WO2017205962A1

WO2017205962A1 - Method for solvent recovery from gravity drainage chamber formed by solvent-based extraction and apparatus to do the same

Info

Publication number: WO2017205962A1
Application number: PCT/CA2017/000138
Authority: WO
Inventors: Mark Anthony Eichhorn; Alex Mackenzie Crosby; Gharandip Singh Bawa; Evan Thomas Crawford; Paul Krawchuk; Cassandra Amanda Lee
Original assignee: N-Solv Corporation
Priority date: 2016-06-02
Filing date: 2017-06-01
Publication date: 2017-12-07
Also published as: CA2931907A1; CA3025807C; CA3025807A1

Abstract

A method and apparatus to recover the solvent that remains in a mature in situ gravity drainage chamber formed by solvent-based extraction is disclosed. The method involves transitioning from an oil production phase to a liquid solvent recovery phase by continuing to produce fluids from the chamber, even after solvent injection has stopped. Additional liquid solvent that cannot drain freely from the chamber and some solvent that is held up in the gas phase in the chamber are then recovered by drawing gas from the chamber. Chamber pressure management by injection of non-condensable gas or formation water into the chamber, as well as injecting water to improve solvent recovery from reservoirs with low initial water saturation are also comprehended. An apparatus suitable to carry out the present invention is also disclosed.

Description

Title: METHOD FOR SOLVENT RECOVERY FROM GRAVITY DRAINAGE CHAMBER FORMED BY SOLVENT-BASED EXTRACTION AND APPARATUS TO DO THE SAME FIELD OF THE INVENTION

This invention relates generally to the field of hydrocarbon extraction and more particularly to in situ hydrocarbon extraction using solvents. Most particularly, this invention relates to solvent based gravity drainage processes and to the recovery of solvent remaining in situ at the end of the primary recovery process.

BACKGROUND OF THE INVENTION

Gravity drainage is a known technique for the in situ extraction of hydrocarbons. At present, it is mainly performed by injection of steam into the hydrocarbon bearing formation; however, gravity drainage by injection of solvent vapour has also been demonstrated using the nsolv technology. In a gravity drainage extraction process, the steam or solvent vapour is injected into a formation from a generally horizontal injection well and recovered from a lower parallel running generally horizontal production well. An extraction chamber gradually develops in the formation as the oil or bitumen is removed from the reservoir above and between the wells. As the vapour flows towards the perimeter of the chamber, it encounters lower temperatures, resulting in condensation of the vapour and transfer of heat to the sand and bitumen, causing the bitumen to warm up. In a solvent based process, the warmth reduces the viscosity of the bitumen, thereby allowing the solvent to penetrate more rapidly into the bitumen. The mobilized bitumen and liquid solvent drain towards the bottom of the chamber and are then recovered from the formation through the production well located near the bottom of the chamber. As the mobilized bitumen drains downward, fresh bitumen becomes exposed at an extraction interface that is subsequently exposed to the vapour, such as the condensing solvent and becomes in turn mobilized. This bitumen depleted extraction chamber is called a gravity drainage chamber.

The chamber volume grows vertically and laterally around the wells as bitumen is extracted, eventually approaching the overburden of the formation. The chamber growth may also approach other chambers from other operating wells nearby. At the point where pay hydrocarbon productivity is deemed too low for a given production well, or a set of production wells where their associated solvent chambers have coalesced, the production phase of the chamber may be ended. Then it may be necessary to prepare the chamber for abandonment and eventual reclaim of land at the well pad. Chamber abandonment generally involves stopping the flow of steam or solvent vapour into the chamber and balancing the final chamber pressure with the formation to prevent the chamber from acting as a low pressure sink that attracts steam or solvent vapour from nearby operational well pads or high pressure source that leaks pressure into adjacent areas.

Typically, the injected vapour delivers heat into the chamber to mobilize bitumen or pay hydrocarbons. Therefore, as the vapour injection rate is reduced and eventually stopped, the bitumen drainage rate decreases until it is economically impractical to continue producing oil; that is, when the volume of oil produced is of less value than the cost to operate the wells and corresponding surface plant.

Once all flow is stopped to and from the chamber, the downhole equipment (e.g. tubes, pumps, heaters) may be pulled out of the wells and the wells are plugged, usually with cement up to grade. The well casing is cut just below the surface and capped. At this point, the chamber may be abandoned. For a solvent-based process, some of the injected solvent will remain in the formation both as vapour and condensed liquids at the end of the production phase, occupying the volume of the produced bitumen and water. This remaining solvent is valuable, therefore as much as economically feasible should be recovered before chamber abandonment so that the recovered solvent can be reallocated, for example, to other operating wells and in situ chambers.

U.S. Patent No. 7,464,756 presents a solvent-assisted extraction process involving a unique sequence of steam/solvent injections to recover hydrocarbons from a heavy hydrocarbon reservoir. The patent teaches continuing production at reducing reservoir pressures even after hydrocarbon (solvent) injection is complete to recover additional volumes of solvent. It also teaches to inject a displacement gas, which may be a non-condensable gas, to maintain the pressure of the vapour chamber.

This patent assumes that the solvent remaining in the reservoir is primarily condensed liquid solvent that is able to drain by gravity and be extracted as produced fluids. However, a significant amount of solvent retained in the reservoir may not be able to easily drain by gravity. This includes uncondensed solvent gas in the chamber, condensed solvent held interstitial to sand grains in the chamber, solvent that may be located below the producer so that it cannot be drawn to surface through the producer, and solvent that is dissolved in the immobile asphaltene phase which is therefore trapped. The pay hydrocarbons may also include significant amounts of solvent which are at too low a concentration to mobilize the hydrocarbons at that temperature. Other methods are required to recover this solvent in an economic manner.

SUMMARY OF THE INVENTION

What is required is a procedure to recover both liquid and gas solvent remaining in a mature gravity drainage chamber that has been formed by solvent-based extraction of the hydrocarbons, before chamber abandonment. The apparatus for carrying out the procedure should be compatible with the apparatus required for the preceding oil production phase so as to require little to no additional equipment and minimal plant modifications or disruptions.

The present invention may address some of these requirements. According to the present invention, solvent remaining in a mature gravity drainage chamber formed by solvent-based extraction may be recovered by:

• Reducing the injection rate of solvent vapour into the injector until solvent injection is completely stopped while continuing to draw down on the producer well to produce mobilized pay hydrocarbons;

• Producing solvent-containing liquids through the producer well to the surface plant without adding any further solvent vapour into the chamber, until the water cut of the produced fluids reaches an undesirable liquid threshold which may be when the produced fluids contain too much water to economically separate them;

• Extracting vapours from the reservoir by producing solvent-containing gas to the surface plant until the solvent content in the produced gas reaches the gas threshold which may be until it is uneconomic to separate the solvent from the other produced vapours, for example due to low solvent production rates, or if it is impractical to further reduce chamber pressure.

The present invention may use the same well pump, compressor and surface facilities already used for the production phase of the chamber with only some minor variations. The present invention may also use the injector well or nearby vertical wells, such as observation wells or a new core well to produce the solvent-containing gas or to inject non-condensable gas.

Preparing the chamber for solvent recovery may include a wind down period where the solvent injection rate may be transitioned to zero. Wind down may also include a period of increasing the chamber temperature, which will benefit the solvent recovery in the latter stages. The chamber temperature may be increased by different methods, as understood by those skilled in the art, including increasing the solvent injection temperature and use of downhole heaters.

Chamber pressure management may be an aspect of the present invention. The pressure of the chamber will decrease as the solvent containing liquids and gases are drawn from the chamber in the absence of further injection. In reservoirs with sufficient water saturation, formation water may enter and eventually flood the chamber as the chamber pressure drops below the native reservoir, hindering the liquid solvent recovery. The present invention may comprehend injecting a non-condensable gas to maintain the chamber pressure and may include drawing solvent-containing liquid from the chamber under a gas-trap or controlled gas intake condition. The present invention may also comprehend simultaneously injecting a non-condensable gas to maintain the chamber pressure while producing solvent-containing vapour to maintain a balanced pressure with the reservoir. For chambers that must be left in pressure balance to the reservoir, the present invention may comprehend injecting a non-condensable gas or water into the chamber after the solvent recovery is completed to achieve such pressure balance.

Some chambers may have a significant portion of liquid solvent located below the producer well, such as reservoirs with relatively low water saturation. An embodiment of the present invention includes injecting water into the volume of the chamber below the producer. This may encourage the lower density liquid solvent to float on top of the water and up to the producer so that such liquid solvent may be recovered and brought to surface.

In another embodiment of the present invention, the wells are initially shut-in to allow more time for any formation liquids, including liquid solvent to drain before producing the solvent-containing formation liquids.

Therefore, according to a further embodiment of the present invention there is provided a method of recovering solvent from an in situ gravity drainage chamber, said method comprising the steps of:

transitioning from injecting solvent into said gravity drainage chamber to ceasing to inject solvent;

continuing to produce draining liquids from said gravity drainage chamber during said transition step;

monitoring a content of said produced liquids and continuing to produce draining liquids from said formation until a level of at least one fraction in said produced liquids becomes uneconomic to separate at surface;

transitioning to producing vapour from said formation;

monitoring a percentage of a least one valuable fraction of said produced vapour; and

continuing to produce said vapour until a level of said at least one valuable fraction becomes uneconomic to separate at surface.

According to a further embodiment of the invention, there is provided a surface facility for recovering solvent from an in situ chamber formed by a gravity drainage process, said surface facility comprising:

a liquids separator to separate water from a mixed fluid production stream extracted from said chamber;

a vapour separator to separate gases which are non-condensable at reservoir conditions from said mixed fluid production stream extracted from said chamber;

a first return circuit to permit said separated water to be reinjected back into said chamber;

and a second return circuit to permit said separated non-condensable gases to be reinjected into said chamber. 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 an illustration of a mature gravity drainage chamber;

Figure 2 is a contour graph showing the distribution of solvent in a mature chamber in preparation for abandonment;

Figure 3 is a schematic of a surface plant for separating the formation fluids taken from the well during oil production;

Figure 4 is a schematic showing the different stages of a solvent recovery procedure according to the preferred embodiment of the present invention;

Figure 5 is the contour graph showing the distribution of solvent remaining in a chamber after performing part of the solvent recovery procedure according to the preferred embodiment of the present invention;

Figure 6 is the contour graph showing the distribution of solvent remaining in a chamber after performing another part of the solvent recovery procedure according to the preferred embodiment of the present invention;

Figure 7 is the contour graph showing the distribution of solvent remaining in a chamber after performing the solvent recovery procedure according to one embodiment of the present invention; and

Figure 8 is a schematic of a surface plant for separating the formation fluids taken from the well during solvent recovery. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Figure 1 illustrates the key features of one form of a fully developed extraction chamber, ready to begin a solvent recovery process. The chamber 1 may be located in the payzone of a bitumen-bearing reservoir, such as the Alberta oil sands and may encompass a horizontal well pair, generally consisting of an upper injector well 2 and lower producer well 3. The chamber has grown laterally into the payzone and vertically towards the overburden during extraction of the bitumen by a solvent condensing EOR such as the nsolv process. During the production phase, which may also be referred to as the solvent injection phase, warm solvent vapour enters the chamber through the injector. The vapour condenses when it comes into contact with the colder walls of the chamber, which represents a bitumen- solvent interface 6. The heat transfer from the solvent to the interface reduces the bitumen viscosity to increase its mobility. The condensed solvent may penetrate into the bitumen at the interface, further lowering the bitumen viscosity such that the mixture may drain by gravity down the chamber walls towards the producer well 3, where it may be produced to the surface to recover the bitumen as sales oil. This mixture of bitumen and solvent may be called a drainage layer 5. The area in the chamber from which bitumen may have already drained is referred to as a swept zone 4. Also shown is an observation well 9 with an access opening 11a toward a top of chamber 1 and 11 b towards a bottom, or even underneath chamber 1 which are discussed in more detail below. The provision and position of the access openings 11a and 11 b will depend upon reservoir conditions and what stage the solvent recovery process is then at, as explained in more detail below.

Figure 2 is a contour graph illustrating an example of a possible distribution of solvent remaining in a chamber 10 that is ready to begin a solvent recovery process. While this example is provided for illustration purposes, it will be understood that the precise distribution of remaining solvent will vary, according to local reservoir characteristics, including permeability, the presence of unconformities, the choice of solvent used, and the like.

In Figure 2, the shading represents the moles of solvent contained within each grid cell, corresponding to the legend shown at 12. The injector is shown at 14, while the producer is shown at 16. The highest concentration of solvent is expected in the drainage layer 18 generally below the injector 14 and around the producer 16, indicated by the darkest shading, with a large volume of medium concentration solvent in the swept zone 20.

The solvent remaining may be described as either dynamic or static.

Dynamic solvent is free-draining liquid solvent which will drain to the bottom of the chamber under the force of gravity alone. In the reservoir, this may be solvent that has condensed above the producer and is trickling down through the formation towards the production well, as well as solvent in the drainage layer located above the producer well, so long as the drainage layer mixture is still sufficiently mobile.

Static solvent is that solvent which does not drain under the force of gravity. This includes solvent in the gas phase, solvent held up in the swept zone of the chamber that is held in place by surface tension or capillary forces, and solvent dissolved into the in situ hydrocarbons which hydrocarbons have insufficient mobility to drain under gravity alone.

In Figure 2, the distribution of dynamic and static solvent is shown as roughly 50/50 by way of example for a particular reservoir, located in the Alberta oil sands. The distribution will vary from reservoir to reservoir as it is dependent on permeability, porosity, solvent to oil ratios applied, temperature, viscosity, solvent used etc. The present invention may be applicable to a wide distribution of dynamic and static solvent remaining in a chamber.

Figure 3 shows process steps which may be suitable for separating produced fluids and recovering solvent during the production phase of a solvent-based extraction, for reuse in the production process. The surface plant 30 receives mixed produced fluids 39 from the downhole pump 32 of the producer well 31. The produced water 42 may be separated in a free water knock out vessel 34. The remaining mixed hydrocarbon 43 may be submitted to multi-stage flash to separate produced oil 44 from the lighter hydrocarbons 45, 46 consisting of solvent and non-condensable gas. The lighter hydrocarbons may be distilled in the distillation system 36 into purified solvent 47 and fuel gas 50. Casing or annulus gas 40 that may be drawn to surface by the downhole pump 32, may be primarily non-condensable gas, solvent vapour and condensed solvent that has flashed due to the heat of the downhole pump. The downhole pump is preferably fitted with a gas rejection stage to allow for extended stable operation in the later phase of liquid drawdown where well gas intake may be significant. This casing gas may be compressed along with the low pressure light hydrocarbons 45 in a compressor 38, and injected into the distillation system 36. The purified solvent 47 may be heated 37 for circulation back into the injector well 33. Make-up solvent 49 may be added at the inlet of the distillation system for introduction into the solvent circulation loop. This process configuration is suitable for the early stages of the present invention, although other configurations that separate the water, oil and solvent from the mixed fluids are also comprehended.

Figure 4 shows the different stages of a solvent recovery procedure according to a preferred embodiment the present invention by way of example only. The x-axis 20 represents the four stages of the procedure, while the y-axis 21 plots changes in various parameters during the procedure. The four stages may be defined as I) wind down, II) liquid draw down, III) gas draw down and IV) chamber pressure adjustment.

At the bottom, line 22 is the solvent injection rate trend line which tapers off to zero at the end of phase I. Next, line 23 is the cumulative oil production trend line from the start of wind down, typically reported in barrels per day. Line 24 is the bottom hole chamber temperature trend line, while Line 25 is the bottom hole chamber pressure trend line. Line 26 is the water cut in the produced fluids trend line. Line 27 is the total solvent recovery trend line, calculated as the fraction of solvent recovered divided by the total solvent in the chamber. The total solvent in the chamber can be estimated by a mass balance of the solvent used in the EOR process, with the difference between in the cumulative solvent injected into the formation and the cumulative solvent produced from the formation being the amount remaining below surface in the chamber.

The timescale of the x-axis 20 will vary by reservoir, but for the example shown in Figure 4, which represents an example of a chamber, reservoir and distribution of solvent remaining, the total duration of the four stages may be approximately ten to eighteen months or longer but preferably around twelve months depending upon the nature of the reservoir. The solvent make-up requirements of new and active wells to sustain facility oil production may also determine the rate and overall timing requirements of solvent recovery.

Stage I: Wind Down

During Stage I, the solvent injection rate 22 may be transitioned from its value at the end of the production phase to zero. Preferably, this may be done by first turning down the make-up solvent that is added to the solvent that circulates between the chamber and the surface plant, followed by turning down the solvent re-circulation until the solvent being injected through the injection well reaches zero at the end of Stage I. According to the present invention, the rate of decrease in solvent injection and re-circulation is driven by a number of factors, including chamber size, temperature, pressure, and well productivity and thus the rate of changes in turn down may vary from chamber to chamber. Solvent that may be no longer required for circulation into this chamber may be redirected to other chambers in the well pad or other active well pads.

In one embodiment of the current invention, the solvent injection purity specification may be relaxed in conjunction with the ramp-down of solvent injection rate. This may be accomplished by various means, including the recompression and reinjection of producer casing gas vent which may be enriched in non-condensable gases.

In another embodiment of the current invention, additional heat may be added to the chamber before the solvent injection rate is decreased. This may be achieved by increasing the solvent injection temperature, energizing a downhole heater or other method known to those skilled in the art. The additional heat may sustain hydrocarbon mobility in the chamber for a longer period after solvent recovery begins.

Oil production continues in Stage I, as shown by line 23, although at decreasing rates compared to the production phase (not shown) due to the decreasing solvent injection rates and chamber temperature 24. The chamber pressure may decline due to the drop in injected solvent. The water cut in the produced fluids 26 may increase. As solvent is still being injected at the beginning of Stage I, net solvent recovery 27 may not be expected until towards the end of Stage I, when more solvent may be produced than is injected into the well. Stage II: Liquid Draw Down

Stage II begins when solvent injection has stopped. This next stage may be called liquid draw down because the main intent is to draw as much solvent containing liquid as possible from the production well. Liquid draw down recovers primarily mobile liquid or dynamic solvent, which can drain to the bottom of the chamber under the force of gravity either alone or in combination with other mobile formation liquids. This liquid will be initially oil and solvent rich drainage fluids that have collected during primary production and wind down phases and which has not yet been collected from the production well, for example by the downhole pump. Solvent may also continue to condense where in contact with colder surfaces around the chamber or wells, including the overburden or well liners. Typically, the solvent/oil phase may be lighter than water and tends to float on top of the produced water. In turn, the water may tend to settle below the producer well.

In one embodiment of the present invention, the injector and producer wells may be shut-in for a period of between 4 to 12 weeks after wind down before starting liquid draw down. This allows time for the free-draining fluids to collect at the bottom of the chamber, without being inhibited by the counter-flow of non-condensable gas that may be simultaneously injected during liquid draw down. The disadvantages of shutting in the well are the lack of any hydrocarbon production during this period and the chamber heat loss during the shut-in period, which will have a negative impact on hydrocarbon production in the later phases. As the effectiveness of the initial shut-in varies from reservoir to reservoir due to reservoir properties, operating conditions, and relative location to other wells, reservoir simulations may be used in the planning of chamber abandonment to determine if an initial shut-in is advantageous for the particular well pair.

Going back to the liquid draw down stage in Figure 4, as much liquid solvent as possible may be taken to surface via the producer downhole pump. However, the liquid level in the chamber cannot be monitored directly, therefore the water cut 26 and solvent/oil production rates 23, 27 act as useful indicators for identifying the end of the liquid draw down phase. As the solvent-rich fluids above the producer are depleted, the solvent and oil production rates will drop-off and the water cut will begin to increase, indicating there is little solvent and oil content in any free-draining solvent containing liquids reaching the production well, and the water phase is being produced in greater proportion. The hydrocarbons draining to the producer may also become progressively lower in solvent concentration as wind down progresses, which in conjunction with cooling conditions, can make the resulting drainage fluid more viscous and less mobile. Adding heat downhole to the production well may extend the practical operation of the downhole pump by improving the mobility of drainage fluids in and around the wellbore by lowering the viscosity through thermal effects. The present invention comprehends other forms of viscosity reduction as well at the production well as may be required. The liquid draw down phase may be ended when approximately 40-60% of water content exists in the produced fluids. Depending on the surface facility the water content will reach a level at which it becomes uneconomic to separate and dispose, and so it becomes uneconomic to further produce. This may be considered the liquid threshold and may be based, for example, on the trailing average water cut over several days. For example, as the water cut increases above 60%, it may become increasingly uneconomic to recover solvent in this manner as the energy required to separate the water, along with the potential cost for water treatment and disposal may exceed the value of any recovered hydrocarbons including solvent. In reservoirs with low water saturation, the liquid (solvent and oil) production rate may drop below an economical recovery operation even before the water cut rises to 40%. In this case, the producer casing gas rates may be excessive since the producer will have drawn down local liquid inventory and pressure, and the downhole pump may not operate in a continuously steady manner due to the excessive gas intake with the liquids.

In the preferred embodiment, the chamber pressure 25 may be maintained during Stage II by injecting a non-condensable gas. Maintaining the chamber pressure may be used to prevent the ingress of formation water into the chamber as more liquids are removed thus reducing the water cut in the produced fluids as compared to what it would be without such pressure maintenance. The non-condensable gas means, for this purpose, any gas that will not condense under the chamber conditions, and some examples include but are not limited to, methane, CO2, nitrogen, and the like. A source of non-condensable gas according to an aspect of the present invention may be readily available from the overheads of the solvent purification system in the surface plant. The non-condensable gas is optionally heated before injection into the chamber to slow the chamber temperature drop, pressure drop and the loss of bitumen mobility.

The non-condensable gas may be injected through the injector well and/ or nearby generally vertical observation wells or core well. Well perforations may be included in the liner before installation of the observation or core wells or strategically added after well placement by perforating the casing to provide direct access to specific elevations and areas within the extracted chamber. For solvent recovery, the custom placement of access may be preferable to permit the operator to select a location of injection of non-condensable gases or water or other flushing media where the chamber is at most risk of formation water ingress.

To avoid by-passing of the non-condensable gas directly from the injection points to the producer and retain heat in the reservoir, the liquid may be collected from the producer under the condition of little or no gas intake. For example, the production rate may be set to keep the producer downhole pump flooded with liquid so that little to no casing gas, including the non- condensable gas is drawn into the pump. If the liquid production is lower than the turndown of the downhole pump, some product oil may be recycled downhole to maintain the liquid seal. Other fluids available from the surface facility such as diesel, warm water or condensate liquid separated from product oil may also be used to maintain the liquid seal to the pump. Heating the product oil or other fluids may assist in reducing the mixture viscosity of the pump intake fluids, and this heat may be added to the fluid at the surface or with a downhole heater. These fluids may provide the added benefit of flushing the producer to prevent build-up of high viscosity fluids. In another embodiment of the present invention, a combination of liquids and gas may be collected from the producer, that is under gas intake condition. The gas intake condition may allow the producer pump to operate closer to its nominal flow rate rather than near turndown. This may be a preferred method of operation for reservoirs where the ingress of formation water is not excessive, even when the chamber pressure is not being maintained by non-condensable gas injection.

In this phase, the solvent recovered 27 may be in the range of 15-50% of the total solvent initially remaining in the formation, although the exact extent of recovery will be dependent on several factors mentioned before as well as the condition of solvent remaining.

There may be a significant portion of liquid solvent located below the producer well, in reservoirs with relatively low water saturation for example. For these reservoirs, the present invention comprehends injecting water, which may be produced water from the surface plant, into the chamber through an available injection point, for example the injector, producer or an observation well. This allows the lower density liquid solvent to float on top of the injected water as the water fills the chamber from below and drives the liquid solvent up to reach the inlet of the producer so that it can be brought to surface. This may be done either before liquid draw down starts, or towards the end of liquid draw down in order to recover solvent that may be below the producer downhole pump suction. The water is optionally heated before injection into the chamber to slow the chamber temperature drop and the loss of bitumen mobility. The water may be injected into injector well or preferably the producer well or even lower down through an access point provided by a vertical observation or core well. The injection and withdrawal points may be configured in a manner to encourage a sweep of the buoyant, mobile hydrocarbon phase towards the withdrawal point. Stage III: Gas Draw Down

Once the water cut in the produced fluids has reached the liquid threshold value of between 40-60% (or the solvent and oil production rates are no longer economic), the next stage of solvent recovery begins. Stage III may be referred to as the gas draw down stage because the main event is to recover solvent in the vapour or gas phase. This may include solvent that is considered static solvent, as well as slow-draining dynamic solvent that remains in the swept zone at the end of liquid draw down.

In the preferred embodiment of the present invention depicted in Figure 4, solvent-containing gas is drawn from the chamber via the injector well casing, injector tubing, and/ or an observation well or a core well. As a result, the chamber pressure 25 will decrease more rapidly, lowering the bubble point temperature of the residual liquid solvent. Residual heat in the reservoir rock may promote vapourization of that solvent into the gas phase so that it may be recovered through the injector well and/or observation well or core well as well. As the injector is used for pushing fluids during the production phase, the injector casing design may include features to allow suction of gas during the solvent recovery phase. These features may include appropriate orifices and tubing for gas intake as well as heating elements to discourage gas condensation along the length of the injector or tubing.

Solvent gas drawn to the surface via the well casing or tubing through suction alone is subject to various passivating effects. Specifically, heat losses incurred along the casing and tubing cause some of the gas to condense in transit to surface, and this condensate drains in a direction that is counter current to the gas flow. This counter current liquid flow may sufficiently accumulate in the tube to create a major flow resistance to the gas. Furthermore, where the gas is drawn from a liquid pool in the tube or annulus, the lower pressure suction may induce flash cooling at the gas- liquid interfaces, which decreases the temperature and bubble point pressure of the liquid pool and therefore greatly diminishes the extraction rate of the gas. Additionally, in areas where the withdrawal point may be flooded or surrounded with significant saturations of heavier hydrocarbons, a higher viscosity fluid plug may form in the tubing or around the orifice, either alone or in combination with the above mentioned passivation mechanisms. To address such passivating effects, downhole heating may be required. This may prevent the gas from reaching condensing conditions in the tubular up to surface or may warm any liquid pool to sustain higher bubble point pressures and lower viscosity of the liquid to support gas draw down from the pool. Furthermore, NCG injection may be used to lower the dew point temperature of the gas to help prevent condensation or to promote gas draw down through a liquid pool using similar principles as a flushing gas as discussed further below.

During gas draw down, some free-draining liquid solvent that remained in the swept zone at the end of liquid draw down may continue to drain and settle at the producer. Because the chamber pressure is being reduced significantly in this stage, formation water may also flow into the chamber from the surrounding reservoir. In one embodiment of the present invention, the liquid draw down may be continued even during gas draw down. The settling of free-draining liquid solvent and ingress of formation water tends to cool and sequester residual solvent in the flooded area, making it difficult to flash solvent during gas draw down. Continuing to draw down the liquids from the chamber allows for the solvent in the area that would otherwise be flooded to evaporate and be produced to the surface. This liquid may be drawn from the producer or with an appropriate lift system, from a higher elevation, for example through the injector, observation wells or core wells. Liquid draw down may also encourage gas recovery from the same location. Reservoir simulations estimate an additional 5-20% of the total solvent remaining may be recovered with simultaneous gas and liquid draw down. The anticipated value of the additional solvent recovered may be evaluated against the cost of the additional water production during planning of the chamber abandonment activities for a particular chamber to determine if simultaneous gas and liquid draw down should be used in a particular reservoir or chamber.

The gas draw down phase is ended once the withdrawal locations have been flooded with formation water or if there is not enough production of solvent from the injector casing/ observation wells/ core wells to justify the continued operation. This may be considered the gas threshold. The latter may occur before the injector is flooded if simultaneous liquid draw down is employed or if large quantities of solution gas are being drawn into the chamber, such as may be expected for reservoirs with low water saturation and high gas to bitumen ratio.

In this phase, the solvent recovered 27 is expected to be in the range of 20-40% of the total solvent remaining at the end of solvent injection, although the exact recovery will depend on several factors mentioned before as well as the type of solvent remaining.

For chambers that are located close to an aquifer, if gas draw down is done with decreasing chamber pressure, the chamber may fill very quickly with formation water before a significant amount of solvent can be recovered. Similarly, for chambers that are close to intraformational gas zones, decreasing chamber pressure may induce formation gas intake to the chamber and further dilute recovered vapours. Therefore, in another embodiment of the present invention, gas draw down is conducted with the chamber pressure in balance to the reservoir by injecting gas and producing gas simultaneously. A gas other than solvent; preferably one which is non- condensable at reservoir conditions may be injected into the chamber, for example, through the injector well, while solvent-containing gas may be produced at another point in the chamber, such as the producer well. The non-condensable gas may act as a flush to force solvent gas towards a recovery location. When using a flushing gas, the injection and production may occur simultaneously. In another embodiment the injection and production can occur through the same well, but may take place sequentially. In yet another embodiment, the injection and production can occur through wells that are associated with different well pairs to form broader sweeping patterns.

Using observation wells and nearby core wells to inject or produce the gas is also comprehended again either simultaneously or sequentially. As will now be understood the present invention comprehends minimizing mixing of the injected gas (which is to be left in the extraction chamber) and produce solvent gas (which is to be removed from the chamber) by means of separating the injection/production locations, by means of species selection, or by other means.

Injecting a flushing gas into the chamber may reduce the partial pressure of solvent in the gas phase to a point below the vapour pressure of the solvent at the then temperature of the chamber, causing some of the residual liquid solvent to evaporate, after which such newly vapourized solvent gas may also be collected in the gas phase. Such a process is analogous to a low-temperature dehydration process, in which dry air is used to slowly remove water from another medium at a temperature well below the boiling point. A possible limitation of injecting a flushing gas to try to strip solvent from the chamber is that the gas may not expand to the chamber perimeter, therefore such a dehydration step may be more effective near the wellbore or across the source/sink pathways then at the chamber perimeter. In addition, solvent losses in the surface facilities may rise as the solvent purification system, which may use distillation, may not be capable to separate produced gas which is rich in flushing gas, such as methane-rich rather than solvent-rich, which is the condition that the solvent purification system operates under during normal extraction to efficiently separate the targeted hydrocarbon solvent. In this case, a separate dedicated circuit designed for efficient recovery of solvent from flush gas may be preferred.

Therefore, in one embodiment of the current invention, a water soluble gas such as CO2 may be used as the flushing gas and the surface facility equipped with a selective separation step involving an aqueous phase absorption of CO2. In the end such CO2 may be sequestered in the chamber if the conditions are appropriate.

Stage IV: Chamber Pressure Adjustment

If there are other operating wells nearby, the present invention comprehends steps to re-pressurize the chamber to approximately the native reservoir pressure or any other pressure that may be appropriate to facilitate extraction of an adjacent resource. Such re-pressurization or pressure adjustment may be done either by injecting additional flushing gas or high water cut produced fluids/ produced water into the chamber through one or more injection points, for example, the injector, the producer and/or observation wells to fill the chamber and thus discourage this chamber from attracting solvent from nearby extractions.

Figure 5 is a contour graph showing the distribution of solvent remaining in the chamber 10 after performing the liquid draw down according to the preferred embodiment of the present invention. In comparison to Figure 2, the moles of solvent in the drainage layer 18 at the level of the producer 16 are reduced and there is a nearly solvent-free zone 11 generally above the injector 14 where NCG may have been injected for pressure maintenance. However, there may not be much change in the moles of solvent present in the rest of the swept zone 20. This is solvent in the gas phase that cannot be produced to surface through the downhole pump and some liquid solvent that has not yet settled to the drainage layer. In the presented example, the estimated recovery between Figure 2 and Figure 5 may be about 40% of the total solvent retained in the reservoir in some cases.

Figure 6 is the contour graph showing a distribution of solvent remaining in the chamber 10 after performing the gas draw down according to the preferred embodiment of the present invention. In comparison to Figure 5, the amount of solvent in the swept zone 20 has significantly decreased. The estimated recovery between Figure 5 and Figure 6 may be an additional 25% to 30%, for a total recovery of about 70% of the solvent hold-up.

Over time, a thickness of solvent-rich layer near the producer 16 may grow due to some further settling of liquid solvent from the swept zone 20 into the drainage layer 18 during gas draw down. Additional recovery of this liquid solvent may be achieved by simultaneous gas and liquid draw down. Sequential gas and liquid production is also comprehended depending upon reservoir conditions.

Figure 7 is a contour graph depicting the distribution of solvent remaining in the chamber 10 after further gas and liquid draw down after the initial liquid draw down in this example. In comparison to Figure 5, a thin layer of solvent may remain around the perimeter of the chamber. Additional solvent recovery beyond this point may not be economical due to a high water cut in the liquid phase and since there may no longer be enough residual heat in the chamber to flash the solvent into the gas phase. In this example, simultaneous liquid draw down during gas draw down increases the estimated recovery to a total of 80% to 85% of the solvent remaining depending upon reservoir conditions.

Now it can be understood that the present invention may recover at least 50%, preferably 60-70%, most preferably 80-90% of the total solvent remaining in the reservoir after primary extraction has been completed. The exact extent of recovery will vary depending on the reservoir and chamber conditions, including conformance of the wells, the extent of liquid and gas solvent present at the end of production, and rate of heat loss to the overburden and surrounding reservoir rock from the chamber and near well bore areas.

The present invention most preferably is able to use the substantially same surface plant and downhole equipment used during the production phase as previously shown in Figure 3, with some adjustments or plant modifications to accommodate the changing nature of the liquid draw down and gas draw down. Figure 8 is a schematic of the plant configuration which may be used for the liquid draw down stage (shown with solid lines), and for the gas draw down stage (shown with dashed lines). In preparation for liquid draw down, the solvent recovered in the distillation system 36 may be reallocated for other wells or stored as solvent for resale. A compressor may be reconfigured or modified to inject overheads 59 from the distillation system 36 and a make-up methane or other (non-condensable gas) stream 51 along with the casing gas 40 into the chamber to maintain the surface plant and chamber pressure during liquid draw down. An observation well 54 which has been provided with direct communication with the chamber as described above in Figure 1 may also be connected to the compressor 38 outlet. Recirculation of product oil 52 or another fluid with or without supplementary heating may also be provided to the downhole pump 32. The downhole pump 32 may be optionally replaced with a unit for higher viscosity fluid, which may be the pump used at start-up. While a downhole pump is used to describe the artificial lift of fluids in this process, those skilled in the art are aware that various artificial lift devices may have application to this process, such as hydraulic or gas lift.

In an embodiment of the present invention, the operating pressure of the surface plant may be decreased over time to suit the reservoir conditions and recovery metrics.

Once liquid draw down is complete, another adjustment to the surface facility may be required to reorient the compressor 38 so that it may draw gases from the injector 33 and/ or observation well 53 and feed the same to the distillation system 36. However, as this is just a piping and valve arrangement most preferably the surface plant will be initially configured to permit such adjustments to be quickly and easily performed with a minimum amount of additional or new piping installations. Fuel gas 50 from the overheads of the distillation system 36 may be used as fuel in other areas of the facility.

While reference has been made to preferred embodiments of the invention those skilled in the art will understand that various modifications and alterations are comprehended which do not depart from the scope of the claims attached. Some of these has been discussed above and other will be apparent to those skilled in the art.

Claims

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

1. A method of recovering solvent from an in situ gravity drainage chamber, said method comprising the steps of:

transitioning to producing vapour from said formation;

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 1 wherein said gravity drainage chamber includes a pair of generally horizontal wells comprising an upper injection well and a lower production well.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 2 wherein said draining liquids are removed through a pump located in said lower production well.

4. The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 2 wherein said vapours are removed first from said lower production well and then from upper injection well.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 1 wherein said step of monitoring a content of said produced liquids includes monitoring a water cut in said produced liquids.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 5 wherein said production of liquids is ceased when said water cut exceeds 50% of the total volume of said produced fluids.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 1 wherein said solvent recovery method uses a surface plant used in the extraction of hydrocarbons by means of a solvent based gravity drainage process used to form the solvent retaining gravity drainage chamber.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 1 wherein said vapours are recovered from a position in said chamber above a position where said liquids are recovered from.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 8 wherein said vapours are recovered from a position within said gravity drainage chamber above said injection well.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 9 wherein said vapours are recovered through a generally vertically oriented well.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 1 wherein said vapours produced from said formation include solvent vapour.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 1 further including the step of managing a pressure within said gravity drainage chamber during said recovery method.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 12 wherein said method of managing pressure further comprises injecting a gas, which is non-condensable at reservoir conditions, to maintain a chamber pressure during said step of producing vapours from said chamber.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 13 wherein said non-condensable gas is heated prior to injection into said chamber.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claims 13 and 14 wherein said step of injecting further comprises injecting non-condensable gas which has been previously recovered from said formation and separated by an associated surface facility.

16. The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 1 further including the step of injecting water into said formation to float liquid solvent up to the production well to facilitate production of liquid solvent.

17. The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 16 wherein said water is heated prior to said water being injected into said chamber.

18. The method of recovering solvent from an in situ gravity drainage chamber as claimed in claims 16 and 17 wherein said step of injecting water into said chamber further comprises injecting formation water recovered from said formation by means of an associated surface facility.

19. The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 1 further comprising the step of pressure balancing the chamber by means of injecting at least one of water and non-condensable gas as needed to generally balance the chamber pressure with said formation pressure.

20. The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 19 wherein one or both of said water and said non-condensable gas are heated before being injected into said chamber.

21 . The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 19 and 20 wherein chamber pressure is generally balanced with said formation when there is not enough pressure drive across a chamber interface to cause material migration across said interface.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 1 including the pre-treatment step of shutting in said production for a period of time after stopping further solvent injection to permit liquids to drain to a lower elevation in said chamber before beginning to produce liquids from said chamber.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 22 wherein said shut in time is between 4 to 12 weeks in length.

24. The method of recovering solvent from an in situ gravity drainage chamber as claimed in claims 19, 20 and 21 , wherein production of vapours through a well casing are reduced to limit non-condensable gas removal from said chamber.

25. The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 3 further including a step of recycling product oil into said chamber to maintain liquid levels in said chamber above said downhole pump.

26. The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 25 wherein said one or more liquids includes one or more of recycled product oil, water and condensate.

27. The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 25 wherein said one or more liquids flash through said production well and reduce a build up of high viscosity fluids.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 1 further including the step of circulating a flushing gas through said chamber to strip further solvent from said chamber.

The method of recovering solvent from an in situ gravity drainage chamber as claimed in claim 28 wherein said flushing gas is introduced into said chamber at a position remote from a position where said flushing gas is removed from said chamber.

A surface facility for recovering solvent from an in situ chamber formed by a gravity drainage process, said surface facility comprising: a liquids separator to separate water from a mixed fluid production stream extracted from said chamber;

a vapour separator to separate gases which are non- condensable at reservoir conditions from said mixed fluid production stream extracted from said chamber;

a first return circuit to permit said separated water to be reinjected back into said chamber; and

a second return circuit to permit said separated non- condensable gases to be reinjected into said chamber.

The surface facility of claim 30 wherein said surface facility further includes a heater associated with one or both of said first and second return circuits to heat one or both of said re-injected water and non- condensable gases. 32. The surface facility of claims 30 and 31 wherein said surface facility further includes a compressor to compress said re-injected non- condensable gases at surface for re-injection.

The surface facility of claims 30 and 31 wherein said facility further includes a pump to pump said separated water back into said chamber at a predetermined pressure.

The surface facility of 33 wherein said pump pressures said water to match a reservoir pressure.