CA2927978A1

CA2927978A1 - Method and apparatus to produce sales oil in a surface facility for a solvent based eor process

Info

Publication number: CA2927978A1
Application number: CA2927978A
Authority: CA
Inventors: Paul Krawchuk; Mark Anthony Eichhorn; Evan Thomas Crawford; Gharandip Singh Bawa; Cassandra Amanda Lee
Original assignee: Bawa Gharandip Singh; N Solv Corp
Current assignee: N Solv Corp
Priority date: 2016-04-21
Filing date: 2016-04-21
Publication date: 2017-10-21
Also published as: CA3022131C; CA3022131A1; WO2017181264A1

Abstract

A method of separating a heavy hydrocarbon fraction from a mixed fluid production stream produced from an underground reservoir is shown wherein the mixed fluid production stream is produced by means of a solvent based in situ gravity drainage process, the mixed fluid production stream including at least some water, some heavy hydrocarbons including oil, some light hydrocarbons including solvent and some solids. The method includes adjusting a solvent to oil ratio of the mixed fluid stream by doing one or both of reducing the solvent content and increasing an oil content in an amount to dissolve asphaltene particles found in the mixed fluid stream and to thereby destabilize any emulsions present in said mixed fluid production stream. This promotes passive separation of a water fraction from said mixed fluid stream.

Description

, Title: Method and Apparatus to Produce Sales Oil in a Surface Facility for a Solvent Based EOR Process FIELD OF THE INVENTION
This invention relates generally to the process of extraction of hydrocarbons from underground reservoirs and more particularly to the process of enhanced oil extraction (FOR) using a solvent as a working fluid to mobilize the in situ hydrocarbons. Most particularly this invention relates to a method and apparatus to treat produced fluids to separate quality sales oil.
BACKGROUND OF THE INVENTION
A number of extraction technologies exist to extract hydrocarbons from underground reservoirs. Significant hydrocarbon deposits exist which are not mobile at in situ conditions, such as the bitumen in the Alberta oil sands and thus in situ processes have been developed to mobilize the bitumen to permit it to be extracted. Steam is used in an in situ process called SAGD (Steam Assisted Gravity Drainage) to heat, melt and liquefy the bitumen so it can flow and be recovered through production wells. This tends to be a high pressure, high temperature, greenhouse gas intensive process which is limited to use in reservoirs with good pressure confinement namely deeper reservoirs. The use of steam requires a great amount of energy be expended, just to heat and pressurize the steam enough to get the hydrocarbons to flow in situ and so other, less energy intensive methods have been proposed and are being developed.
A much less energy intensive process is a relatively low pressure and low temperature solvent based process called the nsolv extraction process. In this process a solvent is injected into the formation at pressure and temperature conditions designed to permit the solvent to condense on the in situ bitumen. This has the beneficial effect of raising

-2-the temperature of the bitumen (through a latent heat of condensation) as well as dissolving the bitumen with the solvent to reduce fluid viscosity of the bitumen and to allow at least some of the hydrocarbons making up the bitumen to become mobile within the formation. Because of the viscosity reducing solvent effect, a small heat rise is all that is required to create a mobile hydrocarbon fraction within the formation. As the whole in situ extraction process can take place at a much lower temperature than SAGD, much less energy is required. Because it takes place at a much lower pressure it can be widely used in the oil sands, even in relatively shallow reservoirs. This nsolv process can result in significant extraction rates at a lower greenhouse gas emissions cost than SAGD.
However to dilute the bitumen with the solvent can require significant volumes of solvent be injected into the formation and recirculated back up to the surface, purified and then re-injected, which imposes a processing load on any surface facility.
The nsolv process is described in the following patents:
Canadian Patent No. 2,235,085; Canadian Patent No. 2,567,399;
Canadian Patent No. 2,299,790; Canadian Patent No. 2,633,061;
Canadian Patent No. 2,785,871; Canadian Patent No. 2,351,148;
Canadian Patent No. 2,374,115; Canadian Patent No. 2,436,158;
Canadian Patent No. 2,591,354; United States Patent No. 6,883,607;
United States Patent No. 7,363,973; United States Patent No. 7,514,041;
United States Patent No. 7,727,766; United States Patent No. 8,857,512;
United States Patent No. 8,434,551; and United States Patent No.
8,776,900.
In the nsolv process the mobilized in situ fluids may be brought to the surface by means of artificial lift, such as by means of a downhole pump or the like. The mobilized fluids are typically in the form of a mixed fluid with fluid fractions including formation water, hydrocarbons, lighter gases such as the working fluid or solvent and any other gases (called noncondensable gases in the nsolv process) which may either be

-3-impurities in the working fluid or naturally occurring and a solids fraction of clay particles, sand grains, asphaltenes particles and/or other solid particles. The term BS&W is typically used to describe the Basic Sediment and Water content of the mixed fluids. The mixed fluid stream is processed by a surface facility which may have the capability to separate out the BS&W fractions, to separate out and purify the working fluid such as the solvent from a mixed lighter hydrocarbon stream for reinjection and to separate out product oil for sale.
The mixed fluid stream which arrives at a surface facility for processing has typically been agitated by means of the drainage flow through the reservoir as well as the pumping and pipeline configuration that is required to get the mixed fluid production stream to the surface.
Agitation of the mixed fluid stream can lead to the formation of emulsions, either water in oil or oil in water or both, which can make the full separation of the mixed fluid fractions into individual fractions more difficult. More specifically, an emulsion can stabilize an oil and water mixture which can then resist passive attempts, such as gravity settling, to separate the BS&W which may be trapped in the emulsion, for example, from the mixed fluid stream. Although a considerable amount of the water can be removed in a free water knock out gravity settler, the emulsion can hold a certain amount of the water, solvent, oil and solids together in a persistent mixture. A complete density based separation can therefore be hindered or in some cases rendered ineffective in an initial phase separator, such as, a free water knock out vessel, inlet settler, or inlet degasser, by the presence of such an emulsion. Any BS&W that makes it past the free water knock out vessel still combined with the oil stream then has to be dealt with in the remainder of the surface facility adding to the processing load, potentially negatively affecting the performance of the downstream surface facility, and potentially putting the end product oil off spec with respect to certain of the components, such as solids content.
The composition of the produced fluid mixture will vary from

-4-reservoir to reservoir due to the inherent characteristics of the individual reservoir. Therefore, the proportions of the mixed fluid fractions relative to one another can vary from reservoir to reservoir and also within an individual reservoir during the life of a treatment. Another variable is the working fluid which is chosen which might be a solvent such as propane or butane for example. As a result, the composition of any emulsions, including the propensity of any emulsion to form in the first place is somewhat unpredictable. However, should an emulsion form or end up in the facilities initial phase separator vessel it will interfere with the complete BS&W density separation from the mixed fluid stream.
Pipeline operators impose safety shipping specifications on any material being shipped through the pipeline. Among other things there are safety limits on the content of any substances which might have an adverse impact on the integrity of the pipeline itself. Thus there are requirements that the solids content of sales oil not be so high that a physical scouring of the pipeline, with possible loss of confinement, will occur. There are further requirements for the quality of the sales oil, in terms of the water content to ensure that the more valuable hydrocarbons are being shipped and not the less valuable water. There is also a requirement that other material that might affect the downstream refinery or other processing facilities such as corrosion or scale enabling impurities like salt (which may be naturally occurring in the formation water) is at acceptably low levels. Separation of the mixed fluids production stream into a produced oil fraction and ensuring the oil fraction meets shipping specifications and becomes quality sales oil may be required to be able to obtain maximum market value for the oil fraction.
Various techniques are known in the art to facilitate destabilization of emulsions. Chemical demulsifiers can be added to the separator vessel, but add significant operating cost for the actual cost of the chemicals. As well chemical additives can require sophisticated process controls and additional manpower to manage the high volume and variety

-5-of compositions of the emulsions in an nsolv process facility and are therefore impractical. On top of that, the demulsifiers are not always effective at breaking down the emulsions formed from mixed fluid fractions from oil sands reservoirs. A persistent emulsion could lead to process interruptions of the surface facility and off specification product or sales oil.
Heating the fluid to reduce the oil viscosity and increase the settling rate of water droplets can be costly, especially for the nsolv mixed fluid production, as the produced fluids are generally at a low temperature (generally less than 70 degrees C). Saving energy costs in the extraction phase only to expend them in the separation phase is undesirable.
Other techniques involve separators with specific physical design features, such as multiple stages, heating elements, filter elements, electrostatic elements, lamellar elements or inclined vessels, all of which add expense to the separation stage.
SUMMARY OF THE INVENTION
The present invention is directed to, among other things, a method to break down or collapse emulsions which form in mixed fluid production streams from solvent based extraction processes such as the nsolv extraction process to assist an initial gravity based or density separation.
The method may involve adjusting the solvent to oil ratio in the mixed fluid production stream such that the stability of the emulsion is affected, by, among other things, increasing the oil ratio, decreasing the solvent ratio or both. The method may use a product that is readily on hand to increase the oil ratio to help dissolve asphaltenes and therefore help to destabilize the emulsion and which may therefore not require that any expensive demulsifier chemicals be purchased. As well the passive separation process may be operated at the temperature of the mixed fluid stream as it arrives from the formation and thus may not require any additional heat thereby not adding significant further greenhouse gas emissions.

-6-In one preferred embodiment the method may provide for reduction of the solvent to oil ratio in the mixed fluid by adding an improvement fluid, which improves the quality of the separation of undesirable components of the mixed production fluids from the sales oil. In one embodiment the improvement fluid is de-asphalted oil, and may preferably be naturally deasphalted oil produced from a solvent extraction process such as the nsolv process. In this embodiment the improvement fluid may be taken from a downstream location in the surface plant and applied at the front end of the surface plant, such as in a free water knock out vessel (FWKO) or may be applied to the mixed production stream before the FWKO, including adding the improvement fluid downhole to the production well where it mixes with the fluids to be produced. In this embodiment the improvement fluid may dissolve asphaltene particles which may otherwise help stabilize an emulsion between the oil and water. With the emulsion dispersed, a density based separation of any remaining BS&W can be made more efficient and effective than with the emulsion in place in any initial separation vessel.
The method may also provide for reducing the solvent to oil ratio in the mixed fluid production stream by reducing the pressure of the mixed fluid stream to preferentially vapourize some of the lighter species, such as the solvent and produced formation gases, while leaving heavier aromatic and complex hydrocarbons with the mixed fluids stream, before or after the FWKO. Enough of the lighter species may be vapourized so as to elevate the concentration of the heavier hydrocarbons species to a level that can dissolve precipitated asphaltenes in the remaining mixed fluids, thereby destablilzing any emulsions which may be present. Once the emulsion is destabilized the gravity separation of the remaining BS&W
can proceed.
In another embodiment the treatment will involve an improvement fluid which may comprise clean water for salt removal in a washing step.
This step may be applied either before or after lighter species separation

-7-takes place, and may be applied, for example, to a separated heavy hydrocarbon or oil fraction. The clean water preferably has a lower salinity than any residual formation water contained in the oil and can be fresh water or treated water if there is a supply available. The washing step may lower a salt concentration in the oil to an acceptable level for pipeline/shipping of the sales oil or simply to improve the value of the sales oil. The water used for the washing step will be referred to herein as wash water.
Therefore, according to a first aspect the present invention may provide a method of improving a product oil quality by separating one or more contaminants from mixed fluid production stream, said method comprising the steps of:
using an in situ solvent extraction process to mobilize said product oil within an underground hydrocarbon bearing reservoir;
recovering from said reservoir said mixed fluid production stream containing at least some fractions of lighter species including solvent, mobilized product oil, water and solids, adjusting the solvent to oil ratio in the mixed fluid production stream by one or both of treating said mixed fluid production stream with at least one improvement fluid or preferentially removing some of the solvent to destabilize at least some emulsions present in the mixed fluid production stream, and freeing at least some water and solids from said emulsion and separating said freed water and solvent from said mixed fluid production stream.
In another embodiment, the present invention may provide a method of lowering a BS&W content of a mixed fluid production stream produced from an underground reservoir wherein the mixed fluid production stream is produced by means of a solvent based in situ gravity drainage process, said mixed fluid production stream including at least some water, some heavy hydrocarbons including product oil, some light

-8-hydrocarbons including solvent and some solids, said method comprising the steps of:
adjusting a solvent to oil ratio of said mixed fluid production stream by doing one or both of reducing the solvent content and increasing a product oil content to dissolve asphaltene particles found in said mixed fluid production stream and to destabilize at least some emulsions present in said mixed fluid production stream to promote passive separation of said BS&W content from said mixed fluid production stream.
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 following drawing in which:
Figure 1 is a flow chart of one preferred embodiment of the present invention;
Figure 2 is a flow chart of a second preferred embodiment of the present invention;
Figure 3 is a data plot of the effect of recycling product oil on BS&W concentration according one embodiment of the present invention;
Figure 4 is a data plot of the BS&W concentrations as a function of the solvent to oil ratio with and without treatment with product oil according an embodiment of the present invention; and Figure 5 is a schematic of a desalting process according to a further embodiment of the present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Figure 1 shows a flow schematic of a facility incorporating the present invention according to a first embodiment. The underground formation is represented by 10 and may have, for example, an injection well 12 and a production well 14. Solvent flows out of the injection well 10 into the formation, for example into an extraction chamber formed in the

-9-formation, and eventually the solvent and mobilized hydrocarbons flow down through the extraction chamber to the production well 14 as shown at 16. Typically, the wells 12 and 14 will be horizontal wells one above the other with the upper well being the injection well and the lower well being the production well to allow the mobilized fluids to drain by gravity to the lower production well. An artificial lift such as a downhole pump may be used to pump or lift the mobilized fluids to the surface. It will be understood that the present invention comprehends other well configurations, such as spaced apart wells, infill wells, slant wells, vertical wells and others, and the horizontal well configuration described herein is by way of example only.
The surface facility is represented by a box 20 which includes a solvent purification and vaporization module 22. This module will be understood by those skilled in the art and is not explained in any more detail herein. A source of makeup solvent 26 is provided for the module 22. Makeup solvent may be required as the chamber expands due to the requirement to replace void space within the reservoir during continued extraction. The largely recycled purified and vaporized solvent is then directed back down to the injection well in the formation 10 through the line 28.
Coming out of the production well 14 are the mixed production fluids through line 30. In a process such as the nsolve process the mixed production fluids will contain various fractions including liquid fractions and solid fractions. The liquid fractions will include the working fluid, such as the solvent, the mobilized oil or hydrocarbons recovered through the extraction process, and formation water which is naturally present in the formation. The solid fractions will include various fine solids such as sands, clays, and particulates such as asphaltenes. The water and solids are referred to as the BS&W fraction as discussed above.
It will be understood that the exact compositions and proportions of the mixed fluid fractions will vary from formation to formation depending upon the local formation or reservoir characteristics, as well as the point of time in the well life cycle. Some formations have more formation water which is more mobile and others have higher clay or silt contents. The formation water will typically have a high concentration of salt, in the Alberta Oil Sands, but the actual concentration may vary from reservoir to reservoir. The present invention comprehends that a wide range of relative proportions of the mixed fluids and solids fractions can be dealt with in the same manner, and thus the present invention is tolerant to a wide variety of input materials into the FWKO or other separation vessel.
In this disclosure it will be understood that the following terms will have the following meanings. Heavy hydrocarbons are those components recovered from the reservoir and forming part of the mixed fluid stream which are eventually separated out to form the bulk of the product or sales oil. Sales oil and product oil are used interchangeably and mean the separated heavy hydrocarbons that have been processed through the surface facility and are ready for sale. Light hydrocarbons are various species of lighter hydrocarbons, including such potential solvent species such as propane, or butane, as well as any other species which may be naturally occurring or otherwise found in the reservoir, such as methane and the like which are noncondensable at extraction conditions. In this specification the term inlet phase separator is used to mean a vessel for carrying out density based separations including free water knock vessels, inlet settlers and inlet degassers. The term "contaminates"
means components which are undesirable in the product oil, such as water, asphaltene particles, and solids such as clay, sand and the like. It will be further understood that the product or sales oil will be mostly oil, but will include small amounts of solids, water, and salts and one purpose of this invention is to reduce the amounts of these materials in the sales oil to acceptable levels.
The next element in the surface facility 20 is the water separator 40, which may take the form of a free water knock out drum or the like. In a solvent based process such as the nsolv process the produced oil fraction can be lighter or less dense than water. Thus a gravity separation may be used in which the BS&W separate downwardly and the produced oil and dissolved solvent separate upwardly. Thus there is shown a heavier stream 42 which is the produced formation water and solids and a lighter stream 44 which is the separated oil and solvent mixture. The stream 44 may be sent to a solvent/bitumen or oil separation module 45 which produces sales oil at 46. As shown at 50 some of the produced oil may be sent back to the inlet side of the surface facility 20, either into the FWKO 48 or before the FWKO 49. The present invention comprehends treating the produced fluids with recirculated oil at any point between the production well and the FWKO, as described in more detail below. As will now be understood the equipment to facilitate this process arrangement may include piping to route the product oil into the mixed fluids production stream, and pumping equipment, which can be either a dedicated pump or an excess capacity in a product tank or sales oil tank pump.
In another embodiment of the present invention, the surface plant contains at least one flash vessel with a water dropout feature. In this flash vessel with a water dropout feature, the solvent to oil ratio in the mixed fluids is reduced by preferentially removing some of the light aliphatic hydrocarbons from the mixed fluids. For the nsolv process, this represents the solvent fraction that is already required to be separated from the mixed fluids at a later separation step. Asphaltene dissolution as the solvent is flashed off may destabilize emulsions present in the separation vessels and permit water and solids to break out of emulsion with the oil. Preferably such separation vessels are designed for oil/water separation, and the water dropout can be collected. According to the present invention the flash vessel may be located before or after the FWKO, as long as the BS&W remaining can dropout or separate after the solvent has been removed. Therefore, the flash vessel may be located before the free water knock out vessel (FWKO) and use the FWKO as the water dropout feature. In some cases, for energy efficiency, removing the bulk free water prior to adding energy to flash the remaining fluid may be preferred, in which case the flash vessel may be located in the solvent/bitumen separation step 45 and may be for example a three-phase flash vessel. In either case the present invention provides there is sufficient settling time available in or after the flash unit for water droplets comprising remaining BS&W to coalesce and settle out of the production stream after the solvent has been removed.
As shown in Figure 2, the mixed fluids 30 from the production well may first be sent to the free water knock out vessel 40 to separate the bulk water 42 from the solvent and oil 44. These mixed fluids 44 may be sent to a partial flash vessel with phase separation 60. A stream of mostly solvent vapour 62 may be sent directly to the solvent purification/
vapourization step 22, while the remaining mixed fluids 64, now elevated in resin and aromatics content relative to solvent content, may be sent to additional solvent/ bitumen separation. The additional solvent/ bitumen separation step may include additional flash vessels and demethanizer systems as will be understood by those skilled in the art. While not being restricted to this improvement mechanism, it is believed that the composition in stream 64 can solubilize asphaltene particles in the FWKO
and according to this aspect of the invention subsequently destabilize at least some of the water-in-oil emulsions being stabilized by the presence of such particles.
The present invention is illustrated by way of example. A
demonstration plant has been operated near Fort McMurray in Alberta, and uses the nsolv condensing solvent process. The underground facilities consist of a single horizontal injection well pair, with the upper well as the injector and the lower well as the producer. Butane is used as the solvent. Mixed production fluids are brought up from the production well to a surface plant, which consists of an initial separator, where the bulk of the water and particulates are separated from the oil and working solvent. The working solvent is then separated from the oil and recovered for re-injection into the well as described by Nenniger.
Table 1 below shows the average SARA analysis of the product oil inherently deasphalted by the nsolv process relative to the bitumen in the reservoir.
Table 1: SARA analysis of Product Oil produced in Nsolv pilot plant compared to Bitumen from Reservoir SARA wt% Native Bitumen Product Oil from Reservoir Saturates 20 26 Aromatics 46 58 Resins 17 12 (polar) Asphaltene 17 3 The graph presented as Figure 3 shows the BS&W measured in the product oil of the nsolv pilot plant during the solvent injection phase and the production phase. The vertical axis 152 plots a percentage of the BS&W in the tanks containing the produced and separated oil and the horizontal axis 154 represents time. Plotted onto the figure are actual measurements of the BS&W at discrete points in time. As there are two tanks at this demonstration facility, there are shown two separate types of markings, where x's represent a tank A and crosses represent a tank B.
The use of two tanks is simply a function of the production volume relative to the discharge capacity and there may be more or fewer tanks without departing from the scope of the present invention.
The horizontal line 160 represents a target BS&W content, which may be, for example, a maximum BS&W content as permitted by a pipeline specification for the sales oil, such as 0.5%. Although shown as one value in this figure it will be understood that the present invention is not limited to achieving that value only, which is by example only. Instead the present invention comprehends that various content specifications can be met by adjusting the treatment process accordingly. However, since the 0.5% is the current shipping standard, the present example uses this value for illustration purposes.
The vertical lines 162, 164, and 166 mark periods where treatment of the mixed production fluids with the improvement fluid, namely, recycled inherently deasphalted oil was started or stopped. For a short time period, shown as 168, immediately following the initial production of mixed fluids from the formation, the BS&W content of the product oil was at or below the pipeline specification or line 160. However, even though solvent injection was continued through the formation on the same basis as during the initial phase, in terms of the injection procedures, the BS&W
content increased and generally consistently remained well above the target line 160 in both tanks. During this period various measures were tried to reduce the BS&W, such as chemical demulsifiers and varying the operating pressure of the separation vessel. As can be seen from the high BS&W content during this period, none of these approaches met with much success as the BS&W content remained too high and well above the sample shipping specification.
Beginning at line 162 a portion of the inherently deasphalted product oil was used to treat the mixed production fluid at or before the FWKO. As can be seen by the measurements to the right of line 162 an almost immediate drop in BS&W content occurred to an amount that is well below the example target content of line 160. Then at the time represented by line 164, the treatment with the improvement fluids was stopped and almost immediately increases in the BS&W content to back well above line 160 were measured, as shown in Figure 3 by the points above line 160 and located between lines 164 and 166 at 165. Treatment with the treatment fluid began again at line 166 and again, in large measure the BS&W content dropped back below the specification line 160 shown at 167. While there are a few outlier points above the line 160, these likely represent process upsets of one sort or another, and the vast =

majority of the data points show compliance with the desired BS&W
specification. Since implementing this treatment, the measured BS&W
content has stayed below the line 160 with only an occasional outlier data point above the line 160.
Figure 4 shows a further aspect of the present invention. What is desired is to determine a treatment rate which optimizes the application of the treatment fluid. While applying too much treatment fluid will not harm the BS&W outcome of maintaining the BS&W levels at or below the line 160 or other pipeline specification, over treating may have some negative consequences. In particular, applying too much treatment fluid may impose a capital cost penalty in terms of requiring larger separation vessels, and an operating cost penalty by adding to the separation load downstream of the FWKO, in the bitumen/solvent separation phase.
Therefore, the present invention comprehends identifying a treatment metric for gauging if the treatment fluid volume is sufficient for treatment purposes. By identifying a treatment metric the present invention may provide a step for treatment volume optimization. Of course one such metric is the BS&W percentage itself as measure in the product oil tanks, but this metric is fairly far away from the actual inlet separation vessel and a metric which is closer to the inlet setter is preferred.
Figure 4 shows a graph of the BS&W concentration, the vertical axis 170 plotted against the apparent solvent to oil ratio (ASOR) in the separator vessel the horizontal axis 172. In this sense the term ASOR
means the SOR as measured in the vessel after the treatment fluid has been added or at least some of the lighter gases flashed off as described above. Thus, the ASOR is measured based on the total oil in the mixed fluids at that point, namely, the measurement includes both the mixed fluid production stream oil fraction and any inherently deasphalted oil which may have been added thereto as the treatment fluid. The ASOR is not the same as the solvent oil ratio (SOR) which typically means the injected solvent divided by the produced oil and is a metric used for =

overall operational characterization of the extraction process. When there is no treatment fluid added to the separation vessel, and no flashing of the lighter species prior to the measurement, the ASOR roughly equals the SOR.
In Figure 4 the x's represent the BS&W content as compared to the solvent to oil ratio of the mixed produced fluids with no adjustment of the solvent to oil ratio of the produced fluids. A BS&W concentration limit is shown by line 174. As can be seen by the wide dispersion these values are all over the map, but generally not within the sample shipping specification, i.e. not below the line 174.
The crosses in Figure 4 represent the apparent solvent to oil ratio (ASOR) with the adjustment of the oil content to increase the proportion of oil, in this case by means of the treatment fluid being added. As can be seen at 176, again except for a few outliers, the measured amounts are generally well reduced as compared to not adjusting the oil content to increase the proportion of oil. These measured amounts are also generally within the required pipeline specifications, i.e. generally well below the line 174. According to the present invention provided the ASOR is generally maintained within a targeted operating range indicated generally between the lines 178 and 180 by adding the required amount of treatment fluid to achieve such an ASOR the BS&W content of product oil is mostly below the specification of 0.5 wt%. The actual ASOR
required to achieve the shipping specification of BS&W will vary from reservoir to reservoir and with the choice of working fluid. However, the present invention comprehends adjusting the ASOR by increasing the oil ratio or lowering the solvent ratio until the BS&W content meets the desired specification in the production tanks. Thus the present invention may provide, in one aspect, a metric which can be measured from the separation vessel which can be used to determine the volume of treatment fluid to be used to treat the mixed fluids stream. Because this metric may be measured in a real time in the separation vessel the metric can be used as a process control variable to achieve reliable separation results across a wide and variable range of proportions of the various fractions of the mixed fluid production which may be directed into the separation vessel from the formation.
Without product oil recycle, the BS&W content may sometimes be below 0.5 wt% for an SOR within the targeted operating range, but is basically random and with many more instances above the desired specification level or above line 174. For SOR above the targeted operating range, the BS&W is almost always off-spec when product recycle was not used. By adjusting the solvent to oil ratio of the mixed fluid production stream, for example by using the treatment fluid of the inherently deasphalted oil, the resin and aromatic content relative to the solvent in the inlet separator has been increased. Without being restricted to this improvement mechanism, it is believed that this composition can solubilize asphaltene particles in the inlet separator and according to this aspect of the invention subsequently destabilize at least some of water-in-oil emulsions which are being stabilized by the presence of such particles to permit the BS&W specification to be met It has been observed in the demonstration facility that during continuous operation, asphaltenes normally dissolve into the oil downstream of the separator once the solvent has been separated from the produced oil fraction. This observation is based on the lack of precipitated asphaltene found in the product oil post solvent separation in the demonstration plant using the nsolv process as described above.
Consequently, recycling product oil as a treatment fluid does not change the overall asphaltene content in the product oil, but may be thought of as merely shifting the dissolution upstream to at or before the separator. It can now be understood that by shifting the asphaltene dissolution to at or before the separator, which is designed for oil/water separation, the water dropout from the oil using a simple gravity or density based process can be optimized. This has the further benefit of reducing downstream separation requirements (as less fluid is put forward for separation through the rest of the facility).
Adjusting the solvent to oil ratio of the mixed fluids stream and providing ample settling time for water droplets as indicated by the present invention can improve the product oil quality by lowering the BS&W content. Lowering the BS&W content generally has the added benefit of reducing the salt content (expressed as Pounds NaCl per Thousand Barrels oil, PTB) in the product oil, since the chlorides are associated with the water. However, where the reduction of the solvent to oil ratio is achieved by circulating deasphalted product oil, it may be possible to have a build-up of salt precipitation in the circuit, due to the natural evaporation of water across the separation train and the relatively high concentration of salt in the formation water which is produced to the surface as part of the mixed production fluids. Therefore, the present invention also comprehends adding an optional desalting step after the dewatering steps, if additional salt removal is required to meet any PTB
product specification for the product oil as shown in Figure 5. As will be appreciated by those skilled in the art, there is a lot of variability in the PTB levels for product oil. In some cases, it may be as high as 58 for Western Canadian Blend and 34 for Western Canadian Select, but generally a lower amount is preferred. For example, a PTB of less than 20 may be preferred. Thus, the present invention comprehends an acceptable level for PTB may be a range of 0-58, preferably 5-34, and most preferably 10-20.
Figure 5 shows the produced fluids at 200, fed into a FWKO vessel at 202. From there a process stream 204 is directed to a produced water vessel 206. A separate process stream 207 is directed, for example, to a Flash Separator 208. The lighter fractions are directed through process stream 210 to a solvent purification module 212. The heavier fractions (at this point separated oil 214) are directed to a wash cycle at 216. The wash cycle may include wash water 218 which is fed into a mixer 220 with =

219. A separation vessel 221 is provided which may include an electronic desalting mechanism 222 as described below. The vessel 221 is used to separate brine through a process stream to vessel 224 and oil through process stream 226 to a further flash separator 228. From separator 228 light hydrocarbons are separated into a process stream 230 and sales oil stream 232. As described above, the sales or product oil may also be diverted to the produced fluids by process stream 234. Process stream 236 is directed to a refinery.
According to the present invention desalting can be achieved by generally mixing and washing the oil with an improvement fluid consisting of wash water to dilute and remove the salt content to the target PTB. The wash water must have lower PTB and BS&W than the formation water contained in the oil and can be fresh water or treated water if there is a supply available at the plant.
The mixture of the wash water with the oil may create a two phase fluid which may include a water-in-oil emulsion that is collected in a desalting vessel. The vessel may also include an electrostatic desalter, which establishes a high voltage electrical field in the upper oil phase, imposing an electrical charge on the water droplets entrained in the oil as well as dipole attraction forces between the droplets. This causes the droplets to break out of emulsion, coalesce, and drop by gravity into a lower brine phase for removal.
Many different electrostatic desalter may be used according to the present invention, including application of AC only or AC and DC fields, with and without heaters for the oil and/or water streams, as well as single and multi-stage units. Other desalting technologies also exist, for example some desalters mix additional demulsifying chemicals with the wash water and employ high volume settling tanks instead of an electric field and are all comprehended by this invention.
While reference has been made in the foregoing to various preferred embodiments of the present invention those skilled in the art will understand that the foregoing description is by way of example only and the scope of the present invention is only limited by the appended claims.
For example, the present invention comprehends that the apparent solvent to oil ratio can be altered by adding more oil or removing more solvent, both of which may have the effect of destabilizing any emulsions present and thereby freeing up any trapped BS&W for separation and removal.

Claims

THE EMBODIMENTS OF THE INVENTION IN WHICH AN EXCLUSIVE
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS
FOLLOWS:

1. A method of improving a product oil quality by separating one or more contaminants from a mixed fluid production stream, said method comprising the steps of:
using an in situ solvent extraction process to mobilize said product oil within an underground hydrocarbon bearing reservoir;
recovering from said reservoir said mixed fluid production stream containing at least some fractions of lighter species including solvent, mobilized product oil, water and solids;
adjusting the solvent to oil ratio in the mixed fluid production stream by one or both of treating said mixed fluid production stream with at least one improvement fluid and removing some of the solvent to destabilize at least some emulsions present in the mixed fluid production stream; and freeing at least some water and solids from said emulsion and separating said freed water and solvent from said mixed fluid production stream.

2. The method of claim 1 further including the steps of:
selecting an improvement fluid into which at least one of said contaminants is soluble; and treating said mixed fluid production stream with said selected improvement fluid to reduce a concentration of said contaminant.

3. The method of claim 2 wherein said contaminant is precipitated asphaltenes and the step of selecting one or more improvement fluids includes the step of selecting product oil separated from said mixed fluid production stream and said treatment step comprises using said separated product oil to dissolve said precipitated asphaltenes present in said mixed fluid production stream.

4. The method of claim 3 wherein the step of treating said mixed fluid production stream with said improvement fluid further comprises adding said improvement fluid to an initial phase separator of a surface plant.

5. The method of claim 3 wherein the step of treating said mixed fluid production stream with said improvement fluid further comprises adding said improvement fluid to said mixed fluid production stream before an initial phase separator of a surface plant.

6. The method of claim 3 wherein the step of treating said mixed fluid production stream with said improvement fluid further comprises adding said improvement fluid to said mixed fluid production stream downhole in said production well.

7. The method of claim 3 wherein said mobilized product oil is partially deasphalted in situ during the solvent based in situ extraction process.

8. The method of claim 3 wherein said mixed fluid production stream includes at least some emulsion which is stabilized by asphaltene particles and said step of dissolving said asphaltenes with said improvement fluid destabilizes said emulsion to permit improved gravity separation of said water and solids.

9. The method of claim 3 wherein said oil is less dense than said water and said water and solids sink and said oil rises in a separation step after said treatment.

10. The method of claim 2 wherein said contaminant is salt contained in said mixed fluid production stream and said step of selecting an improvement fluid comprises selecting wash water to treat said mixed fluid production stream.

11. The method of claim 10 wherein said treatment step further comprises continuing said washing step until said product oil has less than 58 pounds of NaCI per thousand barrels of oil.

12. The method of claim 2 wherein said step of treating said oil fraction of said mixed fluid production stream further comprises using a process metric to determine rate of addition of improvement fluid.

13. The method of claim 12 wherein said step of using said metric further comprises applying said metric in a separation vessel containing both the improvement fluid and the mixed fluid production stream from the reservoir.

14. The method of claim 13 wherein said step of using said metric comprises determining an apparent solvent to oil ratio in said separator by taking the solvent content of the mixed fluid production stream and dividing by the sum of the product oil content and the improvement fluid content and adding improvement fluid to keep said apparent solvent to oil ratio within a preferred range.

15. The method of claim 12 wherein said metric used is one or both of a water and solids content of a product oil produced by said plant.

16. The method of claim 15 wherein said metric is measured after said product oil is separated from said other fractions of said mixed fluid production stream.

17. A method of lowering a BS&W content of a mixed fluid production stream produced from an underground reservoir wherein the mixed fluid production stream is produced by means of a solvent based in situ gravity drainage process, said mixed fluid production stream including at least some water, some heavy hydrocarbons including product oil, some light hydrocarbons including solvent, and some solids, said method comprising the steps of:
adjusting a solvent to oil ratio of said mixed fluid production stream by doing one or both of reducing the solvent content and increasing a product oil content to dissolve asphaltene particles found in said mixed fluid production stream and to destabilize at least some emulsions present in said mixed fluid production stream to promote passive separation of said BS&W content from said mixed fluid production stream.

18. The invention of claim 17 wherein said solvent content is reduced in said mixed fluid production stream by causing at least some of said solvent to flash off said mixed fluid production stream and then separating both said BS&W and said flashed solvent from a remainder of said mixed fluid production stream.

19. The invention of claim 18 wherein said flashing is caused by one or more of reducing pressure of said mixed fluid production stream and heating said mixed fluid production stream.

20. The invention of claim 17 wherein said product oil content is increased by adding product oil to said mixed fluid production stream.

21. The invention of claim 20 wherein said separation is conducted in a surface facility and product oil is obtained from a downstream location in said surface facility and is applied to an upstream location.

22. The invention of claim 17 wherein said solvent to oil ratio is adjusted according to a process metric.

23. The invention of claim 22 wherein the process metric is a BS&W
content of a downstream product oil.

24. The invention of claim 22 wherein the process metric is a BS&W
content of a downstream product oil and the adjustment step is to apply an amount of product oil to said mixed fluid production stream sufficient to reduce the BS&W content in said product oil to a meeting shipping requirement.

25. The invention of claim 17 further including the step of treating the separated product oil fraction with a treatment fluid to reduce a salt content of said product oil fraction.

26. The invention of claim 25 wherein said treatment fluid is a wash water having low enough salt content to lower a salt level in said product oil fraction to an acceptable level.