WO2017197489A1 - Procédé de mobilisation d'hydrocarbures in situ et installation de surface pour ce dernier - Google Patents

Procédé de mobilisation d'hydrocarbures in situ et installation de surface pour ce dernier Download PDF

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Publication number
WO2017197489A1
WO2017197489A1 PCT/CA2017/000129 CA2017000129W WO2017197489A1 WO 2017197489 A1 WO2017197489 A1 WO 2017197489A1 CA 2017000129 W CA2017000129 W CA 2017000129W WO 2017197489 A1 WO2017197489 A1 WO 2017197489A1
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Prior art keywords
solvent
elevation
temperature
well
situ hydrocarbon
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PCT/CA2017/000129
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English (en)
Inventor
Mark Anthony EICHHORN
Cassandra Amanda LEE
Paul Krawchuk
Michel Alexander CANCELLIERE
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N-Solv Corporation
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Priority to CA3023470A priority Critical patent/CA3023470C/fr
Publication of WO2017197489A1 publication Critical patent/WO2017197489A1/fr

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/2607—Surface equipment specially adapted for fracturing operations

Definitions

  • 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.
  • 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.
  • 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.
  • an extraction chamber grows around and above the wells. In this sense an extraction 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.
  • 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.
  • draining liquid 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.
  • 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.
  • 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 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.
  • 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 and the heating elements themselves.
  • 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.
  • Nenniger and Dunn correlated the mass flux for oil production by solvent based gravity drainage to ( ⁇ ) " ° 5 , where ⁇ 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.
  • 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.
  • a process which is efficient in terms of capital expenditures is also desirable.
  • such a method may use the 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.
  • the present invention 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.
  • a process centreline temperature namely along the mid point between the two horizontal wells
  • 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.
  • 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.
  • 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.
  • 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 bitumen in high concentrations that may be too viscous to be mobile.
  • a gravity drainage flow path can be established between a horizontal well pair by, among other things,
  • 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 gravity flow drainage path that has been established and of the mobility of the fluid in the formation;
  • Temperature 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;
  • the present invention may use the same well pad configuration as 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.
  • the initial phase solvent is a hydrocarbon that is also the working hydrocarbon solvent intended for use in chamber growth in a later phase.
  • a solvent may be, for example propane, butane, pentane and the like.
  • 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.
  • 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.
  • water such as formation water
  • 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.
  • a portion of the formation fluids is circulated 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.
  • a method establishing conformance between a horizontal well pair located within a hydrocarbon bearing formation comprising the steps of:
  • 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.
  • 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.
  • 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.
  • 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 procedure according to the present invention.
  • Figure 4 is a flowchart of a surface plant showing the by-pass for 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 sands of Alberta, Canada.
  • 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 1 18 from the remaining produced fluids, at least one flash vessel (104, 106) to separate oil 1 16 from the solvent and a distillation column system 108 for purifying the solvent.
  • FWKO free water knock out vessel
  • Make-up solvent 1 12 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 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.
  • 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.
  • the working solvent that would be used for later chamber growth (e.g. propane, butane, or pentane) is begun.
  • 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.
  • 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
  • the K e 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 K e is dependent on local reservoir characteristics 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 K e , 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.
  • 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 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 K e 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.
  • bitumen 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 ⁇ ° 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 40 m 2 per m well length.
  • bitumen-solvent contact of about 68,000 m 2 per m well length.
  • 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.
  • 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.
  • the bitumen extraction rate may be controlled because if it occurs too fast, the fluids in the inter well bore region 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.
  • 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 K e 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 minimum flowrate through the lowest initial K e 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 K e 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 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.
  • 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.
  • 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 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 K e 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.
  • 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 5 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.
  • the temperature might be the average downhole temperature of the injected fluid and the production fluids.
  • a more distributed temperature measurement is preferred, with temperature being measured at various points along the length of the horizontal wells.
  • a periodic temperature fall-off test can be conducted to identify development in conformance in both the injector and producer wells.
  • 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.
  • 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.
  • make-up working solvent 1 12 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.
  • line 214 represents the 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.
  • 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.
  • 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 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the production temperature e.g. 40-70°C
  • a further aspect of the present invention is to maintain high enough solvent concentrations within the formation so as to create de-asphalting conditions.
  • de-asphalting solvent concentrations range from, but are not limited to, 50-100% by volume.
  • 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.
  • the in situ upgrading may also help to counter the variations in K e of a reservoir as bitumen is extracted. Regions with initially higher K e 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 K e regions. This effect may moderate the span of K e along the length of the well bore, to reduce channeling tendencies and improve overall conformance.
  • 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.
  • the present invention comprehends using controlled asphaltene deposition as a permeability modifier to encourage consistent permeability and good conformance

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

L'invention concerne un procédé de mobilisation d'hydrocarbures in situ, qui consiste : à sélectionner un solvant de travail pour un processus d'extraction par drainage par gravité in situ par condensation ; à injecter le solvant de travail sous la forme d'un liquide dans une formation contenant des hydrocarbures afin de créer un chemin d'écoulement de drainage par gravité s'étendant vers un puits de production à travers une partie de la formation ; et à passer dans des conditions de condensation in situ avec ledit solvant de travail à l'intérieur de ladite formation pour créer une chambre d'extraction au-dessus dudit chemin d'écoulement de drainage par gravité.
PCT/CA2017/000129 2016-05-19 2017-05-18 Procédé de mobilisation d'hydrocarbures in situ et installation de surface pour ce dernier WO2017197489A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
CA3023470A CA3023470C (fr) 2016-05-19 2017-05-18 Procede de mobilisation d'hydrocarbures in situ et installation de surface pour ce dernier

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
CA2930617A CA2930617A1 (fr) 2016-05-19 2016-05-19 Procede de mobilisation d'hydrocarbures sur place et installation de surface destinee audit procede
CA2,930,617 2016-05-19

Publications (1)

Publication Number Publication Date
WO2017197489A1 true WO2017197489A1 (fr) 2017-11-23

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PCT/CA2017/000129 WO2017197489A1 (fr) 2016-05-19 2017-05-18 Procédé de mobilisation d'hydrocarbures in situ et installation de surface pour ce dernier

Country Status (2)

Country Link
CA (2) CA2930617A1 (fr)
WO (1) WO2017197489A1 (fr)

Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7040400B2 (en) * 2001-04-24 2006-05-09 Shell Oil Company In situ thermal processing of a relatively impermeable formation using an open wellbore
US8776900B2 (en) * 2006-07-19 2014-07-15 John Nenniger Methods and apparatuses for enhanced in situ hydrocarbon production
US20160069171A1 (en) * 2014-09-08 2016-03-10 Suncor Energy Inc. In situ gravity drainage system and method for extracting bitumen from alternative pay regions

Patent Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7040400B2 (en) * 2001-04-24 2006-05-09 Shell Oil Company In situ thermal processing of a relatively impermeable formation using an open wellbore
US8776900B2 (en) * 2006-07-19 2014-07-15 John Nenniger Methods and apparatuses for enhanced in situ hydrocarbon production
US20160069171A1 (en) * 2014-09-08 2016-03-10 Suncor Energy Inc. In situ gravity drainage system and method for extracting bitumen from alternative pay regions

Also Published As

Publication number Publication date
CA3023470C (fr) 2019-06-25
CA2930617A1 (fr) 2017-11-19
CA3023470A1 (fr) 2017-11-23

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