Note: Descriptions are shown in the official language in which they were submitted.
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CANADA
PATENT APPLICATION
PIASETZKI NENNIGER KVAS LLP
File No.: NSOL041/JTN
Title:
SOLVENT INJECTION PLANT FOR ENHANCED OIL RECOVERY
AND METHOD OF OPERATING SAME
Inventor(s):
John Nenniger
Ron Holcek
Jim Dillon
Vining Wolff
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Title: SOLVENT INJECTION PLANT FOR ENHANCED OIL
RECOVERY AND METHOD OF OPERATING SAME
FIELD OF THE INVENTION
The present invention relates generally to enhanced oil recovery
(E0R) processes and in particular to in situ methods for enhanced oil
recovery ("EOR"), of the type that may be used to recovery oil from
underground bitumen or oil sand formations. Most
particularly this
invention relates to solvent based in situ EOR and the surface solvent
injection and purification facilities and methods that are suitable for
operating such a solvent based surface facility.
BACKGROUND OF THE INVENTION
It is challenging to efficiently extract heavy hydrocarbons from
underground reservoirs because, at reservoir conditions such heavy
hydrocarbons may not be very mobile, if at all. Many different reservoir
conditions exist and each one may pose unique challenges for extraction
due to unique characteristics of the reservoir. Presently, although new
discoveries of conventional oil are still being made, it is believed that most
of the easy to recover light mobile hydrocarbon deposits have been
discovered and substantially depleted. Many of the remaining and newly
discovered resources present considerable technical challenges which
have to be overcome for the resource to be economically and safely
recovered.
A prime example of an abundant but technically difficult resource is
found in the oil sands, for example, in Alberta. Surface strip mining is
extensively used, but can only effectively reach a small fraction of the total
resource, typically thought to be about less than 10%. Further, surface
mining is destructive as it requires stripping off the surface layer of dirt
and forest to access the oil sands buried underneath, uses vast amounts
of fresh water in the bitumen sand separation step and leaves a persistent
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liquid residue which collects in large and ever growing tailings ponds on
the surface of the land. The liquid in the tailings pond contain toxic and
carcinogenic pollutants such as heavy metals, as well as residual
hydrocarbons and has proved to be very persistent and difficult to deal
with.
Consequently efforts have been made to develop more
environmentally friendly technologies to extract the estimated remaining
90% of the resource which is unavailable to surface mining. These other
technologies are often referred to as in situ extraction techniques because
they recover the hydrocarbons buried in the ground without significant
disturbance of the surface soil and the arboreal forest as is required with
the strip mining approach.
Among the various technologies which have been or are being
developed are steam assisted gravity drainage (SAGD), using steam
solvent combinations, using direct electrical heating in the reservoir, either
through resistance heating or microwaves and using fire floods through
such methods as Toe to Heel Air Injection (the so called THAI method.)
Other methods include the so called VAPEX method which purports to be
a cold solvent vapour diffusion process using a mixture of solvent and
displacement or diluent gases.
Of all of the foregoing, only SAGD is presently being deployed on a
commercial scale. However it is very energy intensive, producing large
volumes of green house gas emissions. At present vast quantities of
natural gas are consumed to create the high temperature steam needed
to melt and mobilize the bitumen. Further, the energy efficiency of the
SAGD process is nowhere near the theoretical values and so requires
much more energy, on average, than it should according to
thermodynamic calculations. Water use, which is required to make the
steam in the first place, remains a key environmental concern. A better
alternative to SAGD is desired.
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Steam solvent combinations have been tried on a number of
occasions, but this technology is not yet being commercially deployed.
Unfortunately, mixing solvent with steam creates a combination of a
condensable species (steam) with a non-condensable species (solvent
vapour), meaning that the material balance is unstable and inevitably
leads to a build-up of the solvent in the vapour chamber. Further such a
process requires surface facilities which can deal with both solvent
species and steam, meaning that the capital costs of the surface facilities
are up to twice as expensive as compared to just using solvent or steam
alone. THAI has also been tried, on a pilot scale, but is not commercially
deployed. Electrical and microwave applications have also been
proposed, but the upfront fuel to electricity conversion is so inefficient
that
electrical heating processes are highly unlikely to be ever be competitive
on a net energy recovery basis.
The most promising new technology is believed to be a condensing
solvent process called the N-Solv extraction process, which uses
relatively pure solvent vapour at elevated pressures. According to this
technology, a solvent, such as propane or butane can be injected as a
vapour into an underground formation at a predetermined pressure. The
pressure can be selected, having regard to reservoir conditions relating
to, for example, confinement, to determine a temperature at which the
solvent will condense, within the limits of the physical properties of the
solvent. In general, and subject to the limits articulated above, the higher
the reservoir pressure the higher the condensation temperature. The
extraction pressure can be controlled by controlling the injection rate of
the solvent vapour. As it condenses, the solvent will release its latent
heat of condensation to the bitumen, thereby both warming it and
dissolving it due to the liquid solvent's ability to dissolve the bitumen. The
combination of warming and liquid solvent dilution mobilizes the bitumen
permitting it to flow, under the influence of gravity, to a production well. A
feature of the N-Solv process is that the hydrocarbons may be mobilized
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at a much lower temperature than is required for SAGD leading to large
energy and green house gas savings. In part, this is due to the solvent
effect, namely, the viscosity of the bitumen is reduced by being dissolved
by the solvent, leading to increased mobility at a much lower temperature
than is possible with steam processes where there is no solvent effect.
A further feature of the N-Solv technology is the control of the
negative effects of noncondensable gases, for example by the removal of
such noncondensable gases from the vapour extraction chamber during
the extraction process. Noncondensable gases may be considered as
any gas or vapour species other than the solvent which are present in the
extraction chamber and which are not condensable at the extraction
interface at the temperature and pressure selected for the primary
solvent. Such noncondensable gases can arise either naturally, being off
gassed from the warming bitumen or through the accumulation of such
gases as contaminants from the injected solvent. Because such
contaminant gases are noncondensable they can accumulate at the
extraction interface changing the gas concentrations and affecting the
bubble point conditions. In sufficient quantities, such gases can interfere
with the condensation step of the solvent and act as a vapour barrier
between the condensing solvent and the bitumen interface. Such
interference is believed to explain, in part, the failure of the so called
VAPEX process, which mixes a cold solvent gas with a carrier or
displacement gas which are co-injected into the reservoir. An important
advantage of the N-Solv extraction process is the ability to conduct the
condensation within the reservoir in such a way as to be able to remove
the noncondensable gases as the extraction process proceeds to retain
the desired bubble point conditions at the bitumen interface. One way this
may be accomplished is to use a relatively pure solvent so the limited
solubility of the non-condensable gases is sufficient to permit the small
quantity of noncondensable gases to dissolve into the mixed condensed
liquid solvent and bitumen as it drains and thereby continuously removing
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noncondensable gases from the interface and the chamber and
preventing undesirable accumulations.
Similar to SAGD the N-Solv process ideally uses a pair of generally
horizontal wells sometimes referred to as a well pair, in which an upper
well is the injection well used for injecting solvent vapour and the lower
well is the production well used for bitumen and mixed fluid recovery. The
N-Solv process, like SAGD, is a gravity drainage process with the
mobilized liquids draining down into the production well from an extraction
chamber which is formed around and above the injection well by means of
the continuous solvent vapour injection. Unlike SAGD, the N-Solv
process is a low temperature process which requires very little energy as
compared to SAGD to mobilize the bitumen, estimated to be no more than
10 or 15 percent of SAGD. This is because whereas SAGD uses water,
which does not mix with the oil, an N-Solv extraction uses solvent which
can dissolve and thus reduce the viscosity of the in situ bitumen, making it
more mobile at much lower temperatures than is possible with SAGD.
While the N-Solv process has the promise of recovering
hydrocarbons with a much reduced environmental footprint, to be
effective, the surface or plant facilities have to be able to meet the
requirements of solvent purity, solvent handling, bitumen extraction and
conditioning, among other requirements. What is desired therefore is a
simple but effective solvent injection and purification plant design that can
be reliably used, for example, to conduct an in situ N-Solv process
extraction.
Various aspects of the N-Solv technology are disclosed in the
following patents:
Canadian Patent No. 2,235,085 issued January 9, 2007;
Canadian Patent No. 2,299,790 issued July 8, 2008;
Canadian Patent No. 2,351,148 issued July 29, 2008;
Canadian Patent No. 2,567,399 issued January 27, 2009;
Canadian Patent No. 2,374,115 issued May 18, 2010;
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Canadian Patent Application No. 2,633,061 filed February 23,
2000;
Canadian Patent Application No. 2,436,158 filed July 29, 2003;
Canadian Patent Application No. 2,549,614 filed June 7, 2006;
Canadian Patent Application No. 2,552,482 filed July 19, 2006;
Canadian Patent Application No. 2,591,354 filed June 1, 2007;
Canadian Patent Application No. 2,639,851 filed September 26,
2008;
Canadian Patent Application No. 2,688,937 filed December 21,
2009;
Canadian Patent Application No. 2,707,776 filed June 16, 2010;
United States Patent No. 6,883,607 issued April 26, 2005;
United States Patent No. 7,514,041 issued April 7, 2009;
United States Patent No. 7,363,973 issued April 29, 2008;
United States Patent No. 7,727,766 issued June 1, 2010;
United States Patent Application No. 12/308,082 filed June 5,
2007;
United States Patent Application No. 12/601,552 filed May 29,
2008;
United States Patent Application No. 12/567,175 filed September
25, 2009; and
A preliminary outline of a solvent recovery and recirculation facility
can be found in Canadian Patent No. 2,374,115. However, improvements
are required to provide an efficient plant design.
SUMMARY OF THE INVENTION
The purpose of the present invention is to be able to take the raw
multiphase fluid produced from the reservoir during the extraction process
and reliably and efficiently turn such multiphase fluid into sales bitumen or
oil, suitable for pipeline transport and solvent, suitable to be recycled and
re-injected, so more sales bitumen can be recovered. As well, other
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components of the multiphase fluid such as water, and miscellaneous
hydrocarbon species need to be separated and dealt with. The basic
steps of the method include removing the produced water from the
produced fluids, removing the solvent and any solution gas from the
produced fluids, purifying the solvent by removing the light ends (non-
condensables) and adding diluent to the produced oil to meet pipeline
specifications for approved viscosity and density, for example. Another
purpose of the present invention is to add make up solvent in an efficient
way, and in a way which permits continued extraction from the
underground formation. These and other objectives are achieved through
the surface facility design which includes the necessary flow lines,
pressure vessels and other process equipment to achieve these
purposes.
Essentially the solvent can be considered to be like a conveyor
belt, going through the plant, down into the formation, to be mixed with
hydrocarbons to be recovered, returned to the surface with the
hydrocarbons in a mixed fluid, separated from the hydrocarbons or sales
oil, and reconditioned and recirculated. The surface facility is, according
to the present invention, what keeps the solvent conveyor belt going
around and around.
Therefore according to a first aspect of the present invention there
is provided a solvent injection plant for stimulating enhanced oil recovery
from an underground formation by injecting a solvent at a pressure and
temperature to mobilize in situ hydrocarbons, the solvent injection plant
comprising:
an input flow line carrying mixed fluids recovered from the
formation;
a free water knock out vessel connected to said input flow line to
perform a liquid separation of the produced fluids into a mostly
oil/solvent/gas stream and a mostly water stream;
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a skim tank connected to the free water knock out vessel for
receiving water from the mostly water stream for residual oil removal;
a flash vessel in which most of the solvent is flashed into vapour, at
an elevated temperature and pressure;
a distillation column connected to the flash vessel for receiving the
solvent vapour; and purifying it into condensable and non-condensable
components; and
a second flash vessel for stripping additional solvent from the oil-
solvent stream at a higher temperature and lower pressure than the first
flash vessel.
According to a further aspect of the present invention there is
provided a solvent recovery and injection plant for in situ oil extraction,
where the solvent is injected into an underground formation at a bitumen
mobilizing pressure and temperature, said plant comprising:
an input flow line carrying fluids recovered a formation into said
plant, said recovered fluids including at least some recovered solvent;
a primary separation unit wherein said recovered solvent is
separated from said recovered fluids substantially at a bitumen mobilizing
pressure; and
an injector for re-injecting said pressurized solvent back into the
formation.
BRIEF DESCRIPTION OF THE DRAWINGS
Reference will now be made, by way of example only, to preferred
embodiments of the invention by reference to the attached drawings in
which:
Figure 1 is schematic of the inputs and outputs for a solvent
recovery and injection plant according to the present invention; and
Figure 2 is a schematic of the solvent recovery and injection plant
of Figure 1.
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DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
As shown in the Figure 1 the present invention comprises a surface
facility 10 to receive a stream of mixed fluids produced from an
underground formation which surface facility can separate the mixed
fluids into various components and then direct the separated fluids to
distinct destinations first within the facility 10, and then away from the
facility 10. The facility is purpose built to suit an in situ solvent based
gravity drainage extraction process, such as the N-Solv extraction
technology as will be described in more detail below. The specific
operating characteristics of the facility will be dictated by the reservoir
characteristics of the formation being treated, but each facility will share
the same basic process features. What will change is the bitumen
mobilizing pressures, or the pressure used to control the condensing
conditions of the solvent. The bitumen mobilizing pressure may be limited
due to the depth of the deposit or pay zone or due to the integrity of the
formation. What is required is to operate the process at a desired and
safe bitumen mobilizing pressure. Different solvents can be selected to
provide different extraction temperatures at the bitumen mobilizing
pressure, as will be understood by those skilled in the art.
In general terms the inputs into the surface facility 10 are the mixed
fluids production from the reservoir through the pipeline 12 and diluent 14
from a source of diluent 16 (if needed to make the produced or sales oil
meet pipeline specifications). As well another input is makeup solvent 18
from a source of solvent 20. The solvent can be any solvent suitable for
an N-Solv type of extraction process, namely, a bitumen mobilizing
solvent that can deliver warming through the latent heat of condensation
and solvent dilution to the in situ bitumen, at the desired extraction
conditions including a preferred bitumen mobilizing pressure. Typically
such conditions will include a pressure sufficient to permit a reasonable
temperature rise in the formation, without risking a loss of solvent due to
reservoir fracturing or loss through thief zones. At shallower depths and
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lower pressures, it is expected that butane might be a preferred solvent,
while at higher pressures it is expected that propane might be a preferred
solvent. However, the present invention is suitable for a variety of solvents
as discussed below. What is desired is to use a bitumen mobilizing
.. solvent at a bitumen mobilizing pressure that is safe.
The makeup solvent is required as the in situ process extracts oil
from the reservoir thereby creating an ever larger extraction chamber. A
larger extraction chamber in turn requires more solvent vapour to fill the
enlarging chamber and also more solvent as the solvent condenses at a
greater rate as the area of the extraction surface grows. The makeup
solvent may be added to any point of the facility to the solvent circulation
system. If the source of solvent is sufficiently pure to meet the
requirements of the in situ process, then the makeup solvent may be
added at the well head, provided it is heated, vapourized or pressurized
.. as needed to meet the operating specifications. On the other hand, in
most cases it is expected that the solvent will not be sufficiently pure, and
in this case it is preferred to add the solvent to the input side of the
facility
10 so that the solvent can be stripped of non-condensable gases and
purified within the facility 10 prior to passing the solvent into the
formation.
.. In this specification sufficiently pure means, for example, pure enough for
the draining solvent to be able to remove noncondensable gases from the
in situ extraction chamber namely sufficiently pure for use in an N-Solv
type extraction.
As well as purifying any make up solvent so as to meet the desired
.. in situ specifications, another purpose of the facility 10 is to separate
and
treat the mixed fluids recovered from the formation by the in situ
extraction process. According to the present invention therefore the
facility separates any non-condensable gas species from the solvent gas
and the solvent from the fluids such as water and oil. In addition the
.. water is separated from the oil and the oil conditioned, for example with
diluents, to permit the oil to be pipelined or otherwise removed from the
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facility site 10 as sales oil. As well the solvent is recovered from the
mixed fluid production and reconditioned so that it can be re-injected into
the formation at the desired temperature, pressure and purity
specifications. This means that the pressure and temperature of the
injected solvent are consistent with the desired condensing conditions
within the formation and that the solvent (which may be a combination of
makeup solvent and re-circulated solvent) is sufficiently pure, namely of a
single solvent species, so as to be able to remove non-condensable gas
species that may be present in the in situ extraction chamber. According
to the N-Solv technology, this prevents such non-condensable species
from accumulating at an extraction interface, which accumulation would
alter the bubble point conditions and thus inhibiting continued
condensation of the solvent onto the bitumen. It is believed that the most
desired in situ operating conditions are ones in which the solvent can
release its full latent heat of condensation to the bitumen at the extraction
interface and at a condensation rate, temperature and pressure at which
the bitumen is mobilized and permitted to drain by gravity drainage to a
production well. The liquid condensed solvent assists in the mobilization
of the bitumen by reducing the bitumen viscosity by penetrating the
bitumen filled pores in the formation and causing dilution as well as
temperature based viscosity reductions of the in situ bitumen.
Again, in general terms, the mixed fluid inputs are separated in the
surface facility 10 into various specific outputs including sales oil 20
(diluted as necessary to make it suitable for the pipeline), fuel gas 22,
produced water 24 for disposal and conditioned solvent 26 for re-injection
into the formation to further the EOR treatment, such as the N-Solv
process being carried out in situ as described above. The surface facility
10 achieves the required separation and purification of the various fluids
in a number of steps which are outlined below. Most preferably the facility
10 is in the form of discreet modules, which can be easily transported,
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positioned, connected and taken down and removed to a new site once
the extraction of an existing site has been completed.
Figure 2 shows the production well 30 which receives the mixed
fluids from the formation. The fluids might typically be any combination of
water, oil, and solvent such as propane, butane and non-condensable gas
such as methane, as well as other hydrocarbon materials. According to
the N-Solv technology, some partial upgrading of the hydrocarbons
occurs in situ as the most insoluble bottom fractions of the bitumen such
as asphaltenes are deposited in place within the formation and left
behind. This leaving behind of the asphaltenes is also believed to assist
in the mobilization of the remaining hydrocarbon fractions of the bitumen,
thereby assisting in ease of recovery or hydrocarbon extraction.
The mixed produced fluids will also include a certain amount of
water which is naturally occurring in situ water that is produced along with
the other fluids as a byproduct. In the most preferred embodiment the
EOR process is a dry solvent based process and so no water is being
introduced into the reservoir. However, it is anticipated that a certain
amount of water, which can be referred to as mobile pore water will be
produced. A pump 32 is provided to pressurize the fluids and maintain
the flow from the production well 30. The temperature, pressure and
composition of the mixed fluids at this stage will vary in accordance with
the in situ conditions and the operating conditions for the process which
will be optimized for hydrocarbon production. However, in general the
mixed fluids will be produced at elevated temperatures and pressures
because it is desirable to maintain sufficient pressure to keep the
produced fluids mostly in the liquid phase. Figure 2 also shows a pipeline
12 which transports produced fluids from the well to the processing
facility.
The produced fluids first enter a free water knockout 34 which may
have a centrifugal type separation or electrostatic or both to aid in water
removal. The separation of the water in the absence of a gas flash
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vaporization is intended to remove surface active agents such as
napthenic acids and the like which tend to be associated with the water-oil
interface and have a tendency to produce stable foams and emulsions.
The separated water is then sent to a skim tank 36 where solvent vapour
and any residual oil is eventually recovered (not shown) and the produced
water 24 is collected and then disposed of.
The mixed solvent and oil coming from free water knock out vessel
34 is then pressurized with a pump 38 and sent to vessel 44 which
provides the first solvent flash separation. The vaporization of solvent
requires considerable heat to maintain its temperature, so heat is supplied
from co-gen unit 40 as shown by the dashed arrows 42. This heat is
typically transferred indirectly using a circulating heat medium like glycol,
and heat exchangers (not shown).
The solvent vapour exits vessel 44 and is directed via line 46 into
the distillation column 70. The oil which still contains some residual
solvent, is directed into the second flash vessel 60. In this second flash
vessel the pressure is reduced and the oil/solvent mix is further heated 42
by cogen 40 to help strip any residual solvent away from the oil. The
balance of the solvent is removed from vessel 60 as a low pressure
vapour, which is then compressed and cooled 68 and sent to the
distillation column 70.
The oil, in vessel 60 which is now at the desired residual solvent
specification is sent to sales oil tank 54. Any small amount of residual
solvent that continues to evolve from the sales oil is recovered from tank
54 and directed via compression into the distillation column (shown as 55
and 57).
In some circumstances first 44 and second 60 flash vessels may
produce foam instead of vapour. This is undesirable, so several different
means to break or otherwise control any such foam are provided. For
example, sales tank 54 is equipped with a pump 52 that allows sales oil to
be redirected via line 58 to spray nozzles in the headspace of vessels 44
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and 60. These nozzles allow sales oil to be sprayed into any such foam
and thus help keep the foam layer under control. In addition, a tank 56
containing a foam suppression chemical can be provided. The foam
suppression chemical can then be supplied to pump 52 and then directed
to vessels 44 and 60 through line 58 to aid in foam suppression. It will be
understood that any recirculation of oil via line 58 increases the total
throughput of flash vessels 44 and 60, so the recirculation volume is
typically kept small and only used as necessary.
The present invention comprehends that the sales oil will typically
be blended with diluent 14 from tank 48 to achieve pipeline specification
density and viscosity, so it may then be shipped to a refinery via pump 50
and pipeline 20. The present invention also comprehends that it may be
desirable to use diluent for foam suppression in flash vessels 44 and 60,
so diluent 48 can also be directed to pump 52 for circulation via line 58 to
the spray nozzles.
Make up solvent 18 is stored in a solvent tank 64 and sent via
pump 62 to line 46 and into the distillation column 70. As previously
discussed the makeup solvent is required in the underground chamber 86
to fill the pores vacated by the oil. However, for each volume of oil
removal, the makeup of liquid solvent is only expected to be about one
fifth of a volume because the solvent is mostly in the vapour phase in the
underground chamber 86.
The distillation column 70 receives the flash overheads from vessel
44 and 60 and the makeup solvent 18. The feed points are at the
appropriate trays in the distillation column corresponding to the heat and
mass balances. In some situations the feed vapour may need to be
dehydrated (not shown) to avoid ice problems or the like. The condenser
and reboiler are not shown. The distillation column 70 removes non-
condensible gases 72 and these gases are either used for fuel in cogen
40 or else sent to flare (not shown). At an appropriate takeoff location,
pure solvent is removed from the column and directed via line 74 to
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vaporizer 76. Heat from the co-gen 40 is supplied to the vapourizer to
ensure that all of the solvent is vapourized before it is sent to the
injection
well 84. Insulated and heated flowline 78 and 82 is inclined to facilitate
liquid drainage towards trap 80 in the event of a shutdown or the like
where the lines can cool off and the solvent vapour condense. This is a
very important safety feature needed to avoid condensation induced fluid
hammer. This arrangement of sloped lines and liquid drains (traps) will be
used for every vapour-liquid flowline within the plant (not shown) which
has potential to experience condensation induced hammer. The present
invention further comprehends the use of bladders or the like to reduce
any pressure spike from condensation induced hammer and traps and
drain lines may be insulated and heated to operate reliably in winter
conditions according to the present invention.
The distillation column 70 also has a drain 66 to remove higher
boiling liquids, which may be present in some batches of makeup solvent
and would otherwise accumulate at the bottom of the column.
While in this discussion the solvent may be referred to as propane,
by way of example, it will be understood by those skilled in the art that the
facility can accommodate other types of solvent such as normal butane,
iso-butane and the like. All that is required to accommodate different
solvents is to configure the separators, as described below, according to
the preferred solvent being used. Most preferably the present invention
can include separators for more than one solvent, allowing the solvent to
be changed, either to permit the plant to be moved to a different location
where different conditions require a different solvent choice or to permit
different solvents to be used sequentially at the same location according
to changes in in situ conditions. Thus, it will be understood by those
skilled in the art that the present invention comprehends a plant design
that can reliably recirculate and purify more than one type of solvent
species, while producing and making ready for pipelining hydrocarbon
sales products. Of course, each solvent species will need to be
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sufficiently pure to permit a stable material balance in the formation,
meaning that only one solvent species can be purified at any given time.
However, as noted, the plant design of the present invention permits a
sequential change in solvent species.
According to the present invention the free water knockout vessel
34 is operated at elevated pressures, so that the separation of water
occurs as a liquid-liquid separation. This is advantageous for a number of
reasons. Firstly, by maintaining the volatile gases, such as the preferred
solvent, as a liquid, foaming is generally avoided. Foams can be quite
stable and difficult to deal with and are thus to be avoided. The present
invention provides enough pressure in the FWKO vessel 34 so that all of
the mixed fluids remain in a liquid state. Since the compounds that tend
to stabilize foams often accumulate at the water-oil interface removing the
water (and the interface) helps to make the subsequent vapour recovery
step much less prone to foaming.
According to the present invention, the pressure is raised by pump
38 so that flash vessel 44 and distillation column 70 operate at a pressure
above the injection pressure in the reservoir 86. This allows a large
portion, if not most of the solvent to be recycled to the reservoir without
requiring further compression. Compression is expensive and prone to
equipment failure, so operating these vessels at elevated pressures that
minimize the need for additional compression is greatly preferred.
Thus, by applying the pressure to the fluids at the early stage, the
present invention allows for liquid-liquid separation to efficiently occur,
while at the same time conserving on the need for additional compressors
to add pressure to the solvent at a later stage prior to re-injection into the
formation. In this way the present invention reduces the compression
demand and improves the overall efficiency of the facility.
The separated water from the free water knockout 34 can be sent
to a water tank 36. It can now be appreciated that the present invention
removes water at the first possible step and thus also avoids foaming
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problems (arising from water and oil emulsions) that might otherwise arise
due to the physical manipulation of the mixed fluids stream during
additional processing in the facility. In some
situations, it may be
desirable to "wash" the incoming production fluids by injecting additional
water upstream of vessel 34 to help remove surface active agents and
organic salts from the oil/solvent stream.
Each of the storage tanks is preferably provided with an off gas line
which can permit any off gases (which may be coming out of solution in
the oil over time) to be fed back into the facility for further purification
and
separation into fuel gas and pure solvent to use as injection solvent as
desired. Prior to being used for injection into the formation any such off
gas has to meet the purity specifications for the process and has to be
raised in temperature and pressure to the desired injection conditions.
The precise operating conditions for the various process vessels
according to the present invention will depend on the specific reservoir
and the desired reservoir pressure as described above and will be
understood by those skilled in the art and so are not described in any
greater detail herein. The present invention also comprehends being
associated with a co-generation facility, in which case heat and electricity
can be generated from the co-gen facility. The heat, in turn, can be used
to vapourize and flash the solvent prior to the solvent being injected or
reinjected as the case may be in the formation.
It can now be appreciated that the foregoing describes certain
preferred embodiments of the invention, but that others are also
comprehended within the broad scope of the appended claims. For
example, while the preferred solvent is propane, the facility can be
adapted to be suitable for butane or any other suitable solvent. Further,
the precise process conditions and controls for the various vessels and
components will be determined according to the perceived needs of the
formation, to achieve desired temperatures, pressures and solvent/oil
production rates.
