[go: up one dir, main page]

WO2007068682A1 - Enhanced oil recovery process and a process for the sequestration of carbon dioxide - Google Patents

Enhanced oil recovery process and a process for the sequestration of carbon dioxide Download PDF

Info

Publication number
WO2007068682A1
WO2007068682A1 PCT/EP2006/069571 EP2006069571W WO2007068682A1 WO 2007068682 A1 WO2007068682 A1 WO 2007068682A1 EP 2006069571 W EP2006069571 W EP 2006069571W WO 2007068682 A1 WO2007068682 A1 WO 2007068682A1
Authority
WO
WIPO (PCT)
Prior art keywords
carbon dioxide
gas
hydrocarbons
stream
hydrocarbonaceous
Prior art date
Application number
PCT/EP2006/069571
Other languages
French (fr)
Inventor
Eduard Coenraad Bras
Frank Haiko Geuzebroek
Mariette Catharina Knaap
Original Assignee
Shell Internationale Research Maatschappij B.V.
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 Shell Internationale Research Maatschappij B.V. filed Critical Shell Internationale Research Maatschappij B.V.
Publication of WO2007068682A1 publication Critical patent/WO2007068682A1/en

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/32—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
    • C01B3/34—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
    • C01B3/38—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using catalysts
    • C01B3/384—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using catalysts the catalyst being continuously externally heated
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/32—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
    • C01B3/34—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
    • C01B3/48—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents followed by reaction of water vapour with carbon monoxide
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/50—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification
    • C01B3/501—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification by diffusion
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/50—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification
    • C01B3/56—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification by contacting with solids; Regeneration of used solids
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • C09K8/594—Compositions used in combination with injected gas, e.g. CO2 orcarbonated gas
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2/00—Production of liquid hydrocarbon mixtures of undefined composition from oxides of carbon
    • C10G2/30—Production of liquid hydrocarbon mixtures of undefined composition from oxides of carbon from carbon monoxide with hydrogen
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2/00—Production of liquid hydrocarbon mixtures of undefined composition from oxides of carbon
    • C10G2/30—Production of liquid hydrocarbon mixtures of undefined composition from oxides of carbon from carbon monoxide with hydrogen
    • C10G2/32—Production of liquid hydrocarbon mixtures of undefined composition from oxides of carbon from carbon monoxide with hydrogen with the use of catalysts
    • 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
    • E21B43/164—Injecting CO2 or carbonated water
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/50—Carbon oxides
    • B01D2257/504—Carbon dioxide
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/02—Processes for making hydrogen or synthesis gas
    • C01B2203/0205—Processes for making hydrogen or synthesis gas containing a reforming step
    • C01B2203/0227—Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step
    • C01B2203/0233—Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step the reforming step being a steam reforming step
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/02—Processes for making hydrogen or synthesis gas
    • C01B2203/0283—Processes for making hydrogen or synthesis gas containing a CO-shift step, i.e. a water gas shift step
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/0405—Purification by membrane separation
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/042—Purification by adsorption on solids
    • C01B2203/043—Regenerative adsorption process in two or more beds, one for adsorption, the other for regeneration
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/0465—Composition of the impurity
    • C01B2203/0475—Composition of the impurity the impurity being carbon dioxide
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/06—Integration with other chemical processes
    • C01B2203/062—Hydrocarbon production, e.g. Fischer-Tropsch process
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/08—Methods of heating or cooling
    • C01B2203/0805—Methods of heating the process for making hydrogen or synthesis gas
    • C01B2203/0811—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/08—Methods of heating or cooling
    • C01B2203/0805—Methods of heating the process for making hydrogen or synthesis gas
    • C01B2203/0811—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel
    • C01B2203/0822—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel the fuel containing hydrogen
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/08—Methods of heating or cooling
    • C01B2203/0805—Methods of heating the process for making hydrogen or synthesis gas
    • C01B2203/0811—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel
    • C01B2203/0827—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel at least part of the fuel being a recycle stream
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/12—Feeding the process for making hydrogen or synthesis gas
    • C01B2203/1205—Composition of the feed
    • C01B2203/1211—Organic compounds or organic mixtures used in the process for making hydrogen or synthesis gas
    • C01B2203/1235—Hydrocarbons
    • C01B2203/1241—Natural gas or methane
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/80—Aspect of integrated processes for the production of hydrogen or synthesis gas not covered by groups C01B2203/02 - C01B2203/1695
    • C01B2203/86—Carbon dioxide sequestration
    • 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
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00—Capture or disposal of greenhouse gases
    • Y02C20/40—Capture or disposal of greenhouse gases of CO2
    • 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
    • Y02P20/00—Technologies relating to chemical industry
    • Y02P20/10—Process efficiency
    • 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
    • Y02P30/00—Technologies relating to oil refining and petrochemical industry
    • 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
    • Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
    • Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells

Definitions

  • This invention relates to a process for the enhanced recovery of oil (or hydrocarbons) from a subsurface reservoir by injecting a carbon dioxide containing gas into the reservoir in combination with the production of hydrocarbons from a hydrocarbonaceous stream.
  • This invention also relates to a process for the sequestration of carbon dioxide.
  • Enhanced oil recovery involves non-conventional techniques for recovering more hydrocarbons out of subsurface reservoirs than is possible by natural production mechanisms (primary oil recovery) or by the injection of water or gas (secondary oil recovery) .
  • the pressure under which the hydrocarbons exist in the reservoir must be greater than that at the well bottom.
  • the rate at which the hydrocarbons move towards the well depends on a number of features, which include the pressure differential between the reservoir and the well, permeability of the rock, layer thickness and the viscosity of the hydrocarbons.
  • the initial reservoir pressure is usually high enough to lift the hydrocarbons from the producing wells to the surface, but as the hydrocarbons are produced, the pressure decreases and the production rate starts to decline. Production, although declining, can be maintained for a time by naturally occurring processes such as expansion of the gas in a gas cap, gas release by the hydrocarbons and/or the influx of water.
  • Petroleum Handbook 6 "1 ⁇ edition, Elsevier, Amsterdam/New York, 1983, p. 91-97. See also Petroleum Engineering Handbook, Bradley (Ed.), Society of Petroleum Engineers, Richardson, Texas, 1992 (ISBN 1-55563-010-3), Chapter 42- 47.
  • the hydrocarbons not producible, or left behind, by the conventional, natural recovery methods may be too viscous or too difficult to displace or may be trapped by capillary forces.
  • the recovery factor (the percentage of hydrocarbons initially contained in a reservoir that can be produced by natural production mechanisms) can vary from a few percent to about 35 percent. Worldwide, primary recovery is estimated to produce on average some 25 percent of the hydrocarbons initially in place.
  • the use of carbon dioxide for enhanced oil recovery is known.
  • the carbon dioxide can be injected at sufficiently high pressure to enhance the recovery of the hydrocarbons.
  • the carbon dioxide can dissolve in the hydrocarbons and reduce its viscosity, which also enhances the recovery of hydrocarbons from the reservoir.
  • a process for enhanced oil recovery from a subsurface reservoir in combination with the production of normally liquid hydrocarbons and optionally normally solid hydrocarbons from one or more hydrocarbonaceous stream comprising :
  • step (ii) heating a first hydrocarbonaceous stream together with steam using the heat generated in step (i) and reforming the mixture of the hydrocarbonaceous stream and steam to produce a first synthesis gas stream;
  • step (iii) recovering hydrocarbons from a subsurface reservoir using at least a portion of the flue gas produced in step (i) , preferably at least a portion of the carbon dioxide in the flue gas produced in step (i) ;
  • the first part of the process of the present invention (steps (i) and (ii) ) relates to the production of synthesis gas using steam methane reforming, as part of the process of making hydrocarbons from a hydrocarbonaceous stream.
  • the Steam Methane Reformer converts methane and steam at elevated temperatures to a mixture of hydrogen and carbon monoxide (i.e. synthesis gas) typically with a ratio of around 4:1 to 8:1, especially 5:1 to 6:1.
  • the SMR comprises a convection section and a radiant section.
  • the convection section preheats the methane and steam whilst the radiant section has tubes with reforming catalyst, especially nickel reforming catalyst, and this is where the reforming reactions take place.
  • the reactions are endothermic - the heat required is provided by an SMR furnace.
  • the SMR furnace may be powered by, for example, natural gas, off gas from hydrocarbon compound synthesis, e.g.
  • a methanol and/or DME synthesis process or a Fischer-Tropsch process or off gas from a Pressure Swing Adsorption (PSA) unit, especially by the off gas from a Fischer-Tropsch process.
  • PSA Pressure Swing Adsorption
  • This can also be designed to run on natural gas exclusively.
  • the design of the SMR allows operation with less than two percent oxygen (on dry basis) at the exit of the radiant section.
  • the flue gas produced by the combustion of the fuel gas to power the SMR contains carbon dioxide. There are environmental limitations on the release of carbon dioxide into the atmosphere.
  • the first synthesis gas stream may contain synthesis gas with a hydrogen : carbon monoxide ratio of around 4:1 to 8:1, especially 5:1-6:1.
  • the second synthesis gas stream typically comprises synthesis gas with a hydrogen : carbon monoxide ratio of 1.6-2.3, preferably 1.7-2.2.
  • the second synthesis gas stream is made or obtained by partial oxidation of a second hydrocarbonaceous stream, optionally in combination with catalytic reforming .
  • the hydrocarbonaceous streams to be used in the present invention may be the same or different. Suitable streams are natural gas, associated gas, coal bed methane or mixtures thereof. These gas streams usually contain at least 60 vol% methane based on the total stream, preferably at least 70%, more preferably at least 80%. The remaining compounds usually will be ethane, propane, butane and minor amounts of higher alkanes. Some inerts may be present, e.g. nitrogen and/or carbon dioxide, usually less than 10 vol% each, preferably less than 5 vol% each, based on the total stream.
  • the second hydrocarbonaceous stream may also be coal, biomass, residual oil fractions (including tar sand oils) , peat, municipal waste etc.
  • a relatively large reforming unit is required (i.e. steps (i) and (ii) ) , resulting in a large flue gas stream, or, in other words, a large amount of carbon dioxide.
  • the source of the fuel gas is preferably off-gas from the unit which converts the synthesis gas obtained in step (ii) into liquid hydrocarbons, typically a heavy paraffin synthesis (HPS) unit.
  • HPS heavy paraffin synthesis
  • the source of the fuel gas may be product gas from a Steam Methane Reformer. This is typically used under transient conditions only, such as during start up or during upsets.
  • the source of the fuel gas may be off gas from a unit adapted to remove carbon dioxide from a mixture containing hydrogen and carbon dioxide, for example a pressure swing adsorption unit (PSA) .
  • the source of the fuel gas may be natural gas.
  • the source of the fuel gas may be any combination of the sources described herein.
  • PSA off-gas is added to the fuel gas before the combustion in step (i) .
  • the PSA off-gas is not used as fuel gas.
  • the PSA off-gas may be mixed with the flue gas.
  • the furnace is typically adapted to heat the reformer. It is typically provided as an integral part of the reformer. Preferably the furnace is a convection section of a steam methane reformer.
  • step (i) may be done with air, oxygen enriched air or pure oxygen.
  • a (commercial) air separation unit (ASU) may be used to produce the oxygen enriched air on the pure oxygen.
  • Preferably air is used.
  • the partial oxidation process may be carried out with air, oxygen enriched air or pure oxygen. Pure oxygen (> 99 vol%) is preferred.
  • a (commercial) ASU may be used for the oxygen production, also membrane processes may be used.
  • a suitable commercial process for the partial oxidation reaction is the Shell Gasification process, which process is suitable for at least natural gas, heavy residual oil and coal.
  • the partial oxidation process may be carried out in combination with catalytic reforming. In that case steam is added to the hydrocarbonaceous stream and/or the oxygen stream, and the reaction product is directed to a reforming catalyst.
  • a very suitable process for the combined treating is the so called autothermal reforming process. Such processes are commercially available.
  • the carbon dioxide content of the flue gas may be in the region of 5-20%, preferably 8-16%, more preferably 11-14%.
  • the carbon dioxide concentration in the flue gas will be increased. In these circumstances preferably at least 8%, more preferably at least 11% of the flue gas is carbon dioxide .
  • the flue gas is treated to capture the carbon dioxide therein. In that way pure carbon dioxide is obtained which is very suitable for miscible floading. Nitrogen and oxygen are to be removed as much as possible. Oxygen may result in the forming of explosive mixtures and/or may result in the growth of microbiological organisms, which could result in undesired effects as clogging of the reservoir.
  • the captured carbon dioxide stream contains preferably at least 80 vol% carbon dioxide, more preferably at least 90 vol% carbon dioxide, even more preferably at least 95 vol%, based on total stream.
  • the technique of solvent extraction may be used.
  • organic solvents or aqueous solutions of organic solvents for removing carbon dioxide from a gas stream is known. See for instance A. L. Kohl and F. C. Riesenfeld, 1974, Gas Purification, 2nd edition, Gulf Publishing Co. Houston and R.N. Maddox, 1974, Gas and Liquid Sweetening, Campbell Petroleum Series.
  • a regenerable absorbent solvent is used in a continuous process.
  • Chemical solvents which have proved to be industrially useful are primary, secondary and/or tertiary amines derived alkanolamines .
  • the most frequently used amines are derived from ethanolamine, especially monoethanol amine (MEA), diethanolamine (DEA), triethanolamine (TEA) , diisopropanolamine (DIPA) and methyldiethanolamine (MDEA) .
  • a well-known commercial process uses an aqueous mixture of a chemical solvent, especially DIPA and/or MDEA, and a physical solvent, especially cyclotetra- methylene-sulfone .
  • the amines are resistant to degradation by oxygen .
  • Physical solvents which have proved to be industrially suitable are cyclo-tetramethylenesulfone and its derivatives, aliphatic acid amides, N-methylpyrro- lidone, N-alkylated pyrrolidones and the corresponding piperidones, methanol, ethanol and mixtures of dialkylethers of polyethylene glycols.
  • a combination of chemical and physical solvents may be used. For example see US 6051161, the disclosure of which is incorporated herein by reference in its entirety.
  • cryogenic separator is the Ryan/Holmes four column process.
  • the pressure of the flue gas is boosted before it is used to recover hydrocarbons from a subsurface reservoir.
  • this pressure boosting is performed after the carbon dioxide content has been captured.
  • the pressure is boosted to a level sufficient to allow the carbon dioxide to enter the reservoir.
  • the flue gas which at this stage is typically predominantly carbon dioxide, may be boosted in a series of stages, for example where flue gas at 150 bara is required to recover hydrocarbons from a subsurface reservoir, the pressure may be progressively boosted in a first stage up to around 5 bara, in a second stage up to around 15 bara, in a further stage up to around 50 bara and in a final stage up to 150 bara.
  • a part of the energy needed for compression may be obtained by expanding the off-gas from the hydrocarbon synthesis process (step (v) ) from the reaction pressure to a pressure of 1-2 bara.
  • the flue gas is also cooled during pressure boosting.
  • CO2 for the enhanced oil recovery, rather than a mixture of carbon dioxide and nitrogen and/or lower (i.e. C1-C4) hydrocarbon. Due to the different properties of these components it is more convenient to use separate components rather than mixtures. E.g. nitrogen is relatively insoluble in crude oil and is suitable to pressure the gas cap. CO2 is very suitable for miscible floading.
  • the hydrocarbons recovered from the subsurface reservoir may be substantially in the liquid phase optionally in combination with a mixture of light hydrocarbons, especially methane.
  • the carbon dioxide injected can be produced with the hydrocarbons from the reservoir. Sequestration in a subsurface formation is typically when carbon dioxide is injected into a closed off or depleted reservoir from which no further production of hydrocarbons is planned.
  • the subsurface formation need not be a hydrocarbon reservoir since when sequestration is required without enhanced oil recovery, the carbon dioxide may be injected into an area of the subsurface formation which did or did not contain hydrocarbons.
  • the invention also provides a process for the sequestration of carbon dioxide, the process comprising injecting carbon dioxide into a subsurface formation, the carbon dioxide derived from flue gas from a reformer, particularly from a steam methane reformer (SMR) .
  • SMR steam methane reformer
  • the reforming is steam methane reforming which is performed in a steam methane reformer (SMR) .
  • SMR steam methane reformer
  • the hydrocarbonaceous stream to the SMR can be natural gas, associated gas and/or coal-bed methane, or derived from residual (crude) oil fractions or coal.
  • the SMR can operate with a range of feedstocks.
  • the hydrocarbonaceous stream suitably is methane, natural gas, associated gas or a mixture of C]_-4 hydrocarbons.
  • the stream preferably comprises mainly, i.e. more than 90 v/v%, especially more than 94%, C]_-4 hydrocarbons, and especially comprises at least 60 v/v percent methane, preferably at least 75%, more preferably 90%.
  • Very suitably natural gas or associates gas is used.
  • any sulphur in the feedstock is removed.
  • the hydrocarbonaceous stream is methane from natural gas.
  • methane and steam can be introduced into the SMR which operates at an outlet temperature of 800 °C-900 0 C.
  • methane is typically converted into a mixture of carbon monoxide and hydrogen primarily by equilibrium reaction (1) shown below.
  • Some of the carbon monoxide is typically further oxidised to carbon dioxide, according to equilibrium reaction (2) below.
  • This syngas can be used for a number of purposes, for example for use in a Fischer-Tropsch reactor and particularly to increase the relative hydrogen : carbon monoxide content of the syngas from a gasifier before it proceeds to a Fischer-Tropsch Reactor.
  • sufficient hydrogen is also produced for use in other units or processes which are integral or associated with the Fischer-Tropsch process, for example a hydrogenation unit .
  • the syngas is preferably mixed with syngas produced by partial oxidation of methane before being converted into said liquid hydrocarbons.
  • the syngas is converted into liquid hydrocarbons, optionally in combination with solid hydrocarbons and liquefied petroleum gas, by the Fischer- Tropsch process.
  • Fischer-Tropsch process is well known to those skilled in the art and involves synthesis of hydrocarbons from a gaseous mixture of syngas, by contacting that mixture at reaction conditions with a Fischer-Tropsch catalyst .
  • Products of the Fischer-Tropsch synthesis may range from methane to heavy paraffin waxes.
  • the production of methane is minimised and a substantial portion of the hydrocarbons produced have a carbon chain length of a least 5 carbon atoms.
  • the amount of C5+ hydrocarbons is at least 60% by weight of the total product, more preferably, at least 70% by weight, even more preferably, at least 80% by weight, most preferably at least 85% by weight.
  • Reaction products which are liquid phase under reaction conditions may be separated and removed, optionally using suitable means, such as one or more filters. Internal or external filters, or a combination of both, may be employed. Gas phase products such as light hydrocarbons and water may be removed using suitable means known to the person skilled in the art.
  • Fischer-Tropsch catalysts are known in the art, and frequently comprise, as the catalytically active component, a metal from Group VIII of the Periodic Table. (References herein to the Periodic Table relate to the previous IUPAC version of the Periodic Table of Elements such as that described in the 68 ⁇ h Edition of the Handbook of Chemistry and Physics (CPC Press)) .
  • Particular catalytically active metals include ruthenium, iron, cobalt and nickel. Cobalt is a preferred catalytically active metal.
  • the catalysts comprise a catalyst carrier.
  • the catalyst carrier is preferably porous, such as a porous inorganic refractory oxide, more preferably alumina, silica, titania, zirconia or mixtures thereof.
  • the optimum amount of catalytically active metal present on the carrier depends inter alia on the specific catalytically active metal.
  • the amount of cobalt present in the catalyst may range from 1 to 100 parts by weight per 100 parts by weight of carrier material, preferably from 10 to 50 parts by weight per 100 parts by weight of carrier material.
  • the catalytically active metal may be present in the catalyst together with one or more metal promoters or co- catalysts.
  • the promoters may be present as metals or as the metal oxide, depending upon the particular promoter concerned. Suitable promoters include oxides of metals from Groups HA, IHB, IVB, VB, VIB and/or VIIB of the Periodic Table, oxides of the lanthanides and/or the actinides.
  • the catalyst comprises at least one of an element in Group IVB, VB and/or VIIB of the Periodic Table, in particular titanium, zirconium, manganese and/or vanadium.
  • the catalyst may comprise a metal promoter selected from Groups VIIB and/or VIII of the Periodic Table. Preferred metal promoters include rhenium, platinum and palladium.
  • a most suitable catalyst comprises cobalt as the catalytically active metal and zirconium as a promoter.
  • Another most suitable catalyst comprises cobalt as the catalytically active metal and manganese and/or vanadium as a promoter.
  • the promoter if present in the catalyst, is typically present in an amount of from 0.1 to 60 parts by weight per 100 parts by weight of carrier material. It will however be appreciated that the optimum amount of promoter may vary for the respective elements which act as promoter.
  • the Fischer-Tropsch synthesis is preferably carried out at a temperature in the range from 125 to 350oC, more preferably 175 to 275 0 C, most preferably 200 to 260 0 C.
  • the pressure preferably ranges from 5 to 150 bar abs . , more preferably from 5 to 80 bar abs.
  • the Fischer-Tropsch synthesis can be carried out in a slurry phase regime or an ebullating bed regime, wherein the catalyst particles are kept in suspension by an upward superficial gas and/or liquid velocity.
  • Hydrogen and carbon monoxide (synthesis gas) is typically fed to the three-phase slurry reactor at a molar ratio in the range from 0.4 to 2.5.
  • the hydrogen to carbon monoxide molar ratio is in the range from 1.0 to 2.5.
  • Another regime for carrying out the Fischer-Tropsch reaction is a fixed bed regime, especially a trickle flow regime.
  • a very suitable reactor is a multitubular fixed bed reactor.
  • the invention also provides a hydrocarbon synthesised by a Fischer-Tropsch process, the Fischer- Tropsch process being supplied by syngas, at least a portion of the syngas being produced by a method as described herein.
  • the hydrocarbon may have undergone the steps of hydroprocessing, preferably hydrogenation, hydroisomerisation and/or hydrocracking.
  • the hydrocarbon may be a fuel, preferably naptha, kero or gasoil, a waxy raffinate or a base oil.
  • a fuel preferably naptha, kero or gasoil, a waxy raffinate or a base oil.
  • Fischer-Tropsch process is carried out in which synthesis gas from a partial oxidation process (or optionally a autothermal reforming process) is used together with the synthesis gas from a reforming process.
  • the partial oxidation synthesis gas suitably has an H2/CO ratio of
  • the reforming synthesis gas suitably has an H2/CO ratio of 3-8, preferably 4-6.
  • the Fischer-Tropsch process is carried out in a two-stage set-up in which off-gas from the first step together with reforming synthesis gas is sent to the second stage.
  • the off gas from the second stage containing unconverted syngas, lower (C1-C4) hydrocarbons, and inerts (nitrogen, carbon dioxide) is used for heating the reforming furnace.
  • An amine extraction process using commercially available oxygen- stable amines is used to extract the carbon dioxide from the flue gas. After pressurisation the pure carbon dioxide is used for enhanced oil recovery.
  • the feed for the reforming process is preferably hydrogenated (to remove olefins) and shifted (to remove CO) off gas from the Fischer-Tropsch process, optionally in combination with natural gas associated gas and/or coal bed methane.
  • the steam for the reforming process is preferably water made in the Fischer-Tropsch process.
  • part of the reforming syngas is to be shifted (in which process carbon monoxide is reacted with water to obtain carbon dioxide and hydrogen) .
  • the hydrogen is to be separated from the carbon dioxide. Any steams containing the carbon dioxide optionally in combination with hydrogen (e.g.
  • regeneration gas from a PSA or pressure swing adsorption unit may be added to the feed gas or the flue gas of the reformer, depending especially on the hydrogen content. In this way a very efficient process is obtained. All carbon dioxide made in the overall process is used for enhanced oil recovery, while all energy containing compounds are used for energy generation.
  • Fig. 1 is a process diagram of a Fischer-Tropsch Process.
  • Fig. 1 shows a flow diagram of a Fischer-Tropsch process. Methane and oxygen are introduced into a gasifier 10 which produces a mixture of carbon monoxide and hydrogen for use in heavy paraffin synthesis in a Fischer-Tropsch unit 12.
  • SMR steam methane reformer
  • a portion of the product in the SMR 14 is sent to a high temperature shift reactor 16 to convert the carbon monoxide therein to carbon dioxide. This carbon dioxide is then removed in a Pressure Swing Adsorption (PSA) unit 18 to leave pure hydrogen.
  • PSA Pressure Swing Adsorption
  • a membrane separation filter 17 may be provided between the high temperature shift reactor 16 and the pressure swing adsorption unit 18 in order to remove carbon dioxide.
  • the SMR 14 operates at an outlet temperature of between of 800 0 C and 900 0 C.
  • an integral furnace 15 is provided to heat the SMR unit 14.
  • the fuel gas for the furnace 15 can be supplied from a number of sources, including off gas from the Fischer- Tropsch unit 12, the PSA unit 18 or the SMR unit 14 itself. Alternatively natural gas or any other hydrocarbonaceous based gas may be used to fuel the furnace . Typically the fuel gas provided comprises methane, other gaseous hydrocarbons, carbon dioxide and carbon monoxide .
  • the carbon dioxide content of the fuel gas will be increased by the combustion of the hydrocarbons in the furnace 15. Around 14% of the flue gas may be carbon dioxide. Heat is recovered by production of steam so the temperature of the flue gas is reduced to around 150oC.
  • the flue gases produced (which include combustion products and uncombusted gases) proceed to gas cooling and boosting fans 20 and then to an amine recovery unit 22.
  • Carbon dioxide from the membrane separation filter 17 and/or the pressure swing adsorption unit 18 may also be directed to the amine recovery unit 22.
  • solvent extraction is used to extract carbon dioxide from the flue gas mixture.
  • the carbon dioxide extracted need not be pure - a purity of 80%, preferably 95% is sufficient for the purposes of the present invention.
  • the carbon dioxide stream from the amine recovery unit 22 then proceeds to a series of compressors 24 where the pressure of the carbon dioxide is progressively increased.
  • carbon dioxide recovered therefrom may be sent directly to the compressors 24.
  • a dehydration unit 26 removes any water from the carbon dioxide stream before a final compressor 24 boosts the pressure of the carbon dioxide further.
  • the carbon dioxide can then be injected into a reservoir to encourage the production of hydrocarbons therefrom.
  • a benefit of the invention is that the greenhouse gas, carbon dioxide, is injected into a subsurface reservoir rather than released to the atmosphere.
  • the carbon dioxide may be sequestrated, that is injected into a reservoir in order to dispose of the carbon dioxide without releasing it into the atmosphere.
  • the pressure of the carbon dioxide injected into the reservoir should be greater than the reservoir pressure.
  • the number of compressors can be reduced or increased depending on the pressure of the subsurface reservoir.
  • normally gaseous hydrocarbon describes hydrocarbons which are gaseous at STP (0 0 C, 1 bar) . These hydrocarbons are especially methane, ethane, propane and butane and their unsaturated derivates.
  • normally liquid hydrocarbons describes hydrocarbons which are liquid at STP (0 0 C, 1 bar) . This group of compounds comprises C5 up till normal -C]_4 as well as some C]_5 ⁇ C]_g isomers. The group also includes the unsaturated derivatives.
  • normally solid hydrocarabons describes hydrocarbon that are solid at standard temperature and pressure condition (STP, 0 0 C, 1 bar) . This group comprise all n-C]_5 ⁇ alkanes and most iso-C]_5 + alkanes. The group also comprise any unsaturated derivatives .

Landscapes

  • Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Inorganic Chemistry (AREA)
  • Combustion & Propulsion (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Chemical & Material Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Health & Medical Sciences (AREA)
  • General Health & Medical Sciences (AREA)
  • Fluid Mechanics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Environmental & Geological Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Materials Engineering (AREA)
  • Hydrogen, Water And Hydrids (AREA)

Abstract

A process for the sequestration of carbon dioxide, the process comprising injecting carbon dioxide into a reservoir, the carbon dioxide derived from flue gas from a reformer, particularly from a steam methane reformer (SMR). The injected carbon dioxide may be used to enhance the recovery of oil from the reservoir. One aspect of the invention relates to a process for the recovery of hydrocarbons from a subsurface reservoir preferably in combination with the production of synthesis gas from a hydrocarbonaceous stream, comprising: (i) heating the hydrocarbonaceous stream by combustion of at least a portion of a fuel gas containing a Hydrocarbonaceous source, the combustion products of said fuel gas, along with any uncombusted gas in the fuel gas, producing a flue gas containing carbon dioxide; (ii) reforming of the hydrocarbonaceous stream to produce synthesis gas; (iii) recovering hydrocarbons from a subsurface reservoir using at least a portion of the flue gas produced in step (i). In preferred embodiments, the synthesis gas produced is used in a Fischer-Tropsch process for the production of liquid hydrocarbons.

Description

ENHANCED OIL RECOVERY PROCESS AND A PROCESS FOR THE SEQUESTRATION OF CARBON DIOXIDE
This invention relates to a process for the enhanced recovery of oil (or hydrocarbons) from a subsurface reservoir by injecting a carbon dioxide containing gas into the reservoir in combination with the production of hydrocarbons from a hydrocarbonaceous stream. This invention also relates to a process for the sequestration of carbon dioxide.
Enhanced oil recovery (sometimes also called tertiary oil recovery) involves non-conventional techniques for recovering more hydrocarbons out of subsurface reservoirs than is possible by natural production mechanisms (primary oil recovery) or by the injection of water or gas (secondary oil recovery) .
If hydrocarbons are to move through the reservoir rock to a well, the pressure under which the hydrocarbons exist in the reservoir must be greater than that at the well bottom. The rate at which the hydrocarbons move towards the well depends on a number of features, which include the pressure differential between the reservoir and the well, permeability of the rock, layer thickness and the viscosity of the hydrocarbons. The initial reservoir pressure is usually high enough to lift the hydrocarbons from the producing wells to the surface, but as the hydrocarbons are produced, the pressure decreases and the production rate starts to decline. Production, although declining, can be maintained for a time by naturally occurring processes such as expansion of the gas in a gas cap, gas release by the hydrocarbons and/or the influx of water. A more extensive description of natural production mechanisms can be found in the
Petroleum Handbook, 6"1^ edition, Elsevier, Amsterdam/New York, 1983, p. 91-97. See also Petroleum Engineering Handbook, Bradley (Ed.), Society of Petroleum Engineers, Richardson, Texas, 1992 (ISBN 1-55563-010-3), Chapter 42- 47.
The hydrocarbons not producible, or left behind, by the conventional, natural recovery methods may be too viscous or too difficult to displace or may be trapped by capillary forces. Depending on the type of hydrocarbons, the nature of the reservoir and the location of the wells, the recovery factor (the percentage of hydrocarbons initially contained in a reservoir that can be produced by natural production mechanisms) can vary from a few percent to about 35 percent. Worldwide, primary recovery is estimated to produce on average some 25 percent of the hydrocarbons initially in place.
In order to increase the hydrocarbon production by natural production mechanisms, techniques have been developed for maintaining reservoir pressure. By such techniques (also known as secondary recovery) the reservoir' s natural energy and displacing mechanism which is responsible for primary production, is supplemented by the injection of water or gas. However, the injected fluid (water or gas) does not displace all the hydrocarbons. An appreciable amount remains trapped by capillary forces in the pores of the reservoir rock and is bypassed. These entrapped hydrocarbons are known as residual hydrocarbons, and they can occupy from 20 to 50 percent, or even more, of the pore volume. See for a more general description of secondary recovery techniques the above-mentioned Petroleum Handbook, p. 94-96, and the Petroleum Engineering Handbook. Many enhanced oil recovery techniques are known. They cover techniques such as thermal processes, miscible processes and chemical processes. Examples are heat generation, heat transfer, steam drive, steam soak, polymer flooding, surfactant flooding, the use of hydrocarbon solvents, high-pressure hydrocarbon gas, carbon dioxide and nitrogen. See for a more general description of secondary recovery techniques the above- mentioned Petroleum Handbook, p. 97-110, and the Petroleum Engineering Handbook.
The use of carbon dioxide for enhanced oil recovery is known. The carbon dioxide can be injected at sufficiently high pressure to enhance the recovery of the hydrocarbons. Moreover, the carbon dioxide can dissolve in the hydrocarbons and reduce its viscosity, which also enhances the recovery of hydrocarbons from the reservoir. In the present invention, there is provided a process for enhanced oil recovery from a subsurface reservoir in combination with the production of normally liquid hydrocarbons and optionally normally solid hydrocarbons from one or more hydrocarbonaceous stream, the process comprising :
(i) combusting a fuel gas containing a hydrocarbonaceous source to produce heat, the combustion products of said fuel gas, along with any carbon dioxide already present in the fuel gas, producing a flue gas containing carbon dioxide;
(ii) heating a first hydrocarbonaceous stream together with steam using the heat generated in step (i) and reforming the mixture of the hydrocarbonaceous stream and steam to produce a first synthesis gas stream;
(iii) recovering hydrocarbons from a subsurface reservoir using at least a portion of the flue gas produced in step (i) , preferably at least a portion of the carbon dioxide in the flue gas produced in step (i) ;
(iv) producing a second synthesis gas stream, the second synthesis gas stream being made or obtained by partial oxidation of a second hydrocarbonaceous stream, optionally in combination with catalytic reforming; and
(v) producing normally liquid hydrocarbons, normally gaseous hydrocarbons, including liquefied petroleum gas, and optionally normally solid hydrocarbons, from the synthesis gas streams.
The first part of the process of the present invention (steps (i) and (ii) ) relates to the production of synthesis gas using steam methane reforming, as part of the process of making hydrocarbons from a hydrocarbonaceous stream.
The Steam Methane Reformer (SMR) converts methane and steam at elevated temperatures to a mixture of hydrogen and carbon monoxide (i.e. synthesis gas) typically with a ratio of around 4:1 to 8:1, especially 5:1 to 6:1. The SMR comprises a convection section and a radiant section. The convection section preheats the methane and steam whilst the radiant section has tubes with reforming catalyst, especially nickel reforming catalyst, and this is where the reforming reactions take place. Overall, the reactions are endothermic - the heat required is provided by an SMR furnace. In the process of the present invention the SMR furnace may be powered by, for example, natural gas, off gas from hydrocarbon compound synthesis, e.g. a methanol and/or DME synthesis process or a Fischer-Tropsch process, or off gas from a Pressure Swing Adsorption (PSA) unit, especially by the off gas from a Fischer-Tropsch process. This can also be designed to run on natural gas exclusively. The design of the SMR allows operation with less than two percent oxygen (on dry basis) at the exit of the radiant section.
The flue gas produced by the combustion of the fuel gas to power the SMR contains carbon dioxide. There are environmental limitations on the release of carbon dioxide into the atmosphere.
The first synthesis gas stream may contain synthesis gas with a hydrogen : carbon monoxide ratio of around 4:1 to 8:1, especially 5:1-6:1. The second synthesis gas stream typically comprises synthesis gas with a hydrogen : carbon monoxide ratio of 1.6-2.3, preferably 1.7-2.2.
The second synthesis gas stream is made or obtained by partial oxidation of a second hydrocarbonaceous stream, optionally in combination with catalytic reforming .
The hydrocarbonaceous streams to be used in the present invention may be the same or different. Suitable streams are natural gas, associated gas, coal bed methane or mixtures thereof. These gas streams usually contain at least 60 vol% methane based on the total stream, preferably at least 70%, more preferably at least 80%. The remaining compounds usually will be ethane, propane, butane and minor amounts of higher alkanes. Some inerts may be present, e.g. nitrogen and/or carbon dioxide, usually less than 10 vol% each, preferably less than 5 vol% each, based on the total stream. The second hydrocarbonaceous stream may also be coal, biomass, residual oil fractions (including tar sand oils) , peat, municipal waste etc. Due to the relatively low H/C ratio of these heavy compounds, a relatively large reforming unit is required (i.e. steps (i) and (ii) ) , resulting in a large flue gas stream, or, in other words, a large amount of carbon dioxide.
The source of the fuel gas is preferably off-gas from the unit which converts the synthesis gas obtained in step (ii) into liquid hydrocarbons, typically a heavy paraffin synthesis (HPS) unit.
The source of the fuel gas may be product gas from a Steam Methane Reformer. This is typically used under transient conditions only, such as during start up or during upsets.
The source of the fuel gas may be off gas from a unit adapted to remove carbon dioxide from a mixture containing hydrogen and carbon dioxide, for example a pressure swing adsorption unit (PSA) . The source of the fuel gas may be natural gas.
The source of the fuel gas may be any combination of the sources described herein.
Preferably PSA off-gas is added to the fuel gas before the combustion in step (i) . Optionally the PSA off-gas is not used as fuel gas.
The PSA off-gas may be mixed with the flue gas.
The furnace is typically adapted to heat the reformer. It is typically provided as an integral part of the reformer. Preferably the furnace is a convection section of a steam methane reformer.
The combustion process of step (i) may be done with air, oxygen enriched air or pure oxygen. A (commercial) air separation unit (ASU) may be used to produce the oxygen enriched air on the pure oxygen. Preferably air is used.
The partial oxidation process (step iv) may be carried out with air, oxygen enriched air or pure oxygen. Pure oxygen (> 99 vol%) is preferred. A (commercial) ASU may be used for the oxygen production, also membrane processes may be used. A suitable commercial process for the partial oxidation reaction is the Shell Gasification process, which process is suitable for at least natural gas, heavy residual oil and coal. The partial oxidation process may be carried out in combination with catalytic reforming. In that case steam is added to the hydrocarbonaceous stream and/or the oxygen stream, and the reaction product is directed to a reforming catalyst. A very suitable process for the combined treating is the so called autothermal reforming process. Such processes are commercially available.
The carbon dioxide content of the flue gas may be in the region of 5-20%, preferably 8-16%, more preferably 11-14%. Where PSA off-gas has been added to the fuel gas, the carbon dioxide concentration in the flue gas will be increased. In these circumstances preferably at least 8%, more preferably at least 11% of the flue gas is carbon dioxide . Preferably the flue gas is treated to capture the carbon dioxide therein. In that way pure carbon dioxide is obtained which is very suitable for miscible floading. Nitrogen and oxygen are to be removed as much as possible. Oxygen may result in the forming of explosive mixtures and/or may result in the growth of microbiological organisms, which could result in undesired effects as clogging of the reservoir. The captured carbon dioxide stream contains preferably at least 80 vol% carbon dioxide, more preferably at least 90 vol% carbon dioxide, even more preferably at least 95 vol%, based on total stream.
To capture the carbon dioxide content in the flue gas, the technique of solvent extraction may be used. The use of organic solvents or aqueous solutions of organic solvents for removing carbon dioxide from a gas stream is known. See for instance A. L. Kohl and F. C. Riesenfeld, 1974, Gas Purification, 2nd edition, Gulf Publishing Co. Houston and R.N. Maddox, 1974, Gas and Liquid Sweetening, Campbell Petroleum Series. Preferably a regenerable absorbent solvent is used in a continuous process.
On an industrial scale there are chiefly two categories of absorbent solvents, depending on the mechanism to absorb the carbon dioxide: chemical solvents and physical solvents. Each solvent has its own advantages and disadvantages as to features as loading capacity, kinetics, regenerability, selectivity, stability, corrosivity, heat/cooling requirements etc.
Chemical solvents which have proved to be industrially useful are primary, secondary and/or tertiary amines derived alkanolamines . The most frequently used amines are derived from ethanolamine, especially monoethanol amine (MEA), diethanolamine (DEA), triethanolamine (TEA) , diisopropanolamine (DIPA) and methyldiethanolamine (MDEA) .
A well-known commercial process uses an aqueous mixture of a chemical solvent, especially DIPA and/or MDEA, and a physical solvent, especially cyclotetra- methylene-sulfone .
Preferably the amines are resistant to degradation by oxygen .
The use of amines to separate carbon dioxide from a mixture of gases (such as exhaust gases) has been disclosed in a number of documents. See for example CA2265416, US6500397, EP1064980, US5904908, EP0647462, JP7100334 and JP7313840, the disclosures of which are incorporated herein by reference in their entirety. These disclosures describe suitable amines for use in the present invention.
Physical solvents which have proved to be industrially suitable are cyclo-tetramethylenesulfone and its derivatives, aliphatic acid amides, N-methylpyrro- lidone, N-alkylated pyrrolidones and the corresponding piperidones, methanol, ethanol and mixtures of dialkylethers of polyethylene glycols. A combination of chemical and physical solvents may be used. For example see US 6051161, the disclosure of which is incorporated herein by reference in its entirety.
Another option is to use hot potassium hydroxide solution, certain heat resistant diamines and/or certain specific amino-acids. For example see JP7246315, the disclosure of which is incorporated herein by reference in its entirety.
Other methods of capturing carbon dioxide may also be used including pressure swing adsorption units, membrane separators and cryogenic separators. One cryogenic separator is the Ryan/Holmes four column process.
Typically the pressure of the flue gas is boosted before it is used to recover hydrocarbons from a subsurface reservoir. Preferably this pressure boosting is performed after the carbon dioxide content has been captured.
Preferably the pressure is boosted to a level sufficient to allow the carbon dioxide to enter the reservoir.
The flue gas, which at this stage is typically predominantly carbon dioxide, may be boosted in a series of stages, for example where flue gas at 150 bara is required to recover hydrocarbons from a subsurface reservoir, the pressure may be progressively boosted in a first stage up to around 5 bara, in a second stage up to around 15 bara, in a further stage up to around 50 bara and in a final stage up to 150 bara. A part of the energy needed for compression may be obtained by expanding the off-gas from the hydrocarbon synthesis process (step (v) ) from the reaction pressure to a pressure of 1-2 bara.
Typically the flue gas is also cooled during pressure boosting.
It is preferred to use pure CO2 for the enhanced oil recovery, rather than a mixture of carbon dioxide and nitrogen and/or lower (i.e. C1-C4) hydrocarbon. Due to the different properties of these components it is more convenient to use separate components rather than mixtures. E.g. nitrogen is relatively insoluble in crude oil and is suitable to pressure the gas cap. CO2 is very suitable for miscible floading.
The hydrocarbons recovered from the subsurface reservoir may be substantially in the liquid phase optionally in combination with a mixture of light hydrocarbons, especially methane.
Some of the carbon dioxide injected can be produced with the hydrocarbons from the reservoir. Sequestration in a subsurface formation is typically when carbon dioxide is injected into a closed off or depleted reservoir from which no further production of hydrocarbons is planned. The subsurface formation need not be a hydrocarbon reservoir since when sequestration is required without enhanced oil recovery, the carbon dioxide may be injected into an area of the subsurface formation which did or did not contain hydrocarbons. Thus the invention also provides a process for the sequestration of carbon dioxide, the process comprising injecting carbon dioxide into a subsurface formation, the carbon dioxide derived from flue gas from a reformer, particularly from a steam methane reformer (SMR) .
Preferably the reforming is steam methane reforming which is performed in a steam methane reformer (SMR) .
The hydrocarbonaceous stream to the SMR can be natural gas, associated gas and/or coal-bed methane, or derived from residual (crude) oil fractions or coal. The SMR can operate with a range of feedstocks. The hydrocarbonaceous stream suitably is methane, natural gas, associated gas or a mixture of C]_-4 hydrocarbons.
The stream preferably comprises mainly, i.e. more than 90 v/v%, especially more than 94%, C]_-4 hydrocarbons, and especially comprises at least 60 v/v percent methane, preferably at least 75%, more preferably 90%. Very suitably natural gas or associates gas is used. Suitably, any sulphur in the feedstock is removed. In one example, the hydrocarbonaceous stream is methane from natural gas. In use, methane and steam can be introduced into the SMR which operates at an outlet temperature of 800 °C-900 0C. In the SMR, methane is typically converted into a mixture of carbon monoxide and hydrogen primarily by equilibrium reaction (1) shown below.
CH4 + H2O <-> CO + 3H2 (D
Some of the carbon monoxide is typically further oxidised to carbon dioxide, according to equilibrium reaction (2) below.
CO + H2O <-> CO2 + H2 (2) The net result of these reactions, and other minor reactions, is typically a product mixture having an H2/CO ratio of around 5:1 to 6:1. The mixture of hydrogen and carbon monoxide is typically referred to as synthesis gas or syngas.
This syngas can be used for a number of purposes, for example for use in a Fischer-Tropsch reactor and particularly to increase the relative hydrogen : carbon monoxide content of the syngas from a gasifier before it proceeds to a Fischer-Tropsch Reactor. Typically sufficient hydrogen is also produced for use in other units or processes which are integral or associated with the Fischer-Tropsch process, for example a hydrogenation unit . The syngas is preferably mixed with syngas produced by partial oxidation of methane before being converted into said liquid hydrocarbons.
Preferably the syngas is converted into liquid hydrocarbons, optionally in combination with solid hydrocarbons and liquefied petroleum gas, by the Fischer- Tropsch process.
The Fischer-Tropsch process is well known to those skilled in the art and involves synthesis of hydrocarbons from a gaseous mixture of syngas, by contacting that mixture at reaction conditions with a Fischer-Tropsch catalyst .
Products of the Fischer-Tropsch synthesis may range from methane to heavy paraffin waxes. Preferably, the production of methane is minimised and a substantial portion of the hydrocarbons produced have a carbon chain length of a least 5 carbon atoms. Preferably, the amount of C5+ hydrocarbons is at least 60% by weight of the total product, more preferably, at least 70% by weight, even more preferably, at least 80% by weight, most preferably at least 85% by weight. Reaction products which are liquid phase under reaction conditions may be separated and removed, optionally using suitable means, such as one or more filters. Internal or external filters, or a combination of both, may be employed. Gas phase products such as light hydrocarbons and water may be removed using suitable means known to the person skilled in the art. Fischer-Tropsch catalysts are known in the art, and frequently comprise, as the catalytically active component, a metal from Group VIII of the Periodic Table. (References herein to the Periodic Table relate to the previous IUPAC version of the Periodic Table of Elements such as that described in the 68^h Edition of the Handbook of Chemistry and Physics (CPC Press)) . Particular catalytically active metals include ruthenium, iron, cobalt and nickel. Cobalt is a preferred catalytically active metal. Typically, the catalysts comprise a catalyst carrier. The catalyst carrier is preferably porous, such as a porous inorganic refractory oxide, more preferably alumina, silica, titania, zirconia or mixtures thereof.
The optimum amount of catalytically active metal present on the carrier depends inter alia on the specific catalytically active metal. Typically, the amount of cobalt present in the catalyst may range from 1 to 100 parts by weight per 100 parts by weight of carrier material, preferably from 10 to 50 parts by weight per 100 parts by weight of carrier material.
The catalytically active metal may be present in the catalyst together with one or more metal promoters or co- catalysts. The promoters may be present as metals or as the metal oxide, depending upon the particular promoter concerned. Suitable promoters include oxides of metals from Groups HA, IHB, IVB, VB, VIB and/or VIIB of the Periodic Table, oxides of the lanthanides and/or the actinides. Preferably, the catalyst comprises at least one of an element in Group IVB, VB and/or VIIB of the Periodic Table, in particular titanium, zirconium, manganese and/or vanadium. As an alternative or in addition to the metal oxide promoter, the catalyst may comprise a metal promoter selected from Groups VIIB and/or VIII of the Periodic Table. Preferred metal promoters include rhenium, platinum and palladium.
A most suitable catalyst comprises cobalt as the catalytically active metal and zirconium as a promoter. Another most suitable catalyst comprises cobalt as the catalytically active metal and manganese and/or vanadium as a promoter.
The promoter, if present in the catalyst, is typically present in an amount of from 0.1 to 60 parts by weight per 100 parts by weight of carrier material. It will however be appreciated that the optimum amount of promoter may vary for the respective elements which act as promoter.
The Fischer-Tropsch synthesis is preferably carried out at a temperature in the range from 125 to 350oC, more preferably 175 to 275 0C, most preferably 200 to 260 0C. The pressure preferably ranges from 5 to 150 bar abs . , more preferably from 5 to 80 bar abs.
The Fischer-Tropsch synthesis can be carried out in a slurry phase regime or an ebullating bed regime, wherein the catalyst particles are kept in suspension by an upward superficial gas and/or liquid velocity. Hydrogen and carbon monoxide (synthesis gas) is typically fed to the three-phase slurry reactor at a molar ratio in the range from 0.4 to 2.5. Preferably, the hydrogen to carbon monoxide molar ratio is in the range from 1.0 to 2.5.
Another regime for carrying out the Fischer-Tropsch reaction is a fixed bed regime, especially a trickle flow regime. A very suitable reactor is a multitubular fixed bed reactor. Thus the invention also provides a hydrocarbon synthesised by a Fischer-Tropsch process, the Fischer- Tropsch process being supplied by syngas, at least a portion of the syngas being produced by a method as described herein. The hydrocarbon may have undergone the steps of hydroprocessing, preferably hydrogenation, hydroisomerisation and/or hydrocracking.
The hydrocarbon may be a fuel, preferably naptha, kero or gasoil, a waxy raffinate or a base oil. In a preferred embodiment of the invention, a
Fischer-Tropsch process is carried out in which synthesis gas from a partial oxidation process (or optionally a autothermal reforming process) is used together with the synthesis gas from a reforming process. The partial oxidation synthesis gas suitably has an H2/CO ratio of
1.6-2.0, preferably 1.7-1.9. The reforming synthesis gas suitably has an H2/CO ratio of 3-8, preferably 4-6.
Especially the Fischer-Tropsch process is carried out in a two-stage set-up in which off-gas from the first step together with reforming synthesis gas is sent to the second stage. The off gas from the second stage, containing unconverted syngas, lower (C1-C4) hydrocarbons, and inerts (nitrogen, carbon dioxide) is used for heating the reforming furnace. An amine extraction process using commercially available oxygen- stable amines is used to extract the carbon dioxide from the flue gas. After pressurisation the pure carbon dioxide is used for enhanced oil recovery. The feed for the reforming process is preferably hydrogenated (to remove olefins) and shifted (to remove CO) off gas from the Fischer-Tropsch process, optionally in combination with natural gas associated gas and/or coal bed methane. The steam for the reforming process is preferably water made in the Fischer-Tropsch process. In addition, as hydrogen is needed for the upgrading of the Fischer- Tropsch hydrocarbons, part of the reforming syngas is to be shifted (in which process carbon monoxide is reacted with water to obtain carbon dioxide and hydrogen) . The hydrogen is to be separated from the carbon dioxide. Any steams containing the carbon dioxide optionally in combination with hydrogen (e.g. regeneration gas from a PSA or pressure swing adsorption unit) may be added to the feed gas or the flue gas of the reformer, depending especially on the hydrogen content. In this way a very efficient process is obtained. All carbon dioxide made in the overall process is used for enhanced oil recovery, while all energy containing compounds are used for energy generation.
An embodiment of the present invention will now be described, by way of example only, with reference to the accompanying drawing, in which Fig. 1 is a process diagram of a Fischer-Tropsch Process. Fig. 1 shows a flow diagram of a Fischer-Tropsch process. Methane and oxygen are introduced into a gasifier 10 which produces a mixture of carbon monoxide and hydrogen for use in heavy paraffin synthesis in a Fischer-Tropsch unit 12.
Steam and methane are introduced into a steam methane reformer (SMR) 14 producing a hydrogen rich mixture of carbon monoxide and hydrogen which is also used for heavy paraffin synthesis in the Fischer-Tropsch unit 12.
A portion of the product in the SMR 14 is sent to a high temperature shift reactor 16 to convert the carbon monoxide therein to carbon dioxide. This carbon dioxide is then removed in a Pressure Swing Adsorption (PSA) unit 18 to leave pure hydrogen.
A membrane separation filter 17 may be provided between the high temperature shift reactor 16 and the pressure swing adsorption unit 18 in order to remove carbon dioxide.
The SMR 14 operates at an outlet temperature of between of 800 0C and 900 0C. To heat the SMR unit 14, an integral furnace 15 is provided.
The fuel gas for the furnace 15 can be supplied from a number of sources, including off gas from the Fischer- Tropsch unit 12, the PSA unit 18 or the SMR unit 14 itself. Alternatively natural gas or any other hydrocarbonaceous based gas may be used to fuel the furnace . Typically the fuel gas provided comprises methane, other gaseous hydrocarbons, carbon dioxide and carbon monoxide .
The carbon dioxide content of the fuel gas will be increased by the combustion of the hydrocarbons in the furnace 15. Around 14% of the flue gas may be carbon dioxide. Heat is recovered by production of steam so the temperature of the flue gas is reduced to around 150oC. The flue gases produced (which include combustion products and uncombusted gases) proceed to gas cooling and boosting fans 20 and then to an amine recovery unit 22.
Carbon dioxide from the membrane separation filter 17 and/or the pressure swing adsorption unit 18 may also be directed to the amine recovery unit 22.
In the amine recovery unit 22, solvent extraction is used to extract carbon dioxide from the flue gas mixture. The carbon dioxide extracted need not be pure - a purity of 80%, preferably 95% is sufficient for the purposes of the present invention.
The carbon dioxide stream from the amine recovery unit 22 then proceeds to a series of compressors 24 where the pressure of the carbon dioxide is progressively increased. Depending on the purity of the carbon dioxide removed by the membrane separation filter 17 and pressure swing adsorption unit 18, carbon dioxide recovered therefrom may be sent directly to the compressors 24.
Thereafter a dehydration unit 26 removes any water from the carbon dioxide stream before a final compressor 24 boosts the pressure of the carbon dioxide further.
The carbon dioxide can then be injected into a reservoir to encourage the production of hydrocarbons therefrom. A benefit of the invention is that the greenhouse gas, carbon dioxide, is injected into a subsurface reservoir rather than released to the atmosphere.
In some embodiments of the present invention the carbon dioxide may be sequestrated, that is injected into a reservoir in order to dispose of the carbon dioxide without releasing it into the atmosphere.
Typically the pressure of the carbon dioxide injected into the reservoir should be greater than the reservoir pressure. Thus in certain embodiments, the number of compressors can be reduced or increased depending on the pressure of the subsurface reservoir.
Modifications and improvements may be made without departing from the scope of the invention.
The term "normally gaseous hydrocarbon" describes hydrocarbons which are gaseous at STP (0 0C, 1 bar) . These hydrocarbons are especially methane, ethane, propane and butane and their unsaturated derivates. The term "normally liquid hydrocarbons" describes hydrocarbons which are liquid at STP (0 0C, 1 bar) . This group of compounds comprises C5 up till normal -C]_4 as well as some C]_5~C]_g isomers. The group also includes the unsaturated derivatives. The term "normally solid hydrocarabons" describes hydrocarbon that are solid at standard temperature and pressure condition (STP, 0 0C, 1 bar) . This group comprise all n-C]_5~alkanes and most iso-C]_5+ alkanes. The group also comprise any unsaturated derivatives .

Claims

C L A I M S
1. A process for enhanced oil recovery from a subsurface reservoir in combination with the production of normally liquid hydrocarbons and optionally normally solid hydrocarbons from one or more hydrocarbonaceous streams, the process comprising:
(i) combusting a fuel gas containing a hydrocarbonaceous source to produce heat, the combustion products of said fuel gas, along with any carbon dioxide already present in the fuel gas, producing a flue gas containing carbon dioxide;
(ii) heating a first hydrocarbonaceous stream together with steam using the heat generated in step (i) and reforming the mixture of the hydrocarbonaceous stream and steam to produce a first synthesis gas stream; (iii) recovering hydrocarbons from a subsurface reservoir using at least a portion of the flue gas produced in step (i) , preferably at least a portion of the carbon dioxide in the flue gas produced in step (i) ;
(iv) producing a second synthesis gas stream, the second synthesis gas stream being made or obtained by partial oxidation of a second hydrocarbonaceous stream, optionally in combination with catalytic reforming; and
(v) producing normally liquid hydrocarbons, normally gaseous hydrocarbons, including liquefied petroleum gas, and optionally normally solid hydrocarbons, from the synthesis gas streams.
2. A process as claimed in claim 1, wherein the synthesis gas is converted into normally liquid hydrocarbons, optionally in combination with normally solid hydrocarbons and normally gaseous hydrocarbons including liquefied petroleum gas, by the Fischer-Tropsch process .
3. A process as claimed in claim 1 or 2, wherein the source of the fuel gas is one, or a combination, of: (1) a third hydrocarbonaceous stream;
(2) off-gas from a heavy paraffin synthesis reactor; and,
(3) typically under transient conditions, product from a reformer, particularly a steam methane reformer, preferably (2) .
4. A process as claimed in any one of claims 1 to 3, wherein the source of the fuel gas further comprises a carbon dioxide containing gas from a unit adapted to remove carbon dioxide from a mixture containing hydrogen and carbon dioxide, especially a regeneration gas from a pressure swing adsorption unit.
5. A process as claimed in any preceding claim, wherein the flue gas is treated to capture its carbon dioxide content, preferably wherein solvent extraction is used to capture the carbon dioxide content in the flue gas.
6. A process as claimed in claim 5, wherein the captured carbon dioxide is at least 80% carbon dioxide preferably at least 90% carbon dioxide.
7. A process as claimed in any preceding claim, wherein the hydrocarbons recovered from the subsurface reservoir are substantially in the liquid phase optionally in combination with a mixture of light hydrocarbons especially methane, preferably wherein carbon dioxide is produced with the hydrocarbons from the reservoir and at least a portion of the carbon dioxide produced is reinjected into the reservoir.
8. A process as claimed in any preceding claim, wherein the carbon dioxide is sequestrated in the reservoir.
9. A hydrocarbon synthesised by a Fischer-Tropsch process, the Fischer-Tropsch process being supplied by synthesis gas, at least a portion of the synthesis gas being produced by a process as claimed in any one of claims 1 to 15, preferably a hydrocarbon wherein the steps of hydroprocessing, preferably hydrogenation, hydroisomerisation and/or hydrocracking, have been applied to the hydrocarbon.
10. A process for enhanced oil recovery from a subsurface reservoir in combination with the production of normally liquid hydrocarbons and optionally normally solid hydrocarbons from one or more hydrocarbonaceous streams, the process comprising:
(i) combusting a fuel gas containing a hydrocarbonaceous source to produce heat, the combustion products of said fuel gas, along with any carbon dioxide already present in the fuel gas, producing a flue gas containing carbon dioxide;
(ii) heating a first hydrocarbonaceous stream together with steam using the heat generated in step (i) and reforming the mixture of the hydrocarbonaceous stream and steam to produce a first synthesis gas stream;
(iii) recovering hydrocarbons from a subsurface reservoir using at least a portion of the flue gas produced in step (i) , preferably at least a portion of the carbon dioxide in the flue gas produced in step (i) ;
(iv) producing a second synthesis gas stream, the second synthesis gas stream being made or obtained by partial oxidation of a second hydrocarbonaceous stream, optionally in combination with catalytic reforming; and (v) sequestration of the carbon dioxides by mineral carbonation .
PCT/EP2006/069571 2005-12-12 2006-12-12 Enhanced oil recovery process and a process for the sequestration of carbon dioxide WO2007068682A1 (en)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
EP05111939.4 2005-12-12
EP05111939 2005-12-12

Publications (1)

Publication Number Publication Date
WO2007068682A1 true WO2007068682A1 (en) 2007-06-21

Family

ID=36147090

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/EP2006/069571 WO2007068682A1 (en) 2005-12-12 2006-12-12 Enhanced oil recovery process and a process for the sequestration of carbon dioxide

Country Status (1)

Country Link
WO (1) WO2007068682A1 (en)

Cited By (115)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2009046721A1 (en) * 2007-10-12 2009-04-16 Union Engineering A/S Removal of carbon dioxide from a feed gas
WO2011049861A3 (en) * 2009-10-19 2011-08-11 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8123827B2 (en) 2007-12-28 2012-02-28 Greatpoint Energy, Inc. Processes for making syngas-derived products
US8192716B2 (en) 2008-04-01 2012-06-05 Greatpoint Energy, Inc. Sour shift process for the removal of carbon monoxide from a gas stream
US8202913B2 (en) 2008-10-23 2012-06-19 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
US8268899B2 (en) 2009-05-13 2012-09-18 Greatpoint Energy, Inc. Processes for hydromethanation of a carbonaceous feedstock
US8286901B2 (en) 2008-02-29 2012-10-16 Greatpoint Energy, Inc. Coal compositions for catalytic gasification
US8297542B2 (en) 2008-02-29 2012-10-30 Greatpoint Energy, Inc. Coal compositions for catalytic gasification
US8328890B2 (en) 2008-09-19 2012-12-11 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
US8349039B2 (en) 2008-02-29 2013-01-08 Greatpoint Energy, Inc. Carbonaceous fines recycle
US8361428B2 (en) 2008-02-29 2013-01-29 Greatpoint Energy, Inc. Reduced carbon footprint steam generation processes
US8366795B2 (en) 2008-02-29 2013-02-05 Greatpoint Energy, Inc. Catalytic gasification particulate compositions
WO2013056732A1 (en) * 2011-10-19 2013-04-25 Statoil Petroleum As Improved process for the conversion of natural gas to hydrocarbons
WO2013090486A1 (en) * 2011-12-15 2013-06-20 L'air Liquide Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude Hydrogen production with reduced carbon dioxide generation and complete capture
WO2013096073A1 (en) * 2011-12-20 2013-06-27 L'air Liquide Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude Hydrogen production with reduced carbon dioxide generation and complete capture
WO2013098412A1 (en) * 2011-12-30 2013-07-04 Shell Internationale Research Maatschappij B.V. Process for preparing a paraffin product
US8479833B2 (en) 2009-10-19 2013-07-09 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8502007B2 (en) 2008-09-19 2013-08-06 Greatpoint Energy, Inc. Char methanation catalyst and its use in gasification processes
US8557878B2 (en) 2010-04-26 2013-10-15 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with vanadium recovery
US8648121B2 (en) 2011-02-23 2014-02-11 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with nickel recovery
US8647402B2 (en) 2008-09-19 2014-02-11 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
US8652696B2 (en) 2010-03-08 2014-02-18 Greatpoint Energy, Inc. Integrated hydromethanation fuel cell power generation
US8652222B2 (en) 2008-02-29 2014-02-18 Greatpoint Energy, Inc. Biomass compositions for catalytic gasification
US8653149B2 (en) 2010-05-28 2014-02-18 Greatpoint Energy, Inc. Conversion of liquid heavy hydrocarbon feedstocks to gaseous products
US8669013B2 (en) 2010-02-23 2014-03-11 Greatpoint Energy, Inc. Integrated hydromethanation fuel cell power generation
US8709113B2 (en) 2008-02-29 2014-04-29 Greatpoint Energy, Inc. Steam generation processes utilizing biomass feedstocks
US8728183B2 (en) 2009-05-13 2014-05-20 Greatpoint Energy, Inc. Processes for hydromethanation of a carbonaceous feedstock
US8728182B2 (en) 2009-05-13 2014-05-20 Greatpoint Energy, Inc. Processes for hydromethanation of a carbonaceous feedstock
US8733459B2 (en) 2009-12-17 2014-05-27 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8734545B2 (en) 2008-03-28 2014-05-27 Exxonmobil Upstream Research Company Low emission power generation and hydrocarbon recovery systems and methods
US8734547B2 (en) 2008-12-30 2014-05-27 Greatpoint Energy, Inc. Processes for preparing a catalyzed carbonaceous particulate
US8734548B2 (en) 2008-12-30 2014-05-27 Greatpoint Energy, Inc. Processes for preparing a catalyzed coal particulate
US8748687B2 (en) 2010-08-18 2014-06-10 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US8984857B2 (en) 2008-03-28 2015-03-24 Exxonmobil Upstream Research Company Low emission power generation and hydrocarbon recovery systems and methods
US8999020B2 (en) 2008-04-01 2015-04-07 Greatpoint Energy, Inc. Processes for the separation of methane from a gas stream
US9012524B2 (en) 2011-10-06 2015-04-21 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US9027321B2 (en) 2008-03-28 2015-05-12 Exxonmobil Upstream Research Company Low emission power generation and hydrocarbon recovery systems and methods
US9034061B2 (en) 2012-10-01 2015-05-19 Greatpoint Energy, Inc. Agglomerated particulate low-rank coal feedstock and uses thereof
US9034058B2 (en) 2012-10-01 2015-05-19 Greatpoint Energy, Inc. Agglomerated particulate low-rank coal feedstock and uses thereof
US9127221B2 (en) 2011-06-03 2015-09-08 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US9222671B2 (en) 2008-10-14 2015-12-29 Exxonmobil Upstream Research Company Methods and systems for controlling the products of combustion
US9234149B2 (en) 2007-12-28 2016-01-12 Greatpoint Energy, Inc. Steam generating slurry gasifier for the catalytic gasification of a carbonaceous feedstock
US9273260B2 (en) 2012-10-01 2016-03-01 Greatpoint Energy, Inc. Agglomerated particulate low-rank coal feedstock and uses thereof
US9328920B2 (en) 2012-10-01 2016-05-03 Greatpoint Energy, Inc. Use of contaminated low-rank coal for combustion
CN105600750A (en) * 2014-11-18 2016-05-25 乔治·克劳德方法的研究开发空气股份有限公司 Plant for production of hydrogen and method for operating this plant
US9353682B2 (en) 2012-04-12 2016-05-31 General Electric Company Methods, systems and apparatus relating to combustion turbine power plants with exhaust gas recirculation
US9353940B2 (en) 2009-06-05 2016-05-31 Exxonmobil Upstream Research Company Combustor systems and combustion burners for combusting a fuel
US9353322B2 (en) 2010-11-01 2016-05-31 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US9365765B2 (en) 2013-03-15 2016-06-14 Velocys, Inc. Generation of hydrocarbon fuels having a reduced environmental impact
US9399950B2 (en) 2010-08-06 2016-07-26 Exxonmobil Upstream Research Company Systems and methods for exhaust gas extraction
WO2016128362A1 (en) * 2015-02-10 2016-08-18 Shell Internationale Research Maatschappij B.V. Method and system for obtaining a hydrogen rich gas
US9463417B2 (en) 2011-03-22 2016-10-11 Exxonmobil Upstream Research Company Low emission power generation systems and methods incorporating carbon dioxide separation
US9512759B2 (en) 2013-02-06 2016-12-06 General Electric Company System and method for catalyst heat utilization for gas turbine with exhaust gas recirculation
US9574496B2 (en) 2012-12-28 2017-02-21 General Electric Company System and method for a turbine combustor
US9581081B2 (en) 2013-01-13 2017-02-28 General Electric Company System and method for protecting components in a gas turbine engine with exhaust gas recirculation
US9587510B2 (en) 2013-07-30 2017-03-07 General Electric Company System and method for a gas turbine engine sensor
US9599070B2 (en) 2012-11-02 2017-03-21 General Electric Company System and method for oxidant compression in a stoichiometric exhaust gas recirculation gas turbine system
US9599021B2 (en) 2011-03-22 2017-03-21 Exxonmobil Upstream Research Company Systems and methods for controlling stoichiometric combustion in low emission turbine systems
US9611756B2 (en) 2012-11-02 2017-04-04 General Electric Company System and method for protecting components in a gas turbine engine with exhaust gas recirculation
US9618261B2 (en) 2013-03-08 2017-04-11 Exxonmobil Upstream Research Company Power generation and LNG production
US9617914B2 (en) 2013-06-28 2017-04-11 General Electric Company Systems and methods for monitoring gas turbine systems having exhaust gas recirculation
US9631542B2 (en) 2013-06-28 2017-04-25 General Electric Company System and method for exhausting combustion gases from gas turbine engines
US9631815B2 (en) 2012-12-28 2017-04-25 General Electric Company System and method for a turbine combustor
US9670841B2 (en) 2011-03-22 2017-06-06 Exxonmobil Upstream Research Company Methods of varying low emission turbine gas recycle circuits and systems and apparatus related thereto
US9689309B2 (en) 2011-03-22 2017-06-27 Exxonmobil Upstream Research Company Systems and methods for carbon dioxide capture in low emission combined turbine systems
US9708977B2 (en) 2012-12-28 2017-07-18 General Electric Company System and method for reheat in gas turbine with exhaust gas recirculation
US9732675B2 (en) 2010-07-02 2017-08-15 Exxonmobil Upstream Research Company Low emission power generation systems and methods
US9732673B2 (en) 2010-07-02 2017-08-15 Exxonmobil Upstream Research Company Stoichiometric combustion with exhaust gas recirculation and direct contact cooler
US9752458B2 (en) 2013-12-04 2017-09-05 General Electric Company System and method for a gas turbine engine
US9784182B2 (en) 2013-03-08 2017-10-10 Exxonmobil Upstream Research Company Power generation and methane recovery from methane hydrates
US9784185B2 (en) 2012-04-26 2017-10-10 General Electric Company System and method for cooling a gas turbine with an exhaust gas provided by the gas turbine
US9784140B2 (en) 2013-03-08 2017-10-10 Exxonmobil Upstream Research Company Processing exhaust for use in enhanced oil recovery
US9803865B2 (en) 2012-12-28 2017-10-31 General Electric Company System and method for a turbine combustor
US9810050B2 (en) 2011-12-20 2017-11-07 Exxonmobil Upstream Research Company Enhanced coal-bed methane production
US9819292B2 (en) 2014-12-31 2017-11-14 General Electric Company Systems and methods to respond to grid overfrequency events for a stoichiometric exhaust recirculation gas turbine
US9835089B2 (en) 2013-06-28 2017-12-05 General Electric Company System and method for a fuel nozzle
US9863267B2 (en) 2014-01-21 2018-01-09 General Electric Company System and method of control for a gas turbine engine
US9869247B2 (en) 2014-12-31 2018-01-16 General Electric Company Systems and methods of estimating a combustion equivalence ratio in a gas turbine with exhaust gas recirculation
US9869279B2 (en) 2012-11-02 2018-01-16 General Electric Company System and method for a multi-wall turbine combustor
US9885290B2 (en) 2014-06-30 2018-02-06 General Electric Company Erosion suppression system and method in an exhaust gas recirculation gas turbine system
US9903316B2 (en) 2010-07-02 2018-02-27 Exxonmobil Upstream Research Company Stoichiometric combustion of enriched air with exhaust gas recirculation
US9903271B2 (en) 2010-07-02 2018-02-27 Exxonmobil Upstream Research Company Low emission triple-cycle power generation and CO2 separation systems and methods
US9903588B2 (en) 2013-07-30 2018-02-27 General Electric Company System and method for barrier in passage of combustor of gas turbine engine with exhaust gas recirculation
US9903279B2 (en) 2010-08-06 2018-02-27 Exxonmobil Upstream Research Company Systems and methods for optimizing stoichiometric combustion
US9915200B2 (en) 2014-01-21 2018-03-13 General Electric Company System and method for controlling the combustion process in a gas turbine operating with exhaust gas recirculation
US9932874B2 (en) 2013-02-21 2018-04-03 Exxonmobil Upstream Research Company Reducing oxygen in a gas turbine exhaust
US9938861B2 (en) 2013-02-21 2018-04-10 Exxonmobil Upstream Research Company Fuel combusting method
US9951658B2 (en) 2013-07-31 2018-04-24 General Electric Company System and method for an oxidant heating system
US10012151B2 (en) 2013-06-28 2018-07-03 General Electric Company Systems and methods for controlling exhaust gas flow in exhaust gas recirculation gas turbine systems
US10030588B2 (en) 2013-12-04 2018-07-24 General Electric Company Gas turbine combustor diagnostic system and method
US10047633B2 (en) 2014-05-16 2018-08-14 General Electric Company Bearing housing
US10060359B2 (en) 2014-06-30 2018-08-28 General Electric Company Method and system for combustion control for gas turbine system with exhaust gas recirculation
US10079564B2 (en) 2014-01-27 2018-09-18 General Electric Company System and method for a stoichiometric exhaust gas recirculation gas turbine system
US10094566B2 (en) 2015-02-04 2018-10-09 General Electric Company Systems and methods for high volumetric oxidant flow in gas turbine engine with exhaust gas recirculation
US10100741B2 (en) 2012-11-02 2018-10-16 General Electric Company System and method for diffusion combustion with oxidant-diluent mixing in a stoichiometric exhaust gas recirculation gas turbine system
US10107495B2 (en) 2012-11-02 2018-10-23 General Electric Company Gas turbine combustor control system for stoichiometric combustion in the presence of a diluent
US10145269B2 (en) 2015-03-04 2018-12-04 General Electric Company System and method for cooling discharge flow
US10208677B2 (en) 2012-12-31 2019-02-19 General Electric Company Gas turbine load control system
US10215412B2 (en) 2012-11-02 2019-02-26 General Electric Company System and method for load control with diffusion combustion in a stoichiometric exhaust gas recirculation gas turbine system
US10221762B2 (en) 2013-02-28 2019-03-05 General Electric Company System and method for a turbine combustor
US10227920B2 (en) 2014-01-15 2019-03-12 General Electric Company Gas turbine oxidant separation system
US10253690B2 (en) 2015-02-04 2019-04-09 General Electric Company Turbine system with exhaust gas recirculation, separation and extraction
US10267270B2 (en) 2015-02-06 2019-04-23 General Electric Company Systems and methods for carbon black production with a gas turbine engine having exhaust gas recirculation
US10273880B2 (en) 2012-04-26 2019-04-30 General Electric Company System and method of recirculating exhaust gas for use in a plurality of flow paths in a gas turbine engine
US10316746B2 (en) 2015-02-04 2019-06-11 General Electric Company Turbine system with exhaust gas recirculation, separation and extraction
US10315150B2 (en) 2013-03-08 2019-06-11 Exxonmobil Upstream Research Company Carbon dioxide recovery
US10344231B1 (en) 2018-10-26 2019-07-09 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with improved carbon utilization
US10435637B1 (en) 2018-12-18 2019-10-08 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with improved carbon utilization and power generation
US10464872B1 (en) 2018-07-31 2019-11-05 Greatpoint Energy, Inc. Catalytic gasification to produce methanol
US10480792B2 (en) 2015-03-06 2019-11-19 General Electric Company Fuel staging in a gas turbine engine
US10570825B2 (en) 2010-07-02 2020-02-25 Exxonmobil Upstream Research Company Systems and methods for controlling combustion of a fuel
US10618818B1 (en) 2019-03-22 2020-04-14 Sure Champion Investment Limited Catalytic gasification to produce ammonia and urea
US10655542B2 (en) 2014-06-30 2020-05-19 General Electric Company Method and system for startup of gas turbine system drive trains with exhaust gas recirculation
US10788212B2 (en) 2015-01-12 2020-09-29 General Electric Company System and method for an oxidant passageway in a gas turbine system with exhaust gas recirculation
CN114772551A (en) * 2022-06-16 2022-07-22 浙江百能科技有限公司 Method and system for efficiently utilizing methane-rich gas

Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4899544A (en) * 1987-08-13 1990-02-13 Boyd Randall T Cogeneration/CO2 production process and plant
US5055724A (en) * 1989-10-30 1991-10-08 United States Department Of Energy Open-cycle magnetohydrodynamic power plant with CO2 recycling
US5112590A (en) * 1987-11-16 1992-05-12 The Boc Group Plc Separation of gas mixtures including hydrogen
WO2004037391A1 (en) * 2002-10-23 2004-05-06 Shell Internationale Research Maatschappij B.V. Process for removal and capture of carbon dioxide from flue gases
WO2004055323A1 (en) * 2002-12-13 2004-07-01 Statoil Asa A plant and a method for increased oil recovery
WO2005051872A1 (en) * 2003-11-19 2005-06-09 Exxonmobil Chemical Patents Inc. Controlling the ratio of ethylene to propylene produced in an oxygenate to olefin conversion process

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4899544A (en) * 1987-08-13 1990-02-13 Boyd Randall T Cogeneration/CO2 production process and plant
US5112590A (en) * 1987-11-16 1992-05-12 The Boc Group Plc Separation of gas mixtures including hydrogen
US5055724A (en) * 1989-10-30 1991-10-08 United States Department Of Energy Open-cycle magnetohydrodynamic power plant with CO2 recycling
WO2004037391A1 (en) * 2002-10-23 2004-05-06 Shell Internationale Research Maatschappij B.V. Process for removal and capture of carbon dioxide from flue gases
WO2004055323A1 (en) * 2002-12-13 2004-07-01 Statoil Asa A plant and a method for increased oil recovery
WO2005051872A1 (en) * 2003-11-19 2005-06-09 Exxonmobil Chemical Patents Inc. Controlling the ratio of ethylene to propylene produced in an oxygenate to olefin conversion process

Cited By (140)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN101835524B (en) * 2007-10-12 2013-06-05 由宁工程股份有限公司 Removal of carbon dioxide from a feed gas
AU2008310157B2 (en) * 2007-10-12 2011-02-10 Union Engineering A/S Removal of carbon dioxide from a feed gas
WO2009046721A1 (en) * 2007-10-12 2009-04-16 Union Engineering A/S Removal of carbon dioxide from a feed gas
US8529854B2 (en) 2007-10-12 2013-09-10 Union Engineering A/S Removal of carbon dioxide from a feed gas
EA018558B1 (en) * 2007-10-12 2013-08-30 Юнион Инджиниринг А/С Process and plant for removal of carbon dioxide from a feed gas
US9234149B2 (en) 2007-12-28 2016-01-12 Greatpoint Energy, Inc. Steam generating slurry gasifier for the catalytic gasification of a carbonaceous feedstock
US8123827B2 (en) 2007-12-28 2012-02-28 Greatpoint Energy, Inc. Processes for making syngas-derived products
US8361428B2 (en) 2008-02-29 2013-01-29 Greatpoint Energy, Inc. Reduced carbon footprint steam generation processes
US8297542B2 (en) 2008-02-29 2012-10-30 Greatpoint Energy, Inc. Coal compositions for catalytic gasification
US8652222B2 (en) 2008-02-29 2014-02-18 Greatpoint Energy, Inc. Biomass compositions for catalytic gasification
US8349039B2 (en) 2008-02-29 2013-01-08 Greatpoint Energy, Inc. Carbonaceous fines recycle
US8709113B2 (en) 2008-02-29 2014-04-29 Greatpoint Energy, Inc. Steam generation processes utilizing biomass feedstocks
US8366795B2 (en) 2008-02-29 2013-02-05 Greatpoint Energy, Inc. Catalytic gasification particulate compositions
US8286901B2 (en) 2008-02-29 2012-10-16 Greatpoint Energy, Inc. Coal compositions for catalytic gasification
US8984857B2 (en) 2008-03-28 2015-03-24 Exxonmobil Upstream Research Company Low emission power generation and hydrocarbon recovery systems and methods
EP2276559A4 (en) * 2008-03-28 2017-10-18 Exxonmobil Upstream Research Company Low emission power generation and hydrocarbon recovery systems and methods
US8734545B2 (en) 2008-03-28 2014-05-27 Exxonmobil Upstream Research Company Low emission power generation and hydrocarbon recovery systems and methods
US9027321B2 (en) 2008-03-28 2015-05-12 Exxonmobil Upstream Research Company Low emission power generation and hydrocarbon recovery systems and methods
US8999020B2 (en) 2008-04-01 2015-04-07 Greatpoint Energy, Inc. Processes for the separation of methane from a gas stream
US8192716B2 (en) 2008-04-01 2012-06-05 Greatpoint Energy, Inc. Sour shift process for the removal of carbon monoxide from a gas stream
US8502007B2 (en) 2008-09-19 2013-08-06 Greatpoint Energy, Inc. Char methanation catalyst and its use in gasification processes
US8328890B2 (en) 2008-09-19 2012-12-11 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
US8647402B2 (en) 2008-09-19 2014-02-11 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
US10495306B2 (en) 2008-10-14 2019-12-03 Exxonmobil Upstream Research Company Methods and systems for controlling the products of combustion
US9222671B2 (en) 2008-10-14 2015-12-29 Exxonmobil Upstream Research Company Methods and systems for controlling the products of combustion
US9719682B2 (en) 2008-10-14 2017-08-01 Exxonmobil Upstream Research Company Methods and systems for controlling the products of combustion
US8202913B2 (en) 2008-10-23 2012-06-19 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
US8734547B2 (en) 2008-12-30 2014-05-27 Greatpoint Energy, Inc. Processes for preparing a catalyzed carbonaceous particulate
US8734548B2 (en) 2008-12-30 2014-05-27 Greatpoint Energy, Inc. Processes for preparing a catalyzed coal particulate
US8728182B2 (en) 2009-05-13 2014-05-20 Greatpoint Energy, Inc. Processes for hydromethanation of a carbonaceous feedstock
US8728183B2 (en) 2009-05-13 2014-05-20 Greatpoint Energy, Inc. Processes for hydromethanation of a carbonaceous feedstock
US8268899B2 (en) 2009-05-13 2012-09-18 Greatpoint Energy, Inc. Processes for hydromethanation of a carbonaceous feedstock
US9353940B2 (en) 2009-06-05 2016-05-31 Exxonmobil Upstream Research Company Combustor systems and combustion burners for combusting a fuel
WO2011049861A3 (en) * 2009-10-19 2011-08-11 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8479833B2 (en) 2009-10-19 2013-07-09 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8479834B2 (en) 2009-10-19 2013-07-09 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8733459B2 (en) 2009-12-17 2014-05-27 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8669013B2 (en) 2010-02-23 2014-03-11 Greatpoint Energy, Inc. Integrated hydromethanation fuel cell power generation
US8652696B2 (en) 2010-03-08 2014-02-18 Greatpoint Energy, Inc. Integrated hydromethanation fuel cell power generation
US8557878B2 (en) 2010-04-26 2013-10-15 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with vanadium recovery
US8653149B2 (en) 2010-05-28 2014-02-18 Greatpoint Energy, Inc. Conversion of liquid heavy hydrocarbon feedstocks to gaseous products
US9732673B2 (en) 2010-07-02 2017-08-15 Exxonmobil Upstream Research Company Stoichiometric combustion with exhaust gas recirculation and direct contact cooler
US9732675B2 (en) 2010-07-02 2017-08-15 Exxonmobil Upstream Research Company Low emission power generation systems and methods
US10570825B2 (en) 2010-07-02 2020-02-25 Exxonmobil Upstream Research Company Systems and methods for controlling combustion of a fuel
US9903316B2 (en) 2010-07-02 2018-02-27 Exxonmobil Upstream Research Company Stoichiometric combustion of enriched air with exhaust gas recirculation
US9903271B2 (en) 2010-07-02 2018-02-27 Exxonmobil Upstream Research Company Low emission triple-cycle power generation and CO2 separation systems and methods
US9903279B2 (en) 2010-08-06 2018-02-27 Exxonmobil Upstream Research Company Systems and methods for optimizing stoichiometric combustion
US9399950B2 (en) 2010-08-06 2016-07-26 Exxonmobil Upstream Research Company Systems and methods for exhaust gas extraction
US10174682B2 (en) 2010-08-06 2019-01-08 Exxonmobil Upstream Research Company Systems and methods for optimizing stoichiometric combustion
US8748687B2 (en) 2010-08-18 2014-06-10 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US9353322B2 (en) 2010-11-01 2016-05-31 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US8648121B2 (en) 2011-02-23 2014-02-11 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with nickel recovery
US9670841B2 (en) 2011-03-22 2017-06-06 Exxonmobil Upstream Research Company Methods of varying low emission turbine gas recycle circuits and systems and apparatus related thereto
US9463417B2 (en) 2011-03-22 2016-10-11 Exxonmobil Upstream Research Company Low emission power generation systems and methods incorporating carbon dioxide separation
US9599021B2 (en) 2011-03-22 2017-03-21 Exxonmobil Upstream Research Company Systems and methods for controlling stoichiometric combustion in low emission turbine systems
US9689309B2 (en) 2011-03-22 2017-06-27 Exxonmobil Upstream Research Company Systems and methods for carbon dioxide capture in low emission combined turbine systems
US9127221B2 (en) 2011-06-03 2015-09-08 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US9012524B2 (en) 2011-10-06 2015-04-21 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
WO2013056732A1 (en) * 2011-10-19 2013-04-25 Statoil Petroleum As Improved process for the conversion of natural gas to hydrocarbons
US8591769B2 (en) 2011-12-15 2013-11-26 Air Liquide Large Industries U.S. Lp Hydrogen production with reduced carbon dioxide generation and complete capture
WO2013090486A1 (en) * 2011-12-15 2013-06-20 L'air Liquide Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude Hydrogen production with reduced carbon dioxide generation and complete capture
US9810050B2 (en) 2011-12-20 2017-11-07 Exxonmobil Upstream Research Company Enhanced coal-bed methane production
WO2013096073A1 (en) * 2011-12-20 2013-06-27 L'air Liquide Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude Hydrogen production with reduced carbon dioxide generation and complete capture
US8580153B2 (en) 2011-12-20 2013-11-12 Air Liquide Large Industries U.S. Lp Hydrogen production with reduced carbon dioxide generation and complete capture
WO2013098412A1 (en) * 2011-12-30 2013-07-04 Shell Internationale Research Maatschappij B.V. Process for preparing a paraffin product
US9096479B2 (en) 2011-12-30 2015-08-04 Shell Oil Company Process for preparing a paraffin product
CN104105658A (en) * 2011-12-30 2014-10-15 国际壳牌研究有限公司 Process for preparing a paraffin product
US9353682B2 (en) 2012-04-12 2016-05-31 General Electric Company Methods, systems and apparatus relating to combustion turbine power plants with exhaust gas recirculation
US9784185B2 (en) 2012-04-26 2017-10-10 General Electric Company System and method for cooling a gas turbine with an exhaust gas provided by the gas turbine
US10273880B2 (en) 2012-04-26 2019-04-30 General Electric Company System and method of recirculating exhaust gas for use in a plurality of flow paths in a gas turbine engine
US9034061B2 (en) 2012-10-01 2015-05-19 Greatpoint Energy, Inc. Agglomerated particulate low-rank coal feedstock and uses thereof
US9328920B2 (en) 2012-10-01 2016-05-03 Greatpoint Energy, Inc. Use of contaminated low-rank coal for combustion
US9034058B2 (en) 2012-10-01 2015-05-19 Greatpoint Energy, Inc. Agglomerated particulate low-rank coal feedstock and uses thereof
US9273260B2 (en) 2012-10-01 2016-03-01 Greatpoint Energy, Inc. Agglomerated particulate low-rank coal feedstock and uses thereof
US10138815B2 (en) 2012-11-02 2018-11-27 General Electric Company System and method for diffusion combustion in a stoichiometric exhaust gas recirculation gas turbine system
US10100741B2 (en) 2012-11-02 2018-10-16 General Electric Company System and method for diffusion combustion with oxidant-diluent mixing in a stoichiometric exhaust gas recirculation gas turbine system
US9611756B2 (en) 2012-11-02 2017-04-04 General Electric Company System and method for protecting components in a gas turbine engine with exhaust gas recirculation
US9869279B2 (en) 2012-11-02 2018-01-16 General Electric Company System and method for a multi-wall turbine combustor
US9599070B2 (en) 2012-11-02 2017-03-21 General Electric Company System and method for oxidant compression in a stoichiometric exhaust gas recirculation gas turbine system
US10215412B2 (en) 2012-11-02 2019-02-26 General Electric Company System and method for load control with diffusion combustion in a stoichiometric exhaust gas recirculation gas turbine system
US10161312B2 (en) 2012-11-02 2018-12-25 General Electric Company System and method for diffusion combustion with fuel-diluent mixing in a stoichiometric exhaust gas recirculation gas turbine system
US10683801B2 (en) 2012-11-02 2020-06-16 General Electric Company System and method for oxidant compression in a stoichiometric exhaust gas recirculation gas turbine system
US10107495B2 (en) 2012-11-02 2018-10-23 General Electric Company Gas turbine combustor control system for stoichiometric combustion in the presence of a diluent
US9803865B2 (en) 2012-12-28 2017-10-31 General Electric Company System and method for a turbine combustor
US9574496B2 (en) 2012-12-28 2017-02-21 General Electric Company System and method for a turbine combustor
US9631815B2 (en) 2012-12-28 2017-04-25 General Electric Company System and method for a turbine combustor
US9708977B2 (en) 2012-12-28 2017-07-18 General Electric Company System and method for reheat in gas turbine with exhaust gas recirculation
US10208677B2 (en) 2012-12-31 2019-02-19 General Electric Company Gas turbine load control system
US9581081B2 (en) 2013-01-13 2017-02-28 General Electric Company System and method for protecting components in a gas turbine engine with exhaust gas recirculation
US9512759B2 (en) 2013-02-06 2016-12-06 General Electric Company System and method for catalyst heat utilization for gas turbine with exhaust gas recirculation
US10082063B2 (en) 2013-02-21 2018-09-25 Exxonmobil Upstream Research Company Reducing oxygen in a gas turbine exhaust
US9938861B2 (en) 2013-02-21 2018-04-10 Exxonmobil Upstream Research Company Fuel combusting method
US9932874B2 (en) 2013-02-21 2018-04-03 Exxonmobil Upstream Research Company Reducing oxygen in a gas turbine exhaust
US10221762B2 (en) 2013-02-28 2019-03-05 General Electric Company System and method for a turbine combustor
US9618261B2 (en) 2013-03-08 2017-04-11 Exxonmobil Upstream Research Company Power generation and LNG production
US9784140B2 (en) 2013-03-08 2017-10-10 Exxonmobil Upstream Research Company Processing exhaust for use in enhanced oil recovery
US10315150B2 (en) 2013-03-08 2019-06-11 Exxonmobil Upstream Research Company Carbon dioxide recovery
US9784182B2 (en) 2013-03-08 2017-10-10 Exxonmobil Upstream Research Company Power generation and methane recovery from methane hydrates
US9365765B2 (en) 2013-03-15 2016-06-14 Velocys, Inc. Generation of hydrocarbon fuels having a reduced environmental impact
US9994763B2 (en) 2013-03-15 2018-06-12 Velocys, Inc. Generation of hydrocarbon fuels having a reduced environmental impact
WO2014146110A3 (en) * 2013-03-15 2017-03-30 Velocys, Inc. Generation of hydrocarbon fuels having a reduced environmental impact
US10012151B2 (en) 2013-06-28 2018-07-03 General Electric Company Systems and methods for controlling exhaust gas flow in exhaust gas recirculation gas turbine systems
US9631542B2 (en) 2013-06-28 2017-04-25 General Electric Company System and method for exhausting combustion gases from gas turbine engines
US9617914B2 (en) 2013-06-28 2017-04-11 General Electric Company Systems and methods for monitoring gas turbine systems having exhaust gas recirculation
US9835089B2 (en) 2013-06-28 2017-12-05 General Electric Company System and method for a fuel nozzle
US9587510B2 (en) 2013-07-30 2017-03-07 General Electric Company System and method for a gas turbine engine sensor
US9903588B2 (en) 2013-07-30 2018-02-27 General Electric Company System and method for barrier in passage of combustor of gas turbine engine with exhaust gas recirculation
US9951658B2 (en) 2013-07-31 2018-04-24 General Electric Company System and method for an oxidant heating system
US10030588B2 (en) 2013-12-04 2018-07-24 General Electric Company Gas turbine combustor diagnostic system and method
US10731512B2 (en) 2013-12-04 2020-08-04 Exxonmobil Upstream Research Company System and method for a gas turbine engine
US9752458B2 (en) 2013-12-04 2017-09-05 General Electric Company System and method for a gas turbine engine
US10227920B2 (en) 2014-01-15 2019-03-12 General Electric Company Gas turbine oxidant separation system
US9863267B2 (en) 2014-01-21 2018-01-09 General Electric Company System and method of control for a gas turbine engine
US9915200B2 (en) 2014-01-21 2018-03-13 General Electric Company System and method for controlling the combustion process in a gas turbine operating with exhaust gas recirculation
US10079564B2 (en) 2014-01-27 2018-09-18 General Electric Company System and method for a stoichiometric exhaust gas recirculation gas turbine system
US10727768B2 (en) 2014-01-27 2020-07-28 Exxonmobil Upstream Research Company System and method for a stoichiometric exhaust gas recirculation gas turbine system
US10047633B2 (en) 2014-05-16 2018-08-14 General Electric Company Bearing housing
US10655542B2 (en) 2014-06-30 2020-05-19 General Electric Company Method and system for startup of gas turbine system drive trains with exhaust gas recirculation
US10060359B2 (en) 2014-06-30 2018-08-28 General Electric Company Method and system for combustion control for gas turbine system with exhaust gas recirculation
US9885290B2 (en) 2014-06-30 2018-02-06 General Electric Company Erosion suppression system and method in an exhaust gas recirculation gas turbine system
US10738711B2 (en) 2014-06-30 2020-08-11 Exxonmobil Upstream Research Company Erosion suppression system and method in an exhaust gas recirculation gas turbine system
CN105600750A (en) * 2014-11-18 2016-05-25 乔治·克劳德方法的研究开发空气股份有限公司 Plant for production of hydrogen and method for operating this plant
US10486968B2 (en) 2014-11-18 2019-11-26 L'air Liquide Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude Plant for production of hydrogen and method for operating this plant
WO2016078775A1 (en) * 2014-11-18 2016-05-26 L'air Liquide Societe Anonyme Pour L'etude Et L' Exploitation Des Procedes Georges Claude Plant for production of hydrogen and method for operating this plant
US9819292B2 (en) 2014-12-31 2017-11-14 General Electric Company Systems and methods to respond to grid overfrequency events for a stoichiometric exhaust recirculation gas turbine
US9869247B2 (en) 2014-12-31 2018-01-16 General Electric Company Systems and methods of estimating a combustion equivalence ratio in a gas turbine with exhaust gas recirculation
US10788212B2 (en) 2015-01-12 2020-09-29 General Electric Company System and method for an oxidant passageway in a gas turbine system with exhaust gas recirculation
US10316746B2 (en) 2015-02-04 2019-06-11 General Electric Company Turbine system with exhaust gas recirculation, separation and extraction
US10253690B2 (en) 2015-02-04 2019-04-09 General Electric Company Turbine system with exhaust gas recirculation, separation and extraction
US10094566B2 (en) 2015-02-04 2018-10-09 General Electric Company Systems and methods for high volumetric oxidant flow in gas turbine engine with exhaust gas recirculation
US10267270B2 (en) 2015-02-06 2019-04-23 General Electric Company Systems and methods for carbon black production with a gas turbine engine having exhaust gas recirculation
WO2016128362A1 (en) * 2015-02-10 2016-08-18 Shell Internationale Research Maatschappij B.V. Method and system for obtaining a hydrogen rich gas
US10145269B2 (en) 2015-03-04 2018-12-04 General Electric Company System and method for cooling discharge flow
US10968781B2 (en) 2015-03-04 2021-04-06 General Electric Company System and method for cooling discharge flow
US10480792B2 (en) 2015-03-06 2019-11-19 General Electric Company Fuel staging in a gas turbine engine
US10464872B1 (en) 2018-07-31 2019-11-05 Greatpoint Energy, Inc. Catalytic gasification to produce methanol
US10344231B1 (en) 2018-10-26 2019-07-09 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with improved carbon utilization
US10435637B1 (en) 2018-12-18 2019-10-08 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with improved carbon utilization and power generation
US10618818B1 (en) 2019-03-22 2020-04-14 Sure Champion Investment Limited Catalytic gasification to produce ammonia and urea
CN114772551A (en) * 2022-06-16 2022-07-22 浙江百能科技有限公司 Method and system for efficiently utilizing methane-rich gas

Similar Documents

Publication Publication Date Title
WO2007068682A1 (en) Enhanced oil recovery process and a process for the sequestration of carbon dioxide
WO2007077137A1 (en) A process for enhanced oil recovery and a process for the sequestration of carbon dioxide
AU2002331205B2 (en) Tertiary oil recovery combined with gas conversion process
WO2007077138A1 (en) Enhanced oil recovery process and a process for the sequestration of carbon dioxide
CA2320509C (en) Gas conversion using synthesis gas produced hydrogen for catalyst rejuvenation and hydrocarbon conversion
AU2006301154B2 (en) Improvements relating to coal to liquid processes
AU760616B2 (en) Gas conversion using hydrogen from synthesis gas and hydroconversion tail gas
AU2002331205A1 (en) Tertiary oil recovery combined with gas conversion process
AU2006245727B2 (en) Removal of carbon dioxide from a gas stream
EP2170489B1 (en) Process for producing purified gas from gas comprising h2s, co2 and hcn and/or cos
EP1004746A1 (en) Process for the production of liquid hydrocarbons
CA2592599A1 (en) Improvements relating to coal to liquid processes
WO2011048066A1 (en) Method &amp; apparatus for processing fischer-tropsch off-gas
WO2013017700A1 (en) Process for producing hydrocarbons from syngas
WO2001087808A1 (en) Process for the production of liquid hydrocarbons
AU2001281777A1 (en) Process for the production of liquid hydrocarbons
AU2002356086B2 (en) Process for the preparation of hydrocarbons
WO2013056732A1 (en) Improved process for the conversion of natural gas to hydrocarbons
EP2465595A1 (en) Process for capture and compression of carbon dioxide from fischer-tropsch off-gas
WO2007077139A2 (en) A process for enhanced oil recovery in combination with the production of hydrocarbons from synthesis gas

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application
NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 06819941

Country of ref document: EP

Kind code of ref document: A1