In situ process to recover heavy oil and bitumen

Abstract

An in situ reservoir recovery process consisting of a horizontal injection well and a horizontal production well to extract bitumen or heavy oil from a reservoir. The process consists of a first phase operated at high-pressure in which steam, hydrocarbon solvent and non-condensable gases are injected into the reservoir and a second phase in which the injected fluids are transitioned to a high content of solvent and non-condensable gas and a reduced amount of steam to maintain a warm zone in the neighbourhood of the injection and production wells. The steam injection is sufficient to promote vapor transport of the solvent into the vapor depletion chamber and maintain the process at elevated temperatures in order to maintain low fluid viscosities in the production wellbore and to achieve preferred phase behaviour of the solvent hydrocarbon and the heavy oil or bitumen. The operating pressure of the process is controlled to prevent losses of the solvent hydrocarbon to the formation and to aid in solvent production to the production well in order for future re-cycling.

Description

FIELD OF THE INVENTION

The present invention relates to a method to improve heavy oil and/or bitumen recovery from a hydrocarbon reservoir. The invention, in particular, relates to a process in which steam, solvent and non-condensable gas injection rates and pressure into an injection well are phased throughout the process to achieve improved thermal efficiency, mobilization of heavy oil and/or bitumen within the hydrocarbon reservoir and improved solvent recovery.

BACKGROUND OF THE INVENTION

There are many methods that are used to recover in situ heavy oil or bitumen from oilsands reservoirs. Typically, in situ methods are used in heavy oil or bitumen deposits that are greater than about 70 m deep where it is no longer economic to recover the hydrocarbon by current surface mining technologies. Depending on the operating conditions of the in situ process and the geology of the heavy oil or bitumen reservoir, in situ processes can recover between about 25 and 75% of the initial hydrocarbon in the reservoir. For most heavy oil or bitumen recovery processes, the focus of the process is to reduce the in situ viscosity of the heavy oil or bitumen so that its mobility rises to a sufficient amount so that it can flow from the reservoir to a production wellbore. The reduction of the in situ heavy oil or bitumen can be achieved by raising the temperature and/or dilution with solvent which is the typical practice in existing processes for recovering heavy oil or bitumen.

The Steam Assisted Gravity Drainage (SAGD), as described in U.S. Pat. No. 4,344,485, issued Aug. 17, 1982, to Butler, is a relatively popular in situ recovery method which uses two horizontal wells positioned in the reservoir to recover hydrocarbons. In this process, the two wells are drilled substantially parallel to each other by using directional drilling. The bottom well is the production well and is typically located just above the base of the reservoir. The top well is the injection well and is located roughly between 5 and 10 m above the production well. The top well injects steam into the reservoir from the surface. In the reservoir, the injected steam flows from the injection well and forms a vapor phase steam chamber that as the process evolves grows vertically until it reaches the top of the reservoir. The steam loses its latent heat to the cool heavy oil or bitumen at the edges of the steam chamber and as a result raises the temperature of the heavy oil or bitumen. The viscosity of the heated heavy oil or bitumen at the chamber edge drops and flows under gravity down the edges of the chamber towards the production wellbore located below the injection well. The fluids that enter the wellbore are moved, either by natural pressure forces or by pump, to the surface. The thermal efficiency of SAGD is reflected in the steam (expressed as cold water equivalent) to oil ratio (SOR) that is CWE m3 steam/m3 oil. Typically, a process is considered thermally efficient if its SOR is between 2 and 3 or lower. There is extensive published literature concerning the successful design and operation of SAGD. The literature reveals that while SAGD appears to be technically effective at producing heavy oil or bitumen to the surface, there is a continued need for processes that improve the SOR of SAGD. The major capital and operating costs of SAGD involve the facilities to generate steam and re-cycle produced water back to the steam generators. Additionally, there is a need to design processes that improve the capital and operating costs of SAGD.

An extension of SAGD is the Steam and Gas Push (SAGP) process developed by Butler (Thermal Recovery of Oil and Bitumen, Grav-Drain Inc., Calgary, Alberta, 1997). In the SAGP process, steam and a non-condensable gas are co-injected into the reservoir. It is believed that the non-condensable gas provides an insulating layer at the top of the steam chamber that improves the thermal efficiency of the process. At present, it remains unclear what the optimal amount of non-condensable gas that should be added to the injected steam.

Examples of published literature describing drainage rates for SAGD in field operations include: Butler (Thermal Recovery of Oil and Bitumen, Grav-Drain Inc., Calgary, Alberta, 1997), Komery et al. (Paper 1998.214, Seventh UNITAR International Conference, Beijing, China, 1998), Saltuklaroglu et al. (Paper 99-25, CSPG and Petroleum Society Joint Convention, Calgary, Canada, 1999), Butler et al. (J. Can. Pet. Tech., 39(1): 18, 2000).

There are other examples of the processes that use combinations of steam and solvents to recover heavy oil.

U.S. Pat. No. 4,519,454, issued May 28, 1985, to McMillen teaches what is essentially a cyclic thermal-solvent process which consists of first steam heating the reservoir to raise the temperature by 40-200° F. (22-111° C.) and second producing the reservoir fluids directly after heating. In the heating stage, the injection temperature is kept below the coking temperature. The production interval continues until steam production occurs after which liquid solvent is injected into the injection well so that an oil-solvent mixture is produced. At some point, steam injection re-commences and another cycle of the process starts.

Another example is seen in U.S. Pat. No. 4,697,642, issued Oct. 6, 1987, to Vogel which describes a steam and solvent flooding process in which steam and vaporized solvent are injected in a stepwise manner to lower the viscosity of in situ hydrocarbons to aid their production to the surface. Vogel teaches that the choice of solvent is not considered critical and suggests that the solvent should be a light, readily distillable liquid, such as gasoline, kerosene, naphtha, gas well condensates, benzene, toluene, distillates, that is miscible with the in situ hydrocarbons. There are two issues about this process: first the process uses high solvent to hydrocarbon ratio and second the solvents are typically more valuable than the produced hydrocarbon. Both of these issues adversely impact process economics.

In an extension of SAGD, Palmgren (SPE Paper 30294, 1995) describes a process where high temperature naphtha replaces steam in the SAGD process. However, given the value of naphtha, a substantial amount of the injected naphtha is required to be recovered for the process to be economic and compete with SAGD. A similar extension of SAGD which uses solvent, called Vapor Extraction (VAPEX), has been proposed as a commercial alternative to SAGD. VAPEX, similar to SAGD, consists of two horizontal wells positioned in the reservoir. The top well is the injection well whereas the bottom well is the production well. In VAPEX, a gaseous solvent (for example ethane, propane, or butane) is injected into the reservoir instead of steam. The injected solvent condenses and mixes with the heavy oil or bitumen and reduces its viscosity. Under the action of gravity, the mixture of solvent and bitumen flow towards the production well and are produced to the surface. Due to absence of steam generation and water handling facilities, capital costs associated with VAPEX facilities are lower than that of SAGD. However, it is unclear how interwell communication is to be established and how the process is to be operated in order to make the process economic. Also there are unresolved issues on how to prevent significant solvent losses to the reservoir which will be vitally important for economic success of the process. Additionally, the operating pressure range of VAPEX is limited because of required condensation of the injected gaseous solvent at the edges of the vapor chamber. In several papers, Butler and Mokrys (J. Can. Pet. Tech., 30(1): 97, 1991; J. Can. Pet. Tech., 32(6): 56, 1994) documented a version of VAPEX which uses hot water and solvent vapor, for example propane, near its dew point in an experimental Hele-Shaw cell to recover heavy oil. The solvent vapor fills the vapor chamber and at the chamber edges, the solvent dissolves into the heavy oil lowering the oil phase viscosity. The reduced-viscosity oil flows at the chamber edges to the production well located at the bottom of the formation. Butler and Mokrys, supra, describe that the solvent is co-injected with hot water to raise the reservoir temperature by between 4° and 80° C. The hot water also re-vaporizes some of the solvent from the heavy oil to create refluxing and additional utilization of the solvent. Butler, in U.S. Pat. No. 5,607,016, issued Mar. 4, 1997, to Butler, discloses a variant of VAPEX for recovering hydrocarbons in reservoirs that are located on top of an aquifer. A non-condensable displacement gas is co-injected with a hydrocarbon solvent at sufficient pressure to limit water ingress into the recovery zone. Butler and Jiang (J. Can. Pet. Tech., 39(1): 48, 2000) describe means to manage VAPEX in the field. In a paper, Luhning et al. (CHOA Conference, Calgary, Canada, 1999) describe the economics of VAPEX.

In a solvent-aided process, Canadian Patent No. 1,059,432 (Nenninger) discloses a method in which sub-critical solvent gas maintained just below its saturation pressure, such as ethane or carbon dioxide, is injected into the reservoir to lower the viscosity of heavy oil.

In U.S. Pat. No. 5,899,274, issued May 4, 1999, to Frauenfeld et al., a method is described that mobilizes heavy oil by using a vapor mixture of at least two solvents whose dew point corresponds to the reservoir temperature and pressure. The main concern with this process is that the solvent mixture has to be adjusted to fit the reservoir temperature and pressure.

Canadian Patent Number 2,323,029, issued Mar. 16, 2004, to Nasr et al., describes the Expanding Solvent-SAGD (ES-SAGD) method that comprises continuously co-injecting steam and an additive (one or a combination of C1 to C25 hydrocarbons and carbon dioxide) into the reservoir. The additive is chosen so that its saturation temperature is in the range of about ±150° C. of the steam temperature at the operating pressure. After injection, a fraction of the additive changes from vapor to liquid phase in the reservoir. This patent teaches that the additive concentration in the injected stream is between about 0.1% and about 5% liquid volume.

In Canadian Patent Number 2,325,777, issued May 27, 2003, to Gutek et al., a thermal-solvent process is disclosed called the Steam and Vapor Extraction Process (SAVEX). This process has two stages. First, steam is injected into an upper horizontal well until the top of the steam chamber is between about 25 to 75% of the distance from the injection well to the top of the reservoir or the production rate of hydrocarbons from the reservoir is about 25 to 75% of the peak rate anticipated from the SAGD process. Second, a solvent is injected in vapor phase into the steam chamber. The solvent helps to reduce the viscosity of the heavy oil or bitumen and permits additional recovery of heavy oil or bitumen.

Canadian Patent Application Number 2,391,721, issued Jun. 26, 2002, to Nasr, teaches a thermal-solvent process, referred to as the Tapered Steam and Solvent-SAGD (TSS-SAGD) process, in which a steam and/or hot water and a solvent (C1 to C30 hydrocarbons, carbon dioxide; carbon monoxide and associated combinations) is injected into the heavy oil reservoir. Initially, the injectant composition has steam and water-to-solvent volume ratio greater than or equal to about 1. As the process evolves, the steam and water-to-solvent volume ratio is lowered, at least once, to a different steam and water-to-solvent volume ratio greater than or equal to about 1. The injected volume ratio of steam and liquid water-to-solvent is reduced as the process evolves.

The literature contains many examples of attempts to recover in situ heavy oil or bitumen economically yet there is still a need for more thermally-efficient and cost-effective in situ heavy oil or bitumen recovery technologies. The present invention provides a method to recover heavy oil and/or bitumen from an underground reservoir in a manner that is more thermally efficient and cost effective than present methods.

SUMMARY OF THE INVENTION

The invention relates generally to a process to recover hydrocarbons from an underground reservoir.

One object of one embodiment of the present invention is to provide a method for recovering heavy hydrocarbons from an underground reservoir containing heavy hydrocarbons, an injection well and a production well, comprising injecting steam and optionally at least one of non-condensable gas and hydrocarbon solvent into the reservoir, receiving produced hydrocarbons within the production well, progressively adjusting the volume of the steam, the non-condensable gas and hydrocarbon solvent injected into the reservoir, whereby the hydrocarbon solvent and non-condensable gas are predominant relative to the volume of the steam, and recovering further produced heavy hydrocarbons.

In one embodiment of the invention, a method is provided to extract heavy oil or bitumen from a reservoir located underground. The reservoir is penetrated by a horizontal wellpair that comprise a top injection well and a bottom production well both being substantially parallel to each other. In the method, steam, solvent, and non-condensable gas are injected through the injection well into the reservoir over time while reservoir fluids are produced through the production well. The injected fluids enter a vapor chamber that surrounds and extends above the injection well. In the present invention, the injection rates and injection pressure are controlled in order to minimize heat losses to the overburden and maximize the action of the solvent in reducing the viscosity of the heavy oil and/or bitumen. Additionally, the operating pressure is controlled together with the relative amounts of steam, solvent, and non-condensable gas to maximize the solvent recovery from the process. The partial pressure of the solvent is controlled in the vapor chamber as the process is evolved.

The solvent may be a hydrocarbon solvent that consists of one or a combination of the C3+ hydrocarbons or any of the components that may normally be found in gas condensates or diluent. The non-condensable gas may include nitrogen gas, natural gas methane, carbon dioxide, or the flue gas that results from the combustion of a fuel.

The recovery method may include the additional step of adjusting the injection pressure and relative amounts of steam, solvent, and non-condensable gas to control the vapor chamber temperature to enhance the solubility of solvents.

In an embodiment, the method may include recovering additional solvent and heavy oil or bitumen from the reservoir during a blowdown stage at the end of the process.

A further object of one embodiment of the present invention is to provide a method for recovering heavy hydrocarbons from an underground reservoir containing heavy hydrocarbons, an injection well and a production well, comprising injecting steam into the reservoir, to form a steam vapor chamber, co-injecting predetermined quantities of steam, hydrocarbon solvent and non-condensable gas into the steam vapor chamber to maximize the solubility of the solvent in the heavy hydrocarbons, recovering produced hydrocarbons through the production well, adjusting the volume of steam injected into the vapor chamber to be subordinate to the volume of hydrocarbon solvent and non-condensable gas whereby partial pressure of the steam in the chamber is reduced and hydrocarbon solvent solubility is elevated in the heavy hydrocarbons, and recovering further produced hydrocarbons through the production well.

Having thus generally described the invention, reference will now be made to the accompanying drawings illustrating preferred embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a side view of a reservoir and horizontally drilled wells during the initial start up phase of the process;

FIG. 1B is a cross-section of FIG. 1A;

FIG. 2 is a graph showing a sample injection profile conforming to the process;

FIG. 2A is a graph showing a sample injection pressure profile conforming to the process;

FIG. 3A is a side view of a reservoir and horizontally drilled wells during the second phase of the process;

FIG. 3B is a cross-section of FIG. 3A;

FIG. 4 is a graph of the energy requirements of the SAGD, ES-SAGD, and processes as indicated by the cumulative steam to oil ratio over the time of production;

FIG. 5 is a graphical representation comparing bitumen recovery of the SAGD, ES-SAGD, and processes as a function of time;

FIG. 6 is a graphical representation comparing cumulative solvent recovery of the ES-SAGD, and processes as a function of time.

Similar numerals denote similar elements.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

With reference to the Figures, a phased heating and solvent enhanced recovery process for recovery of in situ bitumen or heavy oil is described. Broadly, the invention consists of a sequence of fluid injection and operating pressure changes that results in significantly improved heavy oil or bitumen production from a heavy oil or bitumen reservoir.

Heavy oil and bitumen is a more viscous material compared to light oils at in situ initial reservoir temperatures and pressures. Also, at elevated temperatures, heavy oil and bitumen has higher viscosity than lighter hydrocarbons such as solvent at the same temperature. At even more elevated temperatures, even though heavy oil and bitumen remains in liquid state, the solvent can be in the gaseous state and freely move throughout the reservoir providing there is a driving pressure gradient to motivate the solvent motion. The amount of solvent that can dissolve in heavy oil or bitumen depends on the reservoir temperature and pressure. There are two means to deal with the effectiveness of a heavy oil or bitumen solvent to produce heavy oil or bitumen to a production wellbore: first, the solvent must be chosen to substantially match the reservoir pressure and temperature to maximize its effectiveness in the targeted heavy oil or bitumen and second, change the operating conditions, i.e. the operating pressure and temperature, in order to control the solvent effectiveness in the heavy oil or bitumen. The temperature of the depletion zone from which heavy oil and bitumen are being extracted can be controlled by injecting saturated steam into the formation.

In gravity-drainage processes, there is a requirement to form a vapor chamber in the reservoir. This is to produce the density contrast between the vapor and liquid which allows the gravity-induced flow of liquid to the lower portion of the vapor chamber where a production well is located. The production well then removes the liquid from the chamber and carries it to the surface. The heavy oil and bitumen drains at the edges of the chamber, expanding the chamber in the reservoir. It is also required to expand the chamber to ensure that fresh heavy oil and bitumen is accessed by injected steam and solvent as the process evolves and to manage the operating pressure in the chamber so that solvent carried to the chamber edge mixes and dissolves in the heavy oil and bitumen so that the viscosity of the heavy oil and bitumen is reduced.

It should be noted that when referring to volumes of solvent, volumes are specified as the ratio of liquid hydrocarbon solvent to total liquid injected, and steam volume is expressed in terms of the volume of cold water required to produce the steam volume. In accordance with this invention, as shown in FIGS. 1A and 1B, a horizontal production well 10 is drilled into a reservoir 12 penetrating the surface of the earth 14 and the overburden 16. The reservoir 12 is bounded by the bottom of the overburden 16 and the top of understrata 18. Above the reservoir 12 is overburden 20 which consists of any one or more of shale, rock, sand layers, and other formations such as aquifers. A horizontal injection well 22, positioned several meters above in vertical alignment with a production well 24 is also drilled into the reservoir 12. In the present methodology, steam and solvent, injected through the injection well 22 into the reservoir 12, flow from the injection well 22 into a vapor chamber 26 which develops during this, surrounding the injection well 22. By injecting the fluids supra into the reservoir 12, heat and pressure are transmitted to the reservoir 12. The steam and solvent eventually reach the edge of the vapor chamber 26 and contact the virgin heavy oil or bitumen oil sand denoted by numeral 28. The steam releases its latent heat and the solvent dissolves into the oil, both of which reduce the viscosity of the heavy oil or bitumen which in turn, under the action of gravity, mobilizes the viscosity-reduced heavy oil or bitumen to flow to the production well 10 which carries it to the surface 14 by known techniques.

In FIG. 2, a typical injection and production profile for steam 30, solvent 32, and non-condensable gas 34 is displayed. At the start of the process, in stage 1, steam 30 is the major injectant flowing into the reservoir 12 from the injection well 22 that penetrates the reservoir 12. In stage 1, the vapor chamber 26 is created in the reservoir 12. Also, as shown in FIG. 2A, the injection pressure, 8 is maintained as sufficient to create the vapor chamber in the reservoir.

In stage 1, a small amount of solvent 32 or non-condensable gas 34 can be co-injected with the steam 30 but if desired, steam 30 can be injected alone into the reservoir 12 as is done in the SAGD process. After the steam chamber has formed, in stage 2, steam 30, solvent 32, and non-condensable gas 34 are injected together into the reservoir 12. One means of determining that a steam vapor chamber has formed is the requirement that continuous production of the heavy oil or bitumen is occurring and that the ratio of the cumulative injected steam (expressed as cold water equivalent) to cumulative heavy oil or bitumen production volume (this ratio is called the cumulative steam to oil ratio, cSOR) is under the value 4. This value of the cSOR implies that the heat from the injected steam is reaching the heavy oil or bitumen at the edges of the chamber and that the mobilized bitumen is flowing under gravity drainage to the production well.

The amounts of the steam 30, solvent 32, and non-condensable gas 34 and the injection pressure are chosen so that the solubility of the solvent in the heavy oil and bitumen 36 is maximized. The addition of the solvent improves heavy oil or bitumen mobilization beyond that only due to heating because it dissolves in the heavy oil or bitumen, dilutes the hydrocarbon phase, and reduces its viscosity so that it can readily flow to the production well 32. A further benefit of solvent 30 addition to the hydrocarbon phase is that it also dilutes the produced heavy oil or bitumen towards the specifications of fluid flow and density properties required for pipeline transport of the heavy oil or bitumen.

As the process evolves, the chamber 26 reaches the top of the reservoir and thereafter spreads laterally as shown in FIGS. 3A and 3B. As the chamber 26 grows, heat losses to the overburden 16 increase because the greater exposed area of the heated vapor chamber 26 to the colder overburden 16. To enhance the thermal efficiency of the recovery process, in stage 2, the steam 30 injection rate is lowered and the solvent 32 and non-condensable gas 34 injection rates are raised. The solvent 32 content in the injected fluids is between 1 and 80 volume percent, preferably between 10 and 30 volume percent. The extent of the vapor chamber 26 is maintained by the increasing volume of solvent 31 and non-condensable gas 32 injected into the reservoir 12.

Because the steam injection rate is reduced, the partial pressure of the steam in the vapor chamber 26 falls and as a result the corresponding saturation temperature of the steam drops and heat losses from the vapor chamber 26, in turn, are reduced because the temperature difference between the vapor chamber 26 and the overburden 16 is lowered. If the overburden 16 temperature is higher than the vapor chamber 26, then heat previously lost to the overburden 16 is harvested back to the vapor chamber. This improves the overall efficiency of the process. Furthermore, as the temperature of the vapor chamber 26 falls, the solubility of the solvent 32 increases in the heavy oil or bitumen 36. This leads to reduced viscosity of the heavy oil or bitumen 36 that would not have been possible without the solvent 32. Also, the addition of the non-condensable gas 34 helps to maintain or raise the operating pressure which also enhances the solubility of solvent 32 into the heavy oil or bitumen 36. The relative amounts of the solvent 32 and non-condensable gas 34 are chosen to maximize the effectiveness of the solvent to reduce the viscosity of the heavy oil or bitumen and can be chosen from thermodynamic pressure-volume-temperature (PVT) and viscosity calculations.

The amount of injected solvent 32 is such that only sufficient solvent is provided that is needed by the produced bitumen. This minimizes the build-up and storage of solvent 32 in the reservoir 12 which enhances the economic performance of the recovery process. As the process further evolves, the amount of solvent 32 and non-condensable gas 34 are reduced and con-currently, the injection pressure is reduced. This helps to promote production of the solvent 32 which enhances the economic efficiency of the process. At the end of the process, a blowdown stage (not shown) can be done to recover additional solvent and heavy oil or bitumen from the reservoir 12. Heavy oil or bitumen production from the production well is initiated during stage 1 and continues throughout the rest of the process.

As the process evolves, the injection rates and injection pressure is controlled to result in the most economical recovery of heavy oil or bitumen and solvent 32.

The solvent 32 preferentially consists of one or a combination of C3+ hydrocarbons, for example propane, butane, pentane, hexane, heptane, octane, nonane, and decane or any one or more components normally present in gas condensates or diluent. Preferably, the solvent 32 is hexane or heptane, or is a combination of C5 to C8 hydrocarbons including any of the components that may normally be present in gas condensates or diluent. The non-condensable gas 34 preferentially consists of C1 to C3 hydrocarbons, for example methane, ethane, and propane, natural gas, or other gases such as carbon dioxide or any one or more of the components normally present in the flue gas that results from combustion of a fuel to produce steam.

The solvent 32, non-condensable gas 34, and injection pressure are chosen so that the solvent 32 exist in substantially the vapor state at the conditions of the reservoir but so that the solubility of the solvent is maximized in the heavy oil or bitumen at the edges of the chamber 26.

Computer-aided reservoir simulation models can be used to predict pressure, oil, solvent, water, and gas production rates, and vapor chamber 26 dimensions to help design the injection strategy of the present invention. Also, the reservoir simulation calculations can be used to assist in the estimation of the length of stage 1 and 2 time intervals.

Given that the steam injection rate falls during the process, the process yields reduced capital and operating costs that arise from the activities surrounding steam 4 generation and water handling. Also, given that the solvent is introduced directly to the heavy oil or bitumen in the reservoir, there is inherent in situ upgrading depending on the temperature and pressure evolution of the process. Advantageously, due to solvent addition in the reservoir, the amount of diluent needed to transport the heavy oil or bitumen once it is on surface is reduced leading to reduced surface facilities requirements. Thus, the process delivers equal or more heavy oil or bitumen to currently known methods with higher thermal efficiency and economic performance. With reduced steam usage, the process also has less environmental pollution than current thermal recovery processes such as SAGD.

FIG. 4 is a plot that compares the cumulative steam to oil ratio (cSOR) from field scale numerical model predictions of the SAGD, ES-SAGD, and the process of the present invention processes. The cSOR is a measure of the thermal efficiency of the process and is closely correlated with the economic performance of the recovery processes. The cSOR SAGD results are typical of results found in current field operations. The results show that for the majority of the process life, the process of the present invention performance is substantially greater than that of the SAGD and ES-SAGD processes. FIG. 5 compares the cumulative oil produced (only contains oil component, no solvent) for the SAGD, ES-SAGD, and inventive processes. The results demonstrate that the process of the present invention produces more oil than the other processes. FIG. 6 displays a representation of the cumulative solvent recovery of the ES-SAGD and the instant processes. The results show that the injection rate and pressure strategy of the present process yields significantly higher solvent recovery and thus higher economic performance of the process.

The process operated as described has improved economic benefit with relatively high production at the start of the process, reduction of heat injection after the process starts to lose heat to the overburden to improve thermal efficiency of the process after the overburden is contacted, heated solvent injection to deliver diluted and possibly partially upgraded heavy oil or bitumen to the production wellbore, and high solvent re-cycling capability to improve the economics of the process.

The embodiment(s) of the invention described above is(are) intended to be exemplary only. The scope of the invention is therefore intended to be limited solely by the scope of the appended claims.

Claims

1. A method for recovering heavy hydrocarbons from an underground reservoir containing heavy hydrocarbons, an injection well and a production well, comprising:

a) injecting steam into said reservoir to form a steam vapor chamber;

b) co-injecting predetermined quantities of non-condensable gas, hydrocarbon solvent and steam into said steam vapor chamber to maximize solubility of the solvent in said heavy hydrocarbons;

c) recovering produced hydrocarbons within said production well;

d) controlling the volume of said steam vapor chamber by progressively adjusting the volume of said steam, said non-condensable gas and hydrocarbon solvent injected into said reservoir, whereby said hydrocarbon solvent and non-condensable gas are predominant relative to the volume of said steam; and

e) recovering further produced heavy hydrocarbons.

2. (canceled)

3. The method as set forth in claim 1, wherein in step c) reservoir pressure is progressively increased.

4. The method as set forth in claim 3, wherein reservoir temperature is progressively lowered

5. The method as set forth in claim 4, wherein solvent solubility in said heavy hydrocarbons is increased.

6. The method as set forth in claim 5, further including recovering said hydrocarbon solvent.

7. The method as set forth in claim 1, wherein said hydrocarbon solvent comprises an alkane selected from the group consisting of C3 through C8 alkanes and mixtures thereof.

8. The method as set forth claim 1, wherein said hydrocarbon solvent comprises an alkane derived from gas condensate.

9. The method as set forth in claim 1, wherein said hydrocarbon solvent comprises an alkane derived from gas diluent.

10. The method as set forth in claim 1, wherein said non-condensable gas comprises a gas selected from the group consisting of C1 through C3 hydrocarbons

11. The method as set forth in claim 10, wherein said non-condensable gas comprises carbon dioxide.

12. The method as set forth in claim 11, wherein said non-condensable gas comprises a gaseous component of flue gas.

13. The method as set forth in claim 1, wherein said non-condensable gas is selected from the group consisting of C1 through C3 alkane hydrocarbons, carbon dioxide, a component of flue gas, natural gas and combinations thereof.

14. A method for recovering heavy hydrocarbons from an underground reservoir containing heavy hydrocarbons, an injection well and a production well, comprising:

a) injecting steam into said reservoir, to form a steam vapor chamber;

b) co-injectinag predetermined quantities of steam, hydrocarbon solvent and non-condensable gas into said steam vapor chamber to maximize the solubility of the solvent in said heavy hydrocarbons;

c) recovering produced hydrocarbons through said production well;

d) determining the formation of said vapor chamber by calculating the ratio of cumulative injected steam to cumulative hydrocarbon production volume;

e) adjusting te volume of steam injected into said vapor chamber to be subordinate to the volume of hydrocarbon solvent and non-condensable gas whereby partial pressure of said steam in said chamber is reduced and hydrocarbon solvent solubility is elevated in said heavy hydrocarbons; and

f) recovering further produced hydrocarbons through said production well.

15. (canceled)

16. The method as set forth in claim 14, further including the step of selecting the quantity of steam, non-condensable gas and injection pressure to maximize the solubility of hydrocarbon solvent in said heavy hydrocarbons.

17. (canceled)

18. The method as set forth in claim 14, further including recovering said hydrocarbon solvent.

19. A method for recovering heavy hydrocarbons from an underground reservoir containing heavy hydrocarbons, an injection well and a production well, comprising:

a) injecting steam into said reservoir, to form a steam vapor chamber,

b) co-injecting predetermined quantities of steam, hydrocarbon solvent and non-condensable gas into said steam vapor chamber to maximize the solubility of the solvent in said heavy hydrocarbons, while controlling the volume of said vapor chamber;

c) recovering produced hydrocarbons through said production well;

d) adjusting the volume of steam injected into said vapor chamber to be subordinate to the volume of hydrocarbon solvent and non-condensable gas whereby partial pressure of said steam in said chamber is reduced and hydrocarbon solvent solubility is elevated in said heavy hydrocarbons; and

e) recovering further produced hydrocarbons through said production well.