WO2013056732A1

WO2013056732A1 - Improved process for the conversion of natural gas to hydrocarbons

Info

Publication number: WO2013056732A1
Application number: PCT/EP2011/068260
Authority: WO
Inventors: Erling Rytter
Original assignee: Statoil Petroleum As
Priority date: 2011-10-19
Filing date: 2011-10-19
Publication date: 2013-04-25

Abstract

A process for the conversion of natural gas to essentially hydrocarbons by the Fischer-Tropsch process in a gas to liquid (GTL) plant, the process comprising the steps of feeding natural gas (65) to the GTL plant for conversion, at least some of the gas being produced from a gas hydrate type reservoir (63); generating carbon dioxide during the conversion process, separating the generated carbon dioxide from process or exhaust streams and feeding at least some of the separated carbon dioxide (57) into the gas hydrate type reservoir for further liberation of gas from the hydrate by exchange with the carbon dioxide and feeding the liberated gas (65) to the GTL plant (51) for conversion to essentially hydrocarbons. Thermal decomposition of the hydrate may be achieved by the addition of steam (58) to the reservoir, at least some of the steam being generated during the GTL process.

Description

Improved Process for the conversion of natural gas to hydrocarbons

The present invention relates to an improved process for the conversion of natural gas to essentially hydrocarbons in a gas to liquid (GTL) plant, particularly in relation to natural gas produced from a gas hydrate type reservoir.

Gas to liquid technology relates to processes for converting natural gas to liquid fuels. The process consists essentially of treatment of the natural gas to remove impurities, reforming the natural gas to produce syngas (carbon monoxide and hydrogen), and then carrying out Fischer-Tropsch (FT) conversion of the syngas to produce long chained paraffinic hydrocarbons. After upgrading by hydrogenation and, optionally, isomerization, a large proportion of the liquid hydrocarbons formed comprise ultra- clean diesel fuel having almost zero sulphur and a low to non-existing aromatics content, together with other desirable products, such as naphtha, jet fuel and wax. The products are produced in a GTL production facility. In addition, the GTL plant produces C0₂ and steam. Normally the C0₂will be emitted to the atmosphere whereas the steam will be used to generate useful energy, most likely in the form of electricity.

One source of natural gas is methane hydrate (methane locked in ice). Methane hydrates form at low temperature and high pressure and thus are found in sea-floor sediments, on top of the ocean floor itself, as well as part of deep continental sandstones, permafrost and in arctic environments. As an example, methane hydrate forms at 4°C under a pressure of 50 atmospheres. Normally, the gas hydrates are purer in methane than other natural gas sources and thus, this means that costly separation and purification steps can be minimized or even avoided. There are massive amounts of methane bound in hydrates representing an immense carbon reservoir. Estimates of the oceanic reserves vary considerably, but figures from 2x to 10x and higher than conventional gas have been suggested. However, a commercially viable production method for this type of hydrocarbon recovery is still required. One method involves reducing pressure in the well bore. The methane hydrate can dissociate to release methane which is then collected via a production well. The gas hydrate contained within a formation is accompanied by larger or smaller amounts of water or ice that is coproduced with the gas when harvesting by decompression. This water is harvested in addition to water from the decomposition of the hydrate itself.

Some knowledge about methane hydrates and carbon dioxide sequestration can be found in the literature. A method for sequestering and storing C0₂ in which gaseous carbon dioxide is injected into a subterranean methane hydrate field, displacing methane in the methane hydrate field with the carbon dioxide and forming carbon dioxide hydrate is described in US 2005/0121200 A1 , Gas Technology Institute. The displaced methane may then be collected. The heat from the formation of the C0₂ hydrates facilitates the release of natural gas. A comparatively similar concept has been described in US 5261490 A (T.Ebinuma). In US 2010/0243245 A1 to Gas Technology Institute heat is generated by in-situ combustion of some of the released methane in the hydrate formation, which in turn is used to heat C0₂ which is then injected into the hydrate deposit to release more methane. WO 2010088874 A2, Leibnitz Institut Fur Meereswissen, focuses on injecting C0₂ under super-critical conditions to the hydrate formation, thereby releasing methane. In US 7513306 B2, Precision Combustion, Inc., a mixture of oxygen, carbon dioxide and fuel is combusted downhole. A diluent fluid is then warmed and transported to the methane hydrates, which are then released in gaseous form.

A method and system for combination of GTL with methane hydrate reservoirs comprise the use of a GTL unit where the waste heat from the GTL system is used for the dissociation of hydrates into natural gas and water, has been described in US 2010/0163231 A1 to Chevron. US 6620091 B1 , Chevron, also comprises the use of a GTL unit, but only as to use water from the GTL unit to scrub C0₂ from a hydrocarbon reservoir.

It is an aim of the present invention to provide an improved process for the conversion of natural gas to essentially hydrocarbons by the FT process in a GTL plant.

A further aim of the present invention is to provide an improved process for the extraction of natural gas from hydrate reservoirs. According to a first aspect of the present invention there is provided a process for the conversion of natural gas to essentially hydrocarbons by the Fischer-Tropsch process in a GTL plant, the process comprising the steps of:

(a) feeding natural gas to the GTL plant for reforming to syngas and Fischer- Tropsch conversion, at least some of the gas being produced from a gas hydrate type reservoir;

(b) generating carbon dioxide during the process of step (a), separating at least some of the generated carbon dioxide from process or exhaust streams of the reforming and/or conversion process and feeding the separated carbon dioxide into a gas hydrate type reservoir for further liberation of the gas from the hydrate by exchange with the carbon dioxide; and

(c) feeding the gas liberated in step (b) to the GTL plant for conversion to essentially hydrocarbons.

A second aspect of the present invention provides an integrated gas extraction and gas-to-liquid processing plant, the plant comprising:

(a) a gas-to-liquid processing plant having at least a syngas preparation unit and a Fischer-Tropsch synthesis unit;

(b) at least one injection well extending from the GTL plant to a gas hydrate reservoir wherein carbon dioxide gas is separated from process or exhaust streams of at least one of the syngas preparation unit or Fischer-Tropsch synthesis unit and fed through the at least one injection well; and

(c) at least one production well extending from the reservoir to the GTL plant for producing natural gas to the GTL plant for conversion, at least some of the gas being produced from a gas hydrate reservoir.

In the context of this disclosure, gas hydrate means a solid hydrate mainly consisting of hydrated methane but may include lesser amounts of other hydrocarbon or inert gases, as well as impurity components, typically hydrogen sulfide.

All or some of the carbon dioxide obtained from the GTL process and plant may be fed into the hydrate reservoir for methane liberation by exchange with carbon dioxide. All or some of the CO2 may be obtained from process streams from the FT synthesis unit and/or from one or more syngas streams from the syngas preparation unit. At least some of the C02 for sequestration may be obtained from alternative sources to the GTL process and plant.

Preferably, at least 50% of the CO2 generated by the FT-process of the GTL process is sequestered, more preferably at least 60%, more preferably still, at least 80%.

The syngas preparation unit preferably includes a reforming unit. More preferably, autothermal reforming of the gas is carried out. Carbon dioxide capturing units for obtaining carbon dioxide from the GTL process and plant for injection into a reservoir may comprise any known or developmental technology, such as sorption techniques or membrane separation.

In a preferred, but optional, embodiment of the present invention, additional methane feed for the GTL process or plant is obtained by thermal decomposition of the gas hydrate in the reservoir. Preferably, thermal decomposition is achieved by the addition of steam to the reservoir. More preferably still, at least some of the steam is generated during the GTL process and fed to the reservoir for thermal decomposition of the hydrate. The carbon dioxide gas and steam may be fed through the same or different injection wells. Multiple wells of each type may be used.

Steam may be added to the reservoir in an amount corresponding to 10-80% of the steam generated from the FT process of the GTL plant or process, preferably 20-65%, more preferably 30-50%. Some or all of this steam may be generated by controlling the reaction temperature of the FT process. At least some of the steam for thermal decomposition of the gas hydrate may be obtained from cooling of the syngas.

In a preferred embodiment of the process and plant of the present invention, controlled retracting injection point (CRIP) technology is used for the injection of steam and/or CO2 to the hydrate reservoir.

It is to be appreciated that all or some of the natural gas feed for the GTL process and plant may be achieved from a gas hydrate reservoir. It is preferable for the gas hydrate reservoir to consist of at least 60% methane hydrate, more preferably at least 80% methane hydrate, especially at least 95% methane hydrate. The reservoir preferably has an overburden of at least 20m, more preferably at least 100m, more preferably still at least 300m. The overburden ideally includes an essentially non-porous cap rock. This has the advantage of mitigating or avoiding leakage of gas to the atmosphere. The hydrate zone below should have a certain degree of permeability for efficient transportation of gas, thereby ensuring an attractive production rate of gas is achievable.

The decomposition enthalpy of the gas hydrate is preferably between 40 and 75 kJ/molC, more preferably between 45 and 70 kJ/molC, more preferably still between 50 and 60 kJ/molC. The carbon efficiency of the GTL plant may be between 50 and 85 %, preferably between 60 and 80 %, more preferably between 70 and 80%.

The GTL processing plant and method may comprise any variety of gas reforming technologies and principles. The particular characteristics of the integrated process and plant employed for a given hydrate reservoir will be dependent upon a number of factors, such as geometrical layout, gas flows, heat balances, temperature gradients, decomposition and formation rates, reservoir permeability and the like.

The GTL plant may include a waste heat boiler and, optionally, a super heater for cooling the hot syngas produced during the GTL process thereby generating steam. A slurry FT-reactor may be used in the plant. The operating temperature of the reactor is preferably between 180 and 360 °C, more preferably between 210 and 280 °C, more preferably still between 220 and 260 °C. The FT synthesis unit may include a tailgas recycle line to the syngas preparation unit. At least a portion of this tailgas may be fed to at least one water-gas shift reactor.

Additional syngas may be generated by steam reforming of at least a portion of the feed gas in an optional hydrogen manufacturing unit. The additional syngas generated may be fed to at least one water-gas shift reactor. Tailgas containing carbon dioxide may be fed to this water-gas shift reactor of the hydrogen manufacturing unit for further generation of CO2_, the CO2 being separated off for optional injection into the hydrate reservoir. The hydrogen manufacturing unit also produces a separate hydrogen rich stream, at least a portion of which is fed to the FT unit. Alternatively or additionally, at least a portion of the hydrogen rich stream is used as fuel gas. Additional carbon dioxide gas may be obtained from the preheating of the natural gas fed to the syngas preparation units, in particular the main gas reformer and/or from firing of the steam reformer in the hydrogen manufacturing unit. It is a matter of optimization as to how much of a particular source of carbon dioxide from the various process and exhaust streams of the GTL plant is made available for methane hydrate decomposition.

It is regarded as an advantage to feed carbon dioxide to the gas hydrate reservoir under pressure as this will favour the formation of C02-hydrates over methane- hydrates. This may be accomplished easily by separating the carbon dioxide from high pressure process streams of the GTL plant. Total pressures will typically be in the range 15-50 bar (150-500 N cm²), preferably between 20-35 bar (200-350 N cm²) whereas the carbon dioxide partial pressure may be in the range 2-20 bar (20-200 N cm²), preferably 5-15 bar (50-150 N cm²). Moreover, it may be preferable, or even necessary, to compress further the carbon dioxide before injection for facilitation of the exchange process or to make sure that the pressure complies with the gas-hydrate reservoir pressure.

The liquid hydrocarbon products generated by the GTL processing plant of the present invention are preferably stored on site and then shipped to market.

It is to be appreciated that the produced gas and water are likely to be produced to the surface in the same production well and separated at the surface. It is envisaged that all production facilities are located on-shore but in an alternative embodiment some or all production facilities may be located off-shore.

The present invention will now be further described in relation to the following

Examples which investigate the relationship between GTL carbon efficiency and the amount of methane liberated from a reservoir, and by reference to the accompanying drawings in which:

Figure 1 is a schematic process-layout of a GTL plant according to one embodiment of the present invention;

Figure 2 is a schematic diagram illustrating the integration of gas extraction from hydrate reservoirs with GTL processing; Figure 3 is a plot illustrating the amount of methane gas liberated from exchange with 100% carbon dioxide from a GTL plant, and the additional methane needed as GTL feed; and

Figure 4 is a plot illustrating the amount of methane gas liberated from exchange with 60% carbon dioxide from a GTL plant, and the additional methane needed as GTL feed.

Figure 1 of the accompanying drawings illustrates an example of a process-layout of a GTL plant according to the present invention, although it is to be understood that the invention is not limited as such. Although designed to give an energy efficient plant with special possibilities for C0₂ capture, it should be understood that several options for the lay-out exist. In particular, there are multiple ways of arranging recycle streams in the plant. The three main sections 1 , 2 and 3 of the plant are shown in Figure 1 , consisting of a syngas preparation unit 1 , an optional hydrogen manufacturing unit (HMU) 2 and a further processing unit 3. The syngas preparation section 1 has a feed conditioning unit 1 1 and a reforming section 12 where natural gas feed 14 from a methane hydrate reservoir is reformed to a gas mixture 18 suitable as a make-up gas for further conversion to mainly hydrocarbon products in section 3. The HMU 2 is optional for the production of a smaller amount of hydrogen that is used for upgrading of the raw Fischer-Tropsch (FT) products and possibly as added hydrogen to the FT-section feed stream (s). The natural gas feed 14, 24 used in sections 1 and 2 consists mainly of methane, but normally comprises smaller amounts of other components such as light hydrocarbons, e.g. ethane, propane and butane, a certain amount of C0₂ as well as the inert components nitrogen and noble gases. Mercury, sulfur compounds and possibly other impurities are reduced to very low levels in the feed conditioning unit 1 1 ready for the subsequent processing units and catalysts. At least part of the feed conditioning unit may be common for the raw feeds 14 and 24. The gas conditioning unit 11 also preheats the gas 14 before it enters the reforming unit(s) 12. Normally this heating is done in fired heaters using available fuel gas and/or natural gas. The reforming in 12 reforms the pre-treated natural gas to syngas, line 18. Syngas is a mixture mainly comprising CO and hydrogen, but normally also contains amounts of methane, C0₂, steam and other inert components. There are multiple types of gas reforming technologies and principles, but for GTL it is often found optimal to employ autothermal reforming where the natural gas is reacted with oxygen 17 in a burner and further converted over a catalyst. The oxygen is made from air 16 in an air separation unit 13. In this way an extensive load of nitrogen is avoided in the downstream processing units. In particular, using highly concentrated oxygen facilitates removal of C0₂. Other optional reforming technologies include steam reforming, partial oxidation, combined reforming, heat exchange reforming and gas heated reforming as well as employing an oxygen transport membrane. Sometimes a prereformer is included if the natural gas is rich in higher hydrocarbons than methane. For the FT reaction it can be advantageous to remove steam from the syngas in 18 by condensation before entering a synthesis reactor 31 in the further processing unit 3.

C0₂ produced in the process is normally regarded as an inert in the FT-reaction 31 and acts to reduce the partial pressures of CO and hydrogen in the syngas and therefore reduces the overall productivity. The inventors have surprisingly found that it is a significant advantage to remove the C0₂ in unit 41 , not only to increase overall productivity, but also because the C0₂ in line 45 can be used to decompose methane hydrate and therefore facilitate the supply of natural gas to the GTL plant itself.

The syngas depleted of C0₂ and steam is transferred in line 19 to the FT synthesis unit 31. This unit may comprise a single FT-reactor, but may also contain two or more reactors. FT-reactors can be of different types, but most frequently employed are slurry or fixed-bed reactors with cobalt or iron based catalysts. There are often one or more gas recycle streams internally within the FT synthesis unit 31 from exit to feed of the reactor or rectors. From the recycle (not shown in the figure) water typically is removed. This configuration secures high conversion of the syngas and is also used to optimize the H₂/CO ratio in the feed. The desired products of the FT-synthesis in 31 are miscellaneous hydrocarbons and/or oxygenates. In one type of design, hydrocarbon wax yield is maximized for further hydrocracking and hydroisomerization in the product upgrading unit 32 to naphtha, jet fuel and diesel. Wax in itself, base oil for lubricants and paraffins for further synthesis of detergents are other possible favourable products. The tail gas 34 from the FT- synthesis unit is recycled to the reforming section 12 for further reforming of light hydrocarbons from the FT-reaction. Any C0₂ will also participate in adjusting the H2/CO ratio of 18, possibly to a value slightly below 2. A smaller portion of the tail gas 34 may be purged to the fuel gas system. However, in the flow-sheet of Figure 1 , this process stream 35 instead is directed to the CO shift reactor 22 of the hydrogen manufacturing section 2 as additional C0₂ then can be captured in the separator 42. In the reforming reactor 21 it is preferred to use steam reforming due to the high hydrogen yield in the product gas 25 that is further increased by converting CO and steam to hydrogen and C0₂ to give 26. After separating C0₂, the highly concentrated hydrogen in 27 can be further purified in the unit 23. This can be Pressure Swing Adsorption (PSA) that gives essentially pure hydrogen 28 for further use in product upgrading and optionally for use in the FT section 31 and in the feed conditioning unit 11. The PSA off gas 29 is used as fuel gas.

The C0₂ capturing units 41 and 42 can be of any known or developmental technology using sorption techniques or membrane separation, including sorption by refrigerated methanol (Rectisol process), glycol derivatives (Selexol process) or ammine wash. Apart from the C0₂ streams 45 and 46, further carbon dioxide will be generated in fired heaters, e.g. preheating of the gas fed to the reformer(s) as well as firing of the steam reformer 21 itself. These latter flue gases are normally rich in nitrogen, unless e.g. hydrogen is used as fuel, and the cost of separation therefore is considerable compared to the higher concentration high pressure process gases. It is therefore a matter of optimization how much C0₂ is available for the methane hydrate decomposition. The energy flows are not shown in Fig.1. A GTL plant is self-supplied with process energy and often a surplus energy can be exported as steam or converted to electricity in a steam turbine. Steam comes from two types of sources. The FT-reaction is exothermic and the temperature conveniently is controlled by evaporation of water. In addition water is used to cool down the hot synthesis gases in streams 18 and 25, e.g. by using a waste heat boiler and a superheater. However, separation, possibly compression and injection of C0₂ will require extra energy. Steam is also an attractive energy source to assist in decomposition of the gas hydrate, and it is suggested that the low pressure steam from the FT-synthesis is particularly suited. Thus it is convenient to design the overall gas hydrate supplied GTL plant to be energy neutral. One alternative way of process design of the GTL plant is not to focus on overall carbon and energy efficiency, but rather on a simple cost effective design where recycle and heat integration are relaxed. One such possibility is a once through configuration possibly including two consecutive FT-reactors. The integration of gas extraction from hydrate reservoirs with the GTL processing described above is shown schematically in Figure 2 of the accompanying drawings. The integrated concept consists of two main parts, the GTL facility 5 and the subsurface formations 6. The GTL plant 51 has been described above as detailed in Figure 1. The hydrocarbon products, essentially naphtha, jet fuel, diesel and wax, can be piped through lines 55 to storage facilities for further shipment 56 to market. At least part of the produced C0₂, but preferably also steam, are introduced into the gas hydrate reservoir 63 through the lines 57 and 58, respectively.

In a preferred embodiment of the present invention, the introduction of a stable clathrate forming agent and heat is done through the CRIP method (Controlled Retracting Injection Point process) meaning that the injection points for the carbon dioxide and steam are retracted with time in line with the desired gas production. These injection points are illustrated in Fig.2 by the arrow heads of the horizontal parts of wells 57 and 58 and serve only to illustrate the principle. Details of geometry of injection wells, as well as production wells 65 and 66, and how they are operated will be specific for a given project and reservoir. Injection and production wells can be arranged in a co-current or counter-current fashion. More conventional vertical wells can also be used. For example, the injection wells can be essentially horizontal, whereas the production wells are vertical. The production well(s) can also consist of a portion perpendicular to a portion of the injection well(s). It will be an advantage to develop a production strategy and models that encompasses factors like geometrical lay-out, gas flows, heat balances, temperature gradients, decomposition and formation rates, reservoir permeability and the like. Normally there will be multiple wells of each type.

Below the surface 61 there can be an overburden 62 before the hydrate reservoir is found at larger depths. It will be an advantage if the overburden has a low permeability and thus forms a cap that prevents any gas leakage to the surface. However, the actual position and shape of the hydrate reservoir relative to the surface will depend on pressure and temperature at the given location. In some cases there will be no overburden. It should also be understood that many hydrate reservoirs are located offshore varying from shallow to large depths of water. In that case 61 is the ocean floor. The sea level is not shown in the figure. For an off-shore reservoir, the GTL plant can be placed on a floating barge or production ship, or alternatively the appropriate lines can be extended to shore. For clarity, separate production wells and lines 65 and 66 of water and natural gas, respectively, are shown. However, produced water and gas will normally flow through the same lines and will have to be separated at the surface. It should be noted that there is likely to be a smaller or larger part of the injected C0₂ that will not be converted to C0₂-hydrates and therefore will be recycled through the production line(s). This C0₂ will be part of the feed 14, or alternatively, may be separated for recycle to the reservoir. Before entering the reformer(s) of the GTL plant all the water need not be taken out as in fact steam will be needed to be mixed with the gas in the feeds. Typically the steam to carbon ratio (S/C) varies between 0.3 and 3, with ratios around or below 1 for autothermal reforming and values above 2 for steam reforming. The water to carbon ratio in the hydrate reservoir is larger than 5, first due to the composition of the hydrate itself, second because the hydrate normally is associated with a separate phase of liquid water or ice. Therefore, large amounts of excess water will in any case be produced and will need to be disposed of. Binding some of this water in the reservoir itself to C0₂ will provide the additional benefit of easing the water management system.

The following examples demonstrate that the methane produced by exchanging C0₂ for methane in the hydrate is unlikely to be enough for feeding the GTL plant. This is because it may be uneconomical to separate all the C0₂ available in the GTL plant, but also because the major part of the methane feed will end up as hydrocarbon products, not carbon dioxide. Therefore, additional methane will have to be produced by any other method available. Pressure release is a method suitable for deep reservoirs. However, there are limitations due to temperature drop as the hydrate decomposes. This will partly be compensated by heat flow from the surroundings, but additional heating may be required. Geothermal heating is an option as is combustion of some gas hydrate in situ in the reservoir. The GTL plant will be equipped with an air compressor, at least if electricity is produced, and part of this compressed air can be directed to the reservoir for combustion. As pointed out, however, the most obvious option is to use surplus steam from the GTL plant to decompose the gas hydrate. This steam can be directed to the reservoir in several ways, one of which is illustrated in Figure 2. It can also be advantageous to combine steam injection with the pipes for C0₂ injection and/or the production wells, e.g. through co-axial piping. In this way any production and safety issues due to unforeseen formation of chlathrates in the pipes will be relieved. To be able to supply the GTL plant with sufficient gas, the different production options can be practiced in different parts of the reservoir or in different reservoirs.

Example 1 An energy efficient GTL plant can have a carbon efficiency to hydrocarbon products of ca. 75 %, whereas a less efficient design will reduce the efficiency to e.g. 65 % or even lower. The carbon efficiency of what may be considered to be an ideal plant is around 85 %. If, as a limiting case, it is assumed that 100 % of the C0₂ generated can be separated and used stoichiometrically for exchange with methane in the gas hydrate, there will be a relationship between the GTL carbon efficiency and the amount of methane liberated from the reservoir, as shown in Figure 3. It is seen that for a plant of 70 % carbon efficiency, 30 % of the methane feed needed can be supplied by exchange with C0₂. The rest of the gas will have to be produced by alternative means, e.g. using the steam generated in the FT-process. It is thus clear that the C0₂ storage capacity of the gas hydrate reservoir is well above what is needed for complete storage of all C0₂ generated in the GTL plant. Thus it is demonstrated that the potential for greenhouse gas mitigation is excellent.

Example 2

Figure 4 shows the relationship between the GTL carbon efficiency and the amount of carbon liberated from the reservoir. It is similar to Example 1 above except that only 60 % of the C0₂ generated in the GTL-plant is separated and used for methane production from the gas hydrate reservoir. Referring to the GTL lay-out in Figure 1 above, this corresponds to the streams 45 and 46 of Figure 1 that are process streams at elevated pressures where C0₂ capture and injection is cost effective. The effect on the potential for liberating methane from the hydrate reservoir is shown in Figure 4, and it is seen that for a plant with 70 % carbon efficiency ca. 18 % of the gas feed can be produced in this way. It is possible to expand the hydrogen unit 2 to generate more hydrogen that can be used as fuel gas for fired heaters. The potential for C0₂ separation from these process streams then increases to about 75 %.

Example 3

As shown in Examples 1 and 2 above, ca. 60-85% of the methane fed to the GTL plant will have to be produced by other means than using C0₂. In this example, it is assumed that steam generated from control of the exothermic FT-reaction (31 in Figure 1) is used for decomposition of methane hydrate. Different values for the decomposition enthalpy have been reported in the literature and the values depend on parameters like composition and structure of the hydrate and to what extent the hydrate is found as small crystals in a porous rock or in sand formations. As an average value, this example used 55 kJ/molC for the decomposition enthalpy. This can be compared to ca. 200 kJ/molC available from the overall FT reaction:

CO (g) + 2 H₂ (g)→· -CH₂- (I) + H₂0 (g)

as well as condensation of the water in the reservoir. The available heat from the FT- reaction has to be reduced according to the carbon efficiency in the GTL process in order to make an overall balance of heat available for producing the methane needed, ref. Figures 1 and 2. In addition, a certain loss of steam is estimated in the transfer from the process unit to the reservoir of 10-30 %.

Simulation data given in Table 1 below show that approximately 30 % to at least 50 % of the steam produced by the FT-process will be needed for decomposition of the hydrate. There will also be steam available from other sources, notably from cooling of the syngas stream 18. On the other hand, energy will be needed for other purposes like operation of the ASU unit and gas compression. Therefore an overall energy optimization of the entire concept of gas hydrate-GTL integration should be performed.

Table 1 : Portion of FT-steam needed for hydrate decomposition.

* From Figures 1 and 2. It is clear from the above description and examples that at least part of the C0₂ generated from a GTL plant may be separated comparatively easily from the process streams of the GTL plant and used to extract natural gas, mainly methane, from subterranean or near surface gas hydrate reservoirs. The C0₂ binds favourably to the hydrate in the reservoir thereby expelling methane and possibly other energy gases. These gases are then fed to the GTL plant. The C0₂ is stored as hydrate, providing the added benefit of greenhouse gas mitigation. A further optional aspect of the invention uses steam available from the GTL plant for further hydrate decomposition and the liberation of gas from the hydrate as needed for feeding to the GTL plant. The stored C0₂ hydrate in the reservoir brought about by the present invention is more stable than methane hydrates meaning that the risk of gas leakage to the atmosphere at a later date is mitigated. Furthermore, water management issues are relieved because the amount of produced water with the methane is reduced (or even possibly eliminated) as the water remains condensed in the reservoir as a hydrate. Cooling water is required for the FT-plant and the availability of low temperature water will make this process more efficient. Moreover, the location of the GTL plant directly above or close to the reservoir reduces or eliminates gas transportation pipe lines. This is a particular advantage in rural or arctic environments where the liquid GTL products are transported to market with relative ease. Thus, the present invention reduces the environmental impact of gas extraction and GTL processing.

In addition to the steam and carbon dioxide being used for extraction of the gas from the hydrate, it may be necessary to produce additional gas by heat decomposition of the gas hydrate. Such heat assisted gas hydrate decomposition may be performed by in situ combustion of the hydrate. It is well known that gas hydrate burns when exposed to air or oxygen. Compressed air and/or oxygen will be available from the front end of the GTL plant which may be used for in situ combustion of the hydrate. Furthermore, electricity may be produced from the GTL steam on site for all plant operations, including well maintenance and expansion.

Claims

CLAIMS:

1. A process for the conversion of natural gas to essentially hydrocarbons by the Fischer-Tropsch process in a gas to liquid (GTL) plant, the process comprising the steps of:

(b) generating carbon dioxide during the process of step (a), separating at least some of the generated carbon dioxide from process or exhaust streams of the reforming and/or conversion process and feeding the separated carbon dioxide into a gas hydrate type reservoir for further liberation of gas from the hydrate by exchange with the carbon dioxide; and

2. A process according to claim 1 wherein all of the natural gas for the conversion is obtained from a gas hydrate type reservoir.

3. A process according to claim 1 or claim 2, wherein all or some of the carbon dioxide is generated from process streams of the Fischer-Tropsch (FT) conversion.

4. A process according to any one of claims 1 to 3 wherein at least 50% of the CO2 generated by the GTL process is sequestered in the reservoir.

5. A process according to any one of claims 1 to 4 wherein all or some of the carbon dioxide is generated from one or more syngas streams of the GTL process.

6. A process according to any one of claims 1 to 5 wherein at least some of the CO2 for sequestration is obtained from alternative sources to the GTL process.

7. A process according to any one of the preceding claims wherein the carbon dioxide is fed to the gas hydrate reservoir at a pressure of 2-20 bars (20-200 N cm²).

8. A process according to any one of the preceding claims wherein the carbon dioxide is compressed to a pressure of 0-10 bar (0-100 N cm²) above the reservoir pressure.

9. A process according to claim 8 wherein the carbon dioxide is compressed to a pressure that complies with the reservoir pressure.

10. A process according to any one of the preceding claims wherein conversion of the natural gas to syngas includes autothermal reforming.

1 1. A process according to any one of the preceding claims further comprising thermal decomposition of the gas hydrate in the reservoir for use in step (a).

12. A process according to claim 11 wherein thermal decomposition is achieved by the addition of steam to the reservoir.

13. A process according to claim 12 wherein at least some of the steam is generated during the GTL process of step (a) and is fed to the reservoir for thermal decomposition of the hydrate.

14. A process according to claim 13 wherein steam is added to the reservoir in an amount corresponding to 10-80% of the steam generated from the FT conversion of the GTL process.

15. A process according to claim 13 or claim 14 wherein at least some of the steam for thermal decomposition of the gas hydrate is obtained from cooling of syngas produced by the GTL process.

16. A process according to any one of the preceding claims wherein the carbon dioxide is fed into the reservoir by controlled retracting injection point technology.

17. A process according to any one of claims 12 to 16 wherein the steam is fed into the reservoir by controlled retracting injection point technology.

18. A process according to any one of the preceding claims further comprising a tailgas produced from the FT conversion process which is recycled for preparation of the syngas in the GTL plant.

19. A process according to claim 18 wherein the tailgas includes carbon dioxide gas for separation and injection into the hydrate reservoir.

20. A process according to any one of the preceding claims further comprising steam reforming of an additional gas feed to form a hydrogen rich syngas stream.

21. A process according to claim 20 wherein at least a portion of the hydrogen rich stream is used in the FT conversion process.

22. A process according to any one of the preceding claims wherein additional carbon dioxide gas is obtained from preheating of the natural gas prior to preparation of the syngas.

23. A process according to claim 1 or claim 2 wherein the natural gas feed to the GTL plant includes carbon dioxide gas in the produced gas.

24. A process according to claim 23 wherein at least part of the produced carbon dioxide gas is separated from the natural gas and injected into the reservoir.

25. An integrated gas extraction and gas-to-liquid processing plant, the plant comprising:

26. A plant as claimed in claim 25 further comprising at least one carbon dioxide capturing unit for separation of the carbon dioxide gas for injecting through the well.

27. A plant as claimed in claim 25 or 26 further comprising an injection well for injecting steam produced by the syngas preparation unit and/or FT synthesis unit, the injection well be the same or separate to the injection well for the carbon dioxide.

28. A plant as claimed in any one of claims 25 to 27 wherein the injection wells include controlled retracting injection points.

29. A plant as claimed in any one of claims 25 to 28 further comprising a hydrogen manufacturing unit.

30. A plant as claimed in any one of claims 25 to 29 wherein the GTL plant is located off-shore on a barge, FPSO (floating, production and offloading) or platform.