WO2007077138A1 - 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

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Publication number
WO2007077138A1
WO2007077138A1 PCT/EP2006/070053 EP2006070053W WO2007077138A1 WO 2007077138 A1 WO2007077138 A1 WO 2007077138A1 EP 2006070053 W EP2006070053 W EP 2006070053W WO 2007077138 A1 WO2007077138 A1 WO 2007077138A1
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Prior art keywords
carbon dioxide
membrane
gas
hydrocarbons
gaseous mixture
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PCT/EP2006/070053
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French (fr)
Inventor
Johannes Leendert Willem Cornelis Den Boestert
Paul Clinton
Frank Haiko Geuzebroek
Arian Nijmeijer
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Shell Internationale Research Maatschappij B.V.
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Publication of WO2007077138A1 publication Critical patent/WO2007077138A1/en

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    • 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
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/22—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by diffusion
    • B01D53/225—Multiple stage diffusion
    • B01D53/226—Multiple stage diffusion in serial connexion
    • 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
    • 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
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/005—Waste disposal systems
    • E21B41/0057—Disposal of a fluid by injection into a subterranean formation
    • E21B41/0064—Carbon dioxide sequestration
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2317/00—Membrane module arrangements within a plant or an apparatus
    • B01D2317/08—Use of membrane modules of different kinds
    • 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
    • C01B2203/0465—Composition of the impurity
    • 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
    • C01B2203/047—Composition of the impurity the impurity being carbon monoxide
    • 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
    • C01B2203/04—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
    • C01B2203/048—Composition of the impurity the impurity being an organic compound
    • 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
    • Y02P20/129—Energy recovery, e.g. by cogeneration, H2recovery or pressure recovery turbines
    • 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
    • Y02P20/151—Reduction of greenhouse gas [GHG] emissions, e.g. 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
    • 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 hydrocarbons, especially oil, from a subsurface reservoir by injecting a carbon dioxide containing gas into the reservoir, in combination with the production of hydrocarbons and carbon dioxide from a hydrocarbonaceous stream, especially a natural gas 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) .
  • primary oil recovery or by the injection of water or gas
  • secondary oil recovery or by the injection of water or gas.
  • 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, 6th edition, Elsevier, Amsterdam/New York, 1983, p. 91-97. See also the 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 their viscosity, which enhances the recovery of hydrocarbons from the reservoir.
  • Carbon dioxide can be recovered from a number of sources but the sources are typically impure, containing other gases such as hydrogen, nitrogen, hydrocarbons, especially C1-C4 hydrocarbon, and/or carbon monoxide.
  • a process for enhanced oil recovery comprising: injecting a carbon dioxide containing stream into a subsurface reservoir to enhance the recovery of hydrocarbons from the reservoir, wherein the carbon dioxide containing stream has been obtained from a gaseous mixture comprising hydrogen, carbon dioxide and carbon monoxide, optionally C1-C4 hydrocarbons and optionally inerts, by: (i) utilising a first membrane to separate hydrogen from the gaseous mixture; and then,
  • the gaseous mixture is especially heavy paraffin synthesis (HPS) off-gas.
  • HPS heavy paraffin synthesis
  • the gaseous mixture is heavy paraffin synthesis (HPS) off-gas from a Fischer- Tropsch hydrocarbon synthesis process, more preferably a cobalt catalyst based Fischer-Tropsch process.
  • the gaseous mixture may comprise heavy paraffin synthesis (HPS) off-gas.
  • HPS off-gas will contain a certain amount of unconverted synthesis gas (i.e. carbon monoxide and hydrogen) , carbon dioxide, C1-C4 hydrocarbons (formed in the hydrocarbon synthesis reaction) and, optionally, inerts (mainly nitrogen and some argon) .
  • HPS off-gas will contain 10-40 wt% hydrogen, especially 15-35 vol%, 20-65 vol% Co, especially 30-55 vol%, 10-50 vol% CO2, especially 15-
  • the invention also provides a process for enhanced oil recovery in combination with the production of liquid hydrocarbons from synthesis gas, the process comprising: (a) converting synthesis gas into normally liquid hydrocarbons, normally gaseous hydrocarbons, especially liquefied petroleum gas, and optionally normally solid hydrocarbons at elevated temperatures and pressures, optionally followed by hydroconversion of the hydrocarbons obtained;
  • step (b) recovering heavy paraffin synthesis (HPS) off-gas from said conversion of synthesis gas into normally liquid and gaseous hydrocarbons in step (a) , the off-gas comprising hydrogen, carbon dioxide and carbon monoxide, C]_-C4 hydrocarbons and optionally inerts;
  • HPS heavy paraffin synthesis
  • step (d) recovering hydrocarbons from a subsurface reservoir using at least a portion of the first stream enriched in carbon dioxide produced in step (c) .
  • the term "normally” refers to STP-condition, i.e. 0 0 C and 1 bar.
  • the invention also provides a process for the production of carbon dioxide, the process comprising: (a) obtaining a gaseous mixture comprising heavy paraffin synthesis (HPS) off-gas from a Fischer-Tropsch process, the off-gas comprising hydrogen, carbon dioxide and carbon monoxide, C1-C4 hydrocarbons and inerts, ; (b) utilising a first membrane to separate hydrogen from the HPS off-gas, and then utilising a second membrane to separate carbon dioxide from the HPS off-gas.
  • HPS heavy paraffin synthesis
  • the inerts in HPS off-gas are mainly nitrogen and argon.
  • the nitrogen may be present in an amount up till 55 vol%, suitably 15-50 vol%.
  • the invention also provides a process for the sequestration of carbon dioxide, the process comprising injecting a carbon dioxide containing stream into a subsurface formation, wherein the carbon dioxide containing stream has been obtained from a gaseous mixture, comprising hydrogen, carbon dioxide and carbon monoxide, optionally C1-C4 hydrocarbons and optionally inerts, such as heavy paraffin synthesis (HPS) off-gas, by utilising a first membrane to separate hydrogen from the gaseous mixture, and then utilising a second membrane to separate carbon dioxide from the gaseous mixture.
  • a gaseous mixture comprising hydrogen, carbon dioxide and carbon monoxide, optionally C1-C4 hydrocarbons and optionally inerts, such as heavy paraffin synthesis (HPS) off-gas
  • the hydrocarbonaceous stream to be used in the present invention is suitably 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 compound 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 hydrocarbonaceous stream may also be coal, biomass, residual oil fractions (including tar sand oils), peat, municipal waste etc.
  • the hydrocarbonaceous stream is reacted with oxygen and/or steam to provide synthesis gas, e.g. by means of (catalytic) partial oxidation or by steam/autothermal reforming.
  • synthesis gas e.g. by means of (catalytic) partial oxidation or by steam/autothermal reforming.
  • the first membrane is adapted to allow the passage of hydrogen but resist the passage of the remaining gases.
  • the second membrane is adapted to allow the passage of carbon dioxide but resist the passage of the remaining gases.
  • the HPS off-gas may be at a pressure of between 20 - 100 bar, preferably 40 - 80 bar.
  • the second stream may be used as fuel gas for a gas to liquids plant in particular the second stream could be used for a turbine, or to heat a steam methane reforming unit, or especially, can be used as the feed to a stream methane reforming unit, for example.
  • 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 first membrane may comprise a metal based membrane, and is suitably a palladium based membrane.
  • a metal based membrane is suitably a palladium based membrane.
  • ceramic membranes especially microporous silica based membranes.
  • polymeric membranes such as polyimide, polyaramide, polyetherimide, could be used.
  • the second membrane may be cellulose acetate, a polyimide, a facilitated transport membrane or another type of membrane, e.g. a zeolite silica membrane, a polyalkylene-oxide membrane, an ionic liquid membrane or a hydroxyl appathite membrane.
  • the first membrane may be at a different, especially a higher, temperature compared to the second membrane.
  • the first membrane is at a temperature of between 10-200 °C, preferably 25-120 °C, more preferably 40-100 °C.
  • the second membrane is at a temperature of between 10-200 °C, preferably 25-120 °C, more preferably 40-100 °C.
  • the first membrane may be at a different pressure compared to the second membrane.
  • the first membrane is at a pressure of between 10 and 145 bar, preferably 20-95 bar, more preferably 30-65 bar.
  • the second membrane is at a pressure of between 10 and 150 bar, preferably 20 - 100 bar, more preferably 30 - 70 bar.
  • Chemicals may be added to the membranes to facilitate hydrogen or carbon dioxide transport, for example the second membrane may comprise amines.
  • Chemicals may be added to the first membrane which preferably inhibits carbon dioxide transport. Chemicals may be added to the second membrane which preferably inhibits hydrogen transport.
  • Chemicals may also be added to the gas mixture to inhibit or facilitate hydrogen or carbon dioxide transport, e.g. water to enhance swelling.
  • An advantage of certain embodiments of the invention is that the level of hydrogen contamination in the stream containing carbon dioxide is reduced compared to certain known systems.
  • An advantage of certain embodiments of the invention is that the hydrogen recovered in the first stage can be used as a resource in itself, for example as a fuel gas or, preferably, in a hydrogenation or hydroprocessing facility. Another preferred used of the hydrogen is in the Fischer-Tropsch process, to increase the H2/CO ratio of the syngas.
  • membranes in series may be used to extract the hydrogen and/or carbon dioxide. See for a general description of membrane technology "Basic Principles of Membrane Technology, second edition, Marcel Mulder, Kluwen Academic Publishers, 1996.
  • the synthesis gas is converted into liquid hydrocarbons 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 68th Edition of the Handbook of Chemistry and Physics (CPC Press)) .
  • 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, VIIB and/or VIIIB of - li ⁇
  • the catalyst may comprise a metal promoter selected from Groups VIIB and/or VIII of the Periodic Table.
  • Preferred metal promoters include rhenium, manganese, iron, 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 0.001 to 100 parts by weight per 100 parts by weight of carrier material, preferably 0.05 to 20, more preferably 0.1 to 15. 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 350 0 C, 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.
  • a multi tubular fixed bed reactor is used.
  • Hydrogen and carbon monoxide (synthesis gas) is typically fed to the 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 2.0.
  • 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, wherein off gas from the Fischer-Tropsch process has been used by a process described herein.
  • the hydrocarbon may have undergone the steps of hydroprocessing, preferably hydrogenation, hydroisomerisation and/or hydrocracking.
  • the hydrocarbon may be a fuel, preferably naphtha, kero or gasoil, a waxy raffinate or a base oil.
  • heavy paraffin syntheses (HPS) off gas from a Fischer-Tropsch plant (not shown) is fed to a first membrane 10 where hydrogen is removed.
  • the hydrogen may thereafter be used as a fuel or for other purposes such as used in a hydroprocessing facility of the Fischer-Tropsch plant.
  • the hydrogen depleted stream proceeds to a second membrane 20 where carbon dioxide is removed.
  • the remaining gases can then proceed back to the Fischer- Tropsch plant where they may be used as a fuel gas for example for a turbine or to heat a steam methane reformer .
  • the recovered carbon dioxide stream is recovered at a pressure of 1-20 bara, preferably 5-15 bara which is then directed to a series of gas compressors 11-14. Depending on the pressure of the recovered carbon dioxide, some of the compressors 11-14 may be bypassed. In a preferred embodiment, two or three or even more membranes in series are used. In that way the carbon dioxide may become available at different pressures.
  • the first compressor 11 boosts the carbon dioxide to around 5 bara and so in most cases the carbon dioxide can bypass the first compressor since it is typically recovered at a pressure of at least 5 bara.
  • the second compressor 12 boosts the pressure to around 15 bara and so when the pressure of the recovered carbon dioxide is at least 15 bara, the second compressor 12 can also be bypassed.
  • the third compressor 13 boosts the carbon dioxide to around 50 bara. At this stage the pressurised carbon dioxide may be directed to a dehydration unit 15 and then to a final gas compressor 14 which boosts pressure to around 150 bara.
  • the number of gas compressors and the amount of boosting provided may be varied.
  • the final pressure required of the carbon dioxide should be sufficient to allow it to be injected into a well. In alternative embodiments the pressure required for this can be more than or less than 150 bara, depending on the well pressure.
  • the carbon dioxide can then be injected into a subsurface reservoir in order to enhance the recovery of oil therefrom.
  • the carbon dioxide can then be disposed and sequestrated by injection into a subsurface formation. This provides for the disposal of carbon dioxide without releasing it to the atmosphere. Improvements and modifications may be made without departing from the scope of the invention.
  • the carbon dioxide containing stream to be used in the enhanced oil recovery process of the present invention suitably contains at least 80 vol% of carbon dioxide, preferably 90 vol%, more preferably 96 vol%.
  • the amount of nitrogen is suitably less than 10 vol%, more preferably less than 4%, more preferably less than 2%.
  • EOR process is considerably less than the miscibility of carbon dioxide.
  • Nitrogen is especially suitable for pressure increase of the reservoir, for instance by injection into the gas cap.
  • Carbon dioxide is suitably injected via injection wells at high pressure at 200-1200 meters from the production well directly into the oil containing layer. The carbon dioxide will assist transport of the oil to the production well.
  • Lower hydrocarbons may be present in relatively large amounts, as these compounds will also increase the transport of the oil via a miscible process mechanism
  • C1-C4 hydrocarbon may suitable be present up till 20 vol%, especially 10 vol%.
  • the lower hydrocarbons C1-C4 hydrocarbons
  • the hydrogen stream obtained in the present invention is preferably used in the Fischer-Tropsch process, especially in any hydrochemical upgrading of the products .
  • the carbon dioxide containing stream to be used in the present invention may be combined with other carbon dioxide streams.
  • carbon dioxide made in the SMR-process optionally in combination with a hot and/or cold shift process to convert carbon monoxide and water into hydrogen and carbon dioxide, or carbon dioxide extracted from flue gases, e.g. gas turbine flue gases, boiler furnaces flue gas, and/or (especially) SMR-furnace flue gas, may be used.
  • flue gases e.g. gas turbine flue gases, boiler furnaces flue gas, and/or (especially) SMR-furnace flue gas

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  • General Life Sciences & Earth Sciences (AREA)
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  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)

Abstract

A process for the sequestration of carbon dioxide, the process comprising injecting a carbon dioxide containing stream into a subsurface formation, wherein the carbon dioxide containing stream has been obtained from a gaseous mixture by utilising a first membrane to separate hydrogen within the gaseous mixture, and then utilising a second membrane to separate carbon dioxide within the gaseous mixture. A further aspect of the invention discloses a process for enhanced oil recovery, the process comprising injecting a gaseous mixture comprising carbon dioxide into a subsurface reservoir to enhance the recovery of hydrocarbons from the reservoir, wherein the carbon dioxide content in the gaseous mixture has been enriched by utilising a first membrane to separate hydrogen within the gaseous mixture, and then utilising a second membrane to separate carbon dioxide within the gaseous mixture. Typically a carbon dioxide depleted stream is also produced and used as a feed gas or a fuel gas for a gas to liquids plant.

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 hydrocarbons, especially oil, from a subsurface reservoir by injecting a carbon dioxide containing gas into the reservoir, in combination with the production of hydrocarbons and carbon dioxide from a hydrocarbonaceous stream, especially a natural gas 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, 6th edition, Elsevier, Amsterdam/New York, 1983, p. 91-97. See also the 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 it 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. Especially, the carbon dioxide can dissolve in the hydrocarbons and reduce their viscosity, which enhances the recovery of hydrocarbons from the reservoir. Carbon dioxide can be recovered from a number of sources but the sources are typically impure, containing other gases such as hydrogen, nitrogen, hydrocarbons, especially C1-C4 hydrocarbon, and/or carbon monoxide.
Conventional membranes used to recover carbon dioxide from a mixture of gases containing at least carbon dioxide and hydrogen tend to allow passage of the small hydrogen molecules, thus resulting in a carbon dioxide stream containing a significant amount of hydrogen and so membranes are typically not used to separate carbon dioxide from streams which also contain hydrogen. Although the hydrogen in the carbon dioxide will not substantially interfere with the EOR process, it is generally preferred to use it in a different way, e.g. in a hydroprocessing process or in a hydrocarbon synthesis reaction .
There are environmental limitations on the release of carbon dioxide into the atmosphere. According to a first aspect of the invention, there is provided a process for enhanced oil recovery, the process comprising: injecting a carbon dioxide containing stream into a subsurface reservoir to enhance the recovery of hydrocarbons from the reservoir, wherein the carbon dioxide containing stream has been obtained from a gaseous mixture comprising hydrogen, carbon dioxide and carbon monoxide, optionally C1-C4 hydrocarbons and optionally inerts, by: (i) utilising a first membrane to separate hydrogen from the gaseous mixture; and then,
(ii) utilising a second membrane to separate carbon dioxide from the gaseous mixture, preferably wherein the gaseous mixture comprises heavy paraffin synthesis (HPS) off-gas from a Fischer-Tropsch synthesis process, more preferably a Fischer-Tropsch process using a cobalt based catalyst .
The gaseous mixture is especially heavy paraffin synthesis (HPS) off-gas. Preferably the gaseous mixture is heavy paraffin synthesis (HPS) off-gas from a Fischer- Tropsch hydrocarbon synthesis process, more preferably a cobalt catalyst based Fischer-Tropsch process.
The gaseous mixture may comprise heavy paraffin synthesis (HPS) off-gas. The HPS off-gas will contain a certain amount of unconverted synthesis gas (i.e. carbon monoxide and hydrogen) , carbon dioxide, C1-C4 hydrocarbons (formed in the hydrocarbon synthesis reaction) and, optionally, inerts (mainly nitrogen and some argon) .
In most cases the HPS off-gas will contain 10-40 wt% hydrogen, especially 15-35 vol%, 20-65 vol% Co, especially 30-55 vol%, 10-50 vol% CO2, especially 15-
45 vol% and 10-55 vol% N2, especially 15-50 vol%.
The invention also provides a process for enhanced oil recovery in combination with the production of liquid hydrocarbons from synthesis gas, the process comprising: (a) converting synthesis gas into normally liquid hydrocarbons, normally gaseous hydrocarbons, especially liquefied petroleum gas, and optionally normally solid hydrocarbons at elevated temperatures and pressures, optionally followed by hydroconversion of the hydrocarbons obtained;
(b) recovering heavy paraffin synthesis (HPS) off-gas from said conversion of synthesis gas into normally liquid and gaseous hydrocarbons in step (a) , the off-gas comprising hydrogen, carbon dioxide and carbon monoxide, C]_-C4 hydrocarbons and optionally inerts;
(c) treating the off-gas by utilising a first membrane to separate hydrogen from the gaseous mixture, and then utilising a second membrane to separate carbon dioxide from the gaseous mixture, the second membrane producing a first stream enriched in carbon dioxide and a second stream depleted in carbon dioxide;
(d) recovering hydrocarbons from a subsurface reservoir using at least a portion of the first stream enriched in carbon dioxide produced in step (c) . The term "normally" refers to STP-condition, i.e. 0 0C and 1 bar.
The invention also provides a process for the production of carbon dioxide, the process comprising: (a) obtaining a gaseous mixture comprising heavy paraffin synthesis (HPS) off-gas from a Fischer-Tropsch process, the off-gas comprising hydrogen, carbon dioxide and carbon monoxide, C1-C4 hydrocarbons and inerts, ; (b) utilising a first membrane to separate hydrogen from the HPS off-gas, and then utilising a second membrane to separate carbon dioxide from the HPS off-gas.
The inerts in HPS off-gas are mainly nitrogen and argon. The nitrogen may be present in an amount up till 55 vol%, suitably 15-50 vol%.
The invention also provides a process for the sequestration of carbon dioxide, the process comprising injecting a carbon dioxide containing stream into a subsurface formation, wherein the carbon dioxide containing stream has been obtained from a gaseous mixture, comprising hydrogen, carbon dioxide and carbon monoxide, optionally C1-C4 hydrocarbons and optionally inerts, such as heavy paraffin synthesis (HPS) off-gas, by utilising a first membrane to separate hydrogen from the gaseous mixture, and then utilising a second membrane to separate carbon dioxide from the gaseous mixture.
The hydrocarbonaceous stream to be used in the present invention is suitably 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 compound 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 hydrocarbonaceous stream may also be coal, biomass, residual oil fractions (including tar sand oils), peat, municipal waste etc. The hydrocarbonaceous stream is reacted with oxygen and/or steam to provide synthesis gas, e.g. by means of (catalytic) partial oxidation or by steam/autothermal reforming. Typically the first membrane is adapted to allow the passage of hydrogen but resist the passage of the remaining gases.
Typically the second membrane is adapted to allow the passage of carbon dioxide but resist the passage of the remaining gases.
The HPS off-gas may be at a pressure of between 20 - 100 bar, preferably 40 - 80 bar.
The second stream may be used as fuel gas for a gas to liquids plant in particular the second stream could be used for a turbine, or to heat a steam methane reforming unit, or especially, can be used as the feed to a stream methane reforming unit, for example.
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 first membrane may comprise a metal based membrane, and is suitably a palladium based membrane. Other possibilities are ceramic membranes, especially microporous silica based membranes. Further polymeric membranes, such as polyimide, polyaramide, polyetherimide, could be used.
The second membrane may be cellulose acetate, a polyimide, a facilitated transport membrane or another type of membrane, e.g. a zeolite silica membrane, a polyalkylene-oxide membrane, an ionic liquid membrane or a hydroxyl appathite membrane.
The first membrane may be at a different, especially a higher, temperature compared to the second membrane.
Typically the first membrane is at a temperature of between 10-200 °C, preferably 25-120 °C, more preferably 40-100 °C.
Typically the second membrane is at a temperature of between 10-200 °C, preferably 25-120 °C, more preferably 40-100 °C.
The first membrane may be at a different pressure compared to the second membrane.
Typically the first membrane is at a pressure of between 10 and 145 bar, preferably 20-95 bar, more preferably 30-65 bar.
Typically the second membrane is at a pressure of between 10 and 150 bar, preferably 20 - 100 bar, more preferably 30 - 70 bar. Chemicals may be added to the membranes to facilitate hydrogen or carbon dioxide transport, for example the second membrane may comprise amines.
Chemicals may be added to the first membrane which preferably inhibits carbon dioxide transport. Chemicals may be added to the second membrane which preferably inhibits hydrogen transport.
Chemicals may also be added to the gas mixture to inhibit or facilitate hydrogen or carbon dioxide transport, e.g. water to enhance swelling. An advantage of certain embodiments of the invention is that the level of hydrogen contamination in the stream containing carbon dioxide is reduced compared to certain known systems. An advantage of certain embodiments of the invention is that the hydrogen recovered in the first stage can be used as a resource in itself, for example as a fuel gas or, preferably, in a hydrogenation or hydroprocessing facility. Another preferred used of the hydrogen is in the Fischer-Tropsch process, to increase the H2/CO ratio of the syngas.
Rather than one membrane, also two or more membranes in series may be used to extract the hydrogen and/or carbon dioxide. See for a general description of membrane technology "Basic Principles of Membrane Technology, second edition, Marcel Mulder, Kluwen Academic Publishers, 1996.
Preferably the synthesis gas is converted into liquid hydrocarbons 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 68th 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, VIIB and/or VIIIB of - li ¬
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, manganese, iron, 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 0.001 to 100 parts by weight per 100 parts by weight of carrier material, preferably 0.05 to 20, more preferably 0.1 to 15. 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 350 0C, 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. Preferably a multi tubular fixed bed reactor is used. Hydrogen and carbon monoxide (synthesis gas) is typically fed to the 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 2.0. 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, wherein off gas from the Fischer-Tropsch process has been used by a process described herein.
The hydrocarbon may have undergone the steps of hydroprocessing, preferably hydrogenation, hydroisomerisation and/or hydrocracking.
The hydrocarbon may be a fuel, preferably naphtha, kero or gasoil, a waxy raffinate or a base oil.
An embodiment of the present invention will now be described, by way of example only, with reference to the accompanying figure which is a flow diagram showing a carbon dioxide recovery process.
Referring to Fig. 1, heavy paraffin syntheses (HPS) off gas from a Fischer-Tropsch plant (not shown) is fed to a first membrane 10 where hydrogen is removed. The hydrogen may thereafter be used as a fuel or for other purposes such as used in a hydroprocessing facility of the Fischer-Tropsch plant.
The hydrogen depleted stream proceeds to a second membrane 20 where carbon dioxide is removed. The remaining gases can then proceed back to the Fischer- Tropsch plant where they may be used as a fuel gas for example for a turbine or to heat a steam methane reformer . The recovered carbon dioxide stream is recovered at a pressure of 1-20 bara, preferably 5-15 bara which is then directed to a series of gas compressors 11-14. Depending on the pressure of the recovered carbon dioxide, some of the compressors 11-14 may be bypassed. In a preferred embodiment, two or three or even more membranes in series are used. In that way the carbon dioxide may become available at different pressures. The first compressor 11 boosts the carbon dioxide to around 5 bara and so in most cases the carbon dioxide can bypass the first compressor since it is typically recovered at a pressure of at least 5 bara. The second compressor 12 boosts the pressure to around 15 bara and so when the pressure of the recovered carbon dioxide is at least 15 bara, the second compressor 12 can also be bypassed. The third compressor 13 boosts the carbon dioxide to around 50 bara. At this stage the pressurised carbon dioxide may be directed to a dehydration unit 15 and then to a final gas compressor 14 which boosts pressure to around 150 bara.
In alternative embodiments the number of gas compressors and the amount of boosting provided may be varied. The final pressure required of the carbon dioxide should be sufficient to allow it to be injected into a well. In alternative embodiments the pressure required for this can be more than or less than 150 bara, depending on the well pressure.
The carbon dioxide can then be injected into a subsurface reservoir in order to enhance the recovery of oil therefrom.
Alternatively, the carbon dioxide can then be disposed and sequestrated by injection into a subsurface formation. This provides for the disposal of carbon dioxide without releasing it to the atmosphere. Improvements and modifications may be made without departing from the scope of the invention.
The carbon dioxide containing stream to be used in the enhanced oil recovery process of the present invention suitably contains at least 80 vol% of carbon dioxide, preferably 90 vol%, more preferably 96 vol%. The amount of nitrogen is suitably less than 10 vol%, more preferably less than 4%, more preferably less than 2%. The miscibility of nitrogen in the oil fraction in the
EOR process is considerably less than the miscibility of carbon dioxide. Nitrogen is especially suitable for pressure increase of the reservoir, for instance by injection into the gas cap. Carbon dioxide is suitably injected via injection wells at high pressure at 200-1200 meters from the production well directly into the oil containing layer. The carbon dioxide will assist transport of the oil to the production well. Lower hydrocarbons may be present in relatively large amounts, as these compounds will also increase the transport of the oil via a miscible process mechanism C1-C4 hydrocarbon may suitable be present up till 20 vol%, especially 10 vol%. It is observed that from a technical point (high H/C ratio) as from an economical point, it is preferred to use the lower hydrocarbons (C1-C4 hydrocarbons) in the hydrocarbon synthesis process, for instance as feed to the syngas manufacturing unit, or, preferably, as feed for the manufacture of hydrogen. Also the hydrogen stream obtained in the present invention is preferably used in the Fischer-Tropsch process, especially in any hydrochemical upgrading of the products .
The carbon dioxide containing stream to be used in the present invention may be combined with other carbon dioxide streams. For instance carbon dioxide made in the SMR-process, optionally in combination with a hot and/or cold shift process to convert carbon monoxide and water into hydrogen and carbon dioxide, or carbon dioxide extracted from flue gases, e.g. gas turbine flue gases, boiler furnaces flue gas, and/or (especially) SMR-furnace flue gas, may be used.

Claims

C L A I M S
1. A process for enhanced oil recovery, the process comprising: injecting a carbon dioxide containing stream into a subsurface reservoir to enhance the recovery of hydrocarbons from the reservoir, wherein the carbon dioxide containing stream has been obtained from a gaseous mixture comprising hydrogen, carbon dioxide and carbon monoxide, optionally C1-C4 hydrocarbons and optionally inerts, by: (i) utilising a first membrane to separate hydrogen from the gaseous mixture; and then,
(ii) utilising a second membrane to separate carbon dioxide from the gaseous mixture.
2. A process according to claim 1, wherein the gaseous mixture comprises heavy paraffin synthesis (HPS) off-gas from a Fischer-Tropsch synthesis process, preferably a Fischer-Tropsch process using a cobalt based catalyst.
3. A process for enhanced oil recovery in combination with the production of liquid hydrocarbons from synthesis gas, the process comprising:
(a) converting synthesis gas into normally liquid hydrocarbons, normally gaseous hydrocarbons, especially liquefied petroleum gas, and optionally normally solid hydrocarbons at elevated temperatures and pressures, optionally followed by hydroconversion of the hydrocarbons obtained;
(b) recovering heavy paraffin synthesis (HPS) off-gas from said conversion of synthesis gas into normally liquid and gaseous hydrocarbons in step (a) , the off-gas comprising hydrogen, carbon dioxide and carbon monoxide, C]_-C4 hydrocarbons and optionally inerts;
(c) treating the off-gas by utilising a first membrane to separate hydrogen from the gaseous mixture, and then utilising a second membrane to separate carbon dioxide from the gaseous mixture, the second membrane producing a first stream enriched in carbon dioxide and a second stream depleted in carbon dioxide;
(d) recovering hydrocarbons from a subsurface reservoir using at least a portion of the first stream enriched in carbon dioxide produced in step (c) .
4. A process as claimed in any preceding claim, wherein the first membrane is adapted to allow the passage of hydrogen but resist the passage of the remaining gases, preferably wherein the first membrane comprises a metal based membrane such as a palladium based membrane or wherein the first membrane comprises a ceramic membrane, especially a microporous silica based membrane.
5 A process as claimed in any preceding claim, wherein the second membrane is adapted to allow the passage of carbon dioxide but resist the passage of the remaining gases .
6. A process as claimed in claim any preceding claims, wherein the gaseous mixture containing carbon dioxide stream or the HPS off-gas is at a pressure of between 20-100 bar, preferably 40-80 bar.
7. A process as claimed in any one of claims 3 to 6, wherein the second stream is used as feed gas or fuel gas, especially for a gas to liquids plant.
8. A process as claimed in any preceding claim, wherein the first membrane is at a temperature of between 10- 150 °C, preferably 25-120 °C, more preferably 40-100 0C and at a pressure of between 10 and 150 bar, preferably 20-100 bar, more preferably 30-70 bar
9. A process as claimed in any preceding claim, wherein the second membrane is at a temperature of between 10- 150 °C, preferably 25-120 °C, more preferably 40-100 0C at a pressure of between 10 and 145 bar, preferably 20-95 bar, more preferably 30-65 bar.
10. A process as claimed in any preceding claim, wherein carbon dioxide from the reservoir is produced with the hydrocarbons and at least a portion of the carbon dioxide produced is reinjected into the reservoir.
PCT/EP2006/070053 2005-12-30 2006-12-21 Enhanced oil recovery process and a process for the sequestration of carbon dioxide WO2007077138A1 (en)

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