Note: Descriptions are shown in the official language in which they were submitted.
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
1
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 002 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:
01-14 + H20 CO + 3H2 AH = +206 kJ/mol
CnH2n+2 + nH20 nC0 + (2n+1 )H2 + AH
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 002 + H2 AH = - 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 AH = +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:
201-14 + 02 200 + 4H2 AH = -75 kJ/mol
Similar reactions will also happen with any other type of hydrocarbons, for
example
for heavier paraffins:
2CnH2n+2 + n02 2n00 + (2n+2)H2 + AH
Heavier hydrocarbon gases may also be involved in a set of other exothermic
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
2
chemical reactions resulting in hydrogen generation or splitting of e.g.
carbon-carbon or
carbon-hydrogen bonds shown here with ethane as an example:
02F-I6 -> 02F-I4 + H2 AEI = -138 kJ/mol
021-16+ H2 -> 201-14 AEI = -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 CO2 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
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
3
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
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
4
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.
002, CO,
possibly NON, 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. /0, 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
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
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
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
6
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
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
7
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, 002, CO, NON) 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,
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
8
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. SrCe03, BaCe03) 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
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
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
9
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
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
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.
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
11
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, NON) 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, NON) 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.
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
12
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 CO2 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 CO2 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 Mg2SiO4
and
Mg3Si205(0H4). Calcium silicate minerals, such as CaSiO3, can also be used.
Further silicate
minerals which can be used include olivine ((Mg', Fe2+)2SiO4), orthopyroxene
(Mg2Si206-
Fe2Si206), clinopyroxene (CaMgSi206-CaFeSi206) and serpentine ((Mg,
Fe)35i205(OH)4).
Carbonates have up to approximately three times higher density storage in the
form of
MgCO3 than in the super-critical carbon dioxide form (e.g. 1600 kg of CO2 per
1 m3 (for
MgCO3) compared to 500-700 kg for super-critical CO2). MgCO3 and CaCO3 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
CA 03100233 2020-11-13
WO 2019/224326 PCT/EP2019/063382
13
"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 002, 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)xSie0x+2e + xCO2 ¨> x(Mg,Ca)CO3 + ySi02 -,LI-1
As part of a HGHS process with in situ mineralization reactions in the
presence of
water, additional H+ may be released in the reservoir e.g. as follows:
(Ca2+, Mg2+) + CO2+ H20 = (Ca, Mg)003+ 2H+
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
CA 03100233 2020-11-13
WO 2019/224326
PCT/EP2019/063382
14
hydrogen is obtained from hydrocarbons without producing 002 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.
