Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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Method for production and upgrading of oil
The field of the invention
The present invention relates to an environmental-friendly, integrated process
for
S increased production and upgrading/refining of heavy and extra-heavy crude
oil to
finished products, based on extensive use of hydrogen to maximise the yield of
liquid
products, while cogenerating large amounts of steam, COZ and optionally NZ
produced
by large-scale natural gas conversion, used for increased oil production. The
finished
products from upgrading/refining of heavy/extra heavy oils will be
predominantly
naphtha, kerosene, diesel and fuel oil, shipped separately or blended.
The background of the invention
Compared to conventional oil, the utilization of heavy oil
(density<20°API, viscosity
>100cP) and extra heavy oil/bitumen (density<10°API, viscosity>10000cP)
is limited
because of cost of production and upgrading. However, it is expected that the
continued
need for petroleum liquids such as transportation fuels will be met in the
future more
and more by heavy oils. Hence new technologies for increased production and
more
efficient upgrading/refining of heavy and extra heavy oil are much sought for.
Due to
its high viscosity the primary recovery of heavy oils by conventional methods
is low.
Recent developments in production technology, such as horizontal drilling,
gravity
drainage methods, non-thermal production from horizontal wells with
multilaterals, cold
production of heavy oil with sand co-production, pressure pulse flow
enhancement are
methods which can increase the recovery of heavy oils at a reasonable cost. In
particular, improvements in cyclic steam stimulation (CSS) and steam assisted
gravity
drainage (SAGD) have reduced the cost of those hot production methods, but
still they
require large amounts of steam (volumetric steam-to-oil ratios of 2 or higher)
.
Today, heavy and extra-heavy oil are converted to finished products in two
steps, where
the first step referred to as upgrading gives a synthetic crude oil which has
to be further
refined to finished products. The upgrader is usually designed for the
specific heavy oil
in question, while the synthetic crude with API in the range of typically 20-
35 API is an
attractive feedstock for conventional refineries, within certain limitations.
The essential
feature of the heavy/extra heavy oil upgrader will be the conversion of
residue, either by
carbon rejection or hydrogen addition, to give a stable synthetic crude that
might be
more or less residue-free, while the liquid fractions do not have the quality
needed for
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road transportation fuels. A subsequent refining of the synthetic crude is
needed to
produce finished products with the right quality, but this reprocessing is not
very energy
efficient since the synthetic crude oil has to be reheated and fractionated.
S The heavy oils generally have high density and high viscosity due to the
large presence
of higher boiling, polyaromatic molecules in which the resin and asphaltene
content can
be as high as 70%. As a result, these oils are low in hydrogen content, such
as for
Athabasca bitumen with an ratio (atomic) H/C equal to 1.49, compared to
conventional
crudes with a ratio H/C typically around 1.8, which is slightly lower than the
value of
the most important refinery products, gasoline and diesel (see, J. S. Speight:
"The
chemistry and technology of petroleum", 3rd ed., Marcel Dekker, Inc., New
York,
1999).
Hence, to produce valuable liquid products in high quantities, substantial
amounts of
1 S hydrogen will be needed, and more so the heavier the crude oil. In
comparison, natural
gas is rich in hydrogen with a H/C-ratio around 3.8; therefore natural gas
represents a
natural source of hydrogen for upgrading of heavy oil, as it is when
refineries need
additional hydrogen to close their hydrogen balance. The attractiveness of
using natural
gas as hydrogen source will depend on local factors such as availability and
cost of the
natural gas.
The need for hydrogen in the refineries depends on the feedstock and product
slates, as
well as the specific refinery configuration. The general market trend is
towards lighter
products such as LPG, naphtha, gasoline and diesel, putting a pressure on the
refineries
with respect to upgrading of the heavier fractions. Moreover, new
specification on the
sulfur content in transportation fuels normally requires increased
hydrotreating in the
refineries, a type of processing that consumes hydrogen, thereby contributing
to a
hydrogen imbalance in the refineries.
Upgrading of the heavier fractions can be done either by "carbon-rejection"
type of
processes such as delayed coking or catalytic cracking, or by hydrogen
addition such as
hydrocracking. The former produces "coke" which is burnt as energy input in
the
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processing/upgrading or sold as a product (petroleum coke), while the latter
gives a
higher yield of high-value liquid products of the kind mentioned above, at the
penalty of
higher hydrogen consumption.
The particular high content of residue in heavy oils requires particular
refinery
configurations to process these crudes, and the high content of metals and
carbon
residue/asphaltenes in the residue limits the use of catalytic processes
available to
upgrade the heavy ends of those heavy crudes. The hydrocracking option allows
for
production of ultra-clean (low sulfur) transportation fuels of a quality in
compliance
with the most stringent fuel specifications both in EU and in the US. This
will normally
require a two-step hydrocracking scheme, where the products from the residue
hydrocracker must be hydrocracked in a VGO type of hydrocracker to give the
ultra-
clean transportation fuels.
In catalytic hydrocracking of residue, the metals will end up on the catalyst,
which by
proper treatment can be dissolved and the metals, mainly Vanadium and Nickel,
recuperated. The sulfur ends up as H2S which is easily captured and for
example
converted to elementary sulfur by use of techniques commonly used in
refineries today.
Thus, the inherent high content of impurities such as metals and sulfur in the
heavy oil,
will be properly handed in the upgrader.
Today, the change in demand pattern has created regional lack of sufficient
upgrading
capacity in the refining industry, the so-called bottom-of the-barrel problem.
This,
combined with limited hydrogen availability, will probably make it less
attractive for
conventional refineries to process heavier crudes.
Heavy oils are, due to their physical properties and particularly the high
viscosity,
difficult to produce and transport. Technologies have been developed for
partial
upgrading at the wellhead to make the oil transportable, as an alternative to
dilution of
the viscous oil by lighter fractions such as typically naphtha. The common
solution for
the Orinoco bitumen produced in Venezuela is transport by pipeline by naphtha
dilution
to an upgrader located at the coast, where the naphtha is separated from and
recycled,
while the crude is partially upgraded to an essentially residue-free synthetic
crude with
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densities in the range of typically 20-32API. The synthetic crude is then
exported to a
conventional refinery for upgrading to finished products.
As an alternative to this conventional two-step upgrading of heavy oil, we see
potential
advantages at locations where natural gas can be made available in large
quantities, to
profit from large scale hydrogen production from natural gas, by upgrading the
heavy or
extra-heavy crude oil to products in one step at a dedicated upgrader/refinery
located so
as to obtain maximum synergetic effects with the hydrogen production, which
will take
place so as to also obtain synergetic effects with respect to improved
recovery of heavy
or extra-heavy oil from the reservoir, by the use of energy such as steam in
combination
with by-products such as COZ and/or N2, generated by the natural gas
conversion step.
The amount of hydrogen required of course depends on the characteristics of
the heavy
oil, the upgrader/refmery scheme and the types of products, but a simple mass
balance
demonstrates that production of finished products from an extra-heavy oil
requires so
much hydrogen that it could possibly serve as a single solution for remote or
stranded
gas which then must be transported to (or close to) the heavy oil production
site. In
some cases, the natural gas could even be available as associated gas,
produced with the
oil.
Due to its high viscosity the primary recovery of heavy oils by conventional
methods is
low. Recent developments in production technology, such as horizontal
drilling, gravity
drainage methods, non-thermal production from horizontal wells with
multilaterals, cold
production of heavy oil with sand co-production, pressure pulse flow
enhancement are
methods which can increase the recovery of heavy oils at a reasonable cost.
The reinjection of various gases into an oil reservoir in order to enhance the
oil recovery
from the reservoir, and to stabilise it, has long been known and used. In
particular,
improvements in cyclic steam stimulation (CSS) and steam assisted gravity
drainage
(SAGD) have reduced the cost of those hot production methods, but still they
require
large amounts of steam (volumetric steam-to-oil ratios of 2 or higher) . Gases
such as
CO2, NZ and natural gas will reduce the surface tension between gas and oil,
and thus
contribute to both increased recovery and stabilisation of the reservoir.
Additionally,
natural gas as such may be injected into fields where the gas does not have a
net value
that exceeds the excess profits of increasing the oil recovery in the field.
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S
W003/018958 relates to a combined facility for production of gases for
injection into
an oil field and production of synthesis gas for synthesis of methanol or
other
oxygenated hydrocarbons or higher hydrocarbons in a synthesis loop.
Introduction of gases as mentioned above is not sufficient to produce and
transport
heavy oil and extra heavy oil /bitumen even if oil soluble gases like e.g. COZ
and
methane will, dependent on the pressure and temperature of the mixture, reduce
the
viscosity somewhat.
An integrated process for gas conversion and bitumen production is described
in
W002/077124. Synthesis gas, comprising a mixture of HZ and CO is produced from
hydrocarbons, preferably from natural gas. The natural gas may be found in the
same
formations as the heavy oil or in nearby the heavy oil reservoir. Heat from
the synthesis
gas production is used to produce steam for injection into the formation to
lower the
viscosity of the heavy oil by heating it. The synthesis gas is used to produce
hydrocarbons by use of a Fischer-Tropsch catalyst. At least a part of the
produced
hydrocarbons is used to dilute the produced heavy hydrocarbons to lower the
viscosity
to facilitate the transportation of the oil in pipelines.
US 4.706.751 describes another heavy oil recovery process for the recovery of
heavy
oils from deep reservoirs. Reactant streams are produced in a surface process
unit. The
reactant streams, that may be e.g. Hz and OZ plus water, or CO and steam plus
water, is
introduced into the well and reacted in a catalytic reactor downhole to
produce high
quality steam, H2, COz and any gas or vapour that are readily soluble in the
heavy oil
such as methane, methanol, light hydrocarbons etc. The reactions in the
downhole
reactor are exothermal and produce heat for steam formation and heating.
Cleaning waste gas from the combustion on the production installation can
provide COz
for injection into oil reservoirs. In addition it has been suggested that COZ
cleaned from
the flue gas from gas power plants be reinjected by laying a pipeline from a
gas power
plant to the production installation for hydrocarbons.
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The present invention aims at combining various elements of known methods of
natural
gas conversion and heavy oil upgrading by upgrading of the heavy/extra heavy
oil to
high value, finished products by the use of large amounts of hydrogen
generated from
the natural gas. As byproducts we obtain steam, CO2, water and optionally N2,
which
S can be used for enhanced recovery of the heavy oils from the reservoir. In
particular, the
capture of COZ from the hydrogen generation plant represents a significant
potential of
reduction of the COZ emissions from the upgrading by injection of the COZ into
underground storage (sequestering), or injection into to reservoir to obtain
enhanced oil
recovery.
Summary of the invention
According to the present invention there is provided an integrated process for
production and upgrading of heavy and extra-heavy crude oil, comprising (a)
reforming
of natural gas to produce hydrogen, COZ and steam (b) separating the produced
1 S hydrogen from the COz, steam and any other gases to give a hydrogen rich
fraction and
a COZ rich fraction and steam, (c) injecting the steam alone or in combination
with the
COZ rich fraction into the reservoir containing heavy or extra heavy oil to
increase the
oil recovery, and (d) upgrading/refining of the heavy or extra heavy oil by
hydroprocessing , comprising hydrocracking and hydrotreating using the
hydrogen rich
fraction in the hydroprocessing steps. The term "hydrotreating" comprises, as
used in
the present invention, removal of sulfur, nitrogen and metals as well as
hydrogenation
of olefins and aromatics.
According to a preferred embodiment the reforming in step (a) is steam
reforming.
The steam reforming may be performed under supercritical conditions.
According to another preferred embodiment the reforming in step (a) is
autothermal
reforming or partial oxidation.
Air may be used as oxidizer in the autothermal reformer or in the partial
oxidation
reactor.
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Preferably the process comprises the additional step of air separation to
produce purified
oxygen comprising more than 95%, preferably more than 98% oxygen, that is used
as
oxidizer in the reforming. The use of purified oxygen in the reforming and
separation of
the reformed gases, reduces the gas volume in the reactors and the separation
units.
Accordingly the volume and building costs may be reduced and the separation of
hydrogen from the remaining gases is more effective.
Preferably, purified nitrogen co-produced with the purified oxygen is injected
into the
reservoir together with the C02 rich fraction in step (c) to stimulate the oil
production.
Nitrogen is effective as pressure support in the reservoir together with the
COZ rich
fraction. It is therefore cost effective to use the produced purified nitrogen
for injection.
The process according to any of the preceding claims, wherein CO produced
during the
reforming process is reacted in a water gas shift reaction to produce
additional COZ and
H2.
The reformed gas from steam reforming, partial combustion or autothermal
reforming
comprises CO. The CO is therefore preferably converted by a water gas shift
reaction to
produce additional COZ and H2.
According to a preferred embodiment the heavy or extra heavy oil is partially
upgraded
in the reservoir by hydrogen injection.
According to a preferred embodiment the heavy or extra heavy oil is partially
upgraded
in a downhole upgrading unit.
Partial upgrading of the heavy or extra heavy oil in the reservoir makes the
oil less
viscous. Upgrading in the reservoir may therefore increase the oil production,
whereas
both upgrading in the reservoir and in a downhole unit will improve the
transportability
of the oil
It is preferred that the heavy or extra heavy oil is upgraded on an offshore
or onshore
upgrading facility.
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According to a preferred embodiment at least a part of the heat to increase
recovery of
the heavy or extra heavy oil is generated by in-situ combustion.
According to an embodiment geothermal heat is used to increase recovery and
transport
of the heavy or extra heavy oil.
As an alternative to traditional two-step upgrading of heavy oil (via
synthetic crude), a
potential advantages is seen at locations where natural gas can be made
available in
large quantities, to profit from large scale hydrogen production from natural
gas, by
upgrading/refining the heavy or extra-heavy crude oil to finished products in
one step at
a dedicated upgrader/refinery located so as to obtain maximum synergetic
effects with
the hydrogen production, which will take place so as to also obtain synergetic
effects
with respect to improved recovery of heavy or extra-heavy oil from the
reservoir, by the
use of energy such as steam in combination with by-products such as C02 and/or
N2,
generated by the natural gas conversion step.
Brief description of the drawings
Figure 1 is a flowchart illustrating a first preferred embodiment, and
Figure 2 is a flowchart illustrating a second preferred embodiment.
Detailed description of the invention
The present invention will be described by means of two examples describing
two
preferred embodiments of the invention. According to the present invention gas
and
optionally heat as steam for injection into an oil field
Example 1 - Generation of hydrogen by steam reforming of natural gas
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Figure 1 is a simplified flow diagram of a plant according to a first
preferred
embodiment and is based on the production of 200 000 barrels per day of Zuata
Heavy
(API=9) oil.
Natural gas, 115 ton per hour, is introduced into a steam reforming unit 2 via
a gas line
1. Steam reforming is an endothermal reaction. The steam reforming unit
comprises a
conventional steam generation unit where water is heated and converted into
hot steam
by combustion of any suitable fuel such as natural gas, lower or higher
hydrocarbons.
The natural gas from the gas line 1 and the hot steam is reacted in one or
more reactors
according to the following reactions:
Steam reforming CH4 + H20 = CO + 3H2
Water gas shift CO + H20 = COz + HZ
The product gas from the steam reformer is then sent to a shift converter (one
or two
step) in which CO is converted to C02 by the water gas shift reaction, and
hydrogen is
then separated by means of well known separation techniques, such as membrane
separation or separation by absorption based on the different chemical
properties of
gases e.g. as described in WO00/18681, into a hydrogen rich fraction leaving
the steam
reformation unit 2 through a hydrogen line 3 and a fraction comprising mainly
COz and
steam leaving the unit through line 4. The hydrogen rich fraction in line 3
constitutes
about 35 ton per hour, whereas about 300 ton COZ per hour and 210 ton steam
per hour
leaves the unit through line 4 . This concept represents a favourable way of
COZ
capture due to the high concentration of the COz in the process stream.
The preparation of a HZ rich gas and a COZ rich gas may be performed high
pressure at
supercritical conditions as described in WO/00/18681.
The C02 and steam is led to a unit for heavy oil production 5 and injected to
enhance
the recovery of heavy oil. Heavy oil produced in the unit for heavy oil
production 5 is
led from the unit to a unit for heavy oil upgrading 7 through a heavy oil line
6.
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The heavy oil is upgraded by several steps of catalytic hydroprocessing of the
heavy or
extra heavy oil using hydrogen from line 3, by hydrocracking in combination
with
hydrotreating steps, to produce valuable liquid products (distillates) from
the
distillation residue, to saturate unsaturated hydrocarbons and to remove
asphaltenes,
metals, nitrogen and sulphur from the finished products.
The products from the heavy oil upgrading unit 7 leaves the unit through a
plurality of
lines 8. Table 1 indicates a typical yield structure from the unit 7.
10 Table 1
Product Ton per hour C-range
Naphtha 200 CS-C8
Kerosine 140 C8-C 12
Diesel 580 C12-C22
VGO 300 C22 - 380C
Fuel oil , sulphur 60 380 C +
Example 2 - Generation of hydrogen by autothermal reforming of natural gas
Figure 2 illustrates a second preferred embodiment of the present invention,
where
hydrogen for the heavy oil upgrading and gas for injection into the reservoir
is
generated by autothermal reforming (ATR) of natural gas. The example is based
on the
same heavy oil and production volume of oil as Example 1.
Natural gas, 135 ton per hour (221.000 Sm3 per hour), is introduced through a
gas line
10 and OZ (from an air separation unit) is introduced through a line 10' into
an ATR unit
11. The ATR unit 11 comprises one or more autothermal reforming reactors
wherein
natural gas is reformed by steam reforming combined with partial combustion.
Steam
reforming is, as mentioned above, an endothermal reaction and the energy
required is
supplied from partial combustion of a part of the natural gas in the same
reactor
according to the following reactions:
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Steam reforming CH4 + H2O = CO + 3H2
Partial combustion CH4 + 3/2 OZ = CO + 2H20
The CO is thereafter converted into C02 according the following reaction:
Water gas shift CO + H20 = COz + Hz
Hydrogen, 35 ton per hour, is separated from the remaining gases as described
in
example 1 and a hydrogen rich fraction is led into a hydrogen line 12 to a
heavy oil
upgrading unit 17.
Oxygen for the partial combustion is preferably introduced into the reactors)
as purified
oxygen or oxygen enriched air. Purified oxygen is preferred as the absence of
the inert
nitrogen in the reactor reduces the total gas in the system and simplifies the
separation
of hydrogen. The purified oxygen is generated in an air separation unit (ASU),
separating oxygen and nitrogen in two fractions.
The nitrogen, 4.1 GSm3/y, from the ASU is led through a nitrogen line 13 and
CO2, 350
ton per hour from the ATR unit 11 is led through a line 14 to a unit for heavy
oil
production 15. The steam amount available for injection is the difference
between the
steam produced in the synthesis gas heat recovery section and the steam needed
for
production of 70 MW power for the ASU. In the unit for heavy oil production
the
nitrogen, COZ and steam are injected to enhance the recovery of heavy oil.
Heavy oil
produced in the unit for heavy oil production 15 is led from the unit to a
unit for heavy
oil upgrading 17 through a heavy oil line 16. The products from the unit for
heavy oil
upgrading correspond to the products described in Example 1.
Calculations have been carned out for a plant, according to Figure 2, for
production of
hydrogen by Auto-Thermal Reforming (ATR) of natural gas. The hydrogen
consumption will be about 35 ton/hr (410500 Sm3/hr) for upgrading 200000 bpd
heavy
oil. The natural gas needed for production of this amount of HZ will be about
1.75
GSm3/year depending on of much flue gas and LPG that are available in the
integrated
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natural gas and heavy oil upgrading complex. In this example no flue gas or
LPG are
used as feed to the reforming section. By partly replacing the natural gas
feed with flue
gas and LPG the natural gas consumption may be decreased by more than 20 %.
The air separation unit can deliver 23040 MTPD N2 and 3840 MTPD 02. This air
separation unit requires approximately 70 MW of power, which is delivered in
the form
of high-pressure steam from the synthesis gas section. The ratio between 02
and natural
gas will be about 0.65 giving a nitrogen production of about 4.1 GSm3/year
(2.34* 1.75
GSm3/year)
The nitrogen is extracted at 3 bar and 0 degrees C. The gas is compressed to
220 bars
for injection (IOR). Compression requires approximately 180 MW.
The oxygen is fed to an ATR for production of synthesis gas from natural gas.
The
process operates with a steam/carbon ratio of 0.6. The temperature and
pressure at the
outlet from the ATR is 1030 degrees Celsius and 45 bars respectively. See
Table 2 for
the natural gas composition. Note! All compositions are given on a dry basis,
i.e.
without water.
Natural as Ox en
Mole % Mole
CH4 83.7
CZH6 5.2
C3+ 3.2
COZ 5.2
NZ + Ar 2.7 1.0
OZ 0.0 99.0
H20 0.0
Sum 100
Total [Sm 221 000 ~ 190 85~
/hr]
Table 2. Composition of feeds to synthesis gas section
ATR outlet
Mole
HZ 62.9
CO 28.5
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COZ 4.8
CH4 2.5
NZ + Ar 1.3
Sum 100
Total [5m 652000
/hr]
Table 3. Gas composition out of the ATR
The synthesis gas is further sent to CO shift conversion. The gas mixture into
the shift
reactor can have a varying composition depending on the conditions in the ATR
(steam
ratio, pressure and temperature). One-step shift reactor may convert the CO
down to a
few percent. A two-step shift converter may decrease the CO content in the gas
far
below 1 percent. The gas mixture out from the shift reactor contains
significant amounts
of steam. After cooling to e.g. 40 °C most of the steam will be
condensed out.
The separation of COZ may be performed by amine washing (e.g. ethanol amine)
capturing above 90 % of the COZ in the gas. The COZ rich amine solution is fed
to a
stripping unit where the COz will be liberated because of the temperature
increase and
pressure reduction, further COZ can be set free from the amine solution by
stripping
with steam.
99% of the COZ in the gas (equivalent to 330 ton COZ per hour) is recovered in
an
MDEA process. Due to a high concentration of COZ in the natural gas feed, this
example includes COZ removal prior to ATR (equivalent to 20 ton COz per hour),
so
that the total amount of recovered COZ is 350 ton per hour. Recovered COZ is
compressed to 220 bar, and may if so desired be mixed with nitrogen (and
eventually
available steam) prior to injection into the reservoir. This concept also
represents a
favourable way of C02 capture due to the high concentration of the C02 in the
process
stream.
The remaining gas is used in fired heaters for superheating of steam in power
production and preheating of natural gas feeds.
The unit for heavy oil upgrading/refining may in both examples one can
envisage use
the gases produced in the present concept for both downhole upgrading and
enhanced
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oil recovery. Hydrogen could be used for partial downhole upgrading to obtain
a
transportable oil which would be upgraded to finished products at a nearby
upgrader or
exported to another refinery. A downhole unit will reduce the loss of energy
(heat) in
transport lines of steam, gases and oil. Additionally, dilution of the heavy
oil to make it
flow through transport lines will be unnecessary.
The energy needed to increase the transportability of the heavy oil in the
reservoir may
also be geo heat or a combination of geo heat and energy produced in the
reforming
process both down hole and in more conventional facilities off or onshore.
It is also possible to supply heat to a reservoir by injection air, oxygen or
oxygen
enriched air into the reservoir. For reservoir temperatures above about 50
°C,
spontaneous combustion will usually occur soon after the start of air
injection. The heat
produced by the combustion will, if the temperature of the combustion is high
enough,
vaporize the water and some of the oil to enhance the recovery of oil from the
reservoir.
Any hydrogen produced in the gas conversion part, i.e. ATR or steam reforming
units,
can be used for other purposes, such as fuel for fuel cells, and for other
industrial
purposes such as production of ammonia, methanol and synthetic fuel.
