CA3023470C - In situ hydrocarbon mobilization process and surface facility for the same - Google Patents

Abstract

An in situ hydrocarbon mobilization process includes the steps of: Selecting a working solvent for a condensing in situ gravity drainage extraction process; injecting the working solvent as a liquid into a hydrocarbon bearing formation to create a gravity drainage flow path to a production well through a portion of the formation; and transitioning to in situ condensing conditions with said working solvent within said formation to create an extraction chamber above said gravity drainage flow path.

Description

Title: IN SITU HYDROCARBON MOBILIZATION PROCESS AND
SURFACE FACILITY FOR THE SAME
FIELD OF THE INVENTION
This invention relates to the mobilization of in situ hydrocarbons and more particularly to the mobilization of in situ hydrocarbons which do not readily flow at native in situ conditions. Most particularly this invention relates to the mobilization of in situ hydrocarbons in association with enhanced oil extraction through a generally horizontal well pair.
BACKGROUND OF THE INVENTION
In situ gravity drainage technologies for extracting heavy hydrocarbons from bitumen deposits may use a pair of generally horizontal wells that are spaced vertically apart. The upper well is generally the injector, used to inject a working fluid, such as steam or solvent vapour, while the lower well is generally the producer, from which the produced fluids, including any extracted hydrocarbon is withdrawn. The well bores may be located within the hydrocarbon pay zone and an inter well bore region located between the two wells may include pay hydrocarbons. These wells may extend hundreds of meters in the horizontal direction.
For solvent-based gravity drainage extraction, such as the nsolv technology, a warm working solvent vapour enters the formation through the injector well and condenses when it comes into contact with the colder sand and bitumen. The latent heat of condensation is transferred to the sand and bitumen. As the bitumen is heated and mixes with the solvent, its viscosity reduces, allowing it to drain by gravity to the producer well, where it may be pumped to surface mixed with the condensed solvent as well as any mobile formation water. As more and more bitumen is extracted, an extraction chamber grows around and above the wells. In this sense an extraction

-2-chamber consists of an oil depleted volume of the formation pay zone.
An initial extraction phase for the well pair occurs after the wells have been drilled, but before an initial extraction chamber can be developed. In this initial phase, the substantially immobile hydrocarbons may need to be removed from the inter well bore region to permit formation fluids to drain by gravity to the lower well. Conformance is the term used to describe how uniform the gravity drainage flow path is along the length of the well pair.
Improvement in effective permeability of the gravity drainage fluid through the inter well bore region enables effective conformance. It is important to establish fluid communication between the wells with sufficient conformance to ensure good drainage along the length of the wells to permit good production results. Areas above the production well where there are any obstructions (i.e. where there may be poor conformance), may fill or flood with draining liquid, preventing a working fluid from contacting, heating, and extracting the hydrocarbons in that region above the blockage. Further drainage rates may be adversely affected if the draining fluids have to traverse a large distance horizontally to reach an unblocked draining section.

It can be difficult to improve conformance once a gravity drainage extraction has started.
A modest temperature rise, in the order of 40 to 60 degrees C can result in a significant reduction of the in situ viscosity of the native hydrocarbons rendering them at least partially mobile. The dilution of the native hydrocarbons or bitumen with a solvent can further lower the viscosity and improve mobility. In the past, some operators have focused on heating the inter well bore region up to bitumen mobility temperatures as quickly as possible. Because the heat transfer is by conduction and its rate is related to the temperature driving force, with a greater temperature difference meaning a faster heat transfer, some operators have sought to apply very high temperatures during this stage. In other cases, operators have tried

-3-combining conduction heat transfer with diluting the bitumen with non-deasphalting solvent to displace the bulk of the hydrocarbon from between the well pair and establish fluid communication. The heating may be done for example, by circulating steam or other fluid, by electrical heaters placed into the wells, or even by electromagnetic, microwave, and radio frequency heating.
Circulation of steam in each of the injector and producer wells to establish fluid communication between wells has been used as an initial step in the SAGD process. For solvent based processes such as the nsolv process, steam injection introduces water into the formation, which can act as a barrier between the working solvent and the pay hydrocarbon, negatively affecting the production rates. It would also require high capital expenditures for steam generation facilities that are otherwise not required for the following production phase.
Prior art patents and applications (CA 2,691,889 and 2,730,680) teach the need to circulate solvent gas above its critical temperature in both wells to warm the inter well bore region. The problem with using gas to establish fluid communication is the relatively low heat capacity of the gas;
consequently, the start-up process will take a long time or require high gas flow rates and pressure drops and consequently high energy consumption.
United States Patent No. 8,528,639 discloses a solvent pre-soak before heating the well bores, followed by squeeze stage of injecting steam to accelerate the communication process. This process takes advantage of the bitumen viscosity reduction afforded by the solvent and the high rate of heat delivery into the reservoir by steam but requires two separate fluid delivery systems in the surface facilities and is therefore capital intensive as well.
Steam or solvent gas circulation may also have the disadvantage that high pressures are required, which will likely lead to spot breakthroughs

-4-between the well pair and short-circuiting. This will establish some, but limited localized draining, resulting in poor conformance. For shallower reservoirs, it may not even be possible to achieve high enough pressures to deliver practical start-up fluid temperatures without such pressures exceeding safe operating pressures. Too high a pressure may lead to a loss of working fluid to thief zones, or fracturing of the reservoir with further losses, or even leakage from the well casings and potential damage thereto due to thermal stresses.
Canadian Patent Application No. 2,784,582 teaches to use hydrocarbon-based liquids that will remain liquid in the temperature and pressure ranges suitable for its start-up process, such as synthetic crude oil (SCO), and diesel fuel. These liquids are chosen for their substantially non-deasphalting properties, to avoid asphaltene precipitation in the inter well bore area. Precipitated asphaltenes can become plugging deposits which can block the flow pathway to the production well of gravity draining liquids.
This is a result to be avoided. However, this requires two separate working fluids, one for the initial phase and a second for the chamber growth phase.
The aforementioned start-up fluids, as well as electrical, and other heating methods generally transfer heat from the wells to the inter well bore region by conduction. Therefore, inter well distance variations due to drilling tolerances and variations in reservoir heterogeneity between the wells along the well pair length can cause low resistance regions and high resistance regions, leading to varied permeability conformance along the well length.
Further, as noted above, a high temperature driving force is required for .. practical heat transfer rates. The high temperatures, which may be at least 120 C and preferably higher, may cause thermal stress on the casing and couplings of the well which can lead to casing leaks (after cooling down to normal working fluid temperature) and accelerating corrosion on any metallic surfaces that are in contact with the formation fluids, including the well casing

-5-and the heating elements themselves.
Furthermore, these high temperatures at low reservoir pressures may evaporate formation water from the near well bore region, changing the wettability of rock, and therefore affecting the effective permeability of the formation in this vicinity to draining liquids.
In the 2008 publication in the Proceedings of the Canadian International Petroleum Conference [Nenniger, J.E. and S.G. Dunn, "How Fast is Solvent Based Gravity Drainage?", CIPC 2008, Paper 2008-139]
Nenniger and Dunn correlated the mass flux for oil production by solvent based gravity drainage to (p)- .51, where p is the raw oil viscosity at extraction temperature. Nenniger and Dunn also explained that solvent extraction processes are driven by solvent-bitumen diffusion at the pore scale level in the reservoir matrix and that high mass flux rates of oil are achieved due to steep concentration gradients between the bitumen and the solvent interface.
However, this description applies to a gravity drainage process once gravity drainage has commenced as opposed to establishing a gravity drainage flow path to begin with.
SUMMARY OF THE INVENTION
Therefore, what is desired is an initial extraction process or hydrocarbon mobilization process that may be compatible with a following solvent-based gravity drainage extraction process; that may heat-up and extract bitumen from the inter well bore region generally uniformly and efficiently without requiring excessive temperatures above the bitumen mobility temperature, and may achieve a reasonably high degree of conformance along the length of the well pair to establish a good flowing gravity drainage flow path. As well, a process which is efficient in terms of capital expenditures, is also desirable.
According to one preferred embodiment such a method may use the

-6-working solvent, to be used in the following extraction process, in liquid form to remove the inter well bore hydrocarbons to establish a gravity drainage flow path from the injection well to the production well. This may be capital efficient, since it avoids the need for extra surface equipment to deal with multiple materials or fluids (i.e. both steam and solvent facilities as in the prior art). In this way, capital costs may be reduced as compared to the prior art.
According to the present invention it may also be preferable to aim to achieve a process centreline temperature (namely along the mid point between the two horizontal wells) of the inter well bore region to just below a bulk bitumen mobility temperature. Such a temperature will permit bitumen mobilization, but may avoid mobilizing a large portion of the pay hydrocarbon at once, which may require high pressure driving forces to produce the fluids and may lead to short circuiting or a non-conformance along the length of the well. By utilizing lower temperatures, the risk of thermal stress induced casing leaks and corrosion in the wells may also be mitigated. In one aspect, the present invention may be able to utilize lower temperatures because it delivers solvent and heat effects generally evenly throughout the inter well bore region by forced convection.
According to the present invention using a low operating temperature, and a pressure differential, it may be possible to distribute solvent through many small drainage paths/fingers/fluid communication channels between the injector and producer, to create a high surface area for the bitumen-solvent interface, as an alternative to the prior art teachings of a need for well re-circulation methods with each well to try to establish good conformance.
In the present invention, a relatively higher pressure driving force may be desired at the beginning to ensure there is a sufficient working solvent flowrate between the well pair to maintain a high solvent concentration even in low initial effective permeability regions. This may help to avoid extracting

-7-bitumen in high concentrations that may be too viscous to be mobile.
According to an aspect of the present invention, a gravity drainage flow path can be established between a horizontal well pair by, among other things, = Injecting a continuous flow of liquid start-up solvent, beginning at near native reservoir temperature through the injector well; at a pressure which may keep the solvent as a liquid and which may ensure the solvent flowrate through the lower permeability zones in the inter well bore region remains high enough to attain sufficient fluid mobility. The process comprehends adding make-up solvent to maintain the pressure as the solvent penetrates through the formation; with a minimum pressure which keeps the solvent in a liquid state and mobile but the present process comprehends higher pressures as well.
= Drawing down on the producer well to remove formation fluids from the inter well bore region; This step comprehends applying a pressure on the producer that is lower than the injector pressure and is appropriate to the reservoir; thus sufficient pressure difference may be applied between the well pair to cause the fluids to flow through the formation, including the liquid solvent. The actual pressure applied may vary according to specific reservoir characteristics.
= Controlling the pressure drop between the injector and producer which may provide for adequate distribution of start-up liquid across the length of the well. In this case a sufficiently high pressure drop to be applied in the low permeability regions to permit solvent penetration in such low permeability regions; pressure sensors are used at one or more locations along the length of the well to monitor pressure drop;
= Monitoring the concentrations of one or more of the produced fluids in total produced fluids may be used as one indication of the amount of

-8-gravity flow drainage path that has been established and of the mobility of the fluid in the formation;
= Monitoring the temperatures in the injector and producer wells; use of temperature data, and in particular temperature fall-off data, may help determine how much of the gravity drainage flow path has been established and of the mobility of the fluid in the formation;
= Gradually increasing the liquid start-up solvent injection temperature, which may increase the bitumen extraction rate, to maximize the uniformity of heat delivery into the inter well bore region; the higher the temperature, the lower the viscosity of the bitumen will be and the higher permeability regions will heat up faster than lower permeability regions due to additional convective heat transfer, which may lead to preferential channel development and ultimately short circuiting.
Using a starting liquid solvent injection temperature at or about the initial formation temperature and a gradual temperature ramp up may permit the solvent to penetrate more evenly before the temperature is raised. In this sense a gradual temperature ramp up means ensuring that the temperature difference between the injector and the producer remains within a preferred temperature band and only increasing the injector temperature as the producer temperature rises while keeping within the temperature band.
= Monitoring progress of fluid communication and conformance along the horizontal length of the well pair; this may be done by means of bitumen extraction monitoring, fall-off test temperature profiles, pressure differentials, residence time distribution analysis of injected tracers, or other means.
= Transitioning the injector fluids to solvent vapour injection once sufficient fluid communication or conformance is established.
The present invention may use the same well pad configuration as

9 PCT/CA2017/000129 SAGD operations or one as defined by CA 2,784,582. It may also use the surface facilities as would be required for production in a solvent based EOR
without major additional equipment.
In one preferred embodiment of the present invention, the initial phase solvent is a hydrocarbon that is also the working hydrocarbon solvent intended for use in chamber growth in a later phase. Such a solvent may be, for example propane, butane, pentane and the like. By using the same solvent for start-up and production, the formation of high viscosity liquids from the mixing of different solvents and diluted bitumen may be avoided.
These high viscosity liquids may plug surface lines and the production well bore, leading to operational and maintenance difficulties.
In the present invention, fluid communication between the wells may be established mainly through sand grain level extraction of bitumen, rather than bulk displacement of hydrocarbon, which has been the objective of most prior methods for establishing communication between horizontal well pairs.
With bulk hydrocarbon displacement, it is difficult to achieve high levels of conformance due to preferential channelling of the fluid between the wells caused by natural variations in the permeability and/or variation in vertical drilling distances along the well length that are difficult to avoid.
In one embodiment of the present invention, water, such as formation water, may be initially circulated and the water-cut of the injection fluid ramped down with make-up solvent addition over time. Co-injecting water and solvent may moderate the bitumen extraction rate by reducing the contact area of solvent and unextracted bitumen. Water provides a persistent mobile phase in the inter well region in the event of significant process interruption and may improve the initial effective permeability of the mobile fluid phase with or without the use of chemical surfactants.
In another embodiment of the present invention, as the water cut of the formation fluids decreases, a portion of the formation fluids is circulated

-10-into the injector well with the heated liquid start-up solvent to increase the rate of heat delivery into the formation, increase viscosity of the fluid sweeping the inter well bore region, and reduce the contact area of solvent and unextracted bitumen.
In a further embodiment of the present invention, there is provided a method establishing conformance between a horizontal well pair located within a hydrocarbon bearing formation comprising the steps of:
a. injecting a liquid solvent into at least an inter well bore region, b. monitoring a permeability of the inter well bore region and selectively modifying an asphaltene deposition concentration along the inter well bore region between the well pair to reduce permeability in high permeability regions or increase permeability in low permeability regions by either adding or removing asphaltenes.
The present invention may not require a non-productive preheat phase during which the production well is merely circulating start-up fluids and not in production. In the present invention, oil production, albeit at a reduced rate, may be realized as soon as drawdown on the producer begins to draw through solvent and diluted hydrocarbons. Thus, the present process may be viewed as a ramp-up phase to full oil production, rather than as a separate, non-oil producing start-up phase of well operation.
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 horizontal well pair located within a pay zone of an underground formation;
Figure 2 is a flowchart of a surface plant for separating the formation fluids taken from the well pair;
Figure 3 is a schematic showing the different stages of a start-up

-11-procedure according to the present invention; and Figure 4 is a flowchart of a surface plant showing the by-pass for a preferred embodiment of the present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
In a preferred embodiment of the present invention, a pair of generally horizontal wells may be used, one above the other, which is sometimes referred to as a well pair. While reference is made herein to a horizontal well pair, it will be understood that the present invention is not limited to such a well configuration and the process may be operated on vertical wells, and other horizontal or slanted well configurations. A horizontal well pair is used by way of example only.
The upper well may be the injection well used for injecting the working fluids, while the lower well may be the production well used for extraction of pay hydrocarbon and working fluid recovery. Figure 1 is a schematic view of an example of a suitable well pair for the present invention. The wells are located within an underground formation 18 which includes a pay hydrocarbon zone 20, with an overburden 19 and an under-burden 21. The upper well 10 and lower well 12 are separated by a well spacing 14. It will be understood that the upper well is at a first elevation within the formation and the lower well is at a second elevation. In this example the first elevation is above the second elevation. The upper well may be referred to as the injector, while the lower well may be referred to as the producer, indicative of the general fluid direction in those wells relative to each other. A
centreline 16 is located at the vertical midpoint between the two wells or half way between the upper and lower elevations. The well pair is positioned towards the bottom of the pay hydrocarbon zone in accordance with a conventional positioning of the well pair for gravity drainage processes. The preferred type of pay zone is a heavy hydrocarbon pay zone such as may be found in the oil

-12-sands of Alberta, Canada.
Although the wells are shown with slanted risers 22, 24, and horizontal casings 26, 28, it will be appreciated by those skilled in the art that these are illustrations only and that in practice the angle of the well might vary considerably from this, as well as the practice of well design such as vertical injection or herringbone patterns. Each well may be equipped with a fluid delivery or extraction system using narrow diameter tubes 30, 32, for example, 3.5 inch tubing, which is fed down the risers and extending to the toe 34, 36 of each well 10, 12. A second narrow diameter tube 38, 40, such as the 3.5 inch tubing, is also fed down the riser portion of each well, but preferably extends only to about the heel 39, 42 of each well 10, 12. Each of the narrow diameter tubes 30, 32, 38, 40 are connected to the appropriate pumps and heaters to allow fluid delivery into the heel and toe of the upper well 10 and fluid removal from the heel and toe of the lower well, 12.
Although these are shown as extending from toe and heel, the present invention comprehends ending the narrow diameter tubes intermediate the ends depending upon the circumstances.
The present invention requires a surface plant to separate the multiphase mixed fluid produced from the wells and to recover and recycle a working fluid such as a solvent. The mixed fluids will typically include solvent, formation water, extracted hydrocarbons, including bitumen and formation gases and various solids such as sand or clay fines. Figure 2 is a schematic of a suitable surface plant 100, which includes a free water knock out vessel (FWKO) 102 or similar apparatus to remove the produced water 118 from the remaining produced fluids, at least one flash vessel (104, 106) to separate oil 116 from the solvent and a distillation column system 108 for purifying the solvent. Make-up solvent 112 may be added as required to the distillation system to maintain pressure in the surface plant and wells during the process as described below, as well as to affect the bitumen extraction rate and

-13-adjust the viscosity of the drainage fluids downhole. The purified solvent may be heated using heater 110 located in the surface plant or downhole that may use fuel gas or heat recovery from other streams in the facility. There may be solvent storage 114 provided. This surface plant layout is provided by way of example only and various other configurations, which include separation of water, product oil and solvent, followed by solvent purification with provisions for solvent make-up, storage and heating are also comprehended.
Once the wells and surface plant are ready to be put into service, injection of the working solvent that would be used for later chamber growth (e.g. propane, butane, or pentane) is begun. Preferably once started the injection is continuous into the injector well 10 and under conditions which render the working fluid as a liquid at in situ native reservoir temperature.
The selection of the working solvent will depend on the reservoir conditions, as will be understood by those skilled in the art. The selection of solvent may be made based on chamber growth efficiency rather than gravity drainage path formation efficiency. The working solvent flow may be injected entirely from the tube extending to the toe (30 in Figure 1), entirely from the tube extending to the heel (38 in Figure 1) or portioned between both for better distribution across the length of the well. What is desired is provide a distribution of liquid solvent, under pressure, along the length of the injection well so that the liquid solvent may begin to penetrate the surrounding formation and spread outwardly all along the well length.
At the start of liquid solvent injection, the inter well bore region of the reservoir has a relatively low effective permeability Ke to the liquid working solvent, which may be due to the presence of bitumen in this region Furthermore, the Ke will vary between and along the length of the wells due to, for example naturally occurring reservoir heterogeneities or well drilling disturbances. The range of Ke is dependent on local reservoir characteristics

-14-such as absolute permeability and water saturation and may be determined by such means as historical field performance data, an initial cold water flood test, field tracer analysis, core permeability analysis, well logging, and/or descriptive geology data correlated to permeability, as will be understood by those skilled in the art. The present invention may achieve an overall improvement to Ke, in preparation for the following solvent-based gravity drainage extraction process, by removing free water and extracting bitumen into the liquid working solvent, thereby creating gravity drainage flow paths for fluid communication between the well pair.
Upon initial solvent injection, substantial amounts of free water may be initially produced as observed in the demonstration plant that has been operating near Fort McMurray, Alberta, which uses the nsolv condensing solvent process. During the start-up of the horizontal well pair for the demonstration plant, a substantial amount of water was produced when the start-up fluid (diesel) injection in the upper injection well began. A high rate of water production relative to bitumen was unexpected because the inter well bore region had already been preheated by electric heaters to about 50 C, at which bitumen starts to be mobile. As the displacement phase continued, the water production decreased while bitumen production increased. Thus, even at temperatures high enough to mobilize bitumen, the start-up fluid may preferentially displace the water film in the inter well bore region before displacing mobilized bitumen.
In the present invention, a pressure difference between the wells encourages the cold liquid solvent to finger through the formation. Since the viscosity of water is lower and its mobility is higher than bitumen at the native reservoir temperature, the solvent may initially displace mostly free water from the pores of the reservoir down towards the producer. The free water is removed as part of the mixed produced fluids (along with solvent and some oil) by drawing down on the producer well. The produced fluid is put through

-15-the surface plant to separate water and oil and to recover, purify and heat/pressurize the solvent for re-injection. The produced fluids may be drawn off entirely from the tube extending to the toe (32 in Figure 1), entirely from the tube extending to the heel (40 in Figure 1) or portioned between both.
This first step of drawing out mostly free water from the reservoir around the production well may improve the Ke of the reservoir to the solvent-rich drainage fluid and has the added advantage of removing, from the gravity drainage path, at least some of a cold, high heat capacity fluid that, if left in the path, would represent a parasitic heat load taking heat energy away from the in situ bitumen in the later steps of the present process.
As cold solvent fills the "dewatered" pores in the reservoir, it contacts bitumen with a very high contact surface area to unit volume ratio. Leaching of the bitumen into the solvent occurs at the bitumen-solvent interface, due to the concentration shock at the sand grain level described by Nenniger, J.E.
and S.G. Dunn, How Fast is Solvent Based Gravity Drainage?, CIPC 2008, Paper 2008-139. Despite the low temperature, productive extraction rates may still be achieved due to the high contact surface area. For example, consider a 20 m payzone in the Athabasca oil sands, with porosity of 30%, water saturation of 20%, and sand particles of 100 microns in diameter. A
horizontal well pair using 298.5 mm casing, spaced 5 m vertically is located appropriately in the payzone. The bitumen viscosity at the native reservoir temperature of 10 C is 8.5 million cP, but decreases to about 8,500 cP when heated to 60 C, a decrease by a factor of 1000. This decrease in viscosity contributes to elevating the mass flux rate for bitumen extraction by a factor of about 34 accounting for Nenniger's correlation of 110.51 to the mass flux.
The bitumen-solvent interface per length of well for a formed extraction chamber may be approximated as the 20 m payzone multiplied by 2 sides for

-16-40 m2 per m well length. Before the chamber is formed, the solvent fingers in between the 100 micron sand particles, with an estimated potential surface area for bitumen-solvent contact of about 68,000 m2 per m well length. Now it can be understood that while high mass flux rates of bitumen extraction may be achieved with low bitumen viscosity at elevated temperatures, at least a comparable bitumen extraction rate may also be possible at high bitumen viscosity near native reservoir temperatures due to the large potential interface area that may be applied to the lower mass flux.
The bitumen extraction rate at initial reservoir temperature is dependent on the reservoir characteristics and may be initially estimated using historical field performance data or a lab test with core samples flooded with working solvent at low temperature, or other established methods of estimating bitumen extraction. The potential bitumen extraction kinetics by cold liquid solvent from a reservoir in the Athabasca oil sands have been tested by a physical test. A stack of unextracted core plugs, approximately 4 cm in diameter by 26 cm long, taken from the aforementioned nsolv demonstration plant reservoir, was pressurized and placed in a chiller at 8 degrees Celsius to simulate native reservoir conditions. To apply aspects of the present invention, the core stack was injected with 8 degrees celcius liquid butane for approximately 24 hours, then removed from the chiller, with liquid butane injection continuing for approximately 46 more hours at room temperature of 22 degrees Celsius. The solvent to oil ratio ranged from 7 to 13 on a volumetric basis during the test. Over 45% of the oil in the core stack was produced at 8 degrees Celsius, while a total of over 70% of the oil was produced over the entire test period of 70 hours. The present invention comprehends that the potential extraction kinetics even at native reservoir temperatures may be rather fast and effective.
For the present invention, the bitumen extraction rate may be controlled because if it occurs too fast, the fluids in the inter well bore region

-17-will have a high bitumen concentration and not enough solvent to reduce the viscosity to adequately mobilize the extracted bitumen without an impractically high pressure driving force for the draining fluids. On the other hand, if the bitumen extraction rate is too slow then this process may take too long to be of commercial value. Therefore, an aspect of the present invention is to limit the overall bitumen extraction rate by selecting injection parameters such as injected solvent temperature, flowrate, water cut and solvent concentration to try to achieve optimum permeability, flowrate and/or conformance.
Further, the bitumen extraction rates will vary along the length and in between the wells, affected by heterogeneities in the reservoir, local temperature, pore velocity, and available interfacial surface area, among other things. Another aspect of the present invention is to determine and maintain the minimum solvent injection rate to avoid creating a viscous bitumen plug without sufficient solvent which plug may block the gravity drainage flow path. The minimum injection flow rate and corresponding solvent concentration may be determined by such means as using historical field performance data or reservoir simulation to ensure the bitumen extraction rate does not dominate the viscosity of the fluid traversing the well pair. The present invention comprehends setting the minimum solvent concentration based on the inter well bore region with lowest initial Ke such that the local bitumen extraction rate at initial reservoir temperature does not overwhelm the solvent and prevent adequate mobility of the fluids. Real time monitoring of the downhole conditions (either directly or indirectly) may also be used according to the present invention.
The minimum solvent concentration may determine the design pressure driving force or design pressure drop between the injector and producer wells. This design pressure drop may ensure a safe operating pressure below the fracture pressure for the reservoir while achieving the

-18-minimum flowrate through the lowest initial Ke regions to maintain the solvent concentration. The present invention comprehends applying a significant enough pressure drop between the wells to permit solvent to flow sufficiently through the lower permeability regions. Therefore, an aspect of the present invention is to manage the pressure difference between the injector and producer to ensure that low Ke regions receive a sufficient amount of solvent flow for more uniform conformance along the well length. The pressure drop maybe adjusted by an artificial lift device and by adding or removing make-up solvent from the circulation loop. An artificial lift system, if required, may accommodate an appropriate inter well pressure driving force to ensure a sufficient flowrate can be maintained across the effective permeability range seen during the process for the specific reservoir. The pressure driving force will naturally reduce once the volumetric limit on the artificial lift system is reached or if injection flowrate is reduced because the solvent concentration produced to surface is sufficiently high.
As the process of the present invention advances, the draw down pressure on the draining fluids may be monitored to prevent the flashing of solvent from the draining fluids in situ. An aspect of the present invention is to avoid creating a local condition in the near well bore area of a more viscous bitumen which has been partially solvent depleted by reason of the drawdown pressure, and thus can block the gravity drainage flow path.
Thus, the present invention provides for the control of the draw down to limit any unwanted local increases in bitumen viscosity due to reduced solvent concentrations in the draining bitumen. One way this may be addressed is to ensure a high concentration of replacement solvent by maintaining the liquid solvent injection pressure to ensure that more solvent will be available to re-dilute the bitumen. Another way to control this is to monitor the draw down pressure to ensure that this condition can be limited or avoided. Yet another way to control this is to ensure the producer pressure is sufficiently above the

-19-bubble point pressure of the working fluid. A higher draw down pressure may be used initially to remove mobile water, before the draining bitumen has reached the production well bore.
The next aspect of the present invention takes advantage of the inverse relationship between viscosity and extraction rate by increasing the temperature of the injected solvent. It is advantageous to keep the various drainage paths along the length of the horizontal well pair at close to the same temperature to minimize preferential drainage path development, since the Nenniger-Dunn correlation implies a high sensitivity of bitumen extraction mass flux rate to temperature. Hotter drainage paths that undergo much higher rates of extraction will advance in effective permeability much faster than colder paths, thereby making the attainment of widespread, uniform conformance more difficult. There is also the risk that drainage paths in the low Ke regions may become blocked due to a high concentration of bitumen and not enough solvent in the drainage path to reduce the viscosity and adequately mobilize the extracted bitumen. Such a blocked path also adversely affects effective heat transfer since the solvent will have a reduced ability to flow through the lower permeability areas.
Therefore, another aspect of the present invention is to increase the temperature of the injected liquid solvent slowly, possibly by a surface or downhole heater, such that the difference between the injector and producer are kept within a limit of at least about 20 to 30 C, preferably lower such as to 20 C and while remaining below the temperature of bulk bitumen mobility, which is typically 40 to 70 C for Athabasca oil sands. These values may vary according to the native permeability of the reservoir.
Another aspect of the present invention is the nature of the temperature monitoring. In one embodiment the temperature might be the average downhole temperature of the injected fluid and the production fluids.
However, a more distributed temperature measurement is preferred, with

-20-temperature being measured at various points along the length of the horizontal wells. In that case a periodic temperature fall-off test can be conducted to identify development in conformance in both the injector and producer wells. In such a test fluid circulation through the producer may be stopped and the temperature monitored along the length of the producer.
Over time the temperature reading may trend towards the adjacent formation temperature. In this way an area of higher permeability can be identified by a slower temperature fall-off, due to higher thermal inertia generated from higher convective heat transfer, just as areas which are still blocked can be identified by a faster temperature fall-off. The shut in period for this test can vary, from 12 to 24 hours or more and time required may be determined by the rate of change of the temperature trends.
A gradual temperature rise may effect a gradual rise in the oil concentration in the produced fluids due to the temperature effect on bitumen viscosity and extraction rate. Going back to Figure 2, the produced fluids will contain working solvent, oil, displaced water and solution or formation gases.

The water may be separated in the surface plant FWKO 102, while the solvent and solution gases may be separated from the oil by the flash system 104, 106. The solution gases may be recovered as fuel 126, which may for example be used to heat or reheat the circulating solvent. The solvent may be purified in the distillation system 108 for circulation back to the injector. To maintain the pressure difference between a well pair, make-up working solvent 112 may be added or removed from the circulation loop as the drainage paths between the wells begin to expand and merge and the amount of pay hydrocarbon produced increases.
Figure 3 shows the different stages of a start-up procedure according to one embodiment of present invention. The x-axis 200 represents four stages in the chamber development, while the y-axis 202 plots changes in various parameters during the start-up. At the bottom, line 214 represents the

-21-pressure drop between the injector and producer, which is initially high to help distribute the injected fluid across the inter well bore region, but may be decreased as the effective permeability of the inter well pay region increases and drainage paths begin to merge and expand.
At the top, line 204 represents the temperature of the fluid injected into the well, which starts at or near the native reservoir temperature and is gradually increased through all stages until reaching the bubble point temperature of the pure solvent at the end of Stage IV, at which point, injection of the working solvent as vapour and the chamber growth phase of the process may begin.
Line 206 represents the water cut of the produced fluids from the well, which is high in Stage I as the lower viscosity, high relative permeability free water is displaced by the working solvent. The water cut will start to decrease, shown at Stage II, as more bitumen is mobilized through solvent contact and drains through narrow paths formed between the injector and producer. Accordingly, the cumulative oil production shown with line 208 will rise in Stage II at a higher rate. The produced fluids are processed in the surface plant to recover the product oil and purify the solvent for injection back into the well. As the drainage paths through the formation expand, make-up solvent may be added to the circulation loop to maintain the pressure drop between the injector and producer 214, as well as the required flow through the pump.
Initially, the injected fluid is substantially pure liquid working solvent, however, as the water cut 206 and pressure drop between the injector and producer 214 decrease, it may be advantageous to reduce the amount of working solvent in the circulation loop and allow some of the produced fluids, that is, oil and/or water, to recirculate through the wells. This is shown in Stage III. Water has a higher heat capacity than liquid solvent, therefore allowing more water in the injected fluid can transfer more heat to the

-22-formation at the same pressure. Further, adding water and pay hydrocarbon to the solvent liquid being injected through the inter well bore region may increase the viscosity of the injected fluids, helping to maintain the pressure differential between the injector and producer for effective distribution of fluids and improve overall mobilization of hydrocarbons from the gravity drainage flow path.
Line 210 represents the temperature difference between the injector and producer wells. This temperature difference may be kept at a minimum within a band of about no more than 30 C, preferably within a band 5 C to 20 C and most preferably within a band of 10 C to 20 C to encourage a uniform extraction front for more uniform extraction and mobilization of hydrocarbons within the inter well bore area. As can now be understood as the formation warms, the liquid fluids reaching the production well will be raised in temperature. As this temperature rises, the injection temperature can also be increased but may be limited by the desired temperature bands described above.
Line 212 represents the centreline temperature of the inter well bore region, located equidistant from the injector and producer (16 on Figure 1).
This temperature will rise slowly with the injected fluid temperature in Stage I
and II, but may increase more rapidly in Stage III with the introduction of high heat capacity produced fluids to the injected fluid.
Stage III should end as the injected fluid temperature 204 approaches the bubble point temperature of the pure working solvent. In Stage IV, the circulation of produced fluids is stopped, while heated working solvent continues to be injected to prepare the chamber for vapour solvent injection.
The pressure drop between the injector and producer 214 will establish the preferred pressure conditions for the production phase (not shown) and the centreline temperature is at the bubble point of the pure working solvent by the end of Stage IV.

-23-To accommodate circulation of produced fluids depicted in Stage Ill, the present invention comprehends having one or more bypass streams from the surface plant back to the injector well, including one after the FWKO. The bypass is preferably after the FWKO, because the water that is circulated is preferably emulsified in oil to prevent it from easily fingering back into the reservoir upon reinjection. Figure 4 shows the surface plant as defined in Figure 2, with the added feature of a suitable by-pass 124 for this aspect of the invention.
Operators monitor the solvent flow and oil production rate, fall-off test well bore temperature profiles, the pressure drop across the injector and producer, fluid properties, and tracer residence time to determine conformance through the different stages of the initial hydrocarbon mobilization procedure. Once conformance targets are satisfied, the solvent may be transitioned to a vapour at the production temperature (e.g. 40-70 C) at which point, the removal of hydrocarbons from the inter well bore area is completed and the chamber growth above the wells, through the use of a condensing solvent process for example, can commence.
A further aspect of the present invention is to maintain high enough solvent concentrations within the formation so as to create de-asphalting conditions. Typically, de-asphalting solvent concentrations range from, but are not limited to, 50-100% by volume. Unlike the prior art, the present process takes advantage of the phenomenon that asphaltene particles which are precipitated within the formation will remain relatively immobile and stuck to the sand grains which surround them. This deposition of asphaltene particles favours highly de-asphalting conditions and requires the use of a de-asphalting solvent, such as propane, butane or pentane, and their isomers and the like, and in high enough local concentrations to have the de-asphalting effect. This effect may also be referred to as in situ upgrading.
According to an aspect of the present invention the in situ upgrading

-24-may also help to counter the variations in Ke of a reservoir as bitumen is extracted. Regions with initially higher Ke may experience a net decrease in Ke as asphaltene particles deposit in that region, thereby encouraging more de-asphalting solvent to flow to the initially lower Ke regions. This effect may moderate the span of Ke along the length of the well bore, to reduce channeling tendencies and improve overall conformance.
If the asphaltene content in the reservoir is particularly high or if the span of initial Ke is sufficiently large so as to make it a challenge to maintain the de-asphalting conditions, the present invention comprehends dosing the injected solvent, either continuously or preferably intermittently, with asphaltene solvents or dispersants to reduce the amount or affect the location of asphaltene deposition and consequent formation damage. In other words, the present invention comprehends using controlled asphaltene deposition as a permeability modifier to encourage consistent permeability and good conformance Evidence of in situ upgrading was found in the aforementioned core flood test. The unextracted core plugs were taken from an Athabasca reservoir that has about 17 wt% asphaltene in the oil phase. The oil production from the core stack was collected at intervals and the produced oil (after degassing and dewatering) was analysed for API, density and asphaltene content. Table 1 shows the oil sample analyses from the test and how they are comparable to the product oil produced at the nsolv0 demonstration plant. The low asphaltene content of the produced oil compared to the high content in the reservoir may indicate in situ upgrading.
The asphaltene concentration in all of the post-test core pieces was similar, indicating that the asphaltene particles likely precipitated and remained relatively immobile rather than concentrating and plugging the core stack in such a way as to prevent oil extraction. A trend of decreasing average pressure differential across the core stack was observed as the test

-25-progressed even though the liquid butane injection rate was held constant, which may be an indication of increasing fluid mobility and/or effective permeability as required to establish a gravity drainage flow path.
One extrapolation of the oil extraction rate from this test to a 5 m commercial well pair with conservative limitations on solvent injection rates and pressures estimates that communication may be established with the present invention in the order of 100 days, which is a comparable amount of time required for the bulk displacement phase of prior art methods; however the present invention may be able to produce at, or near saleable grade product oil during this period and does not required the lengthy preheat phase required by prior art methods, which may be in the order of several months.
Table 1: Oil Analysis from Core Stack Test Temperature API , Density (15 C) Asphaltene of core kg/m3 Wt%
( C) (15 C) (absolute) relative in Oil Phase Sample 1 8 12.2 984 0.985 3.63 Sample 2 8 13.7 974 0.975 1.53 Sample 3 8 to 22 12.8 980 0.982 0.15 Sample 4 22 13.4, 975 0.976 0.17 Sample Average 13.0 978 0.979 1.37 nsolv Demonstration Plant N/A 13.4 976 0.977 1.6 The physical test shows that a cold liquid de-asphalting solvent, such as butane, is able to extract upgraded oil at the low native reservoir temperatures. The pressure drop that would be required to extract cold, high viscosity bitumen at such low temperatures would be much higher than what was possible in the test set-up, thus indicating the oil production was not due to bulk bitumen displacement. Instead, while not being restricted to a specific mechanism, the oil production may have been due to high bitumen-solvent contact surface area, allowing the solvent to quickly leach into the bitumen, reducing the viscosity of the mixture sufficiently to be mobilized.

-26-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.

Claims (34)

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

1. An in situ hydrocarbon mobilization process to create a gravity drainage flow path through a portion of a hydrocarbon rich formation, said process comprising the steps of:
injecting a solvent at a pressure sufficient for the solvent to remain a liquid at a first elevation in said hydrocarbon rich zone within the formation;
applying a drawdown pressure to said formation at a second elevation to remove mobile fluids from said formation at said second elevation;
monitoring a pressure difference between said first elevation and said second elevation and adjusting said pressure difference between said first elevation and said second elevation to distribute said liquid solvent between said first and second elevations;
continuing to inject said liquid solvent at said first elevation and monitoring the arrival of said liquid solvent at said second elevation;
gradually raising an injection temperature of said liquid solvent to reduce a viscosity of said in SVC/ hydrocarbons located between said first and second elevation and to mobilize the same; and monitoring fall-off temperature profiles at said first and second elevations to determine how complete a gravity drainage path exists between said first and second elevation.

2. The in 3112/ hydrocarbon mobilization process of claim 1 , wherein said process is applied to a vertical well.

3. The in silt/ hydrocarbon mobilization process of claim 1, wherein said process is applied to a substantially horizontal well pair.

4. The in situ hydrocarbon mobilization process of claim 3, wherein said first elevation is above said second elevation.

5. The 1/7 situ hydrocarbon mobilization process of claim 4, wherein said first elevation is between 3 and 5 meters above said second elevation.

6. The in situ hydrocarbon mobilization process of claim 1 , wherein said liquid solvent is capable of being used in a condensing solvent process in the formation.

7. The in situ hydrocarbon mobilization process of claim 6, wherein said liquid solvent is selected from the group of ethane, propane, butane, and pentane.

8. The in situ hydrocarbon mobilization process of claim 6, wherein said liquid solvent precipitates asphaltene particles in said formation.

9. The in situ hydrocarbon mobilization process of claim 8, wherein said asphaltene particles are relatively immobile.

10. The in situ hydrocarbon mobilization process of claim 1, wherein said pressure is supplied by a surface pump to said first elevation.

11. The in situ hydrocarbon mobilization process of claim 1, wherein said drawdown pressure is supplied by a downhole pump at said second elevation.

12. The in situ hydrocarbon mobilization process of claim 3, wherein said pressure monitoring is conducted along a length of said substantially horizontal well pair.

13. The in situ hydrocarbon mobilization process of claim 12, wherein said pressure monitoring provides a profile of a pressure drop along a length of said substantially horizontal well pair.

14. The in silt/ hydrocarbon mobilization process of claim 13, wherein said injection pressure is increased in the event said measured pressure drop profile along said substantially horizontal well pair becomes uneven.

15. The in silt/ hydrocarbon mobilization process of claim 3, wherein said temperature increase is applied after enough said liquid solvent has arrived at said second elevation to indicate general distribution of said liquid solvent along said substantially horizontal well pair.

16. The in silt/ hydrocarbon mobilization process of claim 1, wherein said injection temperature of said liquid solvent is increased by means of one or more of an above grade heater and a below grade heater.

17. The in situ hydrocarbon mobilization process of claim 1, wherein said step of gradually raising an injection temperature of said liquid solvent further comprises monitoring a production well temperature and keeping said injection temperature of said liquid solvent within a desired temperature band relative to said production well temperature.

18.The insiÉuhydrocarbon mobilization process of claim 17, wherein said temperature band is no more than 30 degrees C.

19. The in silt/ hydrocarbon mobilization process of claim 18, wherein said temperature band is between 5 and 20 degrees C.

20. The in situ hydrocarbon mobilization process of claim 1, wherein said temperature rise is controlled by measuring a downhole temperature of said production fluids and said injection fluids.

21. The in situ hydrocarbon mobilization process of claim 20, wherein said temperature rise is controlled by measuring a downhole temperature of said production fluids and said injection fluids at a plurality of locations along a length of said first and second elevations.

22. The in situ hydrocarbon mobilization process of claim 3, wherein said step of monitoring a temperature fall-off at said second elevation provides a temperature profile along a length of said substantially horizontal well pair to identify conformance of said formation along a length of said substantially horizontal well pair.

23. The in situ hydrocarbon mobilization process of claim 1, further comprising the step of installing one or more observation wells and monitoring a temperature profile between said first and second elevations in said formation.

24. The in situ hydrocarbon mobilization process of claim 1, further comprising the step of reducing an injection pressure and beginning injection of solvent vapour under condensing conditions.

25. An in situ hydrocarbon mobilization process comprising the steps of:
selecting a working solvent for a condensing in situ gravity drainage extraction process;
injecting said working solvent as a liquid to create a gravity drainage flow path to a production well through a portion of a hydrocarbon rich formation; and transitioning to condensing conditions with said liquid working solvent at or near an extraction interface within said formation, to create an extraction chamber above said gravity drainage flow path.

26. The in situ hydrocarbon mobilization process as claimed in claim 25, wherein said liquid working solvent is a liquid deasphalting working solvent.

27. The in situ hydrocarbon mobilization process as claimed in claim 25, wherein said step of injecting said working fluid as a liquid to create a gravity drainage path comprises the step of injecting the liquid working fluid at a first elevation and applying a drawdown pressure to said formation at a second elevation to remove mobile fluids from said formation at said second elevation.

28. The in situ hydrocarbon mobilization process as claimed in claim 27, wherein said first elevation is above said second elevation.

29. The In situ hydrocarbon mobilization process as claimed in claim 25, wherein during said step of injecting said working solvent as a liquid a temperature difference between an injection well at said first elevation and said production well is limited to a predetermined amount.

30. The in situ hydrocarbon mobilization process as claimed in claim 25, wherein during said step of injecting said working solvent as a liquid a pressure at an injection well at said first elevation is maintained above a pressure at said production well and a pressure in said production well is maintained above bubble point conditions for said liquid working solvent in a near well bore area.

31. A method of establishing conformance between a horizontal well pair located within a hydrocarbon bearing formation comprising the steps of:
injecting a liquid solvent into at least an inter well bore region;
and monitoring a permeability of the inter well bore region and selectively modifying an asphaltene deposition concentration along the inter well bore region between the well pair to reduce permeability in high permeability regions or increase permeability in low permeability regions by either adding or removing asphaltenes.

32. The method of claim 31, wherein the step of reducing permeability comprises injecting a de-asphalting fluid into at least said low permeability region.

33. The method of claim 31, wherein said step of increasing permeability comprises injecting an asphaltene dissolving fluid into at least said low permeability region.

34. The method of claim 1, 25 or 31, further comprising a first step of producing a higher concentration of water from the inter well bore region and then transitioning to a lower concentration of water in any produced fluid.