steam Flood
  • CCS Cyclic Steam Stimulation
  • Various embodiments of the present disclosure can include a system.
  • the system can include a hydrocarbon production site.
  • the system can include a direct contact steam generator (DCSG) system.
  • the DCSG system can be configured to generate steam and supply the steam to an unconventional oil recovery process.
  • the DCSG system can reside in close proximity to the hydrocarbon production site.
  • the DCSG system can include a DCSG boiler to which feedwater is provided, the feedwater being treated and supplied to the DCSG system from a remote central processing facility (CPF).
  • CPF remote central processing facility
  • Various embodiments of the present disclosure can include a system.
  • the system can include a hydrocarbon production site.
  • the system can include a DCSG system.
  • the DCSG system can be configured to generate steam and supply the steam to an unconventional oil recovery process.
  • the DCSG system can reside in close proximity to the hydrocarbon production site.
  • the DCSG system can include a DCSG boiler to which feedwater is provided, the feedwater being treated and supplied to the DCSG system at a location proximate to a location of the hydrocarbon production site.
  • Various embodiments of the present disclosure can include a system.
  • the system can include a hydrocarbon production site.
  • the system can include a DCSG system.
  • the DCSG system can be configured to generate steam and supply the steam to an unconventional oil recovery process.
  • the DCSG system can reside in close proximity to the hydrocarbon production site.
  • the DCGS system can include a DCSG boiler to which feedwater is provided, the feedwater being treated and supplied to the DCSG system at a location in close proximity to a location of the hydrocarbon production site, wherein the feedwater is not treated or supplied via a central processing facility (CPF).
  • CPF central processing facility
  • Fig. 1 depicts a simplified schematic representation of a SAGD CPF, in accordance with embodiments of the present disclosure.
  • Fig. 2A depicts an example of a new CPF optimized for a DCSG well, pad, or series of pads configuration, in accordance with embodiments of the present disclosure.
  • Fig. 2B depicts an example of a new well, pad, or series of pads optimized for a DCSG configuration that compliments the CPF in Fig. 2A, in accordance with embodiments of the present disclosure.
  • Fig. 3A depicts an example of another new CPF optimized for a DCSG well, pad, or series of pads configuration, in accordance with embodiments of the present disclosure.
  • Fig. 3B depicts an example of another new well, pad, or series of pads optimized for a DCSG configuration that compliments the CPF in Fig. 3A, in accordance with embodiments of the present disclosure.
  • Embodiments of the present disclosure relate generally to a method, apparatus and system for the optimization of an unconventional oil recovery Central Processing Facility (CPF) for the cost effective and efficient implementation of a Direct Contact Steam Generation (DCSG) system which is preferably located at the well pad.
  • CPF Central Processing Facility
  • DCSG Direct Contact Steam Generation
  • SAGD Steam Assisted Gravity Drain
  • DCSGs are today considered unconventional boilers. They are preferably located at a hydrocarbon production site, such as a well, or pad, or at least close to a number of pads. A pad can be a collection of wells. At one of these locations, steam can be used directly or in a worst case scenario, the steam may have to travel a minimal distance.
  • DCSGs can operate on dirty water and for the most part eliminate the "huge water treatment plant" requirement from the CPF. This new paradigm shift presents opportunities to re-think the CPF design and its function to optimize it for DCSG technology. At least 2 approaches to apply this new technology are possible.
  • Embodiments of the present disclosure include methods, apparatus, and systems to optimize the CPF for DCSG applications.
  • a steam outlet conduit associated with the DCGSs can be less than one mile in length.
  • the steam outlet conduit associated with the DCGs can be at the hydrocarbon production site (e.g., well), effectively placing the steam outlet conduit zero feet away from the oil production site.
  • the steam outlet associated with the DCGS can be up to two miles away from the oil production site.
  • the DCSG system can be configured to produce as small as 1,000 bpd of steam and can serve a single well.
  • the DCSG system can be configured to produce as large as 50,000 bpd, if the system serves a number of closely positioned pads that require high volumes of steam.
  • the CPF can now be located any reasonable pipe line distance away from the wells and pads.
  • the CPF can be located remotely from the hydrocarbon production site and/or the DCSG.
  • the CPF can be located a distance from the oil production site in a range from 10 miles to 100 miles, although embodiments are not so limited and the CPF can be located closer than 10 miles or further than 100 miles from the oil production site.
  • the CPF could service over 100,000 bpd of unconventional oil which would equate to a conventional CPF that previously would have had to produce over 300,000 bpd of steam.
  • This disclosed large CPF could be contained at one location and be third party operated by a service provider who sells the CPF services to a producer or a number of producers. This configuration would again reduce the Opex of the unconventional oil recovery process.
  • Fig. 1 depicts a SAGD CPF, in accordance with embodiments of the present disclosure.
  • the steam boiler 1 is typically an OTSG, but could also be a drum boiler or other conventional boiler design .
  • a DCSG could also be used at the CPF in place of an OTSG at the drawn location but it could compromise the efficiency of the complete system due to steam transportation losses to the pads if located in the CPF.
  • Steam traveling through a steam conduit 2, which is fluidly coupled with the steam boiler 1, is produced by the steam boiler 1.
  • the steam that is transported to the pads via the steam conduit 2 is to be injected into the SAGD wells. In some cases, the wells could be over five miles away from the steam generator. Significant system energy losses, sometimes over 10%, can be suffered due to shipping the steam these long distances.
  • a natural gas feed conduit 3 is fluidly coupled to the steam boiler 1 and can carry natural gas or natural gas plus a produced gas fuel supply to the steam boiler 1.
  • a waste water conduit 5 contains the blow down waste water required to maintain the health of the conventional boiler.
  • a boiler feedwater (BFW) conduit 4 contains the boiler feedwater provided to the steam boiler 1 and is fluidly coupled to the steam boiler 1.
  • the boiler feedwater is buffered in a storage tank 8, which is supplemented in its supply of clean and treated boiler feedwater from clean and treated makeup feedwater provided to the storage tank 8 via the makeup feedwater conduit 7.
  • the feedwater is manufactured from returned produced water, which is provided from a bitumen treating and separation plant 16 to a water treatment plant 9 via a produced water conduit 19.
  • the returned produced water is water returned from the bitumen well .
  • the dirty produced water provided to the water treatment plant 9 via the produced water conduit 19 goes through an extensive clean up and filtering process in the water treatment plant 9 that makes up the majority of the CPF.
  • the water treatment plant 9 is diagrammatically shown in Fig. 1.
  • the water treatment plant can produce waste water, lime sludge and cake, which are depicted as exiting the water treatment plant 9 via waste conduit 10.
  • the feedwater provided to the boiler 1 can be treated and supplied to the boiler at a location in close proximity to a location of the hydrocarbon production site.
  • Bitumen emulsion and produced gas arrive from the pad via production conduit 15.
  • the mix is processed and separated via separation system 16, which can be made up of components such as one or more of a Free Water Knockout systems, skimmer (e.g ., skim tank), and gas separation systems.
  • the produced gas can be provided to a treatment system 18 via a produced gas conduit 17.
  • the treatment system 18 can clean up the produced gas, which can be re-used in the boilers (e.g ., steam boiler 1) and pads.
  • semi-processed produced water can be shipped to the water treatment process or "plant" as shown as water treatment plant 9.
  • Some diluent from diluent storage tank 20 may be injected into the bitumen separation system 16 through a first diluent conduit 21.
  • the reduced viscosity bitumen is transported through bitumen conduit 22, which may need additional amounts of diluent added to become Dilbit or salable product, as shown in hydrocarbon storage and handling tank 24.
  • the Dilbit or salable product can be transferred through hydrocarbon conduit 23 into the hydrocarbon storage and handling tank 24.
  • the Dilbit or salable product can be pumped from the hydrocarbon storage and handling tank 24 via a pump 25 and finally exit via exit conduit 26 to a sales pipeline, in an example.
  • Electrical power is shown as power 6, which would be used to power the CPF and the pads.
  • the source of the power 6 can be from an on-site generator and/or electrical transmission line connected to a power plant.
  • a carbon-based fuel and blanket and lift gas can be received from the CPF via a gas conduit 13.
  • conduit 11 is used to provide a method to premix preferred amounts of well head gas into natural gas supply 12, which can be in
  • conduit 14 can contain a non-natural gas, mixed but treated well head gas, to potentially be used as a blanket gas or other hydrocarbon recovery tool .
  • Basic subsystems such as glycol loops and condensate systems have not been shown to aid in clarity.
  • Fig. 2A is an example of a new CPF optimized for a DCSG well, pad or series of pads configuration, in accordance with embodiments of the present disclosure. Similar elements, such as those depicted and discussed with respect to Fig. 1 are denoted with a "prime" symbol in Fig. 2A.
  • the produced gas treating facility 18, as depicted in Fig. 1 can include the same or similar features with respect to the produced gas treating facility 18', as depicted in Fig. 2A.
  • Fig. 2A depicts an embodiment that includes a minimal water treatment system 27. In some cases, the minimal water treatment system can include just a coarse filter.
  • the source of DCSG boiler feedwater provided to the minimal water treatment system 27 via the produced water conduit 19' could come directly from the Free water Knockout or from an additional downstream skim tank, which can be included in the separation system 16'. Neither of these devices are shown in Fig. 2A for simplicity.
  • the lightly (e.g . minimally) treated water then travels through treated water conduit 30 into a dirty feedwater storage tank 28 and is transported through a boiler feedwater conduit 29 to the well, pad, or pads to be consumed by the DCSG.
  • the well, pad, and/or pads can be referred to as a hydrocarbon production site.
  • the make-up feedwater in conduit 7' could be fresh, dirty or contaminated water, or pond water from a bitumen mining operation .
  • Fig. 2B depicts an example of a new well, pad, or series of pads optimized for a DCSG configuration that compliments the CPF in Fig . 2A, in accordance with embodiments of the present disclosure. Similar elements, such as those depicted and discussed with respect to Fig . 1 are denoted with a "prime" symbol in Fig . 2B.
  • the electrical power 6, as depicted in Fig. 1 can include the same or similar features with respect to the electrical power 6', as depicted in Fig. 2B.
  • the electrical power 6' can be received from the CPF.
  • Carbon-based fuel and blanket and lift gas 13' can be received from the CPF.
  • a DCSG system 31 can be located at a well, pad or in close proximity to pads and the deployment of the generated steam via generated steam conduit 32.
  • the steam outlet conduit associated with the DCGs can be at the hydrocarbon production site (e.g. , well), effectively placing the steam outlet conduit zero feet away from the oil production site.
  • the steam outlet associated with the DCGS can be up to two miles away from the oil production site.
  • Generated steam conduit 32 transfers steam generated by the DCSG system 31 to three closely positioned pads (pads not shown), although embodiments are not so limited .
  • the generated steam conduit 32 could be sized to only service one well or many wells or a single pad or many pads.
  • the key to keeping a high efficiency and minimizing both Capex and Opex would be to minimize the steam losses by minimizing the distance the steam is required to travel through careful DCSG system 31 placement versus deploying the minimum amount of DCSG systems required to complete the desired unconventional oil recovery.
  • a waste conduit 33 could be used to eject the waste solids from the produced water if superheat were used in the DCSG system 31 or blowdown waste conduit 34 could be used to eject blowdown if saturated steam conditions were generated in the DCSG system 31.
  • a boiler feedwater conduit 29 delivers Boiler Feedwater from the CPF to the DCSG system 31.
  • a production conduit 15' carries the bitumen emulsion from the well producer back to the CPF.
  • Fig. 3A depicts an example of another new CPF optimized for a DCSG well, pad, or series of pads configuration, in accordance with embodiments of the present disclosure. Similar elements, such as those depicted and discussed with respect to Fig . 1 are denoted with a "double-prime" symbol in Fig . 3A.
  • the electrical power 6, as depicted in Fig. 1 can include the same or similar features with respect to the electrical power 6", as depicted in Fig . 3A.
  • the CPF in Fig. 3A is similar to the CPF depicted in Fig . 2A with the exception that the Bitumen Treating and Separation system (e.g. , see 16' in Fig.
  • Fig. 3B depicts an example of another new well, pad, or series of pads optimized for a DCSG configuration that compliments the CPF in Fig . 3A, in accordance with embodiments of the present disclosure.
  • Fig. 3B depicts a well, pad or series of pads that is configured to be served by the CPF in Fig. 3A.
  • Elements denoted by power 6", makeup feedwater conduit 7", gas conduit 13", production conduit 15", separation system 16", first diluent conduit 21", DCSG system 31', generated steam conduit 32', waste conduit 33', blowdown waste conduit 34', serve the same functions already disclosed in the previous figures and are denoted by a "prime” symbol or a "double-prime".
  • a first diluent conduit 21" carries diluent which is provided from the CPF described in Fig. 3A.
  • the diluent may be used to thin the bitumen in separator 16" or added to the already separated bitumen in conduit 36.
  • Produced gas can be transferred to the DCSG system 31' via produced gas conduit 45.
  • Pump 37 is used to move the Dilbit through conduit 36 to a pipeline or storage area .
  • Separated boiler feedwater is sent in conduit 40 through boost pump 38 to coarse filter 39.
  • the boiler feedwater is buffered in a buffer tank 41, where overflow conduit 44 and pump 43 and make-up inflow water in makeup feedwater conduit 7" are used to maintain the correct level in buffer tank 41.
  • make-up inflow water can be introduced into buffer tank 41 via makeup feedwater conduit 7" and/or water can be extracted from the buffer tank 41 via the overflow conduit 44 and pump 43 to control the level of water in the buffer tank 41.
  • the make-up feedwater in conduit 7" could be fresh, dirty or contaminated water, or pond water from a bitumen mining operation. Feedwater from tank 41 is transferred and pressurized by pump 42 into the DCSG system 31'.
  • joinder references do not necessarily infer that two elements are directly connected and in fixed relationship to each other. It is intended that all matter contained in the above description or shown in the accompanying drawings shall be interpreted as illustrative only and not limiting. Changes in detail or structure can be made without departing from the spirit of the disclosure as defined in the appended claims.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Chemical & Material Sciences (AREA)
  • Combustion & Propulsion (AREA)
  • Sustainable Development (AREA)
  • Sustainable Energy (AREA)
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  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Pipeline Systems (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

Selon certains modes de réalisation, la présente invention concerne un système. Le système peut comprendre un site de production d'hydrocarbures. Le système peut comprendre un système générateur de vapeur par contact direct (DCSG). Le système générateur de vapeur par contact direct peut être configuré pour générer de la vapeur et fournir la vapeur à un processus de récupération d'huile non conventionnel. Le système générateur de vapeur par contact direct peut être situé à proximité immédiate du site de production d'hydrocarbures. Le générateur de vapeur par contact direct peut comprendre une chaudière de générateur de vapeur par contact direct à laquelle de l'eau d'alimentation est fournie, l'eau d'alimentation étant traitée et fournie au système générateur de vapeur par contact direct à partir d'une installation centrale de traitement (CPF) distante.
PCT/US2018/063627 2017-12-01 2018-12-03 Installation centrale de traitement, optimisation de génération de vapeur par contact direct WO2019109080A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
CA3083918A CA3083918A1 (fr) 2017-12-01 2018-12-03 Installation centrale de traitement, optimisation de generation de vapeur par contact direct
US16/768,161 US20200370403A1 (en) 2017-12-01 2018-12-03 Central processing facility, direct contact steam generation optimization

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201762593462P 2017-12-01 2017-12-01
US62/593,462 2017-12-01

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Publication Number Publication Date
WO2019109080A1 true WO2019109080A1 (fr) 2019-06-06

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Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20110005749A1 (en) * 2007-07-19 2011-01-13 Shell International Research Maatschappij B.V. Water processing systems and methods
US8973658B2 (en) * 2011-03-04 2015-03-10 Conocophillips Company Heat recovery method for wellpad SAGD steam generation
US20150275637A1 (en) * 2014-03-28 2015-10-01 Suncor Energy Inc. Remote steam generation and water-hydrocarbon separation in steam-assisted gravity drainage operatons
CA2875034A1 (fr) * 2014-12-17 2016-06-17 John L. Allen Methode, systeme et appareil pour ouvrir et exploiter des puits de petrole non thermiques selon des procedes de recuperation haute temperature

Family Cites Families (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CA2721705C (fr) * 2009-08-07 2014-02-18 Aquatech International Corporation Methode de production de distillat tres pur a partir de l'eau resultant de vapeur a haute pression
WO2014066034A1 (fr) * 2012-10-24 2014-05-01 Conocophillips Company Production directe de vapeur de purge de chaudière
US20140166281A1 (en) * 2012-12-17 2014-06-19 Conocophillips Company Liquid indirect steam boiler
US10247409B2 (en) * 2015-11-04 2019-04-02 Conocophillips Company Remote preheat and pad steam generation
CA2943314C (fr) * 2016-09-28 2023-10-03 Suncor Energy Inc. Production d'hydrocarbure par generation de vapeur en contact direct

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20110005749A1 (en) * 2007-07-19 2011-01-13 Shell International Research Maatschappij B.V. Water processing systems and methods
US8973658B2 (en) * 2011-03-04 2015-03-10 Conocophillips Company Heat recovery method for wellpad SAGD steam generation
US20150275637A1 (en) * 2014-03-28 2015-10-01 Suncor Energy Inc. Remote steam generation and water-hydrocarbon separation in steam-assisted gravity drainage operatons
CA2875034A1 (fr) * 2014-12-17 2016-06-17 John L. Allen Methode, systeme et appareil pour ouvrir et exploiter des puits de petrole non thermiques selon des procedes de recuperation haute temperature

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US20200370403A1 (en) 2020-11-26

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