WO2007077139A2

WO2007077139A2 - A process for enhanced oil recovery in combination with the production of hydrocarbons from synthesis gas

Info

Publication number: WO2007077139A2
Application number: PCT/EP2006/070054
Authority: WO
Inventors: Eduard Coenraad Bras; Intan Augustina Ambari
Original assignee: Shell Internationale Research Maatschappij B.V.
Priority date: 2005-12-30
Filing date: 2006-12-21
Publication date: 2007-07-12
Also published as: WO2007077139A3

Abstract

A process for enhanced oil recovery in combination with the production of hydrocarbons from synthesis gas, 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 cryogenic separation of the off-gas recovered from said conversion of synthesis gas into liquid hydrocarbons. Typically a carbon dioxide depleted stream including methane and hydrogen is also produced and used as a fuel gas, particularly for a gas to liquids plant.

Description

A PROCESS FOR ENHANCED OIL RECOVERY 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, 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 1-55563-10-3), Chapters 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. Moreover, the carbon dioxide can dissolve in the hydrocarbons and reduce their viscosity, which also 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 hydrocarbons and carbon monoxide.

One process for separating carbon dioxide from a mixture of gases containing carbon dioxide is a Ryan/Holmes cryogenic separation configuration. Whilst this process can recover around 80% of the carbon dioxide from a carbon dioxide containing stream, the process requires a significant amount of refrigerant and a number of compression steps which consume energy.

There are environmental limitations on the release of carbon dioxide into the atmosphere. According to an 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 by cryogenic separation.

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 (formal 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 hydrocarbons from synthesis gas, the process comprising: a) converting synthesis gas into normally liquid hydrocarbons, and optionally solid hydrocarbons and normally gaseous hydrocarbons as liquefiable petroleum gas, at elevated temperatures and pressures, preferably in a Fischer-Tropsch process; (b) recovering off-gas from said conversion of synthesis gas into liquid hydrocarbons in step (a) , said off gas being a gaseous mixture containing hydrogen, carbon monoxide and carbon dioxide;

(c) treating the off-gas by cryogenic separation in a first distillation unit to produce a first stream enriched in carbon dioxide and a second stream depleted in carbon dioxide, wherein the carbon dioxide depleted stream includes methane and hydrogen and wherein the carbon dioxide enriched stream exits the first distillation unit from the warmer end of said unit;

(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" relates to STP-conditions, i.e. 0 ⁰C and 1 bar.

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, such as heavy paraffin synthesis (HPS) off-gas, by cryogenic separation. 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 can be used for gas turbines or as a fuel gas in an SMR furnace. The second stream may also be used as feedgas for the preparation of synthesis gas and/or hydrogen.

Sequestration in a subsurface formation is typically when the 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. Typically the process of cryogenic separation comprises distilling the gaseous mixture in a first distillation unit to produce a first stream enriched in carbon dioxide and a second stream depleted in carbon dioxide .

The gaseous mixture may be separated into a plurality of streams before it enters the first distillation unit. For example the gaseous mixture may be separated into three streams of differing temperature, the first coldest stream entering the first distillation unit as a gas, towards an upper end of the first distillation unit. The second stream may enter as a liquid, below the second stream but above the third stream. The third, relatively warm, stream may enter the first distillation unit towards the bottom thereof, below the first and second streams .

To generate additional power, an expander may be provided for the first stream before it enters the first distillation unit.

Preferably the pressure in the first distillation unit is between 15 and 25 bar, preferably around 20 bar. Preferably the temperature of the first distillation unit ranges from between -24 ⁰C to -4 ⁰C, preferably approximately -14 ⁰C at the bottom of the unit to between -66 ⁰C to -46 ⁰C, preferably approximately -56 ⁰C at the top of the unit.

Preferably the carbon dioxide depleted stream comprises a mixture of gases typically including methane and hydrogen and also sometimes containing carbon monoxide, nitrogen and some carbon dioxide. Preferably the carbon dioxide depleted stream exits the first distillation unit from the top of the first distillation unit. Thus preferably light end gases (including hydrogen, nitrogen and methane) are removed in a first distillation unit. Optionally additional power may be generated using an expander, for example said light end gases removed from the first distillation unit may then proceed through an expander . Preferably the carbon dioxide enriched stream exits the first distillation unit from the bottom of the unit.

Preferably the carbon dioxide enriched stream proceeds to a second distillation unit.

Preferably the carbon dioxide enriched stream is not cooled further between the first and second distillation units. Preferably the carbon dioxide enriched stream is heated between the first and second distillation units. The heating of the carbon dioxide enriched stream may be done, in part at least, by a heat exchanger. Preferably the carbon dioxide enriched stream is not compressed between the first and second distillation units .

Typically the carbon dioxide enriched stream also comprises C2+ hydrocarbons. Preferably the second distillation unit enriches the carbon dioxide stream further, typically by removing at least a portion of the C2+ content of the carbon dioxide enriched stream.

Thus preferably said light end gases are removed upstream of where the carbon dioxide is separated from C2+ hydrocarbons, especially C3₊ hydrocarbons.

Preferably the pressure in the second distillation unit is between 12 and 22 bar, preferably around 17 bar.

Preferably the temperature of the second distillation unit ranges from between 73 ⁰C to 93 ⁰C, preferably approximately 83 ⁰C at the bottom of the unit to between -33 ⁰C to -13 ⁰C, preferably approximately -23 ⁰C at the top of the unit. Preferably the further enriched carbon dioxide stream exits the second distillation unit from the top of said distillation unit.

Thus preferably the further enriched carbon dioxide stream exits the second distillation unit as a gas.

Typically the further enriched carbon dioxide stream is injected into a subsurface reservoir to enhance the recovery of oil from the reservoir.

Preferably a gaseous mixture comprising C2+ hydrocarbons exits from the bottom of the second distillation unit. Preferably the mixture containing C2+ hydrocarbons from the second distillation unit proceeds to a third distillation unit. Preferably the pressure in the third distillation unit is between 5 and 10 bar, preferably around 7.5 bar. Preferably the temperature of the third distillation unit ranges from between 62 ⁰C to 82 ⁰C, preferably approximately 72 ⁰C at the bottom of the unit to between 8 ⁰C to 28 ⁰C, preferably approximately 18 ⁰C at the top of the unit.

Preferably the third distillation unit separates the mixture containing C2+ hydrocarbons to a mixture enriched in C2 and C3 hydrocarbons and a mixture enriched in C4+ hydrocarbons.

Preferably the stream enriched in C2 and C3 hydrocarbons exits the third distillation unit at the top of the third distillation unit and preferably the stream containing the C4₄. hydrocarbons exits the third distillation unit at the bottom of the third distillation unit .

Preferably a distillation unit which separates carbon dioxide from light end gases (for example hydrogen and methane) , such as the first distillation unit, receives a product stream from one of the other distillation units, the product stream acting as a wash to encourage the separation of carbon dioxide from light end gases. Preferably a portion of the stream enriched in C2 and

C3 hydrocarbons is used as a wash in one of the upstream distillation units.

More preferably a distillation unit which separates carbon dioxide from light end gases, such as the first distillation unit, receives a portion of the stream enriched in C2 and C3 hydrocarbons to encourage the separation of carbon dioxide from light end gases.

The mixture enriched in C4+ hydrocarbons may be added to an upstream distillation unit, typically the distillation unit which separates the carbon dioxide from the C2+ hydrocarbons, such as the second distillation unit .

A portion of either the C2 and C3 enriched stream or the C4₄. enriched stream may be used as a fuel gas for a gas to liquids plant in particular the second stream could be used for gas turbines or as a fuel gas in an SMR furnace .

Preferably at least one of the temperature and pressure in the second distillation unit is different compared to the temperature and pressure of the first distillation unit.

Preferably at least one of the temperature and pressure in the third distillation unit is different compared to the temperature and pressure of the second distillation unit.

Preferably each successive distillation unit operates at a reduced pressure compared to the previous unit. 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 C5₄. 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 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 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.

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, 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 naptha, kero or gasoil, a waxy raffinate or a base oil. An embodiment of the present invention will now be described, with reference to the accompanying figures, in which:

Fig. 1 is a diagrammatic view of a known Ryan Holmes cryogenic separating plant;

Fig. 2 is a diagrammatic view of a cryogenic separating plant in accordance with one aspect of the present invention.

A conventional Ryan Holmes process is shown in Fig. 1. A gaseous mixture containing carbon dioxide is compressed and dehydrated before being injected into an ethane recovery unit 11 which cryogenically distils the C2+ hydrocarbons from the remaining mixture. The C2+ hydrocarbons proceed from the bottom of the ethane recovery unit 11 to a fourth vessel, being an additive recovery unit 14, described in more detail below.

Meanwhile the remaining gases, including the carbon dioxide, exit from the top, colder end, of the ethane recovery unit 11, are compressed and chilled further before entering a carbon dioxide recovery unit 12.

The carbon dioxide recovery unit 12 cryogenically distils out liquid carbon dioxide which exits from the warmer bottom end of the unit 12 for further use. The remaining gases, which may still contain some carbon dioxide, proceed to a demethaniser 13.

In the demethaniser 13, methane is distilled out from the top of the demethaniser 13 leaving the remaining gases to proceed from the bottom of the demethaniser 13 back to the ethane recovery unit 11 to start the process again.

Referring back to the additive recovery unit 14, a gaseous mixture of C2+ hydrocarbons is received from the ethane recovery unit 11. By distillation, C4₄. hydrocarbons are removed from the bottom of the additive recovery unit 14. Some of this stream may be recycled to the ethane recovery unit 11 or demethaniser 13.

A cryogenic separating plant 20 in accordance with one aspect of the present invention is shown in Fig. 2. A gaseous mixture of heavy paraffin synthesis (HPS) off- gas is received from a HPS unit (not shown) at a pressure of 50 - 60 bar and a temperature of 50 - 60 ⁰C. The HPS off-gas contains carbon dioxide, carbon monoxide, hydrogen, nitrogen, and C2+ hydrocarbons. This mixture proceeds through a cold separator 24 and, in three separate streams, enters a first cryogenic distillation unit 21. The upper stream may enter at between -83 ⁰C to -63 ⁰C, preferably approximately -73 ⁰C. The middle stream may enter at between -66 ⁰C to -46 ⁰C, preferably approximately -56 ⁰C. The lower stream may enter at between -60 ⁰C to -40 ⁰C, preferably approximately -50 ⁰C.

An advantage of certain embodiments of the invention is that the HOG received, being at a higher pressure, requires less cooling than an equivalent gaseous mixture received at ambient pressure.

The cold separator 24 typically comprises a number of sub-components (not shown) . One embodiment comprises two coolers and two separators. The HOG mixture is cooled in a first cooler and then enters a first separator where it is separated into a gaseous stream and a liquid stream. The liquid stream is the lower stream which enters the first cryogenic distillation unit 21 as described above. The gaseous stream passes through a further cooler and then a further separator to condense some more of the stream into liquid. The liquids from this stream enter the first cryogenic distillation unit 21 as the middle stream as described above. The gaseous stream enters the first cryogenic distillation unit 21 as the upper stream, also as described above. An expander may be provided for the gaseous stream between said further separator and the first cryogenic distillation unit 21. External refrigerant may also be used to cool the various streams.

The cooler between the first separator and second separator may be a heat exchanger which receives the relatively cold evaporated gases from the first cryogenic distillation unit 21.

Operating at a pressure of between 15 and 25 bar, preferably 20 bar, the first cryogenic distillation unit 21 separates carbon dioxide and C2+ hydrocarbons from the rest of the gaseous mixture. The remaining gases proceed out of the colder top end of the distillation unit 21 and may pass through an expander (not shown) and then said heat exchanger to cool gas entering the first cryogenic unit 21. Thereafter they may be used as a fuel gas for gas turbines or an SMR furnace for example. The carbon dioxide and C2+ hydrocarbons (especially C3₊ hydrocarbons) proceed from the warmer, bottom end of the distillation unit 21 to a second cryogenic distillation unit 22.

The second cryogenic distillation unit 22, which receives the mixture of carbon dioxide and C2+ hydrocarbons, operates at a pressure of between 12 and 22 bar, preferably approximately 17 bar. Carbon dioxide is separated from the C2+ hydrocarbons and proceeds from the colder upper end of the cryogenic distillation unit 22 to a compressor 31 described in more detail below. The remaining gases proceed from the bottom of the distillation unit 22 to a depropaniser 23. In the depropaniser 23, the C2 and C3 hydrocarbons are removed from the top of the distillation unit 23 and a portion of them are first cooled and then proceed to the first cryogenic distillation unit 21. C4₄. hydrocarbons exit the bottom of the distillation unit 23 and may be used as a fuel gas for a Fischer Tropsch plant, for example for a gas turbine or to heat a steam methane reformer. Some of the C4+ hydrocarbons are cooled and then recycled back to the second distillation unit 22.

The carbon dioxide recovered from the second distillation unit 22 is at a pressure of around 17 bar. Typically its pressure must be increased before in can be used for enhanced oil recovery - so that it is of a sufficient pressure to displace oil in the reservoir. The carbon dioxide stream thus proceeds to a first compressor 31 which increases the pressure to around 50 bar. The carbon dioxide is then dehydrated in a dehydration unit 33 before proceeding to a second compressor 32 where the pressure is increased to approximately 150 bar. The carbon dioxide can then be injected into a reservoir for use in enhanced oil recovery. Any combination of compressors may be used to provide the sufficiently pressurised carbon dioxide and it will be appreciated that the required pressure can vary from reservoir to reservoir.

For certain embodiments of the invention, the carbon dioxide can be sequestrated in a reservoir, that is injected into a reservoir from which no further production is planned. This allows the disposal of carbon dioxide without releasing it to the atmosphere.

An advantage of certain embodiments of the invention is that no compression is required to separate the carbon dioxide after the mixture has entered a first cryogenic distillation unit (although compression is typically required once the carbon dioxide stream has been separated. ) An advantage of certain embodiments of the invention is that the light end gases, including carbon monoxide, hydrogen, methane and some inerts such as nitrogen, are removed at a relatively early stage, typically the first distillation unit, thus reducing the amount of gases which flow through the process. In contrast with the Ryan Holmes configuration, such light end gases proceed to a third distillation unit before being removed.

An advantage of certain embodiments of the invention is that the carbon dioxide is recovered as a gas whereas for certain known systems of cryogenic distillation, such as the Ryan Holmes system, the carbon dioxide is recovered as a liquid.

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 40 vol%, 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. 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.

Improvements and modifications may be made without departing from the scope of the invention.

Claims

C L A I M S

1. A process for enhanced oil recovery in combination with the production of hydrocarbons from synthesis gas, the process comprising: a) converting synthesis gas into normally liquid hydrocarbons and normally gaseous hydrocarbons as liquefiable petroleum gas and optionally solid hydrocarbons, at elevated temperatures and pressures, preferably in a Fischer-Tropsch process;

(b) recovering off-gas from said conversion of synthesis gas into liquid hydrocarbons in step (a) , said off gas being a gaseous mixture containing hydrogen, carbon monoxide and carbon dioxide;

(c) treating the off-gas by cryogenic separation in a first distillation unit to produce a first stream enriched in carbon dioxide and a second stream depleted in carbon dioxide, wherein the carbon dioxide depleted stream includes methane and hydrogen and wherein the carbon dioxide enriched stream exits the first distillation unit from the warmer end of said unit; (d) recovering hydrocarbons from a subsurface reservoir using at least a portion of the first stream enriched in carbon dioxide produced in step (c) .

2. A process as claimed in claim 1, wherein the second stream is used as fuel gas, especially for a gas to liquids plant, or as feedgas for the preparation of synthesis gas and/or hydrogen.

3. A process as claimed in any one of claims 1 to 2, wherein the HPS off-gas is at a pressure of between 20 - 100 bar, preferably 40 - 80 bar.

4. A process as claimed in any one of claims 1-3, wherein the pressure in the first distillation unit is between 15 and 25 bar, preferably around 20 bar and wherein the temperature of the first distillation unit ranges from between -24 ⁰C to -4 ⁰C, preferably approximately -14 ⁰C at the bottom of the unit to between -66 ⁰C to -46 ⁰C, preferably approximately -56 ⁰C at the top of the unit.

5. A process as claimed in any one of claims 1 to 4, wherein the carbon dioxide enriched stream proceeds to a second distillation unit and is preferably not cooled between the first and second distillation units.

6. A process as claimed in claim 5, wherein the carbon dioxide enriched stream also comprises C2+ hydrocarbons and the second distillation unit enriches the carbon dioxide stream further by removing at least a portion of the C2+ content of the carbon dioxide enriched stream.

7. A process as claimed in claim 5 or 6, wherein the pressure in the second distillation unit is between 12 and 22 bar, preferably around 17 bar and wherein the temperature of the second distillation unit ranges from between 73 ⁰C to 93 ⁰C, preferably approximately 83 ⁰C at the bottom of the unit, to between -33 ⁰C to -13 ⁰C, preferably approximately -23 ⁰C at the top of the unit.

8. A process as claimed in any one of claims 5 to 7, wherein the further enriched carbon dioxide stream exits the second distillation unit from a colder end of said distillation unit as a gas and wherein a mixture comprising C2+ hydrocarbons exits from a warmer end of the second distillation unit and proceeds to a third distillation unit.

9. A process as claimed in claim 8, wherein the pressure in the third distillation unit is between 5 and 10 bar, preferably around 7.5 bar and wherein the temperature of the third distillation unit ranges from between 62 ⁰C to 82 ⁰C, preferably approximately 72 ⁰C at the bottom of the unit to between 8 ⁰C to 28 ⁰C, preferably approximately 18 ⁰C at the top of the unit.

10. A process as claimed in claim 8 or 9, wherein the third distillation unit separates the mixture containing C2+ hydrocarbons to a mixture enriched in C2+3 hydrocarbons and a mixture enriched in C4+ hydrocarbons.

11. A process as claimed in claim 10, wherein at least one of the C2+3 enriched stream and the C4₄. enriched stream is used as a fuel gas, especially for a gas to liquids plant or as feed in the preparation of synthesis gas and/or hydrogen.

12. A process as claimed in claim 1 or 11, wherein a portion of the stream enriched in C2 and C3 hydrocarbons is used as a wash fluid in an upstream distillation unit.

13. A process as claimed in any one of claims 5 to 12, wherein the first distillation unit receives a portion of a product stream received from a colder upper end of another distillation unit, such as the third distillation unit, the product stream acting as a wash fluid to encourage the separation of carbon dioxide from hydrogen and from methane.

14. A process as claimed in any one of claims 8 to 13, wherein the second distillation unit receives a portion of a product stream from another distillation unit, such as the third distillation unit, the product stream acting as a wash fluid to encourage the separation of C2+ components from carbon dioxide.

15. A hydrocarbon synthesised by a Fischer Tropsch process, wherein off gas from the Fischer Tropsch process has been used by a process as claimed in any one of claims 1 to 14, preferably a hydrocarbon which has undergone the steps of hydroprocessing, preferably hydrogenation, hydroisomerisation and/or hydrocracking.