CA2620734C

CA2620734C - Method of producing a hydrocarbon stream from a subterranean zone

Info

Publication number: CA2620734C
Application number: CA2620734A
Authority: CA
Inventors: Hendrik Jan Van Der Ploeg; Thian Hoey Tio; Pieter Lammert Zuideveld
Original assignee: Shell Canada Ltd
Current assignee: Shell Canada Ltd
Priority date: 2005-09-21
Filing date: 2006-09-19
Publication date: 2014-04-22
Anticipated expiration: 2026-09-19
Also published as: WO2007039443A1; JP2009508977A; CA2620734A1; EP1926885A1; CN101268250B; RU2412340C2; JP5468260B2; CN101268250A; RU2008115427A

Abstract

The present invention relates to a method of producing a hydrocarbon containing stream (110) from a subterranean zone (100) wherein an injection fluid (50) is injected into the subterranean zone (100), the method at least comprising the steps of: (a) providing an injection fluid (50) comprising synthesis gas; (b) injecting the injection fluid (50) into a subterranean zone (100) for obtaining a desired pressure therein; (c) obtaining a hydrocarbon containing stream (110) from the subterranean zone (100).

Description

- I -ME T HOD OF PRODUCING A HYDROCARBON STREAM FROM A
SUBTERRANEAN ZONE
The present invention relates to a method of producing a hydrocarbon containing stream from a subterranean zone wherein an injection fluid is injected into the subterranean zone.
It is known to inject an injection fluid into a subterranean zone such as an oil or gas field in order to maintain a desired pressure therein to improve the production of the desired hydrocarbon stream from the subterranean zone. In case oil is the hydrocarbon stream to be produced from an oil field, this is called 'enhanced oil recovery' (also known as 'EOR'). Injection fluids that have been proposed to inject in an oil field for EOR are a.o. natural gas (NG), carbon dioxide (CO2) and nitrogen (N2). The injection of injection fluids such as NG, CO2 and N2 in an oil field has been described in e.g. <<World's Largest N2-generation Plant, Commissioned for Cantarell Pressure Maintenance>>, J.C. Kuo, Doug Elliot, Javier Luna-Melo, Jose B. De Leon Perez, published in Oil & Gas Journal, March 12, 2001. Other publications which describe the use of such injection fluids are for example CA-A-2147079, CA-A-2261517, CA-A-2163684 and US-A-4161047.
The above and other known injection fluids have several disadvantages. Natural gas as such has become too expensive to be used for injection. Also the usual method for the production of nitrogen using an Air Separation Unit (ASU) is relatively expensive.
A further problem is that the known injection fluids are often available at low pressures and as a result a Pr!nted 01 /081200Z SCPAM D
EP260.60664*
- / Z 04.

compression step is necessary before injection into t(;:e) oil field, leading to additional costs.
US-A-4512400 describes a process to make a LPG type injection fluid from natural gas. In this process natural gas is first converted into a mixture of carbon monoxide and hydrogen and secondly this gas mixture is used as feed in a Fischer-Tropsch synthesis. From the synthesis product an ethane, propane and butane containing gas, i.e. the LPG type gas, is isolated and used as injection fluid.
EP-A-1004746 describes a process for performing an enhanced oil recovery by partial oxidation of an associated gas into a mixture of carbon monoxide and hydrogen. This mixture is used as feed in a Fischer-Tropsch synthesis to obtain a liquid hydrocarbon product and an off-gas. This off-gas will contain nitrogen, carbon monoxide, carbon dioxide, hydrogen and C1-05 hydrocarbons. This off-gas is used as fuel to generate energy in an expanding/combustion process, e.g. a combined gas turbine/steam turbine cycle. The energy generated is in turn used for the secondary and/or enhanced recovery of oil from a subsurface reservoir.
A disadvantage of the process of US-A-4512400 and EP-A-1004746 is that a Fischer-Tropsch process step is part of the method. Such a process step makes the method complex.
US-A-3150716 describes a method for producing a hydrocarbon stream from a subterranean zone wherein an injection fluid is used comprising synthesis gas. The injection fluid is obtained by catalytically converting, i.e. steam reforming, methane and steam to a synthesis gas mixture.
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AMENDED SHEET

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- 2a -US-A-4434852 describes the preparation of an injection fluid. The injection fluid is a flue gas, which may be obtained in a boiler or internal combustion engine.
In Chenglin Zhu et al., An EOR application at Liaohe Oil field in China, Test for pumping Boiler Flue Gas into Oil Wells, Paper at First National Conference on Carbon Sequestration, May 15-17, 2001, Washington DC, USA flue gas as obtained in a fired boiler is described as injection fluid.
A disadvantage of using a flue gas is that the oxygen content of the directly obtained flue gas is about G:\OA\TS1714PCT
AMENDED SHEET
=IY1Q4/20071 ".44,r fluid. Special measures have to be taken to lower the oxygen content.
The above problems are even more pertinent if huge amounts of the injection fluid are required.
It is an object of the present invention to at least minimize one of the above problems.
It is a further object to provide an alternative method of producing an injection fluid for injection in a subterranean zone such as an oil or gas field.
One or more of the above or other objects can be achieved according the present invention by providing a method of producing a hydrocarbon containing stream from a subterranean zone wherein an injection fluid is injected into the subterranean zone, the method at least comprising the steps of:
(a) providing an injection fluid comprising synthesis gas;
(b) injecting the injection fluid into a subterranean zone for obtaining a desired pressure therein;
(c) obtaining a hydrocarbon containing stream from the subterranean zone.
It has been surprisingly found that according to the present invention the production of the hydrocarbon containing stream from the subterranean zone can be performed in an economic manner, in particular if large amounts of injection fluid are desired.
A further advantage of the present invention is that the injection fluid will be substantially free of free oxygen (02), as a result of the presence of the synthesis gas.
The hydrocarbon stream to be produced from the subterranean zone may have various compositions, but will usually be natural gas, gas condensate, oil, also referred to as crude mineral oil, or a mixture thereof.

The subterranean zone may be any subterranean zone comprising hydrocarbons to be harvested. Examples of a subterranean zone are e.g. an oil field, gas field, etc.
It goes without saying that the subterranean zone may also be located underwater or the like.
The injection fluid may be produced in various manners, e.g. by catalytic or non-catalytic partial oxidation or by any other way, provided that it comprises synthesis gas (i.e. carbon monoxide (CO) and hydrogen (H2)).
The injection of an injection fluid and the associated production of the hydrocarbon stream from the subterranean zone is known as such and for example described in the references discussed in the introductory part of this disclosure. The desired pressure to be obtained in the subterranean zone will depend on the circumstances and can be readily determined by the person skilled in the art. Usually, it is desired to maintain the existing pressure in the subterranean zone;
therefore, the term "obtaining a desired pressure" also includes maintaining a certain pressure in the subterranean zone.
Preferably, the injection fluid comprises from 0.1 to 20 mol% synthesis gas (i.e. CO + H2) based on dry gas, preferably > 3 mol% and < 10 mol%, more preferably about 5 mol%.
Further it is preferred that the injection fluid comprises, based on dry gas:
- from 0.1 to 20 mol% synthesis gas, preferably > 3 mol% and < 10 mol%, more preferably about 5 mol%;
- from 5 to 20 mol% CO2, preferably from 10 to 20 mol% and even more preferably from 12 to 15 mol%;
- from 70 to 90 mol% N2, preferably from 80 to 90 mol%.

Advantageously, the injection fluid provided in step (a) is substantially free of 02, preferably comprising less than 10 ppmv.
Further it is preferred that the injection fluid at injection has a pressure in the range from 50 to 500 bar, preferably > 70 bar and < 400 bar, more preferably > 80 bar and < 300 bar; and a temperature in the range from 0 to 300 C, preferably > 20 C and < 100 C.
The injection fluid is preferably made from a hydrocarbon stream. This hydrocarbon stream may be isolated from the hydrocarbon stream to be produced from the subterranean zone. Alternatively this hydrocarbon stream may be derived from another source. In order to avoid any confusion this hydrocarbon stream is further referred to as the carbonaceous synthesis gas source. The synthesis gas may in general be made from one or more carbonaceous synthesis gas sources using one or more conversion processes. Examples of suitable carbonaceous synthesis gas sources are natural gas, LPG, coal, brown coal, peat, wood, coke, soot, biomass, oil, condensate or any other gaseous, liquid or solid fuel or mixture thereof. Preferred carbonaceous synthesis gas sources are part of the hydrocarbon containing stream produced from the subterranean zone. Examples of such sources are natural gas when producing a natural gas hydrocarbon and more especially associated gas when producing a crude oil hydrocarbon. In case of a gaseous feed, especially gaseous feeds comprising methane, the preferred conversion processes are steam reforming, suitably auto thermal steam reforming (ATR), catalytic partial oxidation and preferably by a partial oxidation process, more preferably by a non-catalytic partial oxidation process. The non-gaseous carbonaceous sources, like for example coal, peat, wood, petroleum coke, soot, biomass, oil, de-asphalted oil, cracked vacuum residue and gas condensate, are preferably converted to synthesis gas by means of a partial oxidation process.
The partial oxidation may be performed in one or more partial oxidation steps in order to increase the volume percentage of nitrogen and carbon dioxide relative to the amount of carbonaceous synthesis gas source used.
In another aspect, the present invention provides a method of producing an injection fluid, the method at least comprising:
(al) providing a synthesis gas containing stream; and (a2) partially oxidising the synthesis gas containing stream provided in step (al), thereby obtaining an injection fluid comprising synthesis gas.
It has been surprisingly found that, by partially oxidising a synthesis gas stream, a huge amount of suitable injection fluid can be obtained in a relatively economic manner.
A further advantage is that the stream obtained in step (a2) is available at relatively high pressures such that the stream obtained has a pressure suitable to be injected directly or after further compression in an oil field or other subterranean zone. As a result, less costs for compression have to be made before injection in an oil field. In some cases a subsequent compression step may even be dispensed with.
The synthesis gas containing stream provided in step (al) may be a partially oxidised stream, but may also be obtained in any other suitable way. Anyway, the 'synthesis gas containing stream' provided in step (al) contains more synthesis gas (preferably > 25 mol%, based on dry gas) than the 'injection fluid' obtained in step (a2) (preferably from 0.1 to 20 mol% based on dry gas). If desired more than two partial oxidation steps may take place, if desired.

As an example the synthesis gas containing stream provided in step (al) may be obtained from a carbonaceous synthesis gas source as described above.
Preferably, the synthesis gas containing stream provided in step (al) is obtained by partial combustion, i.e. partially oxidising a hydrocarbon stream, preferably selected from the group consisting of oil, gas and coal, more preferably gas. The latter is frequently available at an oil field, in the form of associated gas, in which the injection fluid is to be injected for producing oil.
As methods for producing synthesis gas are well known from practice, this is not further discussed here. An advantage of using natural gas or associated gas as feed for step (al) is that these feeds are obtained from the subsurface reservoir at high pressures. This allows this feed to be used without less or no compression as feed to the partial oxidation as performed at elevated pressure.
Preferably the synthesis gas containing stream provided in step (al) comprises > 25 mol% synthesis gas based on dry gas, preferably from 30 to 50 mol%, more preferably from 30 to 40 mol%.
Further it is preferred that the synthesis gas containing stream provided in step (al) has a pressure in the range from 20 to 200 bar, preferably > 40 bar and < 100 bar; and a temperature in the range from 100 to 400 C, preferably > 200 C and < 350 C.
It is preferred that the synthesis gas containing stream provided in step (al) is also obtained by partially oxidising a hydrocarbon stream. Preferably the partial oxidation in both steps (al) and (a2) are obtained by non-catalytic partial oxidation, i.e. partial combustion. The advantage of more than one partial oxidation step to obtain the injection fluid (compared to one partial oxidation step) is that the temperature of the process can be better controlled.

If desired, the synthesis gas containing stream obtained in step (al) may be cooled before partially oxidising it in step (a2). If in step (al) non-catalytic partial oxidation is used, any free 02 containing stream may be used. In step (a2) preferably air or oxygen-enriched air is used, preferably containing at least 70%
N2.
In a further preferred embodiment step (a2) is performed by recycling part of the synthesis gas containing stream obtained in step (al) back to step (al). Preferably the recycle synthesis gas is reduced in temperature before being recycled. Preferably 1 to mol% is recycled to step (al), wherein the recycle is calculated as the mol fraction recycle stream on the 15 total injection fluid prepared by the process times 100%.
Preferably the injection fluid obtained in step (a2) or in case of a recycle embodiment in the combined steps (al) and (a2) has a pressure in the range from 20 to 200 bar, preferably > 50 bar and < 80 bar; and is cooled 20 to a temperature in the range from 0 to 300 C, preferably > 20 C and < 100 C. If desired the injection fluid may be compressed before injection to a pressure in the range of from 50 to 500 bar.
Further it is preferred that the injection fluid obtained in step (a2) is substantially free of 02, preferably comprising less than 10 ppmv.
More preferably, the injection fluid obtained in step (a2) comprises from 0.1 to 20 mol% synthesis gas based on dry gas, preferably > 3 mol% and < 10 mol%, more preferably about 5 mol%; even more preferably the injection fluid obtained in step (a2) comprises, based on dry gas:
- from 0.1 to 20 mol% synthesis gas, preferably > 3 mol% and < 10 mol%, more preferably about 5 mol%;

- from 5 to 20 mol% CO2, preferably from 10 to 20 mol% and even more preferably from 12 to 15 mol%;
- from 70 to 90 mol% N2, preferably from 80 to 90 mol%.
If desired, the injection fluid obtained in step (a2) may be further processed before injection into an oil field or other subterranean zone, without substantially changing the amount of synthesis gas being present. As an example, the injection fluid obtained in step (a2) may be cooled, freed from any H20 being present and compressed.
In an even other aspect the present invention provides an injection fluid obtainable by the method according to the present invention, preferably comprising, based on dry gas:
- from 0.1 to 20 mol% synthesis gas, preferably > 3 mol% and < 10 mol%, more preferably about 5 mol%;
- from 5 to 20 mol% CO2, preferably from 10 to mol% and even more preferably from 12 to 15 mol%;
- from 70 to 90 mol% N2, preferably from 80 to 20 90 mol%.
Preferably the injection fluid is substantially free of 02, preferably comprising less than 10 ppmv.
In a further aspect, the present invention provides a system for producing an injection fluid for injection in a subterranean zone, the system at least comprising:
- a first gasification reactor having an inlet for an oxygen containing stream, an inlet for a hydrocarbon stream, and downstream of the first gasification reactor an outlet for a synthesis gas containing stream produced in the first gasification reactor;
- a second gasification reactor having an inlet for a second oxygen containing stream, an inlet being connected to the outlet of the first gasification reactor, and downstream of the second gasification reactor an outlet for an injection fluid produced in the second gasification reactor.
Preferably the system further comprises:
- a first cooler for cooling the synthesis gas containing stream produced in the first gasification reactor; and - a second cooler for cooling the injection fluid produced in the second gasification reactor.
The first and second gasification reactors may be any suitable gasification reactor. As gasification reactors are known as such, they are not further discussed here.
If desired more than one first and second gasification reactors may be used thereby obtaining a system comprising more than two gasification reactors.
Preferably the second gasification reactor is a gas gasification reactor in which partial oxidation of the gas can be performed. Examples of suitable gas gasifiers and coolers are described in US-A-4836831, EP-A-257719, EP-A-774103.
The first and second oxygen containing streams may be from any suitable source. Preferably substantially pure (> 95 mol%) oxygen or (optionally oxygen-enriched) air or the like is used in the first gasification reactor and (optionally oxygen-enriched) air in the second gasification reactor.
In a further aspect, the present invention provides a system for producing an injection fluid for injection in a subterranean zone, the system at least comprising:
- a gasification reactor having an inlet for an oxygen containing stream, an inlet for a hydrocarbon stream, and downstream of the first gasification reactor an outlet for a synthesis gas containing stream produced in the gasification reactor;
- a cooler for cooling the synthesis gas containing stream produced in the first gasification reactor; and - splitter to split the cooled synthesis gas into two streams, a conduit to recycle one synthesis stream to the gasification reactor and a conduit to discharge the injection fluid.
The gasification reactors may be any suitable gasification reactor. As gasification reactors are known as such, they are not further discussed here. If desired more than one gasification reactor may be used in parallel thereby obtaining a system comprising two or more gasification reactors. Preferably the gasification reactor is a gas gasification reactor in which partial oxidation of the gas can be performed.
The invention will now be described by way of example in more detail with reference to the accompanying non-limiting drawings, wherein:
Figure 1 schematically shows a method of producing a hydrocarbon stream from a subterranean zone according to the present invention; and Figure 2 schematically shows a process scheme for performing a method of producing an injection fluid according the present invention wherein two gasification reactors are used in series flow.
Figure 3 schematically shows a process scheme for performing a method of producing an injection fluid according the present invention wherein a recycle is applied.
For the purpose of this description, a single reference number will be assigned to a line as well as a stream carried in that line. Same reference numbers refer to similar components.
Figure 1 schematically shows a method of producing oil 110 from a subterranean oil field 100 (under the surface 150 of the earth) wherein an injection fluid 50 is injected in or near the oil field 100.

The injection fluid 50 contains synthesis gas (CO + H2), preferably 0.1 - 20 mol% based on dry gas. The injection fluid 50 may have been obtained in various manners. Preferably, the injection fluid 50 is obtained by partial oxidation, e.g. in a system 1 comprising one or more gasification reactors. The injection fluid 50 is injected using an injector 120 in the subterranean oil field 100, thereby obtaining or maintaining a desired pressure to enhance oil production from the oil field 100. Usually the injection fluid 50 is compressed (the compressed injection fluid is indicated as stream 51) before injecting into the oil field 100. From the oil field 100, an oil stream 110 is obtained and removed at the pumping unit 130 for further processing. More than one stream 110 may be obtained; also, other hydrocarbon streams such as natural gas may be produced.
Reference is now made to Figure 2. Figure 2 schematically shows a system 1 for producing an injection fluid 50 containing synthesis gas to be injected in an oil field (not shown in Fig. 2; see Fig. 1).
The system 1 comprises a first gasification reactor 2 and a second gasification reactor 3.
In the embodiment shown in Fig. 2, the first gasification reactor 2 is an oil gasification reactor and the second gasification reactor 3 is a gas gasification reactor. The person skilled in the art will readily understand that the first gasification reactor 2 may also be a coal gasification reactor or a gasification reactor suitable for any other hydrocarbon containing stream.
In the system 1 of Fig. 2 an oil containing stream 10 and an oxygen containing stream 20 are fed at inlets 4 and 5, respectively, into the oil gasification reactor 2.
The oil containing stream 10 is partially oxidised by combustion in the gasification reactor 2 in a usual manner thereby obtaining a synthesis gas containing stream 30 (removed via outlet 6) and a slag 60 (removed via outlet 13). To this end usually one or more burners (not shown) are present in the gasification reactor 2.
The synthesis gas containing stream 30 produced in the oil gasification reactor 2 usually comprises > 25 mol% synthesis gas; has a pressure in the range from 20 to 200 bar; and has a temperature in the range from 1000 to 1500 C. Usually the stream 30 is cooled to a temperature in the range of 100-400 C in cooler 15, wherein the heat is used for e.g. steam generation.
Subsequently, the synthesis gas containing stream 30 is fed at inlet 7 into the second gasification reactor 3, being a gas gasification reactor. If desired, the synthesis gas containing stream 30 may be treated before entering the second gasification reactor 3, e.g. to remove any sulphur compounds being present.
In the second gasification reactor 3, the synthesis gas containing stream 30 is partially oxidised, preferably also by combustion, until only a small amount of synthesis gas (i.e. CO + H2) is left. If combustion is used for the partial oxidation in second gasification reactor 3, air or oxygen-enriched air is used, which is supplied at inlet 8 via stream 40.
Injection fluid 50 is obtained (which is removed via outlet 9). Usually, the injection fluid 50 obtained in the second gasification reactor 3 comprises from 0.1 to 20 mol% synthesis gas based on dry gas.
Although according to the embodiment of Figure 2 the synthesis gas containing stream 30 is a 'partially oxidised stream', it may also have been obtained in any other suitable way. Anyway, the 'synthesis gas containing stream' provided in the first gasification reactor 2 (or 'step (a)') contains more synthesis gas (viz. preferably > 25 mol% CO + H2) than the 'injection fluid' obtained in the second gasification reactor 3 (or 'step (a2)';
preferably from 0.1 to 20 mol% CO + H2).
Usually, the injection fluid 50 obtained in the second gasification reactor 3 has a pressure in the range from 20 to 200 bar, preferably between 50 and 80 bar; has a temperature in the range from 0 to 300 C (after cooling in second cooler 25); and is substantially free of 02, preferably comprising less than 10 ppmv 02.
As the injection fluid 50 may (and usually will) have a relative high pressure that is suitable for injection in an oil field (at about 70 bar), the resulting stream can be used as such as an injection fluid, with only a reduced amount of additional compression (e.g. in compressor 12 thereby obtaining stream 51) needed.
Usually the pressure of the stream 51 is in the range from 50 to 500 bar. In some cases the additional compression may even be dispensed with. If desired any remaining free 02 may be further removed, e.g. by catalytic oxidation using a suitable catalyst.
The person skilled in the art will readily understand that the present invention may be modified in various ways without departing from the scope as defined in the claims. As an example, the injection fluid 50 may be further processed (such as cooling, H20 removal, etc.) before use as an injection fluid in an oil field or other subterranean zone. Alternatively, the injection fluid 50 may be stored for later use.
Figure 3 shows another preferred embodiment of the present invention. In gasification reactor 201 a methane containing gas 202 is partially oxidized with air 203 to obtain a synthesis gas containing stream 204. This stream is cooled in a first step against evaporating water 206 to prepare high-pressure steam 207 in a boiler 205. The cooled synthesis gas containing stream is further cooled against air in air cooler 208. Water 212 is separated in drum 209. Part 210 of the synthesis gas containing stream is recycled to gasification reactor 201. The remaining net synthesis gas containing stream or injection fluid 211 is preferably further dehydrated in a so-called TEG
Dehydration Unit (not shown) before being compressed in compressor 213 to obtain a pressurized injection fluid 214 suited for injection in the hydrocarbon reservoir 219 as present below surface 218. The subsurface reservoir 219 will produce a hydrocarbon stream 215 due to the resulting higher pressure in the reservoir 219. In case the hydrocarbon stream 215 is a natural gas stream, optionally in combination with gas condensate stream, a separation unit 216 may be part of the scheme. This unit 216 will separate the liquid condensates, the LPG
fraction and optionally the ethane fraction (all shown as 217) from the produced gas 215. In the process according the present invention the stream 202 may be gas 215 or a gas richer in methane 217 from which gas condensate, a LPG fraction and/or an ethane fraction is separated from.
It will depend on the local value of these products whether they will be present in stream 202.
By adjusting the recycle ratio between recycle stream 210 and net production stream 211 the desired content of nitrogen and carbon dioxide in the injection fluid can be achieved. For example, in time the nitrogen content of the gas 202 or gas 215 will increase due to the use of injection fluid 214. This would result in less recycle in time to achieve the same nitrogen content in steam 211.
The invention will be illustrated by the following experiment based on model calculations. Reference is made to Figure 3. In this example a methane containing gas 202 is partially oxidized with air 203. The quality and quantity of the most important streams are provided on a water free basis in the below table. This table shows that a 10 kg/s stream of lean gas can prepare 210 kg/s of injection fluid using the present invention. The percentage recycle is 20/210 * 100% = 9,5%
Stream as in 202 203 210 211 Figure 3 Kg/s 10 200 20 210 H2 (%mol) - - 2 2 CO2 0.5 (*) 10 10 N2 3.4 80 85 85 C2+ 11.1 - - -02 - 20 <10 ppm <10 ppm (*) Assumed zero

Claims

1. Method of producing a hydrocarbon containing stream from a subterranean zone wherein an injection fluid is injected into the subterranean zone, the method at least comprising the steps of:
(a) providing an injection fluid comprising from 0.1 to 20 mol% synthesis gas based on dry gas, wherein the injection fluid is obtained by partial oxidation of a carbonaceous synthesis gas source with air;
(b) injecting the injection fluid into a subterranean zone for obtaining a desired pressure therein;
(c) obtaining a hydrocarbon containing stream from the subterranean zone.

2. Method according to claim 1, wherein the injection fluid provided in step (a) comprises > 3 mol% and < 10 mol%.

3. Method according to claim 2, wherein the injection fluid provided in step (a) comprises about 5 mol% synthesis gas.

4. Method according to claim 2, wherein the injection fluid comprises, based on dry gas:
- from 0.1 to 20 mol% synthesis gas;
- from 10 to 20 mol% CO2;
- from 70 to 90 mol% N2.

5. Method according to claim 4, wherein the injection fluid comprises, based on dry gas:

- > 3 mol% and < 10 mol% synthesis gas;
- from 12 to 15 mol% CO2;
- from 80 to 90 mol% N2.

6. Method according to claim 1, wherein the injection fluid provided in step (a) comprises less than 10 ppmv of O2.

7. Method according to claim 1, wherein the injection fluid has a pressure in the range from 50 to 500 bar.

8. Method according to claim 7, wherein the injection fluid has a pressure in the range from > 70 bar and < 400 bar.

9. Method according to claim 8, wherein the injection fluid has a pressure in the range from > 80 bar and < 300 bar.

10. Method according to claim 1, wherein the injection fluid has a temperature in the range from 0 to 300 °C.

11. Method according to claim 10, wherein the injection fluid has a temperature in the range from > 20 °C and < 100 °C.

12. Method according to claim 1, wherein the carbonaceous synthesis gas source is part of the hydrocarbon containing stream as obtained from the subterranean zone.

13. Method according to claim 12, wherein the carbonaceous synthesis gas source is natural gas when the hydrocarbon containing stream is natural gas or associated gas when the hydrocarbon containing stream is a crude oil hydrocarbon.

14. Method according to claim 1, wherein the injection fluid is produced by a method at least comprising:

(a1) providing a synthesis gas containing stream; and (a2) partially oxidising the synthesis gas containing stream provided in step (a1) with air or oxygen enriched air containing at least 70% N2, thereby obtaining an injection fluid comprising synthesis gas.

15. Method according to claim 14, wherein step (a2) is performed by recycling part of the synthesis gas containing stream obtained in step (a1) back to step (a1).

16. Method according to claim 15, wherein the recycle synthesis gas is reduced in temperature to a range from 100 to 400 °C before being recycled.

17. Method according to claim 15 or 16, wherein the mol ratio of synthesis gas recycled back to step (a1) and the net amount of synthesis gas as prepared by the process is between 1:2 and 2:1.

18. Method according to claim 14, wherein the synthesis gas containing stream provided in step (a1) comprises > 25 mol%
synthesis gas based on dry gas.

19. Method according to claim 18, wherein the synthesis gas containing stream provided in step (a1) comprises from 30 to 50 mol% synthesis gas based on dry gas.

20. Method according to claim 19, wherein the synthesis gas containing stream provided in step (a1) comprises from 30 to 40 mol% synthesis gas based on dry gas.

21. Method according to claim 14, wherein the synthesis gas containing stream provided in step (a1) has a temperature in the range from 100 to 400 °C.

22. Method according to claim 21, wherein the synthesis gas containing stream provided in step (a1) has a temperature in the range from > 200 °C and < 350 °C.

23. Method according to any one of claims 14-22, wherein the synthesis gas containing stream provided in step (a1) is obtained by partially oxidising a hydrocarbon stream.

24. Method according to any one of claims 14-22, wherein the synthesis gas containing stream provided in step (a1) is obtained by partially oxidising oil, gas or coal.

25. Method according to claim 23, wherein the synthesis gas containing stream provided in step (a1) is obtained by partially oxidising a natural gas or associated gas.