CA3049597C

CA3049597C - Methods for vapor solvent flood bitumen recovery operations following thermal recovery processes

Info

Publication number: CA3049597C
Application number: CA3049597A
Authority: CA
Inventors: Jianlin Wang; Zhihong Liu; Nafiseh Dadgostar
Original assignee: Imperial Oil Resources Ltd
Current assignee: Imperial Oil Resources Ltd
Priority date: 2019-07-15
Filing date: 2019-07-15
Publication date: 2020-07-14
Anticipated expiration: 2039-07-15
Also published as: CA3049597A1; CA3081220A1; CA3081220C

Abstract

Methods of conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process are described herein. The methods include determining a temperature of the reservoir, injecting pressurizing fluid into a voidage formed in the reservoir during the thermal recovery process to increase a pressure of the reservoir; monitoring the pressure of the reservoir; and in response to the monitored pressure reaching a predetermined recovery pressure selected based on a determined temperature: injecting mobilizing fluid comprising vapor solvent into the reservoir, the vapor solvent having a liquid-vapor phase boundary proximate the determined temperature and the predetermined recovery pressure; and producing fluid comprising mobilized bitumen from the reservoir.

Description

METHODS FOR VAPOR SOLVENT FLOOD BITUMEN RECOVERY OPERATIONS
FOLLOWING THERMAL RECOVERY PROCESSES
FIELD
[0001] This disclosure relates generally to solvent-dominated recovery process operations, and more specifically to methods for promoting improved efficiency during solvent-dominated recovery processes in one or more underground reservoirs that have previously undergone a thermal recovery process.
BACKGROUND

[0002] Various systems and methods are known to extract hydrocarbons from subterranean formations, which also may be referred to herein as reservoirs and/or as underground reservoirs. Typically, a particular extraction process is selected based on one or more properties of the hydrocarbon and/or of the subterranean formation.

[0003] For example, hydrocarbons having a relatively lower viscosity and extending within relatively higher fluid permeability subterranean formations (which may be characterized as conventional hydrocarbons) may be pumped from the subterranean formation utilizing a conventional oil well.

[0004] However, conventional oil wells may be ineffective (or at least economically ineffective) at producing hydrocarbons having a relatively higher viscosity and/or extending within relatively lower fluid permeability subterranean formations (which may be characterized as unconventional hydrocarbons). Examples of unconventional hydrocarbon production techniques that may be utilized to produce viscous hydrocarbons from an underground formation include thermal recovery processes and solvent-dominated recovery processes.

[0005] Thermal recovery processes generally inject a thermal recovery stream, at an elevated temperature, into the subterranean formation. The thermal recovery stream contacts the viscous hydrocarbons within the subterranean formation, and heats, dissolves, and/or dilutes the viscous hydrocarbons, thereby generating mobilized viscous hydrocarbons. The mobilized viscous hydrocarbons generally have a lower viscosity than a viscosity of the naturally occurring viscous hydrocarbons at the native temperature and pressure of the subterranean formation and may be pumped and/or flowed from the subterranean formation. A variety of different thermal recovery processes have been utilized, including cyclic steam stimulation (CSS) processes, liquid addition to steam to enhance recovery (LASER) processes, steam flooding processes, solvent-assisted steam flooding processes, steam-assisted gravity drainage (SAGD) processes, solvent-assisted steam-assisted gravity drainage (SA-SAGD) processes, heated vapor extraction (VAPEX) processes, and/or near-azeotropic gravity drainage processes.

[0006] Thermal recovery processes may differ in the mode of operation and/or in the composition of the thermal recovery stream. However, all thermal recovery processes rely on injection of the thermal recovery stream into the subterranean formation at an elevated temperature, and thermal contact between the thermal recovery stream and the subterranean formation to heat the subterranean formation. Thus, after performing a thermal recovery process within an underground formation, a significant amount of thermal energy may be retained within the subterranean formation.

[0007] During a thermal recovery process, as the viscous hydrocarbons are produced from the subterranean formation, an amount of energy required to produce viscous hydrocarbons typically increases due to increased heat loss within the subterranean formation. Similarly, a ratio of a volume of the thermal recovery stream provided to the subterranean formation to a volume of mobilized viscous hydrocarbons produced from the subterranean formation also typically increases. Both of these factors decrease economic viability of thermal recovery processes late in the life of a hydrocarbon well and/or after production and recovery of a significant fraction of the original oil-in-place from a given subterranean formation.

[0008] Also, as thermal recovery processes (such as CSS and SAGD) reach a late-life' period (e.g. as the reservoir becomes increasingly depleted), pressure communication may be established between neighboring wells or well pairs. In such situations, the recovery operation is usually transitioned to a continuous, lower-pressure flooding operation. For example, steam flood has been adopted as an effective follow-up process to CSS for continued recovery of bitumen at much lower pressure (e.g.
1-3 MPa).

[0009] During a steam flood process, thermal energy introduced into the reservoir (e.g. via a continuous injection of steam) is distributed into bitumen, sand, overburden, and under burden. As the reservoir depletion continues, the fraction of the injected thermal energy that enters bitumen becomes less, and thermal efficiency, e.g.
as measured by the produced oil to injected steam ratio (OSR) becomes lower.
Steam flood is a stable process that can last for decades and can increase the oil recovery factor from about 30-40% to up to about 60-80%. Typically, the steam flood process continues until the oil production no longer justified the steam injection, e.g. the OSR
reaches a certain economic cut-off.

[0010] Overall, a steam flood process may be characterized as an energy-intensive process, particularly during the later stage during which the OSR continues declining (e.g.
to less than 0.2) due to reservoir depletion and heat loss. To reduce the energy intensity, a different process may be used to enhance or replace steam flooding. Reducing the energy intensity by using a different process to enhance or replace steam flooding may have one or more advantages. For example, green-house-gas (GHG) emissions may be reduced.

[0011] For example, the steam flood may be transitioned to a solvent-assisted steamflood (SA-Steamflood) or a solvent flood process. SA-Steamflood is a follow-up or enhancement process for steam flood by adding a solvent composition to the injected steam (e.g. co-injecting steam and solvent) to improve bitumen uplift and/or reduce steam intensity. Solvent flood is a process that involves the injection of a solvent composition instead of steam. Solvent flood may be characterized as a solvent-dominated recovery process (SDRP). Solvent-dominated means that the injectant comprises greater than 50 percent ( /0) by mass of solvent or that greater than 50% of the produced oil's viscosity reduction is obtained by chemical solvation rather than by thermal means.

[0012] Solvent, such as a low boiling point range solvent (e.g. C3, C4) may be injected as vapor into the depleted reservoir, as described in Canadian Patent No.
2,974,712. The key mechanism of vapor solvent flood is that solvent vapor condenses when contacting relatively cold bitumen (typically at a boundary of the depleted chamber), reducing the bitumen viscosity and allowing it to flow toward a producer wellbore via gravity drainage (see Figure 1).

[0013] However, there are a number of challenges associated with applying vapor solvent flood with light solvent as a follow-up process to thermal operations, with one key challenge being achieving a low solvent utilization as a significant problem in the prior art is that a majority of the solvent stays in vapor phase at the pressure and the temperature that the process is operated. The prior art discusses the broad concept of solvent flood, but does not disclose how to operate or modify the processes of conventional solvent flood processes to make these operations work more effectively and efficiently in the field.
SUMMARY

[0014] The following introduction is provided to introduce the reader to the more detailed discussion to follow. The introduction is not intended to limit or define any claimed or as yet unclaimed invention. One or more inventions may reside in any combination or sub-combination of the elements or process steps disclosed in any part of this document including its claims and figures.

[0015] In accordance with one broad aspect of this disclosure, there is provided a method for conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process, the method comprising: determining a temperature of the reservoir;
injecting pressurizing fluid into a voidage formed in the reservoir during the thermal recovery process to increase a pressure of the reservoir; monitoring the pressure of the reservoir;
and in response to the monitored pressure reaching a predetermined recovery pressure selected based on the determined reservoir temperature: injecting mobilizing fluid comprising vapor solvent into the reservoir, the vapor solvent having a liquid-vapor phase boundary proximate the reservoir temperature and the predetermined recovery pressure;
and producing fluid comprising mobilized bitumen from the reservoir.

[0016] In some embodiments, the vapor solvent in the mobilizing fluid comprises a C2-C7 hydrocarbon, a C2-C4 natural gas liquid, a natural gas condensate, a naphtha product, or an ether.

[0017] In some embodiments, the vapor solvent in the mobilizing fluid consists primarily of C3 to C4 hydrocarbons.

[0018] In some embodiments, the mobilizing fluid comprises a mixture of vapor solvent and steam.

[0019] In some embodiments, the pressurizing fluid comprises at least one of methane, carbon dioxide, flue gas, and gas produced during the thermal recovery process.

[0020] In some embodiments, the pressurizing fluid consists primarily of non-condensable gas.

[0021] In some embodiments, the pressurizing fluid comprises at least one of non-condensable gas and propane vapor.

[0022] In some embodiments, the temperature of the reservoir is in a range of about 20 C to about 180 C.

[0023] In some embodiments, the pressure of the reservoir is in a range of about 500 kPa to about 3 MPa.

[0024] In accordance with another broad aspect of this disclosure, there is provided a method for conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process, wherein the reservoir is at an elevated temperature due to the thermal recovery process, the method comprising: injecting thermal recovery fluid into a voidage formed in the reservoir during the thermal recovery process, the thermal recovery fluid being injected at a temperature below the elevated temperature of the reservoir;
producing fluid from the reservoir, the produced fluid primarily comprising thermal recovery fluid at a temperature greater than the temperature at which it was injected;
determining a reservoir pressure of the voidage; monitoring the temperature of the reservoir; and in response to the temperature of the reservoir reaching a predetermined recovery temperature: injecting mobilizing fluid comprising vapor solvent into the reservoir, the vapor solvent having a liquid-vapor phase boundary proximate the temperature of the reservoir and the reservoir pressure; and producing fluid comprising mobilized bitumen from the reservoir.

[0025] In some embodiments, the vapor solvent in the mobilizing fluid comprises a 02-C7 hydrocarbon, a C2-C4 natural gas liquid, a natural gas condensate, a naphtha product, or an ether.

[0026] In some embodiments, the vapor solvent in the mobilizing fluid consists primarily of C3-C4 hydrocarbons.

[0027] In some embodiments, the thermal recovery fluid primarily comprises water.

[0028] In some embodiments, the predetermined recovery temperature is selected based on the determined reservoir pressure.

[0029] In some embodiments, the method further includes, prior to injecting mobilizing fluid, ceasing injection of thermal recovery fluid.

[0030] In some embodiments, the temperature of the reservoir is in a range of about 20 C to about 180 C.

[0031] In some embodiments, the pressure of the reservoir is in a range of about 500 kPa to about 3 MPa.

[0032] In accordance with another broad aspect of this disclosure, there is provided a method for conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process, the method comprising: determining a temperature of the reservoir;
injecting mobilizing fluid comprising vapor solvent into a voidage formed in the reservoir during the thermal recovery process while restricting production from the reservoir to increase a pressure of the reservoir; monitoring the pressure of the reservoir; and in response to the monitored pressure reaching a predetermined recovery pressure:

producing fluid comprising mobilized bitumen from the reservoir, wherein fluid is produced at a rate sufficient to maintain the pressure of the reservoir at the predetermined recovery pressure; wherein the vapor solvent has a liquid-vapor phase boundary proximate the reservoir temperature and the predetermined recovery pressure.

[0033] In some embodiments, the vapor solvent in the mobilizing fluid comprises a C2-C7 hydrocarbon, a C2-C4 natural gas liquid, a natural gas condensate, a naphtha product, or an ether.

[0034] In some embodiments, the vapor solvent in the mobilizing fluid consists primarily of C3-04 hydrocarbons.

[0035] In some embodiments, the mobilizing fluid comprises a mixture of vapor solvent and steam.

[0036] In some embodiments, the method further includes, while producing fluid comprising mobilized bitumen from the reservoir: co-injecting a pressurizing fluid into the reservoir to maintain or increase the reservoir pressure.

[0037] In some embodiments, the pressurizing fluid comprises at least one of methane, carbon dioxide, flue gas, and gas produced during the thermal recovery process.

[0038] In some embodiments, the pressurizing fluid consists primarily of non-condensable gas.

[0039] In some embodiments, the predetermined recovery pressure is selected based on a determined temperature.

[0040] In some embodiments, restricting production from the reservoir comprises restricting gas production while permitting liquid production.

[0041] In some embodiments, fluid is produced at a rate that is less than about 80%, or less than about 90%, or less than about 95% of a rate of recovery mobilizing fluid injection.

[0042] In some embodiments, fluid is being produced, mobilizing fluid is injected at an injection pressure greater than 110% of the predetermined recovery pressure.

[0043] In accordance with another broad aspect of this disclosure, there is provided a method for performing a solvent-dominated recovery process in an underground reservoir that has previously undergone a thermal recovery process, the solvent-dominated recovery process being a vapor flooding process. The method includes injecting mobilizing fluid comprising vapor solvent into a voidage formed in the reservoir during the thermal recovery process via a first wellbore; producing fluid comprising mobilized bitumen from the reservoir via a second wellbore, the second wellbore being different than the first wellbore; and while producing fluid: injecting non-condensable gas into the reservoir.

[0044] In some embodiments, the vapor solvent in the mobilizing fluid comprises a C2-C7 hydrocarbon, a C2-C4 natural gas liquid, a natural gas condensate, a naphtha product, or an ether.

[0045] In some embodiments, the vapor solvent in the mobilizing fluid consists primarily of C3-C4 hydrocarbons.

[0046] In some embodiments, the mobilizing fluid comprises a mixture of vapor solvent and steam.

[0047] In some embodiments, the non-condensable gas comprises at least one of methane, carbon dioxide, flue gas, and gas produced during the thermal recovery process.

[0048] In some embodiments, mobilizing fluid and non-condensable gas are co-injected.

[0049] In some embodiments, non-condensable gas comprises between 1% and 20% on a molar basis of the co-injected fluid.

[0050] In some embodiments, mobilizing fluid and non-condensable gas are alternately injected into the reservoir.

[0051] In some embodiments, mobilizing fluid is injected via the first wellbore used during the thermal recovery process, wherein fluid is produced via the second wellbore used during the thermal recovery process, and non-condensable gas is injected into the reservoir via a third wellbore completed subsequent to an initial phase of the thermal recovery process.

[0052] In some embodiments, injecting non-condensable gas into the reservoir includes injecting non-condensable gas into the reservoir via a vertical wellbore.

[0053] In some embodiments, injecting non-condensable gas into the reservoir includes injecting non-condensable gas into the reservoir via a horizontal wellbore.

[0054] In some embodiments, injecting non-condensable gas into the reservoir includes co-injecting the non-condensable gas into the reservoir with mobilizing fluid comprising vapor solvent.

[0055] In some embodiments, injecting non-condensable gas into the reservoir includes co-injecting the non-condensable gas into the reservoir with mobilizing fluid comprising vapor solvent through a same wellbore.

[0056] In some embodiments, injecting non-condensable gas into the reservoir includes co-injecting the non-condensable gas into the reservoir with mobilizing fluid comprising vapor solvent through separate wellbores.

[0057] In some embodiments, co-injecting the non-condensable gas into the reservoir with mobilizing fluid comprising vapor solvent through separate wellbores includes injecting the non-condensable gas into the reservoir at a first depth and injecting the mobilizing fluid comprising vapor solvent into the reservoir at a second depth, the second depth being different than the first depth.

[0058] In some embodiments, the non-condensable gas is injected into the reservoir nearer to atop of the reservoir than the mobilizing fluid comprising vapor solvent.

[0059] It will be appreciated by a person skilled in the art that a method or apparatus disclosed herein may embody any one or more of the features contained herein and that the features may be used in any particular combination or sub-combination.

[0060] These and other aspects and features of various embodiments will be described in greater detail below.
BRIEF DESCRIPTION OF THE DRAWINGS

[0061] Fora better understanding of the described embodiments and to show more clearly how they may be carried into effect, reference will now be made, by way of example, to the accompanying drawings in which:

[0062] Figure 1 is simplified schematic representation of examples of a hydrocarbon production system that may include and/or be utilized with methods, according to the present disclosure.

[0063] Figure 2 is a schematic cross-sectional view of the hydrocarbon productions system of Figure 1.

[0064] Figure 3 is another schematic cross-sectional view of the hydrocarbon productions system of Figure 1,

[0065] Figure 4 is another schematic cross-sectional view of the hydrocarbon productions system of Figure 1.

[0066] Figure 5 is a schematic cross-sectional view of a hydrocarbon production system showing a solvent bitumen interface zone;

[0067] Figure 6 is a phase diagram of an exemplary mobilizing fluid:
propane;

[0068] Figure 7 is a flowchart depicting methods, according to the present disclosure, for producing fluid comprising mobilized bitumen from an underground reservoir.

[0069] Figure 8 is a plot showing an exemplary vapor solvent operating window;

[0070] Figure 9 is a schematic cross-sectional view of a hydrocarbon production system showing NCG injection into an underground reservoir that has previously undergone a thermal recovery process;

[0071] Figure 10 is a schematic cross-sectional view of a hydrocarbon production system showing water injection into an underground reservoir that has previously undergone a thermal recovery process;

[0072] Figure 11 is a flowchart depicting additional methods, according to the present disclosure, for producing fluid comprising mobilized bitumen from an underground reservoir.
-10-.

[0073] Figure 12 is a flowchart depicting additional methods, according to the present disclosure, for producing fluid comprising mobilized bitumen from an underground reservoir.

[0074] Figure 13 is a flowchart depicting additional methods, according to the present disclosure, for producing fluid comprising mobilized bitumen from an underground reservoir.

[0075] Figure 14 is a plot showing injection and production pressures over time of a vapor solvent flood process for producing fluid comprising mobilized bitumen from an underground reservoir.

[0076] Figure 15 is a plot showing solvent injection and bitumen production rates of a system for producing fluid comprising mobilized bitumen from an underground reservoir.

[0077] Figure 16 is a plot showing propane vapor and liquid split in an underground reservoir undergoing a method for producing fluid comprising mobilized bitumen from an underground reservoir; according to one embodiment.

[0078] Figure 17 is a plot showing bitumen production rate over time for a method for producing fluid comprising mobilized bitumen from an underground reservoir utilizing gas co-injection, according to one embodiment.

[0079] The drawings included herewith are for illustrating various examples of articles, methods, and apparatuses of the teachings of the present specification and are not intended to limit the scope of what is taught in any way.
DESCRIPTION OF EXAMPLE EMBODIMENTS

[0080] Various apparatuses, methods and compositions are described below to provide an example of an embodiment of each claimed invention. No embodiment described below limits any claimed invention and any claimed invention may cover apparatuses and methods that differ from those described below. The claimed inventions are not limited to apparatuses, methods and compositions having all of the features of any one apparatus, method or composition described below or to features common to multiple or all of the apparatuses, methods or compositions described below.
It is possible that an apparatus, method or composition described below is not an embodiment of any claimed invention. Any invention disclosed in an apparatus, method or composition described below that is not claimed in this document may be the subject matter of another protective instrument, for example, a continuing patent application, and the applicant(s), inventor(s) and/or owner(s) do not intend to abandon, disclaim, or dedicate to the public any such invention by its disclosure in this document.

[0081] Furthermore, it will be appreciated that for simplicity and clarity of illustration, where considered appropriate, reference numerals may be repeated among the figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the example embodiments described herein. However, it will be understood by those of ordinary skill in the art that the example embodiments described herein may be practiced without these specific details. In other instances, well-known methods, procedures, and components have not been described in detail so as not to obscure the example embodiments described herein. Also, the description is not to be considered as limiting the scope of the example embodiments described herein.

[0082] As used herein, the wording "and/or" is intended to represent an inclusive -or. That is, "X and/or Y" is intended to mean X or Y or both, for example. As a further example, "X, Y, and/or Z" is intended to mean X or Y or Z or any combination thereof.

[0083] As used herein, the phrase "subterranean formation", or "subterranean reservoir" or "underground reservoir" may refer to any suitable portion of the subsurface region that includes viscous hydrocarbons and/or from which mobilized viscous hydrocarbons may be produced utilizing the methods disclosed herein. In addition to the viscous hydrocarbons, the subterranean reservoir also may include other subterranean strata, such as sand and/or rocks, as well as lower viscosity hydrocarbons, natural gas, and/or water. The subterranean strata may form, define, and/or be referred to herein as a porous media, and the viscous hydrocarbons may be present, or may extend, within pores of the porous media.

[0084] Terms of degree such as "about" and "approximately" as used herein mean a reasonable amount of deviation of the modified term such that the end result is not significantly changed. These terms of degree should be construed as including a deviation of at least 5% or at least 10% of the modified term if this deviation would not negate the meaning of the word it modifies. Similarly, terms such as "proximate" as used herein mean a reasonable deviation from a known value or variable. Again, these terms of degree should be construed as including a deviation of at least 5% or at least 10%
from the known value.

[0085] As used herein, the phrase, "viscous hydrocarbons" may refer to any carbon-containing compound and/or compounds that may be naturally occurring within the underground reservoir and/or that may have a viscosity that precludes their production, or at least economic production, utilizing conventional hydrocarbon production techniques and/or conventional hydrocarbon wells. Examples of such viscous hydrocarbons include heavy oils, oil sands, and/or bitumen.

[0086] Figure. 1 is a schematic representation of examples of a hydrocarbon production system 100 that may include and/or may be utilized with methods according to the present disclosure, such as methods 200, 300, 400 and 500 of Figures 7 and 11-13, respectively. Figures 2-4 are schematic cross-sectional views of hydrocarbon production system 10taken along plane P of Figure 1.

[0087] Turning to Figure 1, illustrated therein is a schematic representation of a hydrocarbon production system 100 that may include and/or be utilized with methods according to the present disclosure. Hydrocarbon production system 100 includes a plurality of spaced apart hydrocarbon wells 20. Each hydrocarbon well 20 includes a corresponding wellhead 22 and a corresponding wellbore 24. Wel!bores 24 extend within an underground reservoir 44 that includes viscous hydrocarbons 46, Wellbores 24 also may be referred to herein as extending within a subsurface region 42 and/or as extending between a surface region 40 of the underground reservoir 44.

[0088] System 100 may include any suitable number and/or combination of hydrocarbon wells 20. As an example, and as illustrated in solid lines in Figures 1-4, system 100 generally includes a first hydrocarbon well 31. As another example, and as illustrated in both dashed and solid lines in Figure 1 and in solid lines in Figures 2-4, system 100 also generally includes at least a second hydrocarbon well 32. As additional examples, and as illustrated in dash-dot lines in Figures 1-4, system 100 may include a third hydrocarbon well 33 and/or a fourth hydrocarbon well 34.

[0089] As discussed in more detail herein, it is within the scope of the present disclosure that system 100 additionally or alternatively may include a plurality of spaced-apart hydrocarbon wells 20 and that Figures 1-4 only may illustrate a subset, or fraction, of the plurality of spaced-apart hydrocarbon wells 20. As examples, system 100 may include at least 2, at least 4, at least 6, at least 8, at least 10, at least 15, at least 20, at least 30, or at least 40 spaced-apart hydrocarbon wells 20.

[0090] Methods 200, 300, 400 and 500 may be configured to be performed, such as utilizing system of Figures 1-4, subsequent to one or more thermal recovery processes being performed by system 100. An example of such thermal recovery processes includes a single-well thermal recovery process in which a single hydrocarbon well 20 is utilized to cyclically provide a thermal recovery stream to the underground reservoir 44 and receive a mobilized viscous hydrocarbon stream from the underground reservoir 44.
Examples of single-well thermal recovery processes include cyclic steam stimulation and solvent-assisted cyclic steam stimulation. An example of such a single-well thermal recovery process is illustrated in Figures 2-4.

[0091] In a single-well thermal recovery process, system 100 may include two spaced-apart hydrocarbon wells 20, such as first hydrocarbon well 31 and second hydrocarbon well 32. As illustrated in Figure 2, first hydrocarbon well 31 may be utilized to inject a first thermal recovery stream 52 into the underground reservoir 44, and second hydrocarbon well 32 may be utilized to inject a second thermal recovery stream 62 into the underground reservoir 44. The thermal recovery streams may be injected for corresponding injection times. Subsequently, and as illustrated in Figure 3, injection of the thermal recovery streams may cease, first hydrocarbon well 31 may be utilized to produce a first mobilized viscous hydrocarbon stream 54 from the underground reservoir 44, and second hydrocarbon well 32 may be utilized to produce a second mobilized viscous hydrocarbon stream 64 from the underground reservoir 44. This cycle of injection and production may be repeated any suitable number of times.

[0092] The single-well thermal recovery process that is performed utilizing first hydrocarbon well 31 may produce and/or generate a first thermal chamber 50 within the underground reservoir 44. Similarly, the single-well thermal recovery process that is performed utilizing second hydrocarbon well 32 may produce and/or generate a second thermal chamber 60 within the underground reservoir 44. Ideally, the first thermal chamber 50 and the second thermal chamber 60 will not have any fluid communication between them. As such, in the early stages of well operation, these chambers and associated processes and process conditions (such as temperature, pressure, injection rates, injection compositions) may be operated and controlled completely independently of one another. However, over time, the first thermal chamber 50 and second thermal chamber 60 may grow, expand, and/or increase in volume over an operational lifetime of system 100 and/or responsive to repeated cycles of injection and subsequent production.
Eventually, and as illustrated in Figure 4, fluid communication may be established between the first thermal chamber and the second thermal chamber, such as at an interface region 70 therebetween. Such a configuration of thermal chambers in fluid communication with each other also may be referred to herein collectively as a communicating thermal chamber 80.

[0093] As used herein, the phrase "thermal chamber," including first thermal chamber 50 and/or second thermal chamber 60, may refer to any suitable region of the underground reservoir 44 within which injection of a corresponding thermal recovery stream and production of a corresponding mobilized viscous hydrocarbon stream has depleted, at least substantially depleted, and/or depleted a producible fraction of, naturally occurring viscous hydrocarbons.

[0094] It is within the scope of the present disclosure that the two single-well thermal recovery processes described above may have any suitable temporal, relationship that leads to the formation of communicating thermal chamber 80.
As examples, the single-well thermal recovery process performed utilizing first hydrocarbon well 31 and the single-well thermal recovery process performed utilizing second hydrocarbon well 32 may be performed concurrently, at least partially concurrently, sequentially, and/or at least partially sequentially.

[0095] Another example of thermal recovery processes includes a well pair thermal recovery process in which a pair of hydrocarbon wells 20 is utilized to concurrently, continuously, and/or at least substantially continuously provide a thermal recovery stream to the underground reservoir 44 and also to receive a mobilized viscous hydrocarbon stream from the underground reservoir 44. Examples of well pair thermal recovery processes include steam flooding processes, solvent-assisted steam flooding processes, steam-assisted gravity drainage processes, solvent-assisted steam-assisted gravity drainage processes, heated vapor extraction processes, and/or near-azeotropic gravity drainage processes.

[0096] An example of such a well pair thermal recovery process also is illustrated in Figures 2-4 for a gravity drainage-type well pair thermal recovery process.
In this example, system 100 may include two spaced-apart pairs of hydrocarbon wells 20. These may include a first pair, which includes first hydrocarbon well 31 and third hydrocarbon well 33 and a second pair, which includes second hydrocarbon well 32 and fourth hydrocarbon well 34. Within the first pair, first hydrocarbon well 31 may be positioned, within the underground reservoir 44, vertically below third hydrocarbon well 33. Similarly, within the second pair, second hydrocarbon well 32 may be positioned, within the underground reservoir 44, vertically below fourth hydrocarbon well 34.

[0097] As illustrated in Figure 2, in a gravity drainage-type well pair thermal recovery process, third hydrocarbon well 33 may be utilized to inject first thermal recovery stream 52 into the underground reservoir 44, and fourth hydrocarbon well 34 may be utilized to inject second thermal recovery stream 62 into the underground reservoir 44.
The thermal recovery streams may be injected continuously, or at least substantially continuously, and may interact with viscous hydrocarbons 46, which are present within the subterranean reservoir 44, to produce and/or generate corresponding mobilized viscous hydrocarbon streams.

[0098] Concurrently, at least partially concurrently, sequentially, and/or at least partially sequentially, and as illustrated in Figure 3, first hydrocarbon well 31 may be utilized to produce first mobilized viscous hydrocarbon stream 54 from the subterranean reservoir 44, and second hydrocarbon well 32 may be utilized to produce second mobilized: viscous hydrocarbon stream 64 from the subterranean reservoir 44.
This process may be performed for any suitable injection time period and/or for any suitable production time period. Injection of the thermal recovery streams and production of the mobilized viscous hydrocarbon streams may produce and/or generate first thermal chamber 50 and second thermal chamber 60 within the subterranean reservoir 44.

[0099] Similar to single-well thermal recovery processes described previously, these thermal chambers may be isolated from each other during the beginning stages of production, but over time, these thermal chambers may continue to grow in volume, eventually forming, producing, and/or generating communicating thermal chamber 80 that is illustrated in Figure 4. Furthermore, and as discussed, hydrocarbon production system

100 may include more than two pairs of spaced-apart wellbores, and thus may create more than two such thermal chambers that may grow to form part of communicating thermal chamber 80. As an example, two pairs of spaced-apart single wellbores and/or well pairs may be a part of greater repeating patterns of wellbores and/or well pair locations that may be systematically located to facilitate production and recovery of viscous hydrocarbons from the subterranean reservoir 44 over an extended area.
Thus, the schematic examples of one or two thermal chambers should not constrain the scope of the present disclosure to only these illustrative examples.
[00100] Another example of a well pair thermal recovery process, in the form of a steam flooding process and/or a solvent-assisted steam flooding process, also is illustrated in Figure 2-4. These processes generally may be referred to herein as flooding processes. In the example of flooding processes, system 100 may include a plurality of spaced-apart hydrocarbon wells 20, only two of which are illustrated schematically in Figures 2-4 but any number of which may be present and/or utilized in system 100. These may include first hydrocarbon well 31, which also may be referred to herein as an injection well, and second hydrocarbon well 32, which also may be referred to herein as a production well.

[00101] As illustrated in Figure 2, in the flooding processes, first hydrocarbon well 31 may be utilized to inject first thermal recovery stream 52 into the subterranean reservoir 44. First thermal recovery stream 52 may interact with viscous hydrocarbons 46, which are present within the subterranean reservoir 44, to produce and/or generate a first mobilized viscous hydrocarbon stream 54. The first mobilized viscous hydrocarbon stream may flow to second hydrocarbon well 32 and be produced from the subterranean reservoir 44. Injection of the first thermal recovery stream and production of the first mobilized viscous hydrocarbon stream may produce and/or generate first thermal chamber 50 within the subterranean reservoir 44, as illustrated in Figure 3.
The first thermal chamber may grow with time, as illustrated in Figure 4, eventually reaching and/or contacting second hydrocarbon well 32.

[00102] In the example of the flooding processes, corresponding pairs of the spaced-apart hydrocarbon wells may be utilized to produce mobilized viscous hydrocarbons from the subterranean reservoir 44. This utilization of the corresponding pairs of spaced-apart hydrocarbon wells may include injection of corresponding thermal recovery streams 20 into corresponding injection wells and production of corresponding mobilized viscous hydrocarbon streams from corresponding production wells.
This utilization thus may produce and/or generate corresponding thermal chambers within the subterranean reservoir 44. These thermal chambers may grow with time, eventually merging, forming corresponding communicating chambers, and/or defining corresponding interface regions therebetween. As an example, and in addition to formation of first thermal chamber 50, system 100 may include a second injection well and a second production well that together may be utilized to form, define, and/or generate another thermal chamber within the subterranean reservoir 44. The first thermal chamber and the other thermal chamber may grow with time, eventually merging, forming the communicating chamber, and/or defining the interface region therebetween.

[00103] Regardless of the exact mechanism utilized to form, produce, and/or generate communicating thermal chamber 80 as shown in Figure 4, formation of the communicating chamber may heat subterranean reservoir 44, communicating thermal chamber 80, first thermal chamber 50, and/or second thermal chamber 60 to a chamber temperature that is above a naturally occurring temperature within the subterranean reservoir 44. As discussed, maintaining the chamber temperature may be costly, thereby limiting an economic viability of thermal recovery processes. However, formation of such a heated and communicating thermal chamber may permit methods 200, 300, 400 and 500 to be utilized to improve an efficiency of production of viscous hydrocarbons from the subterranean reservoir 44.

[00104] As illustrated in Figure 5, previous processes that included injecting a mobilizing fluid through an injection well 501 into a depleted reservoir that had previously undergone a thermal recovery process resulted in small portions of the mobilizing fluid 505 condensing in the depleted zone 510 below the overburden 515 at an interface of the bitumen reserve 520 of the underground reservoir and mixing of the condensed mobilizing fluid with the bitumen to induce the bitumen 520 to flow toward a producer wellbore 525.
After undergoing a thermal recovery process, the reservoir pressure is generally low (e.g.
below about 2-3 MPa) due to inter-well communication and, due to residual heat from the previous thermal recovery process, the temperature in the well is generally high (e.g. at or above 60-80 C). At these conditions, most of the injected mobilizing fluid (e.g.
propane) is in a vapor phase, as can be observed from the phase diagram in Figure 6.
When the mobilizing fluid is injected into the reservoir, the mobilizing fluid 505 tends to remain in the vapor phase 601, instead of a preferred liquid phase 605, and only a very small portion of the mobilizing fluid will condense at the interface of the bitumen reserve 520. Due to high mobility of the vapor phase and inter-well communication, the mobilizing fluid therefore quickly passes from the injection well 501 to the producer well 525 with little mixing/solvency with the bitumen 520, which leads to high mobilizing fluid recycling rates and low mobilizing fluid utilization rates.

[00105] Herein, the term "mobilizing fluid" may be used to refer to a fluid, that may include a solvent that decreases a viscosity of bitumen in an underground reservoir. In some embodiments, the mobilizing fluid may include a light hydrocarbon, a mixture of light hydrocarbons or dimethyl ether. In other embodiments, the mobilizing fluid may include a C2-alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics. In one specific example, the mobilizing fluid may consist primarily of 03 to C4 hydrocarbons. In some embodiments, the mobilizing fluid may comprise a mixture of a vapor solvent and steam.

[00106] With this in mind, Figure 7 is a flowchart depicting methods 200, according to the present disclosure, for conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process. Conditioning the underground reservoir can bring the conditions of the underground reservoir after the thermal recovery process closer to the liquid-vapor phase boundary of a selected mobilizing fluid so vapor in the mobilizing fluid (e.g. solvent vapor) can condense upon contact with the bitumen in the reservoir. A plot showing an exemplary vapor solvent flood operating window is shown in Figure 8.

[00107] Herein, four concepts are described for conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process. The four concepts include:
injecting a pressuring fluid into a voidage formed in the underground reservoir before injecting the mobilizing fluid into the reservoir to increase the pressure of the underground reservoir; injecting a thermal recovery fluid into a voidage formed in the reservoir before injecting the mobilizing fluid into the reservoir to decrease the temperature of the underground reservoir; delaying production of fluid from the reservoir after injecting the mobilizing fluid to increase the pressure of the underground reservoir; and injecting a pressurizing fluid during production of fluid from the underground reservoir or co-injecting the pressurizing fluid with the mobilizing fluid to increase the pressure in the underground reservoir.

[00108] Methods 200 may include performing a thermal recovery process at and/or transitioning to a solvent-dominated process at 210. Methods 200 include determining a temperature of the reservoir at 215, injecting a pressurizing fluid into a voidage formed in the reservoir during the thermal recovery process to increase a pressure of the reservoir at 220, monitoring the pressure of the reservoir at 225, and in response to the monitored pressure reaching a predetermined recovery pressure selected based on a determined temperature, injecting mobilizing fluid comprising vapor solvent into the reservoir at 230, the vapor solvent having a liquid-vapor phase boundary proximate the determined temperature and the predetermined recovery pressure, and producing fluid comprising mobilized bitumen from the reservoir at 235.

[00109] Performing the thermal recovery process at 205 may include performing any suitable thermal recovery process within the subterranean reservoir. This may include performing a first thermal recovery process to form, produce, and/or generate a first thermal chamber within the subterranean reservoir. This also may include performing a second thermal recovery process to form, produce, and/or generate a second thermal chamber within the subterranean reservoir.

[00110] The first thermal recovery process may include injection of a first thermal recovery stream into the first thermal chamber and production of a first mobilized viscous hydrocarbon stream from the subterranean reservoir and/or from the first thermal chamber. Similarly, the second thermal recovery process may include injection of a second thermal recovery stream into the second thermal chamber and production of a second mobilized viscous hydrocarbon stream from the subterranean reservoir and/or from the second thermal chamber.

[00111] When methods 200 include the performing at 205, methods 200 may include continuing the performing at 205 until the first thermal chamber and the second thermal chamber define an interface region therebetween. The interface region may include a region of overlap between the first thermal chamber and the second thermal chamber and/or may permit fluid communication, within the subterranean reservoir, between the first thermal chamber and the second thermal chamber.

[00112] The establishment of the interface region and/or the fluid communication between the thermal chambers may be detected and/or confirmed by means of any suitable reservoir surveillance method. Examples of such reservoir surveillance methods include, but are not limited to, 2D and/or 3D seismic surveillance methods, pressure data analysis, temperature data analysis, and/or injection and production data analysis.

[00113] Examples of the first thermal recovery process and/or of the second thermal recovery process include cyclic steam stimulation (CSS) processes, liquid addition to steam to enhance recovery (LASER) processes, solvent-assisted cyclic steam stimulation processes , steam flooding processes, solvent-assisted steam flooding processes, steam-assisted gravity drainage (SAG D) processes, solvent-assisted steam-assisted gravity drainage (SA-SAGD) processes, heated vapor extraction (VAPEX) processes, liquid addition to steam to enhance recovery processes, and/or near-azeotropic gravity drainage processes.

[00114] It is within the scope of the present disclosure that methods 200 are not required to include the performing at 205. Instead, methods 200 may be performed with, via, and/or utilizing a hydrocarbon production system that already includes the first thermal chamber, the second thermal chamber, and the interface region therebetween.
As an example, the first thermal recovery process and the second thermal recovery process may be performed and the first thermal chamber and the second thermal chamber may be formed, within the subterranean reservoir, prior to initiation of method steps 210-235.

[00115] It is within the scope of the present disclosure that the interface region may include and/or be a region of overlap between two adjacent thermal chambers, such as interface region 70 that is illustrated in Figure 4.

[00116] When methods 200 include the performing at 205, methods 200 also may include the transitioning at 210. The transitioning at 210 may include transitioning from performing the first thermal recovery process in the first thermal chamber and performing the second thermal recovery process in the second thermal chamber to performing the injecting at 220 and the producing at 235. The transitioning at 210, when performed, may be initiated based upon and/or responsive to any suitable transition criteria.

[00117] Examples of the transition criteria include establishing and/or detecting fluid communication between the first thermal chamber and the second thermal chamber.
Another example of the transition criteria includes production, from the subterranean reservoir, of at least a threshold fraction of an original oil in place.
Examples of the threshold fraction include at least 10%, at least 20%, at least 30%, at least 40%, at least 50%, at least 60%, at least 70%, and/or at least 80% of the original oil in place.

[00118] Methods 200 include determining a temperature of the reservoir at 215.
Determining the temperature of the reservoir at 215 may include determining a temperature of the reservoir using one or more of a plurality of temperature sensors such as but not limited to Thermocouples, ERD sensors or DTS fibers for measurement of temperature at producer or temperature logs at observation wells.

[00119] In methods 200, to condition the reservoir to a higher pressure, a pressurizing fluid is injected into a voidage (e.g. a thermal chamber) formed in the underground reservoir prior to conducting any flooding operations, as illustrated in Figure 9. The pressurizing fluid may include a non-compressible gas (NCG). The NCG
could be methane, carbon dioxide (CO2), nitrogen, gas produced during the thermal recovery process, flue gas, or a combination of thereof. In some embodiments, the pressurizing fluid may consist primarily of a NCG. In other embodiments, the pressurizing fluid may include a NCG and propane vapor.

[00120] Injecting the pressurizing fluid into the voidage formed in the reservoir during the thermal recovery process at 220 may include injecting the pressurizing fluid into a first thermal chamber via an injection well 901a into a bitumen rich zone 905 located below the depleted zone 910 and the overburden 915. Alternatively, the pressurizing fluid may additionally be into the voidage via a second injection well 901b that is in fluid connection with injection well 901a. The injection wells 901a and/or 901b may be any well used during the previous thermal recovery process.

[00121] After injecting the pressurizing fluid into the voidage formed in the underground reservoir, methods 200 include monitoring the pressure of the reservoir at 225. The pressure of the reservoir can be monitored at 225 by ERD sensors or any other type of pressure sensors or fibers that can measure the pressure in the injectors, producers, and observation wells, which can be used to infer the reservoir pressure.

[00122] In response to the monitored pressure reaching a predetermined recovery pressure selected based on a determined temperature, methods 220 further include injecting mobilizing fluid into the reservoir at 230.

[00123] The predetermined recovery pressure can be selected based on a determined temperature to optimize the conditions within the underground reservoir to maximize the efficiency of the solvent-dominated recovery process. For instance, the predetermined recovery pressure can be a pressure that provides for solvent in the mobilizing fluid subsequently injected into the voidage of the underground reservoir to condense. In some embodiments, the mobilizing fluid comprises a mixture of vapor solvent and steam.

[00124] The solvent composition may comprise (i) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and (ii) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane. The solvent composition may have a Hansen hydrogen bonding parameter of 0.3 to 1.7 (or 0.7 to 1.4). The solvent composition may have a volume ratio of the polar component to non-polar component of 10:90 to 50:50 (or 10:90 to 24:76, 20:80 to 40:60, 25:75 to 35:65, or 29:71 to 31:69). The polar component may be, for instance, a ketone or acetone. The non-polar component may be, for instance, a alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics. For further details and explanation of the Hansen Solubility Parameter System see, for example, Hansen, C. M. and Beerbower, Kirk-Othmer, Encyclopedia of Chemical Technology, (Suppl. Vol. 2nd Ed), 1971, pp 889-910 and "Hansen Solubility Parameters A User's Handbook" by Charles Hansen, CRC Press, 1999.

[00125] The solvent composition may comprise (i) an ether with 2 to 8 carbon atoms;
and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms. Ether may have 2 to 8 carbon atoms. Ether may be di-methyl ether, methyl ethyl ether, di-ethyl ether, methyl iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether, methyl iso-butyl ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-propyl butyl ether, propyl butyl ether, di-isobutyl ether, or di-butyl ether. Ether may be di-methyl ether. The non-polar hydrocarbon may a 02-C30 alkane. The non-polar hydrocarbon may be a C5 alkane. The non-polar hydrocarbon may be propane. The ether may be di-methyl ether and the hydrocarbon may be propane. The volume ratio of ether to non-polar hydrocarbon may be 10:90 to 90:10; 20:80 to 70:30; or 22.5:77.5 to 50:50.

[00126] The solvent composition may comprise at least 5 mol /0 of a high-aromatics component (based upon total moles of the solvent composition) comprising at least 60 wt.% aromatics (based upon total mass of the high-aromatics component). One suitable and inexpensive high-aromatics component is gas oil from a catalytic cracker of a hydrocarbon refining process, also known as a light catalytic gas oil (LCGO).

[00127] In some embodiments, the mobilizing fluid includes a vapor solvent that has a liquid-vapor phase boundary proximate the temperature of the underground reservoir.
As noted above, an exemplary vapor solvent flood operating window is shown in Figure 8. In some embodiments, the temperature of the reservoir is in a range of about 20 C to about 180 C.

[00128] In some embodiments, the mobilizing fluid includes a vapor solvent that has a liquid-vapor phase boundary proximate the predetermined recovery pressure.
In some embodiments, the pressure of the reservoir is in a range of about 500 kPa to about 3 MPa.

[00129] After injecting the mobilizing fluid into the underground reservoir, methods 200 include producing fluid comprising mobilized bitumen from the underground reservoir at 235. Producing fluid comprising mobilized bitumen at 235 may include producing the fluid comprising mobilized bitumen from a second thermal chamber that extends within the underground reservoir and/or via a solvent flood production well that extends within the second thermal chamber. The producing at 235 may be concurrent, or at least partially concurrent, with the injecting mobilized fluid tat 230. Stated another way, the injecting at 230 and the producing at 235 may have and/or exhibit at least a threshold amount of temporal overlap.

[00130] The producing at 235 may include producing with, via, and/or utilizing any suitable well utilized during the thermal recovery process and/or with, via, and/or utilizing any suitable portion and/or region of the well utilized during the thermal recovery process.
As an example, the well utilized during the thermal recovery process may include an at least substantially horizontal and/or deviated production well region that extends within the second thermal chamber. Under these conditions, the producing at 235 may include producing the mobilized bitumen with, via, and/or utilizing the at least substantially horizontal and/or deviated production well region. As another example, the well utilized during the thermal recovery process may include an at least substantially vertical production well region that extends within the second thermal chamber. Under these conditions, the producing at 235 may include producing the solvent flood-mobilized viscous hydrocarbons with, via, and/or utilizing the at least substantially horizontal production well region.

[00131] Alternatively, prior to the injection of mobilizing fluid into the voidage formed in the underground reservoir, a thermal recovery fluid can be injected into the voidage formed in the reservoir to lower the temperature of the underground reservoir.
Figure 10 shows an example of injecting a thermal recovery fluid (e.g. water) via an injection well 1001 into or proximate to a bitumen rich zone 1005 located below the depleted zone 1010 and the overburden 1015 in the underground reservoir to reduce the temperature of the underground reservoir. Specifically, injecting the thermal recovery fluid into the reservoir may reduce the temperature of a lower portion of the underground reservoir close to undepleted bitumen, so when the mobilizing fluid (e.g. comprising a light hydrocarbon) is injected into the underground reservoir, the mobilizing fluid will condense in the lower portion of the underground reservoir 1020 nearest the undepleted bitumen increasing the utilization efficiency of the mobilizing fluid. Water, gas and bitumen can be recovered via a producer well 1025. The injection well 1001 and/or the producer well 1025 may be any well used during the previous thermal recovery process.

[00132] With this in mind, Figure 11 is a flowchart depicting methods 300, according to the present disclosure, for conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process, where the reservoir is at an elevated temperature due to the thermal recovery process.

[00133] Methods 300 may include performing a thermal recovery process at and/or transitioning at 310. Methods 300 include injecting thermal recovery fluid into a voidage formed in the reservoir during the thermal recovery process at 315, the thermal recovery fluid being injected at a temperature below the elevated temperature of the reservoir, producing fluid from the reservoir at 320, the produced fluid primarily comprising thermal recovery fluid at a temperature greater than the temperature at which it was injected; determining a reservoir pressure of the voidage at 325; monitoring the temperature of the reservoir at 330; and, in response to the temperature of the reservoir reaching a predetermined recovery temperature, injecting mobilizing fluid comprising vapor solvent into the reservoir at 335, the vapor solvent having a liquid-vapor phase boundary proximate the temperature of the reservoir and the reservoir pressure, and producing fluid comprising mobilized bitumen from the reservoir at 340.

[00134] In some embodiments, the thermal recovery fluid comprises water, or, alternatively, consists primarily of water.

[00135] Injecting the thermal recovery fluid into the voidage formed in the underground reservoir includes Injecting the thermal recovery fluid at a temperature that is below the temperature of the underground reservoir after the thermal recovery process.
In this manner, the thermal recovery fluid can receive heat from the surrounding reservoir once it has been injected into the underground reservoir to lower the temperature of the underground reservoir.

[00136] Producing at 320 may include producing at least a fraction of the thermal recovery fluid and/or at least a fraction of mobilized bitumen from the underground reservoir.

[00137] In some embodiments, in some embodiments, prior to injecting the mobilizing fluid at 335, methods 300 may include ceasing injection of the thermal recovery fluid at 333.

[00138] Alternatively, after injection of mobilizing fluid into the voidage formed in the underground reservoir, production of fluid comprising mobilized bitumen can be delayed to increase the pressure of the reservoir after the thermal recover process.
By delaying production of fluid from the underground reservoir and increasing the pressure of the underground reservoir, the mobilizing fluid will condense in the lower portion of the underground reservoir nearest the undepleted bitumen and increase the utilization efficiency of the mobilizing fluid.

[00139] Figure 12 is a flowchart depicting methods 400, according to the present disclosure, for conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process.

[00140] Methods 400 may include performing a thermal recovery process at and/or transitioning at 410. Methods 400 include determining a temperature of the reservoir at 415, injecting mobilizing fluid comprising vapor solvent into a voidage formed in the reservoir during the thermal recovery process while restricting production from the reservoir to increase a pressure of the reservoir at 420, monitoring the pressure of the reservoir at 425, and in response to the monitored pressure reaching a predetermined recovery pressure, producing fluid comprising mobilized bitumen from the reservoir at 430, wherein fluid is produced at a rate sufficient to maintain the pressure of the reservoir at the predetermined recovery pressure.

[00141] In methods 400, the vapor solvent has a liquid-vapor phase boundary proximate the reservoir temperature and the predetermined recovery pressure.

[00142] In some embodiments, while producing the fluid comprising mobilized bitumen at 430, the method may also include co-injecting a pressurizing fluid (as described above) into the underground reservoir to maintain or increase the pressure of the underground reservoir.

[00143] In some embodiments, after injecting the mobilizing fluid into the underground reservoir, the method 400 may further comprise restricting production from the reservoir. Restricting production from the reservoir may include restricting gas production from the underground reservoir while permitting liquid production from the underground reservoir. Gas is normally produced by venting from casing, separately from the tubing liquid from production. Gas venting can be throttled as a desired rate to maintain back pressure of the well and thus maintain further drop of reservoir pressure.

[00144] In some embodiments of the producing at 430, the fluid comprising mobilized bitumen is produced at a rate that is less than about 80% or less than about 90%, or less than about 95%of a rate of mobilizing fluid injection.

[00145] In some embodiments, as the fluid is being produced at 430, the mobilizing fluid is injected at an injection pressure greater than about 110% of the predetermined recovery pressure.

[00146] Alternatively, after injection of mobilizing fluid into the voidage formed in the underground reservoir, NCG can be injected into the underground reservoir as fluid comprising mobilized bitumen is produced from the underground reservoir. By injecting NCG into the underground reservoir as fluid is produced from the reservoir, the pressure of the underground reservoir can be inhibited from decreasing and the mobilizing fluid will condense in the lower portion of the underground reservoir nearest the undepleted bitumen and increase the utilization efficiency of the mobilizing fluid.

[00147] Figure 13 is a flowchart depicting methods 500, according to the present disclosure, performing a solvent-dominated recovery process in an underground reservoir that has previously undergone a thermal recovery process, the solvent-dominated recovery process being a vapor flooding process.

[00148] Methods 500 may include performing a thermal recovery process at and/or transitioning at 510. Methods 500 include injecting mobilizing fluid comprising vapor solvent into a voidage formed in the reservoir during the thermal recovery process via a first wellbore at 515, producing fluid comprising mobilized bitumen from the reservoir via a second wellbore at 520, the second wellbore being different than the first wellbore, and, while producing fluid, injecting non-condensable gas into the reservoir at 525.

[00149] In some embodiments, the mobilizing fluid can be injected via a first wellbore used during the previous thermal recovery process and fluid can be produced via a second wellbore used during the thermal recovery process. NCG can be injected into the underground reservoir via a third wellbore. the third wellbore can be a vertical wellbore or a horizontal wellbore and can be completed (e.g. drilled) subsequent to an initial phase of the thermal recovery process. Injecting the NCG into the underground reservoir may include co-injecting the NCG into the reservoir with mobilizing fluid comprising vapor solvent. The co-injecting may be through a same wellbore or through a different (e.g. separate) wellbore. Further, when the co-injecting the NCG is through different wellbores, the NCG may be injected into the underground reservoir at a first depth and the mobilizing fluid comprising vapor solvent may be injected into the reservoir at a second depth. The first depth and the second depth may be different depths. For instance, the NCG may be injected into the underground reservoir nearer to a top of the underground reservoir than the mobilizing fluid comprising vapor solvent.
Examples

[00150] The following provide a simulation example to illustrate some key performance indicators of a vapor solvent flood operation.

[00151] In this example, the initial reservoir pressure is as low as 300 kPa, and propane vapor is injected at a liquid equivalent rate of 40 m3/d per bottom hole (-25m per bottom hole for a horizontal well). Figure 14 shows an injection/production pressure change with time. Figure 15 shows the solvent injection rate (liquid equivalent) and bitumen production rate per bottom hole ("BH").

[00152] It can be seen from these figures that the operating pressure is low (e.g. for majority of the operation, the average reservoir pressure is less than 1000 kPa). Referring back to the phase profile shown in Figure 6, it is clear that most of the propane injected will be in vapor phase.

[00153] The oil solvent ratio (defined produced oil to injection solvent volume ratio -liquid equivalent) is low (e.g. as low as 0.1 in the late stage of the process). This indicates very low solvent utilization, consistent with the observation above.

[00154] The simulator also indicates that less than 15% of the propane condenses into liquid phase 1601, while majority of it stays in vapor phase 1605, as shown in Figure 16. Through reservoir conditioning and optimization of the startup and production control, as outlined in the invention, the portion of the propane in liquid phase will increase significantly (shown as line 1610 in Figure 16).

[00155] Post-startup of the vapor solvent flood process, NCG can be with solvent during the steady-state operation. At certain circumstances, a small fraction of NCG (such as CO2, methane, N2, flue gas, etc.) is injected to help clear up the communication channels, and lead or assist the solvent vapor moving from injectors to producers. The easier flow stream of gas component is expected to carry solvent droplets or drive solvent vapor further towards to the producers, leading to earlier solvent front arriving, more effective mixing, and earlier and more bitumen uplift as well. The mole fraction of the NCG
can be as low as 1-2% and up to 20%. There are a few different approaches of NCG
injection, including but not limited to: simultaneous co-injection of NCG with solvent at constant or varying ratios into the same well; alternating slug injection of NCG and solvent into the same well; and NCG is injected to the top of the reservoir through different wells or the same well at different completion interval (via a different injection string).

[00156] NCG injection during the vapor solvent flood operation has a few other potential benefits other than assisting solvent delivery, such as maintain reservoir pressure, facilitate solvent condensation at certain target areas, and reduce solvent intensity. NCG also helps the redistribution of energy. This becomes of particular interest if we have to use heavier solvent in some commercialization circumstances.
Adding a small amount of gas to be co-injected with solvent also leads to a higher operating pressure and more solvent fraction in liquid phase, which will enhance the dilution. Figure 17 shows a simulation run for a whole life cycle of a thermal process from CSS, to Injection only Infill (101), and then to steam flood and solvent flood transitioning at approximately 8300 days.

[00157] Comparison is made after day 8300 between base solvent flood (solvent flood curve in Figure 17) and gas enhancement of the solvent flood (solvent flood + CO2 curve in Figure 17). It can be seen that there is some clear uplift of the bitumen production rate when co-injecting some CO2 with the solvent.

[00158] Other than gas, hot water can also be co-injected or alternately injected with vapor solvent (similar to WAG) to help redistribute the energy within the reservoir (between hot and cold zones) and assist solvent delivery and condensation.

[00159] While the above description describes features of example embodiments, it will be appreciated that some features and/or functions of the described embodiments are susceptible to modification without departing from the spirit and principles of operation of the described embodiments. For example, the various characteristics which are described by means of the represented embodiments or examples may be selectively combined with each other. Accordingly, what has been described above is intended to be illustrative of the claimed concept and non-limiting. It will be understood by persons skilled in the art that other variants and modifications may be made without departing from the scope of the invention as defined in the claims appended hereto. The scope of the claims should not be limited by the preferred embodiments and examples, but should be given the broadest interpretation consistent with the description as a whole.

Claims

What is claimed is:

1. A method for conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process, the method comprising:
determining a temperature of the reservoir;
injecting pressurizing fluid into a voidage formed in the reservoir during the thermal recovery process to increase a pressure of the reservoir;
monitoring the pressure of the reservoir; and in response to the monitored pressure reaching a predetermined recovery pressure selected based on a determined temperature:
injecting mobilizing fluid comprising vapor solvent into the reservoir, the vapor solvent having a liquid-vapor phase boundary proximate the determined temperature and the predetermined recovery pressure;
and producing fluid comprising mobilized bitumen from the reservoir.

2. The method of claim 1, wherein injecting pressurizing fluid into the voidage includes injecting pressurizing fluid into a first thermal chamber that extends within the reservoir and a second thermal chamber that extends within the reservoir.

3. The method of claim 2, wherein the method includes performing the thermal recovery process and the first thermal chamber and the second thermal chamber are formed by performing the thermal recovery process.

4. The method of claim 3, wherein the first thermal chamber and the second thermal chamber are independently formed during the thermal recovery process.

5. The method of any one of claims 1 to 4, wherein the thermal recovery process is performed using two or more pairs of wellbores.

6. The method of any one of claim 1 to 5, wherein the thermal recovery process is one of a cyclic steam stimulation (CSS) process and a steam-assisted gravity drainage (SAGD) process.

7. The method of any one of claims 1 to 6, wherein the vapor solvent in the mobilizing fluid comprises a C2-C7 hydrocarbon, a C2-C4 natural gas liquid, a natural gas condensate, a naphtha product, or an ether.

8. The method of claim 7, wherein the vapor solvent in the mobilizing fluid consists primarily of C3 to C4 hydrocarbons.

9. The method of any one of claims 1 to 8, wherein the mobilizing fluid comprises a mixture of vapor solvent and steam.

10. The method of any one of claims 1 to 9, wherein the pressurizing fluid comprises at least one of methane, carbon dioxide, flue gas, and gas produced during the thermal recovery process.

11. The method of claim 10, wherein the pressurizing fluid consists primarily of non-condensable gas.

12. The method of any one of claims 1 to 11, wherein the pressurizing fluid comprises at least one of non-condensable gas and propane vapor.

13. The method of any one of claims 1 to 12, wherein the temperature of the reservoir is in a range of about 20 °C to about 180 °C.

14. The method of any one of claims 1 to 13, wherein the pressure of the reservoir is in a range of 500 kPa to 3 MPa.

15. A method for conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process, wherein the reservoir is at an elevated temperature due to the thermal recovery process, the method comprising:
injecting thermal recovery fluid into a voidage formed in the reservoir during the thermal recovery process, the thermal recovery fluid being injected at a temperature below the elevated temperature of the reservoir;
producing fluid from the reservoir, the produced fluid primarily comprising thermal recovery fluid at a temperature greater than the temperature at which it was injected;
determining a reservoir pressure of the voidage;
monitoring the temperature of the reservoir; and in response to the temperature of the reservoir reaching a predetermined recovery temperature:
injecting mobilizing fluid comprising vapor solvent into the reservoir, the vapor solvent having a liquid-vapor phase boundary proximate the temperature of the reservoir and the reservoir pressure; and producing fluid comprising mobilized bitumen from the reservoir.

16. The method of claim 15, wherein injecting pressurizing fluid into the voidage includes injecting pressurizing fluid into a first thermal chamber that extends within the reservoir and a second thermal chamber that extends within the reservoir.

17. The method of claim 16, wherein the method includes performing the thermal recovery process and the first thermal chamber and the second thermal chamber are formed by performing the thermal recovery process.

18. The method of claim 17, wherein the first thermal chamber and the second thermal chamber are independently formed during the thermal recovery process.

19. The method of any one of claims 15 to 18, wherein the thermal recovery process is performed using two or more pairs of wellbores.

20. The method of any one of claim 15 to 19, wherein the thermal recovery process is one of a cyclic steam stimulation (CSS) process and a steam-assisted gravity drainage (SAGD) process.

21. The method of any one of claims 15 to 20, wherein the vapor solvent in the mobilizing fluid comprises a C2-C7 hydrocarbon, a C2-C4 natural gas liquid, a natural gas condensate, a naphtha product, or an ether.

22. The method of claim 21, wherein the vapor solvent in the mobilizing fluid consists primarily of C3-C4 hydrocarbons.

23. The method of any one of claims 20 to 22, wherein the thermal recovery fluid primarily comprises water.

24. The method of any one of claims 15 to 23, wherein the predetermined recovery temperature is selected based on the determined reservoir pressure.

25. The method of any one of claims 15 to 24, further comprising, prior to injecting mobilizing fluid, ceasing injection of thermal recovery fluid.

26. The method of any one of claims 15 to 25, wherein the temperature of the reservoir is in a range of about 20 °C to about 180 °C.

27. The method of any one of claims 15 to 26, wherein the pressure of the reservoir is in a range of 500 kPa to 3 MPa.

28. A method for conditioning an underground reservoir that has undergone a thermal recovery process to promote improved efficiency during a subsequent solvent-dominated recovery process, the method comprising:
determining a temperature of the reservoir;
injecting mobilizing fluid comprising vapor solvent into a voidage formed in the reservoir during the thermal recovery process while restricting production from the reservoir to increase a pressure of the reservoir;

monitoring the pressure of the reservoir; and in response to the monitored pressure reaching a predetermined recovery pressure:
producing fluid comprising mobilized bitumen from the reservoir, wherein fluid is produced at a rate sufficient to maintain the pressure of the reservoir at the predetermined recovery pressure;
wherein the vapor solvent has a liquid-vapor phase boundary proximate the reservoir temperature and the predetermined recovery pressure.

29. The method of claim 28, wherein injecting pressurizing fluid into the voidage includes injecting pressurizing fluid into a first thermal chamber that extends within the reservoir and a second thermal chamber that extends within the reservoir.

30. The method of claim 29, wherein the method includes performing the thermal recovery process and the first thermal chamber and the second thermal chamber are formed by performing the thermal recovery process.

31. The method of claim 30, wherein the first thermal chamber and the second thermal chamber are independently formed during the thermal recovery process.

32. The method of any one of claims 28 to 31, wherein the thermal recovery process is performed using two or more pairs of wellbores.

33. The method of any one of claim 28 to 32, wherein the thermal recovery process is one of a cyclic steam stimulation (CSS) process and a steam-assisted gravity drainage (SAGD) process.

34. The method of any one of claims 28 to 33, wherein the vapor solvent in the mobilizing fluid comprises a C2-C7 hydrocarbon, a C2-C4 natural gas liquid, a natural gas condensate, a naphtha product, or an ether.

35. The method of claim 34, wherein the vapor solvent in the mobilizing fluid consists primarily of C3-C4 hydrocarbons.

36. The method of any one of claims 28 to 35, wherein the mobilizing fluid comprises a mixture of vapor solvent and steam.

37. The method of any one of claims 28 to 36, further comprising, while producing fluid comprising mobilized bitumen from the reservoir:
co-injecting a pressurizing fluid into the reservoir to maintain or increase the reservoir pressure.

38. The method of claim 37, wherein the pressurizing fluid comprises at least one of methane, carbon dioxide, flue gas, and gas produced during the thermal recovery process.

39. The method of claim 38, wherein the pressurizing fluid consists primarily of non-condensable gas.

40. The method of any one of claims 28 to 39, wherein the predetermined recovery pressure is selected based on a determined temperature.

41. The method of any one of claims 28 to 40, wherein restricting production from the reservoir comprises restricting gas production while permitting liquid production.

42. The method of any one of claims 28 to 41, wherein fluid is produced at a rate that is less than about 80%, or less than about 90%, or less than about 95% of a rate of recovery mobilizing fluid injection.

43. The method of any one of claims 28 to 42, wherein, while fluid is being produced, mobilizing fluid is injected at an injection pressure greater than 110% of the predetermined recovery pressure.