WO2008043833A2

WO2008043833A2 - Process to prepare a gaseous mixture

Info

Publication number: WO2008043833A2
Application number: PCT/EP2007/060876
Authority: WO
Inventors: Teck-Soon Lau; Hendrik Jan Van Der Ploeg; Jeroen Van De Rijt; Pieter Lammert Zuideveld
Original assignee: Shell Internationale Research Maatschappij BV
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2006-10-13
Filing date: 2007-10-12
Publication date: 2008-04-17
Anticipated expiration: 2009-04-13
Also published as: WO2008043833A3

Abstract

Process to produce a hydrocarbon product from a subsurface reservoir by injecting into the reservoir the gaseous mixture obtained by the below process to obtain a desired pressure in said reservoir such to enhance the recovery of the hydrocarbon containing stream, wherein the process to prepare the gaseous mixture comprises (a) partial oxidation of a carbonaceous feed and a gas mixture comprising nitrogen and oxygen thereby obtaining the gaseous mixture comprising of nitrogen, carbon dioxide, carbon monoxide and hydrogen, (b) cooling of the gaseous mixture of step (a) by indirect heat exchange against evaporating water obtaining steam, (c) providing to a gas turbine a methane comprising feed thereby obtaining a source of power and an exhaust gas or providing to a fired steam boiler a methane comprising feed thereby obtaining steam and an exhaust gas, and (d) using the exhaust gas as obtained in step (c) as the gas mixture comprising nitrogen and oxygen in step (a).

Description

PROCESS TO PREPARE A GASEOUS MIXTURE

Field of the invention

The present invention relates to a process to prepare a gaseous mixture comprising of nitrogen and carbon dioxide .

Background of the invention Gaseous mixtures comprising nitrogen and carbon dioxide are desired for use as injection fluid into an oil or gas field. The injection fluid maintains a desired pressure in the reservoir such that the production of the desired hydrocarbon stream from the reservoir is enhanced. This method is referred to as ^Λenhanced oil recovery' (also known as ^λEOR' ) . 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 ^-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 and involves power consumption.

A further problem is that the known injection fluids are often available at low pressures and as a result a compression step is necessary before injection into the 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-C5 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.

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 3.5 vol% (between 2 and 4 vol%), which is too high for direct use as injection 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 a gaseous mixture comprising nitrogen and carbon dioxide in combination with power. Summary of the invention

One or more of the above or other objects can be achieved with the following process.

Process to prepare a gaseous mixture comprising of nitrogen, carbon dioxide, carbon monoxide and hydrogen by a partial oxidation of a carbonaceous feed and an oxidiser gas mixture comprising nitrogen and between 5 and 20 vol.% oxygen.

The invention is also directed to the following process . Process to prepare power and a gaseous mixture comprising of nitrogen and carbon dioxide by performing the following steps,

(a) partial oxidation of a carbonaceous feed and a gas mixture comprising nitrogen and oxygen thereby obtaining the gaseous mixture comprising of nitrogen, carbon dioxide, carbon monoxide and hydrogen,

(b) cooling of the gaseous mixture of step (a) by indirect heat exchange against evaporating water obtaining steam, (c) providing to a gas turbine a methane comprising feed thereby obtaining a source of power and an exhaust gas, and

(d) using the exhaust gas as obtained in step (c) as the gas mixture comprising nitrogen and oxygen in step (a) . The invention is also directed to the following process .

Process to produce a hydrocarbon product from a subsurface reservoir by injecting into the reservoir the gaseous mixture obtained by the below process to obtain a desired pressure in said reservoir such to enhance the recovery of the hydrocarbon containing stream, wherein the process to prepare the gaseous mixture comprises

(b) cooling of the gaseous mixture of step (a) by indirect heat exchange against evaporating water obtaining steam,

(c) providing to a gas turbine a methane comprising feed thereby obtaining a source of power and an exhaust gas or providing to a fired steam boiler a methane comprising feed thereby obtaining steam and an exhaust gas, and (d) using the exhaust gas as obtained in step (c) as the gas mixture comprising nitrogen and oxygen in step (a) .

Applicants found that with the present process a gaseous stream comprising nitrogen and carbon dioxide can be prepared in an efficient manner. In one of the embodiments power is prepared simultaneously. The gaseous stream will not contain any large contents of oxygen because the oxidation is conducted in a partial manner. The content of oxygen will be almost zero because of the presence of the relatively larger mol volume of hydrogen in the gaseous mixture. Any traces of oxygen will react with the hydrogen present. Brief description of the drawings

Figure 1 illustrates an embodiment of the claimed process wherein the exhaust gas of a gas turbine is used as oxidiser gas mixture. Figure 2 illustrates an embodiment of the claimed process wherein the exhaust gas of a fired steam boiler is used as oxidiser gas mixture.

Figure 3 illustrates an embodiment of the claimed process wherein the exhaust gas of a diesel or gas engine is used as oxidiser gas mixture.

Figure 4 illustrates the purification of the water as separated from compressed exhaust gas.

Figure 5 illustrates how the gaseous mixture is used as an injection fluid in a process producing a hydrocarbon containing stream from a subterranean zone. Detailed description of the invention

The invention is directed to a process to prepare a gaseous mixture comprising of nitrogen, carbon dioxide, carbon monoxide and hydrogen by a partial oxidation of a carbonaceous feed and a mixture comprising nitrogen and between 5 and 20 vol.% oxygen, also referred to as the oxidiser gas. Preferably the partial oxidation is performed at a pressure of between 20 to 200 bar and most preferably between 40 bar and 130 bar. The partial oxidation may be performed according to well-known principles as for example described for the Shell Gasification Process in the Oil and Gas Journal, September 6, 1971, pp 85-90. Publications describing examples of partial oxidation processes are EP-A-291111, WO-A-9722547, WO-A-9639354 and WO-A-9603345.

Preferably the hot gaseous mixture is reduced in temperature in a so-called waste heat boiler. Examples of suitable waste heat boilers are described in WO-A-2005015105, US-A-4245696 and EP-A-774103. In such a waste heat boiler water evaporates by indirect heat exchange with the hot gaseous mixture to produce preferably high-pressure steam.

Preferably the gaseous mixture obtained is subjected to a scrubber step to remove soot. Especially if the location at which the gaseous mixture is prepared and the location at which the gaseous mixture is used is far apart, it is preferred to subject the scrubbed gas to a dehydration process step to remove water. A preferred dehydration unit is a so-called TEG (Tertiary Ethylene Glycol) Dehydration unit. The content of water in the gaseous mixture after said unit may vary and is for example dependent on the ambient temperature. The water content is preferably below the dew point of the gaseous mixture at a temperature of at least 10 °C below the lowest ambient temperature around the conduit which transports the gaseous mixture as produced. This temperature may vary from, for example 0 ⁰C in hot climates, to lower temperatures in colder regions. The oxidiser gas has an oxygen content which is lower than the oxygen content in atmospheric air, which is about 21 mol%. This oxygen poor oxidiser gas may be obtained by various methods. Preferably the oxidiser gas is an exhaust gas, also referred to as flue gas, of a combustion process wherein a carbonaceous fuel is combusted with atmospheric air. A preferred oxidiser gas is the exhaust gas as obtained in a fired steam boiler or in a diesel or gas engine. Typically the exhaust gas of a fired steam boiler has a very low oxygen content of about between 1 and 3 mol%. The oxygen content of the diesel or gas engine is typically between 4 and 9 mol% . It has been found advantageous to use an oxidiser gas having an oxygen content of between 4 and 8 mol%. It may therefore be preferred to add a certain amount of atmospheric air with the fired boiler exhaust gas to obtain an oxidiser gas having the desired oxygen content. The addition of air is also a means to control the partial oxidation process. Another preferred source of an exhaust gas is the exhaust gas as obtained in gas turbine. This exhaust gas typically has a higher oxygen content. By having - 7 -

additional duct firing a flexible means to reduce the oxygen content is obtained.

The exhaust gas is preferably compressed in one or more stages before being used as oxidiser gas. When compressing the exhaust gas water will condense to liquid water. The condensed water is suitably separated from the compressed exhaust gas.

Preferably the condensed water is subjected to one or more purification steps such that this water may be reused in the process according to the present invention, especially as fresh boiler feed water. Boiler feed water is used in certain preferred embodiments of the current invention, i.e. in the waste heat exchanger and in the fired steam boiler. The purification steps preferably comprise one or more of the following steps, passing the water through a soot filter, degassing the water to remove CO2, polishing the water and deaeration of the water. More preferably the purification process is performed by subjecting the condensed water to the following purification steps, passing the water through a soot filter, degassing the water free of soot to remove CO2, polishing the water free of CO2 and deaeration of the polished water to obtain purified water.

The gaseous mixture comprising of nitrogen, carbon monoxide and hydrogen is preferably used as an injection fluid in a process producing a hydrocarbon containing stream from a subterranean zone. In such a process the injection fluid is injected into the subterranean zone to obtain a desired pressure in said subterranean zone such to enhance the recovery of the hydrocarbon containing stream. Detailed description of the Figures

The invention will be described in more detail making use of Figures 1-5. Figure 1 illustrates a process to prepare power (28) and a gaseous mixture comprising of nitrogen and carbon dioxide (13) . The partial oxidation of step (a) is performed in partial oxidation reactor (2) in which reactor the partial oxidation of a carbonaceous feed (1), and a gas mixture comprising nitrogen, carbon dioxide and oxygen (34) from gas turbine (25) . The hot gaseous mixture comprising of nitrogen, carbon dioxide, carbon monoxide and hydrogen (3) is cooled in a waste heat boiler (4). In such a waste heat boiler water (14) evaporates by indirect heat exchange with the hot gaseous mixture (3) to produce preferably high-pressure steam (15). High-pressure steam, having a pressure of between 80 and 120 bars, is preferred because such steam can be used to generate power. The cooled gaseous mixture (5) is scrubbed in scrubber (6) to remove condensate (7) and wet soot (8) . Scrubbed gaseous mixture (9) is further treated in a so-called TEG dehydrating unit (10) . The resulting gaseous mixture (11) is compressed in compressor (12). The pressure level achieved in compressor (12) makes the gas suited for use as injection fluid in a process producing a hydrocarbon containing stream from a subterranean zone.

In step (c) a gas turbine (25) is used. To said gas turbine (25) a methane comprising feed (24) is fed. Also shown is a supply (24a) to duct firing means (24b) . This feed (24) is preferably from the same methane containing feed (1) . Before feed (24) is used in the gas turbine it is preferably increased in temperature by indirect heat exchange in heat exchange module (22) against the exhaust gas (29) of the gas turbine (25) . The heated gas is preferably desulphurised in sulphur guard bed (23) to remove the last traces of sulphur. Feed (1) preferably contains less than 50 ppmv, more preferably less than 20 ppmv and even more preferably less than 10 ppmv sulphur. Feed (24) , as supplied to gas turbine (25) , preferably contains, after an optional sulphur removal (23) , less than 10 ppmv, more preferably less than 1 ppmv and even more preferably less than 0.1 ppmv sulphur. This is advantageous because corrosion can then be avoided in exhaust gas compressors (31) and (33) and gas cooler (32) .

The gas turbine (25) produces power (26) and an exhaust gas (29) . The exhaust gas (29) is discharged from the gas turbine (25) via (30) . Preferably the gasification in gasification reactor (2) , step (a) , is performed at elevated pressures, more preferably between 20 to 200 bar and most preferably between 40 bar and 130 bar. In order to use exhaust gas (30) as the gas mixture comprising nitrogen and oxygen in step (a) it will be required to compress this gas to said elevated pressures. Before compressing in compressor (31) the gas is suitably cooled in cooler (32a) as shown in more detail in Figure 4. The compressed gas is subsequently cooled in cooler (32) to condensate water, which is separated as water stream (37) . The dry gas is further compressed in compressor (33) and the compressed gas (34) is used in gasification reactor (2) . Figure 1 also shows means (35) to optionally add air as an additional source of the gas mixture comprising nitrogen, carbon dioxide and oxygen. Figure 1 also shows means (36) to discharge surplus exhaust gas if so required.

Figure 1 also shows the preferred preparation of super heated steam (38) by indirect heat exchange of steam flow (15) against exhaust gas (29) in heat exchange module (16) . Super heated steam (38) is used in steam turbine (17) to preferably drive directly exhaust gas compressors (31) and (33) or generate power (21a) . Used steam (18) is condensed to water in condenser (19) and, after heating against exhaust gas (29) in heat exchange module (20), is reused as water (14) in waste heat boiler (4) . Figure 1 also shows power line (27), which represents power usage within the process of this Figure. These usages may be for example the TEG Dehydrating unit (10), compressors (12), (31), (33) and other process items such for example water pumps.

As is clear from the above Figure 1 the invention is preferably directed to a process, wherein super heated steam is used to operate a steam turbine to provide a direct shaft drive to compress the exhaust gas as obtained in step (c) to a pressure which makes it suited for performing step (a) .

Thus the invention is furthermore preferably directed to a process, wherein the exhaust gas as obtained in step (c) is cooled against the steam as obtained in step (b) by indirect heat exchange thereby obtaining super heated steam.

Thus the invention is furthermore preferably directed to a process, wherein the super heated steam is used to operate the steam turbine.

Thus the invention is furthermore preferably directed to a process, wherein the used steam of the steam turbine is condensed to liquid water, the liquid water subsequently increased in temperature by indirect heat exchange against the exhaust gas of step (c) and recycled to step (b) .

Thus the invention is preferably directed to a process, wherein the used steam of the steam turbine is condensed to liquid water, the water subsequently evaporated to steam and further evaporated to super heated steam by indirect heat exchange against the exhaust gas of step (c) . The invention is preferably directed to a process, wherein the gaseous mixture obtained in step (a) is subjected to a scrubber step to remove soot. The invention is preferably directed to a process, wherein the scrubbed gas is subjected to a dehydration process step to remove water. In a further preferred embodiment part of the cooled gaseous steam (5) may be recycled to step (a) . This recycle allows the operator a fine tuning of the process to target the required nitrogen content of the gaseous mixture to be produced. By recycling more gaseous fraction a higher nitrogen content will result. Preferably between 1 to 20 mol% is recycled to step (a) , wherein the recycle is calculated as the mol fraction recycle stream on the total of gaseous product (9) as prepared by the process times 100%.

Figure 2 illustrates an embodiment wherein the exhaust gas of a fired steam boiler is used as the oxidiser gas. The equivalent references used in Figure 1 have the same meaning in Figure 2.

Figure 2 illustrates a process to prepare power (28) and a gaseous mixture comprising of nitrogen and carbon dioxide (13) . The partial oxidation of step (a) is performed in partial oxidation reactor (2) in which reactor the partial oxidation of a carbonaceous feed (1), and an oxidiser gas mixture comprising nitrogen, carbon dioxide and oxygen (34) derived from fired steam boiler (50) and ambient air via supply line (35) . The hot gaseous mixture comprising of nitrogen, carbon dioxide, carbon monoxide and hydrogen (3) is cooled in a waste heat boiler (4). In such a waste heat boiler water (14) evaporates by indirect heat exchange with the hot gaseous mixture (3) to produce preferably high-pressure steam (15) . High-pressure steam, having a pressure of between 80 and 120 bars, is preferred because such steam can be used to generate power. The high-pressure steam may be suitably super-heated to temperatures between 400 and 420 ⁰C. The cooled gaseous mixture (5) is scrubbed in scrubber (6) to remove condensate (7) and wet soot (8). Scrubbed gaseous mixture (9) is further treated in a so- called TEG dehydrating unit (10) . The resulting gaseous mixture (11) is compressed in compressor (12).

In step (c) a fired steam boiler (50) is used. To said fired steam boiler (50) a methane comprising feed

(21) is fed. This feed (21) is preferably the same as the methane containing feed (1) as shown. The gas (21) is preferably desulphurised in a sulphur guard bed (not shown) to remove the last traces of sulphur. Feed (1) preferably contains less than 50 ppmv, more preferably less than 20 ppmv and even more preferably less than 10 ppmv sulphur. Feed (21), as supplied to boiler (50), preferably contains, after an optional sulphur removal, less than 10 ppmv, more preferably less than 1 ppmv and even more preferably less than 0.1 ppmv sulphur. This is advantageous because corrosion can then be avoided in exhaust gas compressors (31) and (33) and gas cooler (32) .

To fired steam boiler (50) fresh boiler feed water (55) is fed to obtain steam (66). Fresh boiler feed water (55) is supplied from storage tank (53). Additional water (54) may be provided from several sources. Preferably these source comprise condensed water (61) and (37) . The steam (66) is combined with steam (15) and further increased in temperature by indirect heat exchange against the exhaust gas (51) of the fired steam boiler (50) to obtain super heated steam (56) . Part of the super heated steam (56) is used to generate power (63) in steam turbine (57) . Part of the power (63) may be exported as power (28) and part (65) will be used for internal uses of the present process as described at Figure 1. Another part of the super heated steam (56) is used to drive compressor (31) and (33) directly by using a steam turbine (58) linked to said compressors via drive shaft (62). The used steam (59) is cooled in cooler (60) and the condensed water is recycles to storage (53).

The exhaust gas (51) of the fired steam boiler is in whole or in part blended with ambient air (35) to obtain oxidiser gas mixture (52) . As in Figure 1 this oxidiser gas is compressed in compressor (31) . The compressed gas is subsequently cooled in cooler (32) to condensate water, which is separated as water stream (37). The dry gas is further compressed in compressor (33) and the compressed gas (34) is used as oxidiser gas in gasification reactor (2).

Figure 3 shows a line-up as in Figure 2 except that instead of the fired steam boiler (50) a gas engine (68) is used to prepare exhaust gas (51). Gas engine (68) is fuelled by a methane comprising feed (21) . The steam generated in waste heat boiler (4) may be further heated to generate super-heated steam against cooled gaseous mixture (5) in super heater module (67) . The super heated steam (15) can be used as in Figure 2. The remaining reference numbers of Figure 3 have the same meaning as in Figure 2. Instead of a gas engine (68) a diesel engine can be used. Obviously such a diesel engine will be fuelled with a source of diesel instead of the methane comprising feed (21) . Figure 4 shows a process for recovery of water and its re-use in the process according to the present invention. In the illustrated process an exhaust gas (70) , which may be comprised of the gas turbine exhaust gas (30) of Figure 1 or the fired boiler exhaust gas (51) of Figure 2 or the gas engine exhaust gas of Figure 3, having an ambient pressure, is compressed in a series of compression stages to an compressed gas (34) . Prior to compression the exhaust gas is cooled in cooler (32a) . The compression stages are illustrated by compressors (31) and (33) . The intermediate compressed gas is cooled by coolers (32) and the condensed water (37) is separated from the gas in a separation vessel (32'), also referred to as knock-out drums. Cooling in coolers (32a) and (32) maybe performed by indirect heat exchange using a cooling medium. Suitable cooling media are water, chilled water and air. Also other cooling media may be used. Cooling may also be performed by direct cooling, preferably by contacting the gas with water.

The condensed water (37) will typically contain inerts, which originate from the ambient air used to prepare the exhaust gas (70). Further the water (37) will contain high amounts of dissolved gasses, for example CC»2, N2, C>2, soot and some ions, typically Fe and Cu ions . Especially in regions where water is scarce it is advantageous to be able to use this water as fresh boiler feed water (BFW) . For this purpose the water needs to be cleaned by first subjecting the water (37) to a soot filter (71) . The water free of soot (72) is subsequently degassed in degasser (74) by stripping with ambient air

(73) to remove CO2. The degassed water (76) is optionally combined with external make-up water (78) in mixing and storage vessel (77) . The water (79) is heat exchanged against polished water (83) in heat exchanger (80) and further chilled in heat exchanger (81) . The water having a temperature of about 40 ⁰C is subjected to a polishing step. In the polishing step water is fed to a mixed bed polishing unit. The unit comprises suitably a strong acid cation (SAC) resin and strong base Anion (SBA) resins. In the polishing step the conductivity of the water is reduced. Preferably the conductivity is reduced to a value of less than 1 micro ohm. To a second mixing and storage tank water (84) and polished water (83) are fed. The preferred sources of water (84) are the condensed water (61) of Figure 3 or the condensed water as condensed in condenser (19) of Figure 1. The combined water (86) is subjected to a deaeration to obtain water (90) suited to be used as fresh boiler feed water. The water (90) is pumped using pump (91) to suitably the waste heat boiler (4), the fired boiler (50) or any optional auxiliary start-up boilers.

The present invention is also directed to a process to recover purified water from an exhaust gas as illustrated in Figure 4. This process comprises of the following steps, (i) cooling down the exhaust gas whereby water may condense, depending on the water content and cooling temperature and/or (ii) compressing the, optionally cooled, exhaust gas from a low pressure to a higher pressure in one or more stages, to condense (more) water, (iii) cooling the compressed gas after each stage whereby water condenses, which water is separated from the gas before it is further compressed or used, wherein the water thus obtained is purified to obtain water of a required quality. Water of required quality may suitably be potable water and demineralised water. A preferred process to purify the water to demineralised water quality is by (iv) passing the water through a soot filter, (v) degassing the water free of soot to remove CC>2, (vi) polishing the water free of CO2 and (vii) deaeration of the polished water to obtain water of demineralised water quality. Preferably the above process involves compression step (ii) and cooling step (iii). More preferably the process also involves cooling step

(i) - The above process to recover water from exhaust gasses may additionally find suitable use in so-called steam based and combined cycle power plants, so-called Integrated Gasification Combined Cycle (ICGG) processes, and processes to prepare hydrocarbons involving partial oxidation of any hydrocarbonaceous feedstock and a Fischer-Tropsch step. In such processes various sources of exhaust gas are available from which water may be recovered by the claimed process.

The carbonaceous feed as used as feed in the partial oxidation may be isolated from the hydrocarbons to be produced from the subsurface reservoir. Examples of such feeds are natural gas, associated gas, ethane, LPG and gas condensates. Alternatively this feed may be derived from another source. Examples of suitable alternative feeds are coal, brown coal, peat, wood, coke, soot, biomass and refinery streams, for example de-asphalted oil and residual oils.

Preferably the carbonaceous feed to step (a) is a methane comprising feed. More preferably part of the methane comprising feed is used in step (a) and part of the methane comprising feed is used in step (c) .

The methane comprising feed is preferably crude natural gas as directly obtained from a natural gas subsurface reservoir, refined natural gas from which components like condensate, LPG and/or ethane have been removed from or associated gas as obtained from a crude oil subsurface reservoir, refined associated gas from which components like condensate, LPG and/or ethane have been removed. These sources of methane containing gas are preferred because they are found in the vicinity where one would like to use the gaseous mixture as prepared by the process according the invention. Furthermore these gasses are obtained at a relatively high pressure from the subsurface reservoir. This required less compression when these feeds are used in step (a) .

The content of oxygen in the gaseous mixture as obtained in the process according to the invention will be less than 10 ppmv. The gaseous mixture may be advantageously be used for an enhanced recovery of a gas or oil product from a subterranean reservoir. Preferably, the gaseous mixture as obtained in the process according to the invention comprises from 0.1 to 20 mol% synthesis gas (i.e. CO + H₂) based on dry gas, preferably more than 3 mol% and less than 10 mol%, more preferably about 5 mol%. More preferably the gaseous mixture comprises, based on dry gas:

- from 0.1 to 20 mol% synthesis gas, preferably more than 3 mol% and less than 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 gaseous mixture provided in step (a) or (c) is substantially free of Qi₂, preferably comprising less than 10 ppmv.

The invention is also directed to a preferred use of the gaseous mixture, namely as injection fluid. In said use the injection fluid comprising of nitrogen, carbon dioxide, carbon monoxide and hydrogen is used as an injection fluid in a process producing a hydrocarbon containing stream from a subsurface reservoir, wherein the injection fluid is injected into the reservoir to obtain a desired pressure in said reservoir such to enhance the recovery of the hydrocarbon containing stream.

The invention is thus also directed to a process to produce a hydrocarbon product from a subsurface reservoir by injecting into the reservoir the gaseous mixture obtained by the above process to obtain a desired pressure in said reservoir such to enhance the recovery of the hydrocarbon containing stream.

Further it is preferred that the injection fluid (13) at injection has a pressure in the range from 50 to 500 bar, preferably greater than 70 bar and less than 400 bar, more preferably greater than 80 bar and less than 300 bar; and a temperature in the range from 0 to 300 °C, preferably greater than 20 ⁰C and less than 100 ⁰C. The hydrocarbon product to be produced from the subsurface reservoir 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 subsurface reservoir 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 of an injection fluid and the associated production of the hydrocarbon stream from a reservoir 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 reservoir 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 reservoir; therefore, the term "obtaining a desired pressure" also includes maintaining a certain pressure in the reservoir. Figure 5 shows the process illustrated in Figure 1 in combination with the production of a hydrocarbon product. The numbering used in Figure 1 is valid for Figure 5. In Figure 5 a hydrocarbon product (45) is produced from a subsurface reservoir (40) . In case the hydrocarbon product (45) is a crude oil an associated gas methane containing gas (1) may be separated in a separator (46), resulting in a degassed crude hydrocarbon product (47) which is discharged as the hydrocarbon product. The associated gas (1) may contain ethane and LPG components next to methane. The volumes of these additional components will depend on availability and the local value of these components. If higher carbon dioxide contents are desired it may be desirable to leave some of the LPG compounds in the methane comprising feed (1) . Any surplus gas (49) may be exported.

In case the hydrocarbon product (45) is a natural gas product a methane containing gas (1) may be isolated in a separator (46) or alternatively be directly used via stream (48) as the methane comprising feed (1) . In separator (46) ethane, LPG and/or gas condensates may be separated from the crude natural gas (45). The volumes of these additional components will depend on availability and the local value of these components. If higher carbon dioxide contents are desired it may be desirable to leave some of the LPG compounds in the methane comprising feed (1) . The main volume of natural gas product (49) is discharged as the hydrocarbon product of the process.

The invention will be illustrated by the following experiment based on model calculations. Reference is made to Figure 1 and 5. In this example a methane containing gas (1) is partially oxidized with the exhaust gas (34) of a gas turbine, which operates on the same methane comprising feed. The quality and quantity of the most important streams are provided on a water free basis in the below table. The illustrated example does not comprise a recycle of gaseous mixture to the gasification reactor (2) .

Claims

C L A I M S

1. Process to prepare a gaseous mixture comprising of nitrogen, carbon dioxide, carbon monoxide and hydrogen by a partial oxidation of a carbonaceous feed and an oxidiser gas mixture comprising nitrogen and between 5 and 20 vol.% oxygen.

2. Process according to claim 1, wherein the carbonaceous feed is a methane comprising feed.

3. Process according to any one of claims 1-2, wherein the partial oxidation is performed at a pressure of between 40 bar and 130 bar.

4. Process according to any one of claims 1-3, wherein the gaseous mixture obtained is subjected to a scrubber step to remove soot.

5. Process according to claim 4, wherein the scrubbed gas is subjected to a dehydration process step to remove water .

6. Process according to any one of claims 1-5, wherein the oxidiser gas is the exhaust gas as obtained in a fired steam boiler.

7. Process according to any one of claims 1-5, wherein the oxidiser gas is the exhaust gas as obtained in a gas turbine .

8. Process according to any one of claims 1-5, wherein the oxidiser gas is the exhaust gas as obtained in a gas engine.

9. Process according to any one of claims 1-5, wherein the oxidiser gas is the exhaust gas as obtained in a diesel engine.

10. Process according to any one of claims 6 -9, wherein the exhaust gas is compressed and cooled in one or more stages before being used as oxidiser gas and wherein condensed water is separated from the compressed exhaust gas.

11. Process according to claim 10, wherein the condensed water is subjected to one or more of the following purification steps, passing the water through a soot filter, degassing the water to remove CC>2, polishing the water and deaeration of the water.

12. Process according to claim 11, wherein the condensed water is subjected to the following purification steps, passing the water through a soot filter, degassing the water free of soot to remove CO2, polishing the water free of CO2 and deaeration of the polished water to obtain purified water.

13. Process according to claim 12, wherein the purified water is used as boiler feed water.

14. Process according to any one of claims 1-13, wherein the gaseous mixture comprising of nitrogen, carbon monoxide and hydrogen is used as an injection fluid in a process producing a hydrocarbon containing stream from a subterranean zone, wherein the injection fluid is injected into the subterranean zone to obtain a desired pressure in said subterranean zone such to enhance the recovery of the hydrocarbon containing stream.

15. Process according to prepare a gaseous mixture comprising of nitrogen, carbon dioxide, carbon monoxide and hydrogen by performing the following steps,

(b) cooling of the gaseous mixture of step (a) by indirect heat exchange against evaporating water obtaining steam, (c) providing to a fired steam boiler a methane comprising feed as fuel thereby obtaining steam and an exhaust gas, and

(d) using the exhaust gas as obtained in step (c) as the gas mixture comprising nitrogen and oxygen in step (a) .

16. Process according to claim 15, wherein a mixture of ambient air and exhaust gas as obtained in step (c) is used in step (a) .

17. Process to prepare power and a gaseous mixture comprising of nitrogen, carbon dioxide by performing the following steps,

(c) providing to a gas turbine a methane comprising feed thereby obtaining a source of power and an exhaust gas, and

18. Process according to claim 17, wherein super heated steam is used to operate a steam turbine to provide a direct shaft drive to compress the exhaust gas as obtained in step (c) to a pressure which makes it suited for performing step (a) .

19. Process according to any one of claims 17-18, wherein the exhaust gas as obtained in step (c) is cooled against the steam as obtained in step (b) by indirect heat exchange thereby obtaining super heated steam.

20. Process according to any one of claims 18-19, wherein the used steam of the steam turbine is condensed to liquid water, the water subsequently increased in temperature by indirect heat exchange against the exhaust gas of step (c) and recycled to step (b) .

21. Process according to any one of claims 18-19, wherein the used steam of the steam turbine is condensed to liquid water, the water subsequently evaporated to steam and further evaporated to super heated steam by indirect heat exchange against the exhaust gas of step (c) .

22. Process according to any one of claims 17-21, wherein the content of oxygen in the gaseous mixture comprising of nitrogen and carbon dioxide is less than 10 ppmw.

23. Process according to any one of claims 17-22, wherein in step (c) the methane comprising feed is combusted with air resulting in a gaseous mixture in step (a) of comprising between 70 and 90 mol% nitrogen.

24. Process according to any one of claims 17-23, wherein the carbonaceous feed of step (a) is a methane comprising feed.

25. Process according to any one of claims 17-24, wherein the pressure of the gas obtained in step (a) is between 40 bar and 130 bar.

26. Process according to any one of claims 17-25, wherein the gaseous mixture obtained in step (a) is subjected to a scrubber step to remove soot.

27. Process according to claim 26, wherein the scrubbed gas is subjected to a dehydration process step to remove water .

28. Process according to any one of claims 17-27, wherein the gaseous mixture comprising of nitrogen, carbon monoxide and hydrogen is used as an injection fluid in a process producing a hydrocarbon containing stream from a subterranean zone, wherein the injection fluid is injected into the subterranean zone to obtain a desired pressure in said subterranean zone such to enhance the recovery of the hydrocarbon containing stream.

29. Process to produce a hydrocarbon product from a subsurface reservoir by injecting into the reservoir the gaseous mixture obtained by the below process to obtain a desired pressure in said reservoir such to enhance the recovery of the hydrocarbon containing stream, wherein the process to prepare the gaseous mixture comprises

(c) providing to a gas turbine a methane comprising feed thereby obtaining a source of power and an exhaust gas or providing to a fired steam boiler a methane comprising feed thereby obtaining steam and an exhaust gas, or providing to a gas engine a methane comprising feed thereby obtaining an exhaust gas or by operating a diesel engine and thereby obtaining an exhaust gas, and

30. Process according to claim 29, wherein the hydrocarbon product is a crude oil and the carbonaceous feed in step (a) and the methane comprising feed in step (c) is the associated gas as obtained with the crude oil.

31. Process according to claim 29, wherein the hydrocarbon product is a natural gas and the carbonaceous feed in step (a) and the methane comprising feed in step (c) is part of the natural gas as produced.

32. Process according to any one of claims 29-31, wherein the gaseous mixture comprising of nitrogen, carbon dioxide, carbon monoxide and hydrogen is obtained - -

according to any one of the processes according to claims 1-28.

33. Process to recover purified water from an exhaust gas comprising of the following steps, (i) cooling down the exhaust gas whereby water condenses, and/or (ii) compressing the, optionally cooled, exhaust gas from a low pressure to a higher pressure in one or more stages, to condense water, (iii) cooling the compressed gas after each stage whereby water condenses, which water from steps (i) and (ii) is separated from the gas before it is further compressed or used, wherein the water thus obtained is purified to obtain water of a required quality.

34. Process according to claim 33, wherein the water is purified to demineralised water quality by (iv) passing the water through a soot filter, (v) degassing the water free of soot to remove CO2, (vi) polishing the water free of CO2 and (vii) deaeration of the polished water to obtain water of demineralised water quality.

35. Process according to any one of claims 33-34, wherein the process comprises compression step (ii) and cooling step (iii) .

36. Process according to claim 35, wherein the process involves cooling step (i) .

37. Process according to any one of claims 6-32 wherein a process to recover water from the exhaust gas is performed according to the process according to any one of claims 33-36.