CA2777966A1 - Solvent injection plant for enhanced oil recovery and method of operating same - Google Patents

Abstract

A solvent injection and recycling plant for stimulating recovery of hydrocarbons from an underground formation, such as an oil sands formation, the plant having a connection to a production flow line carrying mixed fluids from the formation and a free water knock out vessel connected to said production flow line, said free water knock out vessel being operated at a condition to provide for a liquid separation of the mixed fluids into a mostly oil and solvent stream and a most water stream. A skin tank is provided to receive the mostly water stream to permit residual hydrocarbon separation. In another aspect a flash separator is provided, and operated at pressures substantially matching a hydrocarbon mobilizing pressure used in the underground formation.

Description

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 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

-2-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.

-3-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

-4-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

-5-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;

-6-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

-7-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;

-8-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.

-9-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 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

-11-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,

-12-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

-13-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

-14-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

-15-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

-16-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

-17-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.

Claims (16)

1. A solvent injection plant for stimulating hydrocarbon recovery from an underground formation by injecting a solvent at a pressure and temperature to mobilize in situ hydrocarbons, the solvent injection plant comprising:
a. A connection to a production flow line carrying mixed fluids produced from the formation;
b. a free water knock out vessel connected to said production flow line to perform a liquid separation of the produced fluids into a mostly hydrocarbon/solvent stream and a mostly water stream; and c. a skim tank connected to the free water knock out vessel for receiving water from the mostly water stream for residual hydrocarbon removal.

2. A solvent injection plant as claimed in claim 1 further including a heated and pressurized flash vessel connected to the free water knock out vessel, said flash vessel removing solvent as a vapour from the oil/solvent stream.

3. A solvent injection plant as claimed in claim 2 further including a means for purifying the solvent prior to reinjection of said solvent back into said formation.

4. A solvent injection plant as claimed in claim 3 wherein said means for purifying the solvent prior to reinjection of said solvent back into said formation comprises a distillation column.

5. A solvent injection plant as claimed in claim 1 further including a sales oil tank for temporarily storing sales oil.

6. A solvent injection plant as claimed in claim 1 further including a source of make-up solvent for satisfying the solvent demands arising from an expanding underground extraction chamber the underground.

7. A solvent injection plant as claimed in claim 6 further including a connection for the source of make-up solvent upstream of the means for purifying said solvent in said plant.

8. A solvent injection plant as claimed in claim 2 wherein said flash vessel operates at a temperature and a pressure corresponding to a desired injection pressure for said solvent into said formation.

9. A solvent injection plant as claimed in claim 1 further including tubing connecting said plant to a well head, said tubing being inclined and having drains to reduce condensation induced water hammer.

10. A solvent injection plant as claimed in claim 2 further including recirculation loop to recirculate at least some of said mixed fluids liquids and to spray said liquids into a top of said flash vessels to help suppress foam in the flash vessels.

11. A solvent injection plant as claimed in claim 2 further including a means to apply anti foaming chemicals to said flash vessel.

12. A solvent injection plant as claimed in claim 11 wherein said anti foaming chemical includes at least one diluent.

13. A solvent injection plant as claimed in claim 1 further including a source of diluents for blending with said hydrocarbons to produce sales oil.

14. A solvent injection plant as claimed in claim 1 further including a means to recover volatile components from said flash vessel for use as fuel gas.

15. A solvent injection plant as claimed in claim 1 further including a co-generation facility to provide electricity and heat, said heat to be used for flashing solvent and vapourizing solvent prior to injection of said solvent into the formation.

16. A solvent recovery and injection plant for in situ hydrocarbon extraction, where the solvent is injected into an underground formation at a hydrocarbon mobilizing pressure and temperature, said plant comprising:
a. A connection to a production flow line carrying mixed fluids recovered from said underground formation, said recovered mixed fluids including at least some recovered solvent;
b. a primary separation unit wherein said recovered solvent is separated from said recovered fluids substantially at a bitumen mobilizing pressure; and c. an injector for re-injecting said pressurized solvent back into the formation.