WO2019224326A1

WO2019224326A1 - Process for hydrogen generation

Info

Publication number: WO2019224326A1
Application number: PCT/EP2019/063382
Authority: WO
Inventors: Leonid Surguchev; Michael SURGUCHEV; Roman BERENBLYUM
Original assignee: Hydrogen Source As
Priority date: 2018-05-23
Filing date: 2019-05-23
Publication date: 2019-11-28
Also published as: AU2019274775A1; GB201808433D0; EP3797084A1; CA3100233A1

Abstract

The present invention relates to a process for hydrogen generation comprising: introducing a catalyst or precursor thereto into a hydrocarbon containing zone in a subterranean hydrocarbon reservoir (preferably into a hydrocarbon gas-containing zone in a subterranean gas reservoir); raising the temperature in said reservoir to a temperature at which catalysed conversion of hydrocarbon to hydrogen occurs; and recovering a hydrogen stream via a membrane filter installed in a production well, preferably wherein said production well is vertical or deviated vertical.

Description

Process for hydrogen generation

This invention relates to a process of Hydrogen Generation from Hydrocarbon, e.g. hydrocarbon gas, Sub-terrain (HGHS), preferably using only vertical or slightly deviated injection and production wells. The process may advantageously involve segregation and sequestration of carbon dioxide in situ. The process of the invention may be carried out in a field onshore or offshore, e.g. a natural gas field, oil field, oil with a gas cap or gas condensate field, light oil-gas field or a coal field, in order to generate and produce hydrogen, separate and sequestrate CO2 in the same sub-terrain field. The hydrogen produced in this way has a variety of uses, e.g. it may be used for energy production, for example, in fuel cells, or in heavy oil hydrogenation or ammonia production, e.g. for fertilizers.

Hydrogen can be converted from sub-terrain hydrocarbons by means of a variety of chemical reactions carried out in the reservoir.

For example, the reaction of water with hydrocarbon gas yields carbon monoxide and hydrogen in the endothermic Steam Reforming (SR) reactions:

CH₄ + H₂0 CO + 3H₂ DH = +206 kJ/mol

C_nH_2n+2 + nH₂0 nCO + (2n+1 )H₂ + DH

The carbon monoxide resulting from the SR reaction can then be reacted with water to produce carbon dioxide and hydrogen in the slightly exothermic Water Gas-Shift Reaction (WGSR):

CO + H₂0 C0₂ + H₂ DH = - 41 kJ/mol

Another reaction which can be used to make hydrogen, either alone or in

combination with the SR and WGSR reactions, is Methane Catalytic Cracking (MCC), which proceeds as follows:

CH₄ C + 2H₂ DH = +75 kJ/mol

The catalytic cracking, e.g. MCC, can be achieved at temperatures above 500°C.

Alternatively, oxygen may be incompletely reacted with methane (or other hydrocarbons) to produce carbon monoxide and hydrogen in the following exothermic reaction:

2CH₄ + 0₂ 2CO + 4H₂ DH = -75 kJ/mol

Similar reactions will also happen with any other type of hydrocarbons, for example for heavier paraffins:

2C_nH_2n+2 + n0₂ 2nCO + (2n+2)H₂ + DH

Heavier hydrocarbon gases may also be involved in a set of other exothermic chemical reactions resulting in hydrogen generation or splitting of e.g. carbon-carbon or carbon-hydrogen bonds shown here with ethane as an example:

C₂H₆ -> C₂H₄ + H₂ DH = -138 kJ/mol

C₂H₆ + H₂ -> 2CH₄ DH = -85 kJ/mol

As can be seen, the main by-product of hydrogen generation is carbon dioxide, which, in current industrial processes, must be captured and sequestered to prevent environmental damage. Currently some millions of tons of carbon dioxide are sequestered by being injected into subterranean geological formations.

The present invention relates to the performance of a catalytic process of hydrogen generation from a hydrocarbon-containing solid, liquid or gas, preferably a gas or gas mixture, e.g. natural gas, in situ within a subterranean geological formation, e.g. in a carbonate reservoir, a sandstone reservoir, a shale reservoir, a tight low permeable reservoir, with or without C0₂ content in the gas. In this way, several beneficial effects are achieved: firstly, hydrogen may be separated from other gas components in situ and produced from the reservoir; secondly, the resultant carbon dioxide and black carbon are simultaneously sequestered; and thirdly, hydrocarbon reservoirs, e.g. gas reservoirs such as natural gas reservoirs, which are of low productivity or depleted and abandoned as non- commercial deposits may have their natural gas reserves converted to hydrogen in situ and commercially produced.

This in situ production is achieved by placing a catalyst for hydrogen generation or precursor thereto within the reservoir (e.g. within the formation (e.g. rock or other porous medium) or a borehole (well) in the formation), e.g. by means of an injection well, and raising the temperature within the catalyst or catalyst precursor-containing zone of the reservoir to a temperature at which catalysed conversion to hydrogen occurs.

The term "formation" as used herein for convenience means the material from which the reservoir is formed, whether a single medium (e.g. sandstone) or a dual or multiple medium (e.g. carbonates/sandstones/voids, etc.), i.e. the material containing the

hydrocarbon, e.g. the hydrocarbon-containing gas, and possibly also water.

Thus, viewed from one aspect, the invention provides a process for hydrogen generation comprising introducing a catalyst or precursor thereto into a hydrocarbon- containing zone (preferably a hydrocarbon gas containing zone) in a subterranean hydrocarbon reservoir (preferably a gas reservoir), raising the temperature in said reservoir to a temperature at which catalysed conversion of hydrocarbon to hydrogen occurs, and recovering a hydrogen stream from the reservoir via a membrane filter installed in a production well. Preferably, the process involves recovering hydrogen from an extraction section of a production well located above said zone. The hydrogen stream may be recovered from said reservoir by means of a production well, preferably wherein said production well is vertical or deviated vertical, i.e. has an inclination of 0-45°, preferably 0- 20°, from vertical.

In another aspect, the process for hydrogen generation comprises introducing a catalyst or precursor in a water soluble form thereto injected into a porous or fractured medium hydrocarbon, e.g. hydrocarbon oil or gas, containing zone in a subterranean hydrocarbon reservoir, raising the temperature in said reservoir to a temperature at which catalysed conversion of hydrocarbon to hydrogen occurs, recovering a hydrogen stream via a production well, and optionally recovering said hydrogen stream from said subterranean hydrocarbon reservoir by means of a production well, preferably wherein said production well is vertical or deviated vertical. The process preferably achieves commercial purity of hydrogen in the production stream from the well in the HGHS process with segregation of generated in situ hydrogen from the heavier gas components and fluids present in gas and liquid phases, and gas separation by inert membrane filters installed downhole in the production well or at the well head to obtain a required commercial purity of hydrogen in the production stream, if gravity segregation of hydrogen inside the reservoir is not complete within the field project time frame, and other gas components might be still present in the production stream.

Typically, hydrogen will be segregated in situ by means of gravity, e.g. in the porous media (e.g. single and/or dual porous media). An example of single porous media is sandstone rock, whereas dual porous media may be fractured carbonate rock. This gravity separation accumulates hydrogen in the upper parts of the reservoir (e.g. the crest) and may occur before, after and/or simultaneously with, the recovery of the hydrogen stream via the membrane filter. The segregation of light and heavier gas components by gravity forces in the reservoir is a process requiring a certain time period, the length of which will depend on specific reservoir properties (e.g. permeability, wettability) and conditions (e.g. pressure and temperature). Preferably, the gravity segregation takes place in the field scale, e.g.

throughout the majority of the field.

Using a membrane (e.g. downhole) in the production well enables fast, e.g. almost simultaneous and effective separation of hydrogen from other gas components which may be present in the reservoir.

The HGHS process of the invention is advantageously one of transforming a hydrocarbon-containing reservoir (e.g. gas-containing hydrocarbon reservoir) or a hydrocarbon-containing gas reservoir into a hydrogen reservoir from which hydrogen can be recovered as and when required.

The process may comprise the capture of produced carbon dioxide in situ.

Preferably, the process is performed in a natural gas field onshore or offshore. The catalysed conversion of hydrocarbon to hydrogen may occur by means of one or more of the reactions discussed above, e.g. selected from steam reforming (SR), water gas shift reaction (WGSR) and methane catalytic cracking (MCC) reactions.

The catalysed conversion of hydrocarbon to hydrogen produces a product mixture containing hydrogen. However, this will typically include hydrogen in combination with undesirable amounts of other reaction products and unreacted materials, e.g. CO2, CO, possibly NO_x, steam/water, carbon and/or hydrocarbons. In order to produce a purified hydrogen stream suitable for further applications, a membrane filter, preferably inert, is used in a production well, preferably down-hole or at the well head, for example, to separate hydrogen and/or to improve hydrogen stream purity. The membrane filter is preferably configured such that it does only this. The hydrogen stream produced by the membrane filtration step can thus be recovered, e.g. via a production well, and used or stored on the surface. The hydrogen stream recovered via the membrane filter (e.g. that downstream of the membrane, where the stream direction is that of the hydrogen exiting the reservoir via a production well) will typically comprise at least 70 vol. % hydrogen, preferably at least 80 vol. %, especially at least 90 vol.%, e.g. at least 95 vol. %. A hydrogen content of at least 98 vol. % is particularly preferred.

Suitable membrane filters will be apparent to those skilled in the art of hydrogen production and purification. By“membrane filter” is meant any suitable membrane that selectively filters hydrogen from other components. Examples are membranes, porous ceramic membranes, palladium coated membranes and the like.

The catalyst for hydrogen generation is preferably a metal-based catalyst. The metal- based catalyst that is introduced may be a material which is already catalytically active (e.g. a transition metal), preferably a porous or "sponge" metal (for example Raney® nickel), or a material (e.g. a catalyst precursor) which will transform in situ, for example by thermal decomposition, into a catalytically active material. Many materials are known to be catalytically active for converting hydrocarbons to produce hydrogen and may be used in the process of the invention. Preferably, the catalyst should comprise nickel, platinum, and/or palladium, or alloys thereof.

Catalytically active particulates, for example metal or alloy particles, or metals supported on carrier particles, for example silica, alumina or zirconia particles, may be introduced into the reservoir by first fracturing a region of the reservoir around an injection well, for example by overpressure or by use of explosives, and then pumping in a dispersion of the particulate in a carrier liquid, for example water or a hydrocarbon. Preferably, the catalyst or precursor thereto is introduced into the reservoir by means of an injection well.

Particularly preferably, the catalyst or precursor thereto may be applied in the form of a solution or suspension, preferably a solution, for example in water or in organic solvent (such as a hydrocarbon which itself may be liquid or gaseous at atmospheric pressure). In the case of the precursor, the solution or suspension, preferably a solution, may be one of a metal compound which is decomposable, e.g. thermally decomposable, to form a catalytically active species, e.g. the precursor reacts or decomposes to form the catalyst.

The catalyst and/or precursor may be in the form of particles of the material (e.g. metal). Preferably, the catalyst or precursor thereto is dissolved in an aqueous solution. Preferably the catalyst precursor is a metal compound, or a solution thereof, which is thermally decomposable to a catalytically active form or species.

Examples of such metal compounds or precursors include metal salts such as carbonyls, alkyls, nitrates, sulphates, carbonates, carboxylates (e.g. formates, acetates, propionates, etc.), humic acid salt, and such like. Double complexes, e.g. of palladium or platinum and nickel or zinc may, for example, be used. Further examples include metal humates which are known to thermally decompose in the temperature range 100-1000°C, and double salts with oxalate and ammonium which are known to thermally decompose in the range 200-400°C. The use of metal compounds which thermally decompose to produce particles of the catalytically active metal at temperatures in the range of 150-1100°C, especially 200-700°C, is especially preferred. Where a metal compound solution is applied, this may be a solution of a single metal compound or of two or more compounds of the same or different metals, generally transition metals, especially nickel. The concentrations of the metal compound in the solution will preferably be at or close to saturation.

The catalyst or precursor thereto may be applied over as large a horizontal distribution as possible, e.g. using a deviated section of an injection well (e.g. a section with an inclination other than 0° from vertical, e.g. up to 45° or up to 30° from vertical). However, a vertical, substantially vertical or near vertical section of an injection and/or production well is preferred for performing various aspects of the process as herein described. Injection may, and preferably will, be at two or more locations up dip within the reservoir so as to create one or more reaction zones. If desired, injection may be at two or more depths so as to create two or more vertically stacked reaction zones, so that as the reaction progresses vertically it reaches zones of the reservoir that are pre-seeded with fresh catalyst.

Alternatively, the catalyst or precursor thereto may be placed in a well, e.g. by packing a perforated liner in the hole with a particulate catalyst or by the use of nickel or nickel-coated liners (e.g. with a porosified nickel internal coating) in the dedicated well. Such catalysts or their precursors may be activated by heating in a hydrogen atmosphere and may be maintained in an activated state under nitrogen until the thermal front reaches the liners.

In general, a temperature sensor will be placed within the borehole liner at the catalyst "injection" site (through which can be injected e.g. one or more catalysts and/or catalyst precursors) so as to identify when the local temperature of the reservoir has risen to the level where hydrocarbon-to-hydrogen catalysed conversion will begin, and indeed to identify if and when the combustion front reaches the catalyst "injection" site.

The processes of the invention involve raising the temperature of the zone of the reservoir containing the catalyst or a precursor thereto to a temperature at which hydrogen production occurs, typically between 400°C and 1000°C, preferably between 500°C and 1000°C, more preferably at least 500-600°C, optimally between 700 to 1000°C. The catalyst or its precursor can, and preferably will, be placed in the reservoir before this temperature is reached; however, catalyst and/or precursor placement may be effected during the temperature rise or once the local temperature of the reservoir has risen, preferably once the local temperature of the reservoir has risen, for example to increase the local concentration of the catalyst in the reservoir or to provide a fresh catalyst. Typically, the catalyst or precursor thereto will be applied in amounts of at least one tonne calculated on the basis of the catalytic metal. Conveniently, the catalyst or precursor thereto can be applied at a concentration of 5 to 400 kg/m³, especially 10 to 200 kg/m³, particularly 50 to 100 kg/m³.

Raising the temperature in the reservoir may be achieved in several ways, e.g. by the introduction of an agent (e.g. air or water/air mixture) into the reservoir. For shallow reservoirs, particularly on-shore (i.e. under land rather than under sea) reservoirs, e.g. at depths of up to 1700 m, the temperature may be raised by injection of superheated water (steam). However, at greater depths, or, for example, with offshore reservoirs, the

temperature loss of the superheated steam on transit to the injection site within the reservoir may be too great. In this event, the temperature within the reservoir can be raised by the injection of oxygen (e.g. as air) and initiation of hydrocarbon combustion within the reservoir. Combustion may be initiated by electrical ignition down-hole, or self-ignition may occur, for example on oxygen injection into a deep, high temperature, light oil reservoir. Where oxygen is introduced in this way, it is preferred, although not essential, to co-introduce water, e.g. as steam. Preferably, air, oxygen, carbon dioxide, water, steam or a combination of any of these is injected into the reservoir during the HGHS process.

The introduction of oxygen and/or water may occur at the same site(s) as catalyst or catalyst precursor introduction. However, more preferably, oxygen/water introduction is effected at sites below the catalyst or catalyst precursor introduction site, for example 10 to 500 m below, e.g. at one or more positions along a deviated well bore section. However, a vertical, substantially vertical or near vertical section of a bore section is more preferred. Where oxygen is introduced in this fashion, a high temperature front will pass through the reservoir ahead of the combustion front, thus causing hydrogen production to occur before the arrival of the combustion front. The high temperature front will activate the catalyst where thermal decomposition of the catalyst (or precursor thereto) material is required and will push catalyst (or precursor thereto) material, steam and produced hydrogen ahead of the combustion front. Hydrogen, being significantly less dense than the carbon oxides, water, and the hydrocarbons, and having significantly smaller molecular size, will separate upwards within the reservoir to accumulate in the crest of the reservoir e.g. by gravity segregation, where hydrogen rises upwards, e.g. to the top of the reservoir, and other gases sink downwards, e.g. towards the bottom of the reservoir. Hydrogen can thus be removed from the reservoir through sections of a production well, preferably a well dedicated to hydrogen production, located above the catalyst and/or catalyst precursor injection site, for example 20 to 500 m above. Hydrogen can be recovered from the reaction products of the catalysed conversion of hydrocarbon to hydrogen by means of a membrane filter, e.g. installed downhole in the well. The environmentally undesirable "greenhouse gases", such as carbon and nitrogen oxides, being denser than hydrogen, will typically segregate downwards within the reservoir under the influence of gravity. Preferably the process of the invention comprises separation of hydrogen by gravity segregation in said reservoir, preferably prior to contact with the membrane filter in the well.

High or higher purity hydrogen gas can be obtained by separating hydrogen from other gases (e.g. CH₄, CO2, CO, NO_x) in a hydrogen-containing mixture such as that produced by the catalysed conversion of hydrocarbons to hydrogen (e.g. hydrogen in combination with other reaction products or unreacted species). This separation can be carried out using a membrane filter, which can be used before, after, or instead of, gravity segregation of hydrogen and other gases in the reservoir, e.g. to obtain a more concentrated hydrogen stream. Gravity segregation contributes to separation of hydrogen, the lightest component in the gas phase, in the crest, in the top of the reservoir section. The scale of the gravity segregation process is typically the size of the whole field. Downhole, or on the surface, membrane separation of hydrogen in the production well is a fast, almost simultaneous, process, taking place in the well filtering the gas stream flowing to one or several production wells. The membrane filter can be any shape, but is preferably cylindrical, and can be installed at the well head or in a subterranean hydrocarbon reservoir, preferably downhole in the production well, more preferably connected to tubing installed in said production well for transporting hydrogen gas to the surface. The hydrogen stream may be recovered from the reservoir by means of tubing connected from the surface to the membrane filter. The hydrogen is preferably removed from the production well solely by means of the tubing, and not the annulus of the filter and/or tubing.

One or more membrane filters are present in at least one production well. The membrane filters may be downhole or at the surface, preferably downhole. Downhole filters can be installed at any convenient location in the production well, e.g. proximate the reservoir, and/or in higher sections. An especially preferred location for the filter is in the crest, e.g. top, of the reservoir, for example the position shown for 5 in Figure 1. The higher sections of the reservoir are preferred as this is where hydrogen accumulates due to gravity.

The membrane filter can be manufactured from, or may comprise, any material suitable for hydrogen separation, such as silica (e.g. a hydrophobic silica membrane), ceramic (e.g. coated or uncoated), dense (e.g. SrCeCh, BaCeCh) or microporous (e.g. silica, alumina, zirconia, titania, zeolites) ceramic, dense polymer, porous carbon, palladium (e.g. a palladium coating on a high permeability alloy tube), palladium alloys (e.g. palladium-silver, palladium-copper or palladium-gold alloys), and/or palladium-coated composite membranes.

In general, hydrocarbon reservoirs already contain sufficient water for the steam reformation reaction to occur if a catalyst is present and the temperature is raised to the appropriate level. Accordingly, steam injection in the process of the invention is optional rather than essential if temperature raising is to be effected by hydrocarbon combustion.

Oxygen introduction, e.g. air injection, may conveniently be effected at a rate of up to 10 million cubic metres per day, for example 0.5 to 8 x 10³ m³/day. In this context, cubic metres means volume at standard (atmospheric) pressure and temperature.

Where steam is introduced, this can typically be at rates of 10 to 1000 kl_ water per day. Desirably, the injection temperature is at least 300°C, especially at least 400°C;

however, where steam rather than combustion is to be used to raise the local temperature within the reservoir, the injection temperature will preferably be at least 600°C, for example up to 1100°C. Injection of oxygen (e.g. as air) can be alternated with water, if required.

Another energy efficient way to increase reservoir temperature to the required reformation level is a use of downhole heat pumps or micro-wave plasma reactors.

Also electric heating, downhole flameless or non-flameless reactors, non-flameless reactions in situ, or exothermic reactions downhole can be used to increase temperature in situ to the required level for endothermic reactions of hydrogen generation. Preferably, the temperature in the hydrocarbon gas-containing zone is raised by using non-flameless reactions in situ, a non-flameless reactor, or exothermic reaction(s) in the downhole (e.g. a downhole section) of an injection well. Preferably, the temperature in said hydrocarbon gas- containing zone can be raised by using a flameless reactor, heat pump, electric heater, exothermic reactants, plasma and plasma pyrolysis or microwave reactors reactions in situ, a non-flameless reactor or exothermic reaction(s), e.g. downhole in an injection well.

Flameless oxidation reactions in the porous medium are characterised by heat accumulation in the solid phase of the porous structure and results in reduced pressure peaks, lowered temperature and homogeneous combustion with clean process and reduced emission gas generation. In the porous or fractured media of the sub-terrain reservoir, in a confined continuous permeable space of the reservoir rock, the injected air flow may be preheated to the temperatures, reaching levels above self-ignition temperature, e.g. 800- 1000 °C. This may enable flameless combustion or oxidation process to occur yielding low NOx generation.

Once hydrogen generation has reached the desired level, or once the combustion front has risen to the desired level, the reaction, e.g. the reformation reaction, may be shut down by ceasing oxygen/steam injection. If desired, oxygen injection may be terminated before steam injection so as to optimally utilize the heat produced. In any given reservoir, the reaction may be effected in two or more zones so as to optimize hydrogen production.

Where a production well for hydrogen extraction is not already in place, 3D- or 4D- seismic surveying may be used, preferably during the reformation reaction, so as to optimize location of the hydrogen production well. 3D- or 4D- seismic surveying may also be used to optimize placement of the injection wells, for example so as to locate the reaction zone near a gas chimney in the reservoir or beneath a well-defined impervious dome where hydrogen accumulation can occur.

Oxygen injection resulting in oxidation reactions and high temperatures may also cause some thermal cracking of the hydrocarbons in the reservoir to occur and thus, in viscous heavy oil or depleted reservoirs, hydrocarbon extraction from hydrocarbon production wells may also be enhanced.

The invention is especially economically suitable for use in depleted non-commercial natural gas fields. Depleted reservoirs, in this context, include reservoirs which have stopped producing or have non-commercial production rates due to decreased reservoir pressure. In the depleted abandoned fields there often remains 20-30% of the initial gas volume in place, which due to depleted reservoir pressure cannot be commercially recovered. These reserves are considered as non-commercial with the technologies available today, and are not accounted in reserves statistics. Primary recovery (natural reservoir energy) factor in natural gas fields under natural depletion can be in the range of 70-80% of the Gas Initially In Place (GIIP). Gravity drainage, compaction and water drive mechanisms in the reservoir can increase gas recovery from the field to 85-90% of GIIP. So, the reserves of natural gas in the fields with depleted reservoir pressure amount on average to 10-30% of GIIP depending on reservoir properties and conditions. In the gas-condensate field, if the reservoir pressure is falling below the dew point during production, the condensate will drop out within reservoir, stick to the rock surface and remain immobile within the pores of the formation until its saturation exceeds the critical saturation to become mobile. From an economic standpoint, fluid and gas trapped within the reservoir pores at low saturations are generally considered a loss to reservoir rock. These remaining gas reserves are not accounted for under the category of technically recoverable resources with existing technologies and will be left abandoned in situ as non-commercial reserves. The subterranean hydrocarbon reservoir may be a gas reservoir situated in a coal field. The reservoir may be a carbonate reservoir, a sandstone reservoir, a shale reservoir, a tight low permeable reservoir or a natural gas reservoir with CO2 content in the gas.

Since the ability of hydrogen, steam and oxygen to pass through the reservoir is greater than that of water or hydrocarbons, the invention is also applicable to so-called "tight gas" reservoirs, i.e. reservoirs from which methane extraction is inefficient due to the low permeability of the reservoir formation and difficulties with reservoir pressure maintenance.

In the world there are known to be many such reservoirs, containing immense resources of hydrocarbon gas, from which hydrocarbon extraction is not currently economically feasible. Such tight gas reservoirs typically contain dry hydrocarbon gas or hydrocarbon gas and condensate.

In the case of downhole heat pump used to achieve required temperature in the near well bore zone of the natural gas formation for hydrogen generation process may be performed in an energy efficient way.

Where steam is injected in the process of the invention without oxygen injection, the injection site is preferably at a depth of no more than 1700m.

In certain aspects, the process of the present invention may comprise recovering heat from the subterranean hydrocarbon, e.g. gas, reservoir by circulating fluids, e.g. water, between the surface and said subterranean hydrocarbon, e.g. gas, reservoir, e.g. by means of a first injection well or a second injection well connected to the first injection well.

Embodiments of the invention will now be described with reference to the

accompanying drawings. Figure 1 is a schematic illustration of the HGHS process at the conversion stage.

Referring to Figure 1 , there is shown a subterranean hydrocarbon reservoir in, e.g. a natural gas field or a coal field 1, having two wells (injection well 2 and production well 3) and an injection unit 4. Catalyst is introduced, e.g. via an aqueous solution of catalyst or catalyst precursor, via injection into the reservoir through the injection well 2. Thereafter an agent (e.g. air or water/air mixture) can be injected by injection unit 3 (compressor and/or compressor-pump) to initiate reactions. Other means of raising the temperature may be used. Low temperature oxidation reactions taking place in situ will establish a thermal front, which will reach the precursor and decompose its compound to produce catalyst (e.g. in particulate form) and initiate hydrocarbon-to-hydrogen conversion. Gravity segregation and separation will result in hydrogen rising to the top of the reservoir where it is drained through production well 3.

Due to high reactivity of hydrogen and the need to exploit advantages of the gravity segregation, the placement of injection well 2 and production well 3 should preferably be designed based on geological modelling and reservoir simulation studies for specific geological settings.

If the potential consumers of hydrogen are remotely located from the site of hydrogen production from sub terrain, the HGHS process can be designed in a way to allow producing a mixture of hydrogen and methane in order to facilitate transport and to reduce costs associated with long distance pure hydrogen transportation.

The production well 2 is equipped with downhole equipment 5 for hydrogen separation from other possible gas components (e.g. CH₄, CO2, CO, NO_x) in the gas flux. Figure 2 shows an example of a production well 6 with downhole equipment. The separation membrane 9, a cylindrical filter, is preferably installed on the tubing 7, which is used to transport purified hydrogen gas to the surface. The hydrogen is preferably removed from the production well 2 solely by means of the tubing 7, and not the annulus 8. The membrane 9 can be manufactured from silica, ceramic, palladium or other materials suitable for hydrogen separation. Non-hydrogen gas components (e.g. CH₄, CO2, CO, NO_x) separated by the downhole membrane 9 from gas influx 11 will segregate to the deeper parts of the reservoir through the perforations 10.

At HGHS stage two, after conversion of hydrocarbons to hydrogen, the high thermal energy generated in situ by this process may be utilized by temporally using the injection well 2 as a geothermal one. Figure 3 depicts the HGHS second geothermal and third sequestration stages. In order to achieve better wellbore-reservoir thermal contact a dedicated“banana” well 12 can be drilled to connect with vertical injection well 2. Geosteering drilling technology allows very accurate wellbore placement and consequent connection with the existing well. Such a“surface to surface” connected“banana” well assures effective fluid, preferably water, circulation 13 and efficient heat transfer from the reservoir, and geothermal energy is brought to the surface from the heated reservoir.

Preferably, heat is recovered from the subterranean hydrocarbon reservoir by circulating fluid, preferably water, between the surface and said subterranean hydrocarbon reservoir by means of a first injection well (e.g. injection well 2) or by means of a second injection well (e.g.“banana” injection well 12) connected to a first injection well (e.g. injection well 2).

Reduction of the reservoir temperature from steam-vapour conditions at the hydrogen generation stage to conditions corresponding to condensation of water will enhance the separation of hydrogen in situ and C0₂ dissolution in water.

In the reservoir, gravity segregation will lead to the main amount of generated hydrogen flowing upwards, causing methane to flow into the reaction zone containing the catalyst, and carbon dioxide to flow downwards of the reservoir.

Carbon dioxide will be accumulated in the bottom of the reservoir, also getting dissolved in the connate and injected water.

In order to achieve permanent capture of CCh in a geological formation, additional mineralization reactions with reservoir rock can be activated in situ making the storage process safe and reliable in the long run. Carbon Capture and Mineral Carbonation (CCMC) can achieve geologically stable CO2 storage, e.g. as limestone, which reduces

environmental and safety concerns. A metric ton of CO2 will typically require 2.5-3 tons of magnesium silicate minerals. Exemplary magnesium silicates include Mg₂Si0₄ and Mg3Si205(0H₄). Calcium silicate minerals, such as CaSiCh, can also be used. Further silicate minerals which can be used include olivine ((Mg²⁺, Fe²⁺)₂Si0₄), orthopyroxene (Mg2Si2C>6- Fe2Si2C>6), clinopyroxene (CaMgShCh-CaFeShCh) and serpentine ((Mg, Fe)3Si20s(0H)₄). Carbonates have up to approximately three times higher density storage in the form of MgCCh than in the super-critical carbon dioxide form (e.g. 1600 kg of CCh per 1 m³ (for MgCCh) compared to 500-700 kg for super-critical CO2). MgCCh and CaCCh are stable in acid solutions down to pH -1.

CCMC can be achieved by carbonating minerals such as olivine or serpentine, which are naturally and abundantly present in geological formations. Calcium-and magnesium- containing materials, e.g. waste materials produced by industry, can also be injected in the third stage after geothermal energy consumption (see, for example, Figure 3). Preferably, calcium and/or magnesium-containing materials are injected into the subterranean hydrocarbon, e.g. gas, reservoir by means of an injection well (e.g. injection well 2 or “banana” injection well 12).

Examples of possible industrial waste calcium and/or magnesium source materials are waste cement from concrete treatment plants and crushed slags from the blast furnace containing 20-50 weight % of calcium, other by-products of combustion processes (e.g. ash, coal and steel slug), construction residues (e.g. cement, concrete and asbestos) or alkaline solid residues. Further examples of calcium and/or magnesium-containing waste materials include furnace slag, electric arc furnace slag, basic oxygen furnace slag, cement kiln dust, cement bypass dust, recycled concrete aggregate, municipal solid waste incineration ash, air pollution control residue, coal and lignite fly ashes, wood ash, red mud, mine tailings and alkaline paper mill wastes ash. The invention therefore preferably comprises injecting calcium and/or magnesium-containing materials, preferably calcium and/or magnesium waste containing materials, into a subterranean hydrocarbon, e.g. gas, reservoir e.g. by means of an injection well. Suitable compounds are as described above, e.g. silicates, especially those of calcium and/or magnesium.

The minerals for mineralisation of CO2, e.g. the mineral slurry, can be injected in the reservoir in the injection well 2 or“banana” well 12. The carbonation reactions will result in increasing solid volume of carbonates filling porosity, reducing permeability and creating carbonated envelopes or boundaries limiting the flow in the porous media.

Mineralisation of CO2 allows geologically stable CO2 storage (CCMC) as limestone and reduces environmental and safety concerns.

Natural weathering reactions (e.g. as shown below) are exothermic and slow:

(Mg, Ca)xSi_eOx₊2e + XCO2 x(Mg, Ca)CC>3 + ySiC>2 -DH

As part of a HGHS process with in situ mineralization reactions in the presence of water, additional FT may be released in the reservoir e.g. as follows:

(Ca²⁺, Mg²⁺) + C0₂ + H2O = (Ca, Mg)C0₃ + 2FT

The geological mineralization and endothermic weathering reactions in situ after the execution of HGHS process in the natural gas field will be significantly accelerated due to the increased reservoir temperatures even after the geothermal energy utilization stage.

As an additional feature of, or alternative to, the aforementioned process, hydrogen generation can take place downhole in the production well using downhole microwave reactor 14, as shown in Figure 4. In the well bore a downhole microwave reactor will operate with heating temperatures of up to 1000 - 2000°C in plasma pyrolysis regime at micro-wave frequencies of 300 MHz - 3 GHz. The plasma driven hydrocarbon phase thermal

decomposition yields hydrogen and solid phase carbon. In the absence of water and oxygen downhole the process in the micro-wave plasma reactor is environmentally friendly, since hydrogen is obtained from hydrocarbons without producing C0₂ and CO as byproducts.

In any of the embodiments described above, hydrogen gas produced from hydrocarbon flux from the reservoir into a perforated interval 10 of the well may be evacuated from the plasma reactor 14 upwards through the tubing 7 in the well. Any black carbon produced may be accumulated in the bottom hole of the well. The solid carbon can be removed from the well periodically by bottom hole wash out and work over operations in the production well 6.

Claims

1. A process for hydrogen generation comprising:

introducing a catalyst or precursor thereto into a hydrocarbon containing zone in a subterranean hydrocarbon reservoir (preferably into a hydrocarbon gas-containing zone in a subterranean gas reservoir)

raising the temperature in said reservoir to a temperature at which catalysed conversion of hydrocarbon to hydrogen occurs; and

recovering a hydrogen stream via a membrane filter installed in a production well, preferably wherein said production well is vertical or deviated vertical.

2. The process of claim 1 , wherein:

the catalyst or precursor thereto is in a water soluble form and/or

the catalyst or precursor thereto is injected into a porous or fractured medium hydrocarbon oil or gas-containing zone in said reservoir;

said process optionally further comprising achieving commercial purity of hydrogen in the production stream from the well in the HGHS process with segregation of generated in situ hydrogen from the heavier gas components and fluids present in gas and liquid phases; and/or gas separation by inert membrane filters installed downhole in the production well or at the well head to obtain a required commercial purity of hydrogen in the production stream, if gravity segregation of hydrogen inside the reservoir is not complete within the field project time frame, and other gas components might be still present in the production stream.

3. The process as claimed in claim 1 or claim 2, further comprising the capture of produced carbon dioxide in situ.

4. The process as claimed in any one of the preceding claims, wherein the process is performed in a natural gas field onshore or offshore.

5. The process as claimed in any one of the preceding claims, wherein the catalyst or precursor thereto is dissolved in an aqueous solution.

6. The process as claimed in any one of the preceding claims, wherein the temperature is raised by the introduction of an agent to said reservoir.

7. The process as claimed in any one of the preceding claims, wherein the catalysed conversion of hydrocarbon to hydrogen occurs by means of one or more reactions selected from steam reforming (SR), water gas shift reaction (WGSR) and methane catalytic cracking (MCC) reactions.

8. The process as claimed in any one of the preceding claims, comprising separation of hydrogen by gravity segregation in said reservoir, preferably prior to contact with the membrane filter.

9. The process as claimed in any one of the preceding claims, wherein said hydrogen stream is recovered from said reservoir by means of tubing connected from the surface to said membrane filter.

10. The process as claimed in any one of the preceding claims, wherein the catalyst or precursor thereto is introduced into said reservoir by means of a first injection well.

11. The process as claimed in any one of the preceding claims, further comprising recovering heat from the reservoir by circulating water between the surface and said reservoir, e.g. by means of a first injection well or a second injection well connected to the first injection well.

12. The process as claimed in any one of the preceding claims, further comprising injecting calcium and/or magnesium-containing materials into said reservoir by means of an injection well.

13. The process as claimed in any one of the preceding claims, wherein the reservoir is in a coal field.

14. The process as claimed in any one of the preceding claims, wherein the reservoir is a carbonate reservoir, a sandstone reservoir, a shale reservoir, a tight low permeable reservoir or a natural gas or oil reservoir with or without C0₂ content in the gas.

15. The process as claimed in any one of the preceding claims, wherein the catalyst precursor is a metal compound which is thermally decomposable to a catalytically active form, or a solution thereof.

16. The process as claimed in claim 15, wherein the metal compound is a metal salt, e.g. a metal carbonyl, metal alkyl, metal nitrate, metal sulphate, metal carbonate, metal carboxylate compound, or a humic acid salt.

17. The process as claimed in any one of the preceding claims, wherein the temperature in said hydrocarbon containing zone is raised by using downhole in the well flameless reactor, heat pump, electric heater, exothermic reactants, plasma and plasma pyrolysis or microwave reactors reactions in situ, a non-flameless reactor or exothermic reaction(s) in the down-hole of an injection well.

18. The process as claimed in any one of the preceding claims, wherein air, oxygen, carbon dioxide, water, steam or a combination of them, is injected into the reservoir during the HGHS process.

19. The process as claimed in any one of the preceding claims, wherein the temperature in said hydrocarbon containing zone is raised to a temperature between 400°C and 1000°C, preferably between 700°C and 1000°C.

20. The process as claimed in any one of the preceding claims, said process comprising using a downhole microwave reactor operating to yield hydrogen and solid phase carbon; preferably wherein said hydrogen and carbon are produced by plasma driven hydrocarbon phase thermal decomposition.

21. A process of hydrogen generation downhole in a production well, said process comprising using a downhole microwave reactor operating to yield hydrogen and solid phase carbon;

preferably wherein said hydrogen and carbon are produced by plasma driven hydrocarbon phase thermal decomposition.

22. The process of claim 20 or claim 21 , wherein said microwave reactor operates with heating temperatures of up to 1000 - 2000°C in plasma pyrolysis regime at micro-wave frequencies of 300 MHz - 3 GHz.