Note: Descriptions are shown in the official language in which they were submitted.
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ME T HOD OF PRODUCING A HYDROCARBON STREAM FROM A
SUBTERRANEAN ZONE
The present invention relates to a method of
producing a hydrocarbon containing stream from a
subterranean zone wherein an injection fluid is injected
into the subterranean zone.
It is known to inject an injection fluid into a
subterranean zone such as an oil or gas field in order to
maintain a desired pressure therein to improve the
production of the desired hydrocarbon stream from the
subterranean zone. In case oil is the hydrocarbon stream
to be produced from an oil field, this is called
'enhanced oil recovery' (also known as 'EOR'). Injection
fluids that have been proposed to inject in an oil field
for EOR are a.o. natural gas (NG), carbon dioxide (CO2)
and nitrogen (N2). The injection of injection fluids such
as NG, CO2 and N2 in an oil field has been described in
e.g. <<World's Largest N2-generation Plant, Commissioned
for Cantarell Pressure Maintenance>>, J.C. Kuo, Doug
Elliot, Javier Luna-Melo, Jose B. De Leon Perez,
published in Oil & Gas Journal, March 12, 2001. Other
publications which describe the use of such injection
fluids are for example CA-A-2147079, CA-A-2261517,
CA-A-2163684 and US-A-4161047.
The above and other known injection fluids have
several disadvantages. Natural gas as such has become too
expensive to be used for injection. Also the usual method
for the production of nitrogen using an Air Separation
Unit (ASU) is relatively expensive.
A further problem is that the known injection fluids
are often available at low pressures and as a result a
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compression step is necessary before injection into t(;:e)
oil field, leading to additional costs.
US-A-4512400 describes a process to make a LPG type
injection fluid from natural gas. In this process natural
gas is first converted into a mixture of carbon monoxide
and hydrogen and secondly this gas mixture is used as
feed in a Fischer-Tropsch synthesis. From the synthesis
product an ethane, propane and butane containing gas,
i.e. the LPG type gas, is isolated and used as injection
fluid.
EP-A-1004746 describes a process for performing an
enhanced oil recovery by partial oxidation of an
associated gas into a mixture of carbon monoxide and
hydrogen. This mixture is used as feed in a Fischer-
Tropsch synthesis to obtain a liquid hydrocarbon product
and an off-gas. This off-gas will contain nitrogen,
carbon monoxide, carbon dioxide, hydrogen and C1-05
hydrocarbons. This off-gas is used as fuel to generate
energy in an expanding/combustion process, e.g. a
combined gas turbine/steam turbine cycle. The energy
generated is in turn used for the secondary and/or
enhanced recovery of oil from a subsurface reservoir.
A disadvantage of the process of US-A-4512400 and
EP-A-1004746 is that a Fischer-Tropsch process step is
part of the method. Such a process step makes the method
complex.
US-A-3150716 describes a method for producing a
hydrocarbon stream from a subterranean zone wherein an
injection fluid is used comprising synthesis gas. The
injection fluid is obtained by catalytically converting,
i.e. steam reforming, methane and steam to a synthesis
gas mixture.
at+
AMENDED SHEET
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',Ep2b06066473,:
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US-A-4434852 describes the preparation of an
injection fluid. The injection fluid is a flue gas, which
may be obtained in a boiler or internal combustion
engine.
In Chenglin Zhu et al., An EOR application at Liaohe
Oil field in China, Test for pumping Boiler Flue Gas into
Oil Wells, Paper at First National Conference on Carbon
Sequestration, May 15-17, 2001, Washington DC, USA flue
gas as obtained in a fired boiler is described as
injection fluid.
A disadvantage of using a flue gas is that the oxygen
content of the directly obtained flue gas is about
G:\OA\TS1714PCT
AMENDED SHEET
=IY1Q4/20071
".44,r
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fluid. Special measures have to be taken to lower the
oxygen content.
The above problems are even more pertinent if huge
amounts of the injection fluid are required.
It is an object of the present invention to at least
minimize one of the above problems.
It is a further object to provide an alternative
method of producing an injection fluid for injection in a
subterranean zone such as an oil or gas field.
One or more of the above or other objects can be
achieved according the present invention by providing a
method of producing a hydrocarbon containing stream from
a subterranean zone wherein an injection fluid is
injected into the subterranean zone, the method at least
comprising the steps of:
(a) providing an injection fluid comprising synthesis
gas;
(b) injecting the injection fluid into a subterranean
zone for obtaining a desired pressure therein;
(c) obtaining a hydrocarbon containing stream from
the subterranean zone.
It has been surprisingly found that according to the
present invention the production of the hydrocarbon
containing stream from the subterranean zone can be
performed in an economic manner, in particular if large
amounts of injection fluid are desired.
A further advantage of the present invention is that
the injection fluid will be substantially free of free
oxygen (02), as a result of the presence of the synthesis
gas.
The hydrocarbon stream to be produced from the
subterranean zone may have various compositions, but will
usually be natural gas, gas condensate, oil, also
referred to as crude mineral oil, or a mixture thereof.
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The subterranean zone may be any subterranean zone
comprising hydrocarbons to be harvested. Examples of a
subterranean zone are e.g. an oil field, gas field, etc.
It goes without saying that the subterranean zone may
also be located underwater or the like.
The injection fluid may be produced in various
manners, e.g. by catalytic or non-catalytic partial
oxidation or by any other way, provided that it comprises
synthesis gas (i.e. carbon monoxide (CO) and hydrogen
(H2)).
The injection of an injection fluid and the
associated production of the hydrocarbon stream from the
subterranean zone is known as such and for example
described in the references discussed in the introductory
part of this disclosure. The desired pressure to be
obtained in the subterranean zone will depend on the
circumstances and can be readily determined by the person
skilled in the art. Usually, it is desired to maintain
the existing pressure in the subterranean zone;
therefore, the term "obtaining a desired pressure" also
includes maintaining a certain pressure in the
subterranean zone.
Preferably, the injection fluid comprises from 0.1 to
20 mol% synthesis gas (i.e. CO + H2) based on dry gas,
preferably > 3 mol% and < 10 mol%, more preferably about
5 mol%.
Further it is preferred that the injection fluid
comprises, based on dry gas:
- from 0.1 to 20 mol% synthesis gas, preferably
> 3 mol% and < 10 mol%, more preferably about 5 mol%;
- from 5 to 20 mol% CO2, preferably from 10 to
20 mol% and even more preferably from 12 to 15 mol%;
- from 70 to 90 mol% N2, preferably from 80 to
90 mol%.
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Advantageously, the injection fluid provided in
step (a) is substantially free of 02, preferably
comprising less than 10 ppmv.
Further it is preferred that the injection fluid at
injection has a pressure in the range from 50 to 500 bar,
preferably > 70 bar and < 400 bar, more preferably > 80
bar and < 300 bar; and a temperature in the range from 0
to 300 C, preferably > 20 C and < 100 C.
The injection fluid is preferably made from a
hydrocarbon stream. This hydrocarbon stream may be
isolated from the hydrocarbon stream to be produced from
the subterranean zone. Alternatively this hydrocarbon
stream may be derived from another source. In order to
avoid any confusion this hydrocarbon stream is further
referred to as the carbonaceous synthesis gas source. The
synthesis gas may in general be made from one or more
carbonaceous synthesis gas sources using one or more
conversion processes. Examples of suitable carbonaceous
synthesis gas sources are natural gas, LPG, coal, brown
coal, peat, wood, coke, soot, biomass, oil, condensate or
any other gaseous, liquid or solid fuel or mixture
thereof. Preferred carbonaceous synthesis gas sources are
part of the hydrocarbon containing stream produced from
the subterranean zone. Examples of such sources are
natural gas when producing a natural gas hydrocarbon and
more especially associated gas when producing a crude oil
hydrocarbon. In case of a gaseous feed, especially
gaseous feeds comprising methane, the preferred
conversion processes are steam reforming, suitably auto
thermal steam reforming (ATR), catalytic partial
oxidation and preferably by a partial oxidation process,
more preferably by a non-catalytic partial oxidation
process. The non-gaseous carbonaceous sources, like for
example coal, peat, wood, petroleum coke, soot, biomass,
oil, de-asphalted oil, cracked vacuum residue and gas
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condensate, are preferably converted to synthesis gas by
means of a partial oxidation process.
The partial oxidation may be performed in one or more
partial oxidation steps in order to increase the volume
percentage of nitrogen and carbon dioxide relative to the
amount of carbonaceous synthesis gas source used.
In another aspect, the present invention provides a
method of producing an injection fluid, the method at
least comprising:
(al) providing a synthesis gas containing stream; and
(a2) partially oxidising the synthesis gas containing
stream provided in step (al), thereby obtaining an
injection fluid comprising synthesis gas.
It has been surprisingly found that, by partially
oxidising a synthesis gas stream, a huge amount of
suitable injection fluid can be obtained in a relatively
economic manner.
A further advantage is that the stream obtained in
step (a2) is available at relatively high pressures such
that the stream obtained has a pressure suitable to be
injected directly or after further compression in an oil
field or other subterranean zone. As a result, less costs
for compression have to be made before injection in an
oil field. In some cases a subsequent compression step
may even be dispensed with.
The synthesis gas containing stream provided in
step (al) may be a partially oxidised stream, but may
also be obtained in any other suitable way. Anyway, the
'synthesis gas containing stream' provided in step (al)
contains more synthesis gas (preferably > 25 mol%, based
on dry gas) than the 'injection fluid' obtained in
step (a2) (preferably from 0.1 to 20 mol% based on dry
gas). If desired more than two partial oxidation steps
may take place, if desired.
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As an example the synthesis gas containing stream
provided in step (al) may be obtained from a carbonaceous
synthesis gas source as described above.
Preferably, the synthesis gas containing stream
provided in step (al) is obtained by partial combustion,
i.e. partially oxidising a hydrocarbon stream, preferably
selected from the group consisting of oil, gas and coal,
more preferably gas. The latter is frequently available
at an oil field, in the form of associated gas, in which
the injection fluid is to be injected for producing oil.
As methods for producing synthesis gas are well known
from practice, this is not further discussed here. An
advantage of using natural gas or associated gas as feed
for step (al) is that these feeds are obtained from the
subsurface reservoir at high pressures. This allows this
feed to be used without less or no compression as feed to
the partial oxidation as performed at elevated pressure.
Preferably the synthesis gas containing stream
provided in step (al) comprises > 25 mol% synthesis gas
based on dry gas, preferably from 30 to 50 mol%, more
preferably from 30 to 40 mol%.
Further it is preferred that the synthesis gas
containing stream provided in step (al) has a pressure in
the range from 20 to 200 bar, preferably > 40 bar and
< 100 bar; and a temperature in the range from 100 to
400 C, preferably > 200 C and < 350 C.
It is preferred that the synthesis gas containing
stream provided in step (al) is also obtained by
partially oxidising a hydrocarbon stream. Preferably the
partial oxidation in both steps (al) and (a2) are
obtained by non-catalytic partial oxidation, i.e. partial
combustion. The advantage of more than one partial
oxidation step to obtain the injection fluid (compared to
one partial oxidation step) is that the temperature of
the process can be better controlled.
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If desired, the synthesis gas containing stream
obtained in step (al) may be cooled before partially
oxidising it in step (a2). If in step (al) non-catalytic
partial oxidation is used, any free 02 containing stream
may be used. In step (a2) preferably air or oxygen-
enriched air is used, preferably containing at least 70%
N2.
In a further preferred embodiment step (a2) is
performed by recycling part of the synthesis gas
containing stream obtained in step (al) back to step
(al). Preferably the recycle synthesis gas is reduced in
temperature before being recycled. Preferably 1 to
mol% is recycled to step (al), wherein the recycle is
calculated as the mol fraction recycle stream on the
15 total injection fluid prepared by the process times 100%.
Preferably the injection fluid obtained in step (a2)
or in case of a recycle embodiment in the combined steps
(al) and (a2) has a pressure in the range from 20 to
200 bar, preferably > 50 bar and < 80 bar; and is cooled
20 to a temperature in the range from 0 to 300 C,
preferably > 20 C and < 100 C. If desired the injection
fluid may be compressed before injection to a pressure in
the range of from 50 to 500 bar.
Further it is preferred that the injection fluid
obtained in step (a2) is substantially free of 02,
preferably comprising less than 10 ppmv.
More preferably, the injection fluid obtained in
step (a2) comprises from 0.1 to 20 mol% synthesis gas
based on dry gas, preferably > 3 mol% and < 10 mol%, more
preferably about 5 mol%; even more preferably the
injection fluid obtained in step (a2) comprises, based on
dry gas:
- from 0.1 to 20 mol% synthesis gas, preferably
> 3 mol% and < 10 mol%, more preferably about 5 mol%;
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- from 5 to 20 mol% CO2, preferably from 10 to
20 mol% and even more preferably from 12 to 15 mol%;
- from 70 to 90 mol% N2, preferably from 80 to
90 mol%.
If desired, the injection fluid obtained in step (a2)
may be further processed before injection into an oil
field or other subterranean zone, without substantially
changing the amount of synthesis gas being present. As an
example, the injection fluid obtained in step (a2) may be
cooled, freed from any H20 being present and compressed.
In an even other aspect the present invention
provides an injection fluid obtainable by the method
according to the present invention, preferably
comprising, based on dry gas:
- from 0.1 to 20 mol% synthesis gas, preferably
> 3 mol% and < 10 mol%, more preferably about 5 mol%;
- from 5 to 20 mol% CO2, preferably from 10 to
mol% and even more preferably from 12 to 15 mol%;
- from 70 to 90 mol% N2, preferably from 80 to
20 90 mol%.
Preferably the injection fluid is substantially free
of 02, preferably comprising less than 10 ppmv.
In a further aspect, the present invention provides a
system for producing an injection fluid for injection in
a subterranean zone, the system at least comprising:
- a first gasification reactor having an inlet for an
oxygen containing stream, an inlet for a hydrocarbon
stream, and downstream of the first gasification reactor
an outlet for a synthesis gas containing stream produced
in the first gasification reactor;
- a second gasification reactor having an inlet for a
second oxygen containing stream, an inlet being connected
to the outlet of the first gasification reactor, and
downstream of the second gasification reactor an outlet
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for an injection fluid produced in the second
gasification reactor.
Preferably the system further comprises:
- a first cooler for cooling the synthesis gas
containing stream produced in the first gasification
reactor; and
- a second cooler for cooling the injection fluid
produced in the second gasification reactor.
The first and second gasification reactors may be any
suitable gasification reactor. As gasification reactors
are known as such, they are not further discussed here.
If desired more than one first and second gasification
reactors may be used thereby obtaining a system
comprising more than two gasification reactors.
Preferably the second gasification reactor is a gas
gasification reactor in which partial oxidation of the
gas can be performed. Examples of suitable gas gasifiers
and coolers are described in US-A-4836831, EP-A-257719,
EP-A-774103.
The first and second oxygen containing streams may be
from any suitable source. Preferably substantially pure
(> 95 mol%) oxygen or (optionally oxygen-enriched) air or
the like is used in the first gasification reactor and
(optionally oxygen-enriched) air in the second
gasification reactor.
In a further aspect, the present invention provides a
system for producing an injection fluid for injection in
a subterranean zone, the system at least comprising:
- a gasification reactor having an inlet for an oxygen
containing stream, an inlet for a hydrocarbon stream, and
downstream of the first gasification reactor an outlet
for a synthesis gas containing stream produced in the
gasification reactor;
- a cooler for cooling the synthesis gas containing
stream produced in the first gasification reactor; and
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- splitter to split the cooled synthesis gas into two
streams, a conduit to recycle one synthesis stream to the
gasification reactor and a conduit to discharge the
injection fluid.
The gasification reactors may be any suitable
gasification reactor. As gasification reactors are known
as such, they are not further discussed here. If desired
more than one gasification reactor may be used in
parallel thereby obtaining a system comprising two or
more gasification reactors. Preferably the gasification
reactor is a gas gasification reactor in which partial
oxidation of the gas can be performed.
The invention will now be described by way of example
in more detail with reference to the accompanying non-
limiting drawings, wherein:
Figure 1 schematically shows a method of producing a
hydrocarbon stream from a subterranean zone according to
the present invention; and
Figure 2 schematically shows a process scheme for
performing a method of producing an injection fluid
according the present invention wherein two gasification
reactors are used in series flow.
Figure 3 schematically shows a process scheme for
performing a method of producing an injection fluid
according the present invention wherein a recycle is
applied.
For the purpose of this description, a single
reference number will be assigned to a line as well as a
stream carried in that line. Same reference numbers refer
to similar components.
Figure 1 schematically shows a method of producing
oil 110 from a subterranean oil field 100 (under the
surface 150 of the earth) wherein an injection fluid 50
is injected in or near the oil field 100.
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The injection fluid 50 contains synthesis gas
(CO + H2), preferably 0.1 - 20 mol% based on dry gas. The
injection fluid 50 may have been obtained in various
manners. Preferably, the injection fluid 50 is obtained
by partial oxidation, e.g. in a system 1 comprising one
or more gasification reactors. The injection fluid 50 is
injected using an injector 120 in the subterranean oil
field 100, thereby obtaining or maintaining a desired
pressure to enhance oil production from the oil field
100. Usually the injection fluid 50 is compressed (the
compressed injection fluid is indicated as stream 51)
before injecting into the oil field 100. From the oil
field 100, an oil stream 110 is obtained and removed at
the pumping unit 130 for further processing. More than
one stream 110 may be obtained; also, other hydrocarbon
streams such as natural gas may be produced.
Reference is now made to Figure 2. Figure 2
schematically shows a system 1 for producing an injection
fluid 50 containing synthesis gas to be injected in an
oil field (not shown in Fig. 2; see Fig. 1).
The system 1 comprises a first gasification reactor 2
and a second gasification reactor 3.
In the embodiment shown in Fig. 2, the first
gasification reactor 2 is an oil gasification reactor and
the second gasification reactor 3 is a gas gasification
reactor. The person skilled in the art will readily
understand that the first gasification reactor 2 may also
be a coal gasification reactor or a gasification reactor
suitable for any other hydrocarbon containing stream.
In the system 1 of Fig. 2 an oil containing stream 10
and an oxygen containing stream 20 are fed at inlets 4
and 5, respectively, into the oil gasification reactor 2.
The oil containing stream 10 is partially oxidised by
combustion in the gasification reactor 2 in a usual
manner thereby obtaining a synthesis gas containing
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stream 30 (removed via outlet 6) and a slag 60 (removed
via outlet 13). To this end usually one or more burners
(not shown) are present in the gasification reactor 2.
The synthesis gas containing stream 30 produced in
the oil gasification reactor 2 usually comprises
> 25 mol% synthesis gas; has a pressure in the range from
20 to 200 bar; and has a temperature in the range from
1000 to 1500 C. Usually the stream 30 is cooled to a
temperature in the range of 100-400 C in cooler 15,
wherein the heat is used for e.g. steam generation.
Subsequently, the synthesis gas containing stream 30
is fed at inlet 7 into the second gasification reactor 3,
being a gas gasification reactor. If desired, the
synthesis gas containing stream 30 may be treated before
entering the second gasification reactor 3, e.g. to
remove any sulphur compounds being present.
In the second gasification reactor 3, the synthesis
gas containing stream 30 is partially oxidised,
preferably also by combustion, until only a small amount
of synthesis gas (i.e. CO + H2) is left. If combustion is
used for the partial oxidation in second gasification
reactor 3, air or oxygen-enriched air is used, which is
supplied at inlet 8 via stream 40.
Injection fluid 50 is obtained (which is removed via
outlet 9). Usually, the injection fluid 50 obtained in
the second gasification reactor 3 comprises from 0.1 to
20 mol% synthesis gas based on dry gas.
Although according to the embodiment of Figure 2 the
synthesis gas containing stream 30 is a 'partially
oxidised stream', it may also have been obtained in any
other suitable way. Anyway, the 'synthesis gas containing
stream' provided in the first gasification reactor 2 (or
'step (a)') contains more synthesis gas (viz. preferably
> 25 mol% CO + H2) than the 'injection fluid' obtained in
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the second gasification reactor 3 (or 'step (a2)';
preferably from 0.1 to 20 mol% CO + H2).
Usually, the injection fluid 50 obtained in the
second gasification reactor 3 has a pressure in the range
from 20 to 200 bar, preferably between 50 and 80 bar; has
a temperature in the range from 0 to 300 C (after
cooling in second cooler 25); and is substantially free
of 02, preferably comprising less than 10 ppmv 02.
As the injection fluid 50 may (and usually will) have
a relative high pressure that is suitable for injection
in an oil field (at about 70 bar), the resulting stream
can be used as such as an injection fluid, with only a
reduced amount of additional compression (e.g. in
compressor 12 thereby obtaining stream 51) needed.
Usually the pressure of the stream 51 is in the range
from 50 to 500 bar. In some cases the additional
compression may even be dispensed with. If desired any
remaining free 02 may be further removed, e.g. by
catalytic oxidation using a suitable catalyst.
The person skilled in the art will readily understand
that the present invention may be modified in various
ways without departing from the scope as defined in the
claims. As an example, the injection fluid 50 may be
further processed (such as cooling, H20 removal, etc.)
before use as an injection fluid in an oil field or other
subterranean zone. Alternatively, the injection fluid 50
may be stored for later use.
Figure 3 shows another preferred embodiment of the
present invention. In gasification reactor 201 a methane
containing gas 202 is partially oxidized with air 203 to
obtain a synthesis gas containing stream 204. This stream
is cooled in a first step against evaporating water 206
to prepare high-pressure steam 207 in a boiler 205. The
cooled synthesis gas containing stream is further cooled
against air in air cooler 208. Water 212 is separated in
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drum 209. Part 210 of the synthesis gas containing stream
is recycled to gasification reactor 201. The remaining
net synthesis gas containing stream or injection fluid
211 is preferably further dehydrated in a so-called TEG
Dehydration Unit (not shown) before being compressed in
compressor 213 to obtain a pressurized injection fluid
214 suited for injection in the hydrocarbon reservoir 219
as present below surface 218. The subsurface reservoir
219 will produce a hydrocarbon stream 215 due to the
resulting higher pressure in the reservoir 219. In case
the hydrocarbon stream 215 is a natural gas stream,
optionally in combination with gas condensate stream, a
separation unit 216 may be part of the scheme. This unit
216 will separate the liquid condensates, the LPG
fraction and optionally the ethane fraction (all shown as
217) from the produced gas 215. In the process according
the present invention the stream 202 may be gas 215 or a
gas richer in methane 217 from which gas condensate, a
LPG fraction and/or an ethane fraction is separated from.
It will depend on the local value of these products
whether they will be present in stream 202.
By adjusting the recycle ratio between recycle stream
210 and net production stream 211 the desired content of
nitrogen and carbon dioxide in the injection fluid can be
achieved. For example, in time the nitrogen content of
the gas 202 or gas 215 will increase due to the use of
injection fluid 214. This would result in less recycle in
time to achieve the same nitrogen content in steam 211.
The invention will be illustrated by the following
experiment based on model calculations. Reference is made
to Figure 3. In this example a methane containing gas 202
is partially oxidized with air 203. The quality and
quantity of the most important streams are provided on a
water free basis in the below table. This table shows
that a 10 kg/s stream of lean gas can prepare 210 kg/s of
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injection fluid using the present invention. The
percentage recycle is 20/210 * 100% = 9,5%
Stream as in 202 203 210 211
Figure 3
Kg/s 10 200 20 210
H2 (%mol) - - 2 2
CO - - 3 3
CO2 0.5 (*) 10 10
N2 3.4 80 85 85
CH4 85 - - -
C2+ 11.1 - - -
02 - 20 <10 ppm <10 ppm
(*) Assumed zero
