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WO2014201139A1 - Générateur de vapeur et capture de dioxyde de carbone - Google Patents

Générateur de vapeur et capture de dioxyde de carbone Download PDF

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Publication number
WO2014201139A1
WO2014201139A1 PCT/US2014/041948 US2014041948W WO2014201139A1 WO 2014201139 A1 WO2014201139 A1 WO 2014201139A1 US 2014041948 W US2014041948 W US 2014041948W WO 2014201139 A1 WO2014201139 A1 WO 2014201139A1
Authority
WO
WIPO (PCT)
Prior art keywords
steam
carbon dioxide
steam generator
regenerator
recovery unit
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2014/041948
Other languages
English (en)
Inventor
David William LARKIN
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
ConocoPhillips Co
Original Assignee
ConocoPhillips Co
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by ConocoPhillips Co filed Critical ConocoPhillips Co
Publication of WO2014201139A1 publication Critical patent/WO2014201139A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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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]
    • 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
    • E21B36/00—Heating, cooling or insulating arrangements for boreholes or wells, e.g. for use in permafrost zones

Definitions

  • Embodiments of the invention relate to generating steam and efficient recovery of carbon dioxide from flue gases produced while generating the steam.
  • Oxy-fuel combustion for steam boilers provides an alternative option for mitigating carbon dioxide emissions since flue gas contains carbon dioxide and water vapor as primary separable constituents.
  • flue gas contains carbon dioxide and water vapor as primary separable constituents.
  • the oxy-fuel combustion requires energy intensive cryogenic air separation units limiting actual emission avoidance.
  • recovered carbon dioxide still requires treatment to remove oxygen, nitrogen and argon contaminants in order to meet pipeline specifications.
  • a method of steam assisted oil recovery integrated with carbon dioxide capture includes feeding water to a steam generator that produces injection steam and liquid blowdown separated from the injection steam at a first pressure. The method further includes introducing the injection steam into a formation for the steam assisted oil recovery, flashing the blowdown at a second pressure lower than the first pressure to provide regenerator steam and condensate, and passing the condensate through a heat exchanger to preheat the water prior to the water entering the steam generator.
  • a carbon dioxide recovery unit uses the regenerator steam in capturing carbon dioxide from flue gas exhaust of the steam generator.
  • a method of steam assisted oil recovery integrated with carbon dioxide capture includes feeding water to a steam generator that produces injection steam and liquid blowdown separated from the injection steam at a first pressure.
  • the method includes introducing the injection steam into a formation for the steam assisted oil recovery, flashing the blowdown at a second pressure lower than the first pressure to provide regenerator steam and condensate, and supplying the regenerator steam to a carbon dioxide recovery unit for use in capturing carbon dioxide from flue gas exhaust of the steam generator.
  • the blowdown without additional steam input provides all steam requirements for solvent regeneration in the carbon dioxide recovery unit.
  • a method of steam assisted oil recovery integrated with carbon dioxide capture includes feeding water to a steam generator that produces injection steam and liquid blowdown separated from the injection steam at a first pressure.
  • the method also includes introducing the injection steam into a formation for the steam assisted oil recovery, flashing the blowdown at a second pressure lower than the first pressure to provide regenerator steam and condensate, and supplying the regenerator steam to a carbon dioxide recovery unit for use in capturing carbon dioxide from flue gas exhaust of the steam generator. Passing combustion exhaust of a regenerator boiler for the carbon dioxide recovery unit through a heat exchanger preheats one of air and the water that are then supplied to the steam generator.
  • Figure 1 is a schematic of a production system for integrated steam assisted oil recovery and carbon dioxide capture, according to one embodiment of the invention.
  • Figure 2 is a schematic of an alternative system for integrated steam assisted oil recovery and carbon dioxide capture, according to one embodiment of the invention.
  • Methods and systems generate steam for injection into a formation in order to facilitate oil recovery and also capture carbon dioxide in a recovery unit that receives flue gas exhaust from such steam generation.
  • the methods and systems integrate various process streams from and to the carbon dioxide recovery unit. Such integration provides resulting benefits associated with efficiency and/or carbon dioxide avoidance.
  • FIG. 1 shows a system that includes a water feed 100 preheated in a first heat exchanger 102 with production fluids 104 recovered from a hydrocarbon bearing formation.
  • the water 100 then enters a steam generator 106 such as a once-through steam generator (OTSG).
  • the steam generator 106 produces injection steam 108 by a single-pass of the water 100 through boiler tubes heated by burners that combust air and fuel also supplied to the steam generator 106.
  • OTSG once-through steam generator
  • the injection steam 108 which may be saturated and at a pressure above 5000 kilopascals (kPa), passes through one or more injection wells and into the hydrocarbon bearing formation in order to reduce viscosity of the hydrocarbons.
  • the steam condenses to create an oil/water mixture that migrates through the formation.
  • the oil/water mixture gathers at one or more production wells, is brought to surface and forms at least part of the production fluids 104.
  • Steam assisted gravity drainage (SAGD) provides an example of such an application where the systems described herein may be employed.
  • the combustion of the air and fuel in the steam generator 106 creates a flue gas exhaust 110.
  • the exhaust 110 passes through a second heat exchanger 112 to facilitate preheating of the water 100 prior to the water 100 entering the steam generator 106.
  • a carbon dioxide recovery unit 114 receives the exhaust 110 for separating a carbon dioxide output 116 from other flue gas constituents. The carbon dioxide output 116 from the carbon dioxide recovery unit 114 enables subsequent compressing and/or sequestering thereof to avoid emitting the carbon dioxide into the atmosphere.
  • the steam generator 106 may operate at from 5000 kPa to 11,000 kPa based on pressure of the water 100 pumped into the steam generator 106.
  • the steam generator 106 provides initial wet steam that may be about 70 percent to 80 percent quality steam before separating out the injection steam 108. Therefore, a liquid blowdown 118 also exits from the steam generator 106.
  • a separator 120 with flow control to reduce pressure of the blowdown 118 flashes part of the blowdown 118 to produce condensate 122 that may also be used to preheat the water 100 introduced into the steam generator 106 using a third heat exchanger 124. Flashing of the blowdown 118 in the separator 120 further produces regenerator steam 126 at lower pressure than the injection steam 108.
  • the separator 120 may produce the regenerator steam 126 at pressures, such as between 325 kPa and 425 kPa, desired for use in capturing carbon dioxide rather than higher pressures desired for the injection steam 108.
  • the steam is desired to be at such lower pressure relative to output of the injection steam 108 by the steam generator 106 so that special metallurgy is not required in the carbon dioxide recovery unit 114 to contain pressures and so that desired temperatures based on solvent desorption energy and solvent degradation in the carbon dioxide recovery unit 114 can be achieved.
  • the carbon dioxide recovery unit 114 may utilize a selective amine solution to strip the carbon dioxide from the other flue gas constituents by absorption of the carbon dioxide within the solution.
  • the amine solution comes in direct contact with the flue gas exhaust 110 in an absorber of the carbon dioxide recovery unit 114.
  • the other flue gas constituents pass through the absorber and may exit the carbon dioxide recovery unit 114 as treated exhaust via discharge that opens to the atmosphere.
  • Ethanolamine(s) and/or other suitable solvents may be used for the absorber solutions in some embodiments.
  • the amine solution can be regenerated in a regenerator of the carbon dioxide recovery unit 114 by use of the regenerator steam 126.
  • liberation of the carbon dioxide from the amine solution may occur with temperature increase and pressure reduction.
  • the separator 120 may supply all steam requirements for the carbon dioxide recovery unit 114 without any additional steam being generated or otherwise input, such as by utilizing part of the injection steam 108 and reducing pressure thereof, to thus avoid creating additional flue gases and limit boiler capital costs.
  • all of the blowdown 118 from the steam generator 106 may be utilized for the flashing to produce the regenerator steam 126 without splitting or diverting energy content of the blowdown 118 for other purposes before the flashing that forms the condensate stream 122 with energy content below that required to create the regenerator steam 126.
  • Selection of the solvents used for the absorber solutions in the carbon dioxide recovery unit 114 may further assist in meeting all steam requirements for the carbon dioxide recovery unit 114 with only that from the separator 120.
  • a regenerator boiler 128 may supplement supply of the regenerator steam 126 to the carbon dioxide recovery unit 114 even though the boiler 128 may be sized smaller than if the boiler 128 provided all steam requirements to the carbon dioxide recovery unit 114.
  • Combustion products from burning of air and fuel to vaporize water in the boiler 128 may combine with the exhaust of the steam generator 106. This exhaust of boiler 128 thus passes through the second heat exchanger 112 to assist in preheating of the water 100 going into the steam generator 106.
  • FIG. 2 illustrates an alternative system with like components as shown in Figure 1 identified by common reference numbers.
  • This alternative system further functions in a similar manner as described already herein except that the exhaust 110 from the steam generator 106 and/or the regenerator boiler 128 passes through an air preheater 212 for raising temperature of the air supplied to the steam generator 106. The exhaust 110 then exits the air preheater 212 and is treated in the carbon dioxide recovery unit 114.
  • the systems described herein were compared to modeling results for oxy-fuel combustion systems as an alternative approach for capturing of the carbon dioxide. Fuel usage for the systems described herein overlapped with that of the oxy-fuel combustion systems. Even though operating costs from fuel usage may not provide a decisive benefit, the oxy-fuel combustion systems only provided a carbon dioxide emission avoidance of less than 34% whereas the Example System as shown above was 66.5%. Electrical use required by an air separation unit for the oxy-fuel combustion systems contributes to this limited carbon dioxide emission avoidance when using the oxy-fuel combustion systems.

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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)
  • Treating Waste Gases (AREA)
  • Gas Separation By Absorption (AREA)

Abstract

Cette invention concerne des procédés et des systèmes qui génèrent de la vapeur destinée à être injectée dans une formation afin de faciliter la récupération d'huile ainsi que la capture du dioxyde de carbone dans une unité de récupération qui reçoit les gaz d'échappement émis par ladite génération de vapeur. Les procédés et les systèmes intègrent divers flux de procédé en provenance et à destination de l'unité de récupération de dioxyde de carbone. Cette intégration génère des bénéfices associés à l'efficacité et/ou à la séparation du dioxyde de carbone.
PCT/US2014/041948 2013-06-11 2014-06-11 Générateur de vapeur et capture de dioxyde de carbone Ceased WO2014201139A1 (fr)

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US201361833505P 2013-06-11 2013-06-11
US61/833,505 2013-06-11
US14/302,004 2014-06-11
US14/302,004 US20140360726A1 (en) 2013-06-11 2014-06-11 Steam generator and carbon dioxide capture

Publications (1)

Publication Number Publication Date
WO2014201139A1 true WO2014201139A1 (fr) 2014-12-18

Family

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Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2014/041948 Ceased WO2014201139A1 (fr) 2013-06-11 2014-06-11 Générateur de vapeur et capture de dioxyde de carbone

Country Status (2)

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US (1) US20140360726A1 (fr)
WO (1) WO2014201139A1 (fr)

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN104763397A (zh) * 2015-05-06 2015-07-08 中国石油大学(华东) 一种基于蒸汽引射的油田注汽锅炉烟气资源化利用系统及其应用

Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20100147516A1 (en) * 2008-12-12 2010-06-17 Betzer-Zilevitch Maoz System and method for minimizing the negative enviromental impact of the oilsands industry
US20100206565A1 (en) * 2009-02-19 2010-08-19 Conocophillips Company Steam assisted oil recovery and carbon dioxide capture
US20100282644A1 (en) * 2007-12-19 2010-11-11 O'connor Daniel J Systems and Methods for Low Emission Hydrocarbon Recovery
US20120222426A1 (en) * 2011-03-04 2012-09-06 Conocophillips Company Integrated gas turbine, sagd boiler and carbon capture
US20120318141A1 (en) * 2010-02-23 2012-12-20 The Kansai Electric Power Co., Inc. Co2 recovery unit and co2 recovery method
US20130062065A1 (en) * 2011-09-13 2013-03-14 Conocophillips Company Indirect downhole steam generator with carbon dioxide capture

Family Cites Families (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6536523B1 (en) * 1997-01-14 2003-03-25 Aqua Pure Ventures Inc. Water treatment process for thermal heavy oil recovery
ZA200605249B (en) * 2003-11-26 2008-01-30 Aquatech Int Corp Method for production of high pressure steam from produced water
NO330123B1 (no) * 2009-07-11 2011-02-21 Sargas As Lav CO2-anlegg for utvinning av oljesand

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20100282644A1 (en) * 2007-12-19 2010-11-11 O'connor Daniel J Systems and Methods for Low Emission Hydrocarbon Recovery
US20100147516A1 (en) * 2008-12-12 2010-06-17 Betzer-Zilevitch Maoz System and method for minimizing the negative enviromental impact of the oilsands industry
US20100206565A1 (en) * 2009-02-19 2010-08-19 Conocophillips Company Steam assisted oil recovery and carbon dioxide capture
US20120318141A1 (en) * 2010-02-23 2012-12-20 The Kansai Electric Power Co., Inc. Co2 recovery unit and co2 recovery method
US20120222426A1 (en) * 2011-03-04 2012-09-06 Conocophillips Company Integrated gas turbine, sagd boiler and carbon capture
US20130062065A1 (en) * 2011-09-13 2013-03-14 Conocophillips Company Indirect downhole steam generator with carbon dioxide capture

Also Published As

Publication number Publication date
US20140360726A1 (en) 2014-12-11

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