CA2897785A1 - Hydrocarbon recovery using injection of steam and a diluent - Google Patents

Abstract

Generally, described herein is a gravity drainage process for recovering viscous oil from an underground reservoir. The process includes injecting a mobilizing composition including steam and a diluent through an injection well into the reservoir to mobilize the viscous oil.
The mobilizing composition is alternated between a first diluent to steam volume ratio (DSR1) of 0.05-0.5 and a second diluent to steam volume ratio (DSR2) of 0-0.3.
The DSR1 is at least 0.05 greater than the DSR2. The process also includes producing the viscous oil and at least a fraction of the mobilizing composition from the reservoir through a production well.

Description

HYDROCARBON RECOVERY USING INJECTION OF STEAM AND A DILUENT
FIELD OF THE INVENTION
[0001] The disclosure relates generally to hydrocarbon recovery from underground reservoirs. More specifically, the disclosure relates to gravity drainage processes for recovering viscous oil.
BACKGROUND OF THE INVENTION

[0002] This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure.
Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0003] Modern society is greatly dependent on the use of hydrocarbon resources for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface formations that can be termed "reservoirs". Removing hydrocarbons from the reservoirs depends on numerous physical properties of the subsurface formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the subsurface formations, and the proportion of hydrocarbons present, among other things.
Easily harvested sources of hydrocarbons are dwindling, leaving less accessible sources to satisfy future energy needs. As the prices of hydrocarbons increase, the less accessible sources become more economically attractive.

[0004] Recently, the harvesting of oil sands to remove heavy oil has become more economical. Hydrocarbon removal from oil sands may be performed by several techniques.
For example, a well can be drilled to an oil sand reservoir and steam, hot gas, solvents, or a combination thereof, can be injected to release the hydrocarbons. The released hydrocarbons may be collected by wells and brought to the surface.

[0005] Bitumen and heavy oil (collectively referred to herein as "viscous oil" as further defined below) reserves exist at varying depths beneath the earth's surface.
More shallow reserves are often mined followed by surface extraction. Deeper reserves are often exploited by in situ processes.

[0006] Diluents have been used for both in situ and surface extraction processes to dilute viscous oil. The term "solvent" is often used in the industry and literature in place of "diluent".

[0007] Diluents reduce the viscosity of viscous oil by dilution, while steam reduces the viscosity of viscous oil by raising the viscous oil temperature. Reducing the viscosity of in situ viscous oil is done to permit or facilitate its production.

[0008] Where deposits lie well below the surface, viscous oil may be extracted using in situ ("in place") processes. Thermal recovery processes are one category of in situ processes, where steam is used to reduce the viscosity of the viscous oil.
These processes are referred to as steam-based processes. One example of an in situ thermal process is the steam-assisted gravity drainage method (SAGD). In SAGD, directional drilling is employed to place two horizontal wells in the oil sands ¨ a lower well and an upper well positioned above it. Steam is injected into the upper well to heat the bitumen and lower its viscosity. The bitumen and condensed steam will then drain downward through the reservoir under the action of gravity and flow into the lower production well, whereby these liquids can be pumped to the surface. At the surface of the well, the condensed steam and bitumen are separated, and the bitumen is diluted with appropriate light hydrocarbons for transport to a refinery or an upgrader. An example of SAGD is described in U.S. Patent No.
4,344,485 (Butler).

[0009] Other steam-based thermal processes include Solvent-Assisted Steam Assisted Gravity Drainage (SA-SAGD), an example of which is described in Canadian Patent No. 1,246,993 (Vogel); Liquid Addition to Steam for Enhanced Recovery (LASER), an example of which is described in U.S. Patent No. 6,708,759 (Leaute et al.);
Combined Steam and Vapor Extraction Process (SAVEX), an example of which is described in U.S.
Patent No. 6,662,872 (Gutek et al.), and derivatives thereof.

[0010] It is desirable to provide an improved or alternative method for recovering viscous oil from an underground reservoir.
SUMMARY OF THE INVENTION

[0011] Generally, described herein is a gravity drainage process for recovering viscous oil from an underground reservoir. The process comprises injecting a mobilizing composition comprising steam and a diluent through an injection well into the reservoir to mobilize the viscous oil. The mobilizing composition is alternated between a diluent to steam volume ratio (DSR1) of 0.05-0.5 and another diluent to steam volume ratio (DSR2) of 0-0.3.
The DSR1 is at least 0.05 greater than the DSR2. The process also comprises producing the viscous oil and at least a fraction of the mobilizing composition from the reservoir through a production well.

[0012] Other aspects and features of the present invention will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS

[0013] These and other features, aspects and advantages of the disclosure will become apparent from the following description, appending claims and the accompanying drawings, which are briefly described below.

[0014] Fig. 1 is a flow chart of a gravity drainage process.

[0015] Fig. 2 is a graph illustrating the simulation results described below.

[0016] It should be noted that the figures are merely an example and no limitations on the scope of the present disclosure are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure.
DETAILED DESCRIPTION

[0017] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.

[0018] At the outset, for ease of reference, certain terms used in this application and their meaning, as used in this context, are set forth below. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present processes are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.

[0019] A "hydrocarbon" is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sands. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.

[0020] "Bitumen" is a naturally occurring heavy oil material.
Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.) percent (%) aliphatics (which can range from 5 wt. % - 30 wt.
%, or higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % - 50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and some amount of sulfur (which can range from 2 to 7 wt. %, or higher%), the foregoing based upon total weight of the bitumen.
In addition, bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found in bitumen can vary. The term "heavy oil" includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.

[0021] "Heavy oil" includes oils which are classified by the American Petroleum Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil" includes bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP
or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API
gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less than 10.0 API (density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen.

[0022] The term "viscous oil" as used herein means a hydrocarbon, or mixture of hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP
(centipoise) at initial reservoir conditions. Viscous oil includes oils generally defined as "heavy oil" or "bitumen". Bitumen is classified as an extra heavy oil, with an API gravity of about 10 or less, referring to its gravity as measured in degrees on the American Petroleum Institute (API) Scale. Heavy oil has an API gravity in the range of about 22.30 to about 10 . The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes.

[0023] In situ is a Latin phrase for "in the place" and, in the context of hydrocarbon recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For example, in-situ temperature means the temperature within the reservoir. In another usage, an in situ oil recovery technique is one that recovers oil from a reservoir below the earth's surface.

[0024] The term "subterranean formation" refers to the material existing below the earth's surface. The subterranean formation may comprise a range of components, e.g.
minerals such as quartz, siliceous materials such as sand and clays, as well as the oil and/or gas that is extracted. The subterranean formation may be a subterranean body of rock that is distinct and continuous. The terms "reservoir" and "formation" may be used interchangeably.

[0025] The terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.

[0026] The articles "the", "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.

[0027] "At least one," in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase "at least one"

refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, "at least one of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at least one of A and/or B") may refer, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases "at least one," "one or more," and "and/or" are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions "at least one of A, B and C," "at least one of A, B, or C," "one or more of A, B, and C," "one or more of A, B, or C" and "A, B, and/or C" may mean A alone, B alone, C alone, A and B
together, A
and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

[0028] Where two or more ranges are used, such as but not limited to 1 to 5 or 2 to 4, any number between or inclusive of these ranges is implied.

[0029] As used herein, the phrase, "for example," the phrase, "as an example,"
and/or simply the term "example," when used with reference to one or more components, features, details, structures, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, and/or method is an illustrative, non-exclusive example of components, features, details, structures, and/or methods according to the present disclosure. Thus, the described component, feature, detail, structure, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, and/or methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, and/or methods, are also within the scope of the present disclosure.

[0030] The term "mobilizing composition" means a composition that is injected into the reservoir to mobilize the viscous oil.

[0031] The term "DSR" means Diluent to Steam ratio on a volume basis at standard temperature and pressure (STP).

[0032] Figure 1 is a flow chart of a gravity drainage process for recovering viscous oil from an underground reservoir. The process comprises (i) injecting (102) a mobilizing composition comprising steam and a diluent through an injection well into the reservoir to mobilize the viscous oil. The mobilizing composition is alternated between a diluent to steam volume ratio (DSR1) of 0.05-0.5 and another diluent to steam volume ratio (DSR2) of 0-0.3.
The DSR1 is at least 0.05 greater than the DSR2. The process also comprises (ii) producing (104) the viscous oil and at least a fraction of the mobilizing composition from the reservoir through a production well.

[0033] By injecting a diluent in this way as opposed to as in SA-SAGD, there may be a higher incremental bitumen volume per unit volume of diluent left (IBDL), as compared to SA-SAGD, as shown in the simulation results below.

[0034] Additionally, by injecting diluent in this way as opposed to as in SA-SAGD, there may be flexibility to take advantage of the diluent price fluctuations.

[0035] The process may also provide an uplift in cumulative bitumen as compared to SA-SAGD for the same cumulative steam and diluent injection of SA-SAGD.

[0036] By injecting diluent in this way, one causes perturbations to, and shrinkage and expansion of, the vapor-bitumen interface. This may be advantageous in terms of bitumen mobilization.

[0037] While the process involves alternating between injection of primarily steam (DSR2) and steam with diluent (DSR1), there is no requirement that these injection periods have repetition in terms of time or composition beyond what is explicitly stated herein. There is also no requirement that DSR1 commences before DSR2.

[0038] The DSR1 may be at least 0.1 greater than DSR2.

[0039] The DSR2 may be less than 0.2, less than 0.1, less than 0.01, or 0.

[0040] The DSR1 may be greater than 0.2 or greater than 0.3.

[0041] Steps (i) and (ii) may use injection pressures within 20% of each other, or within 10 % of one another, or within 5% of one another.

[0042] Steps (i) and (ii) may use injection rates within 5 % of each other, by volume.

[0043] A duration of (i) may be within 10% of that of (ii). A duration of (i) may be at least four times, at least three times, at least two times, at least 1.5 times, at least 1.2 times, or at least 1.1 times, longer than that of (ii).

[0044] The duration of (ii) may be at least 15 days, at least 30 days, at least 45 days, at least 60 days, at least 90 days, at least 150 days, at least 200 days, or at least 300 days.

[0045] The process is a gravity drainage process. Gravity drainage processes are those processes where the mobilizing composition is injected into an upper well and viscous oil drains to a lower well where it is produced. Known gravity drainage processes include SAGD, SA-SAGD, VAPEX, H-VAPEX (each described in the background section).

[0046] The gravity drainage process may involve directional drilling to place two horizontal wells in the viscous oil reservoir ¨ a lower well and an upper well positioned above it. The mobilizing composition may be injected into the upper well to dilute and reduce the viscosity of the viscous oil. The viscous oil, diluent, and condensed steam will then drain downward through the reservoir under the action of gravity and flow into the lower production well, whereby these fluids can be pumped to the surface. At the surface of the well, reduced-viscosity hydrocarbons may be separated from the produced fluids. The reduced-viscosity hydrocarbons may then be diluted with appropriate light hydrocarbons for transport to a refinery or an upgrader.

[0047] The production well may define a greater distance (or average distance) from the surface when compared to the injection well. At least a portion of the production well may be parallel to, or at least substantially parallel to, a corresponding portion of the injection well.
At least a portion of the injection well, and/or of the production well, may include a horizontal, or at least substantially horizontal, portion.

[0048] The diluent may comprise at least one non-polar hydrocarbon with 2 to 30 carbon atoms (in one embodiment at least 50 wt. %). The diluent may comprise at least one C2-C30 alkane (in one embodiment at least 50 wt. %). The diluent may comprise at least one C2-C30 n-alkane (in one embodiment at least 50 wt. %). The diluent may comprise at least one C2-C20 alkane (in one embodiment at least 50 wt. %). The diluent may comprise at least one C2-C20 n-alkane (in one embodiment at least 50 wt. %). The diluent may comprise a least one C3-C7 alkane (in one embodiment at least 50 wt. %). The diluent may comprise propane (in one embodiment at least 50 wt. %). The diluent may comprise at least one C5-C7 cycloalkane (in one embodiment at least 50 wt. %). The diluent may comprise cyclohexane (in one embodiment at least 50 wt. %). The diluent may comprise a mixture of non-polar hydrocarbons, the non-polar hydrocarbons being C2-C30 alkanes, the mixture being substantially aliphatic and substantially non-halogenated (in one embodiment at least 50 wt. %). "Substantially aliphatic and substantially non-halogenated" means less than 10%
by weight of aromaticity and with no more than 1 mole percent halogen atoms.
The level of aromaticity may be less than 5, less than 3, less than 1, or 0 % by weight.
The diluent may comprise a mixture of non-polar hydrocarbons and may be a gas plant condensate comprising at least one C3-C17 n-alkane, at least one C5-C7 cycloalkane, and at least one C6-C8 aromatic hydrocarbon (in one embodiment at least 50 wt. %).

[0049]
The diluent may be a fluid of a lower viscosity and lower density than those of the viscous oil being recovered. Its viscosity may, for example, be 0.2 to 5 cP (centipoise) at room temperature and at a pressure high enough to make it liquid. Its density may be, for example, 450 to 750 kg/m3 at 15 C, and it may be at a pressure high enough to make it liquid. The mixture or the blend of diluent and viscous oil may have a viscosity and a density that is in between those of the diluent and the viscous oil. The diluent may or may not precipitate asphaltenes if its concentration exceeds a critical concentration.
The diluent may be injected as a liquid, as a heated liquid, as a vapor, as a mixture of vapor and liquid, as a supercritical fluid, or as a combination thereof. The diluent injection may be initiated or terminated manually or using an automated system. For constant pressure injection, the steam rate may have to be lowered during diluent injection. For constant rate injection, the steam rate during diluent injection may also have to be lowered to accommodate the diluent injection.

[0050]
The steam may have a quality (defined as the wt. % of total steam present as steam vapor, and the remainder as liquid) of at least 5%, or 10-95%.

[0051]
The mobilizing composition may be injected with other components, such as diesel, to provide flow assurance, or CO2, natural gas, C3+ hydrocarbons, ketones, or alcohols. The mobilizing composition may also be injected with penetration enhancing agents, such as n-propyl acetate or iso-propyl acetate. The mobilizing composition may comprise at least 1 wt. % of n-propyl acetate or iso-propyl acetate or a mixture thereof.

[0052]
The diluent composition may vary during at least one diluent injection period, for instance, starting with heavier diluent and using lighter diluent near the end to optimize bitumen recovery and injected diluent recovery.

[0053]
The process may include preheating or providing thermal energy to at least a portion of the subterranean formation in any suitable manner. The preheating may include electrically preheating the subterranean formation, chemically preheating the subterranean formation, and/or injecting a preheating steam stream into the subterranean formation. The preheating may include preheating any suitable portion of the subterranean formation, such as a portion of the subterranean formation that is proximal to the injection well, a portion of the subterranean formation that is proximal to the production well, and/or a portion of the subterranean formation that defines a vapor chamber that receives the mobilizing composition.

[0054] The mobilizing composition may be injected at an injection temperature. The mobilizing composition may be selected such that its saturated vapor pressure at the injection temperature is less than a threshold maximum pressure of the subterranean formation. This may prevent damage to the subterranean formation and/or escape of the mobilizing composition from the subterranean formation. Threshold maximum pressures may include, for example, a characteristic pressure of the subterranean formation, such as a fracture pressure of the subterranean formation, a hydrostatic pressure within the subterranean formation, a lithostatic pressure within the subterranean formation, a gas cap pressure for a gas cap that is present within the subterranean formation, and/or an aquifer pressure for an aquifer that is located above and/or under the subterranean formation. The above-mentioned pressures may be measured and/or determined in any suitable manner.
For example, this may include measuring a selected pressure with a downhole pressure sensor, calculating the pressure from any suitable property and/or characteristic of the subterranean formation, and/or estimating the pressure, such as via modeling the subterranean formation. The threshold pressures disclosed herein may be selected to correspond to any suitable or desired manner to one or more of these measured or calculated pressures. For example, the threshold pressures disclosed herein may be selected to be greater than, to be less than, to be within a selected range of, to be a selected percentage of, or to be within a selected constant of, etc., one or more of these selected or measured pressures. A threshold pressure may be a user-selected, or operator-selected, value that does not directly correspond to a measured or calculated pressure.

[0055] The threshold maximum pressure also may be related to and/or based upon the characteristic pressure of the subterranean formation. This may include threshold maximum pressures that are less than or equal to 95%, less than or equal to 90%, less than or equal to 85%, less than or equal to 80%, less than or equal to 75%, less than or equal to 70%, less than or equal to 65%, less than or equal to 60%, less than or equal to 55%, or less than or equal to 50% of the characteristic pressure for the subterranean formation and/or threshold maximum pressures that are at least 20%, at least 25%, at least 30%, at least 35%, at least 40%, at least 45%, at least 50%, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, or at least 80% of the characteristic pressure for the subterranean formation. The mobilizing composition may be injected at a pressure of 20% to 95% of a fracture pressure of the reservoir. Suitable ranges may include combinations of any upper and lower amount of characteristic pressure listed above. Additional examples of suitable threshold maximum pressures may include any of the illustrative threshold amounts listed above.

[0056] The mobilizing composition may be injected at a pressure of 400 to 6000 kPa.

[0057] The injection temperature of the mobilizing composition, when it is injected into the injection well, may be 120 to 280 C.

[0058] In various embodiments, the mobilizing composition may be heated, vaporized, condensed and/or recycled. Heating the mobilizing composition may include heating the mobilizing composition in any suitable manner, such as directly heating the mobilizing composition in a surface region.

[0059] Vaporization of the mobilizing composition may be effected by any suitable system or structure above ground or downhole.

[0060] Condensing the mobilizing composition within the subterranean formation may include condensing any suitable portion of the mobilizing composition to release a latent heat of condensation of the mobilizing composition, heat the subterranean formation, heat the viscous oil, and/or generate the reduced-viscosity hydrocarbons within the subterranean formation. The condensing may include condensing a majority, at least 50 wt.
%, at least 60 wt. %, at least 70 wt. 'Yo, at least 80 wt. %, at least 90 wt. (Yo, at least 95 wt. %, at least 99%, or substantially all of the mobilizing composition within the subterranean formation. The condensing may include regulating a temperature within the subterranean formation to facilitate, or permit, the condensing.

[0061] At the surface of the well, the mobilizing composition may be separated from the produced fluids, purified, and recycled into the process.

[0062] Light hydrocarbon gases may also be separated from the produced fluids and may include hydrocarbons and/or carbon compounds with four or fewer carbon atoms, such as methane, ethane, propane, and/or butane. Light hydrocarbon gases may be used upstream in the process, for instance, as fuel to heat the mobilizing composition prior to injection.

[0063] Recycling the mobilizing composition may include recycling the mobilizing composition in any suitable manner. The recycling may include separating at least a separated portion of the mobilizing composition from the reduced-viscosity hydrocarbon mixture and/or from the reduced-viscosity hydrocarbons. The recycling also may include utilizing at least a recycled portion of the mobilizing composition as, or as a portion of, the hydrocarbon solvent mixture and/or returning the recycled portion of the condensate to the subterranean formation via the injection well. The recycling may include purifying the recycled portion of the mobilizing composition prior to utilizing the recycled portion of the mobilizing composition and/or prior to returning the recycled portion of the mobilizing composition to the subterranean formation.

[0064] Separation of the produced fluid may be effected in any suitable separation system or structure, such as a single stage separation vessel, a multistage distillation assembly, a liquid-liquid separation or extraction assembly and/or any suitable gas-liquid separation, or extraction assembly.

[0065] Purification of the mobilizing composition may be effected in any suitable system or structure, such as any suitable liquid-liquid separation or extraction assembly, any suitable gas-liquid separation or extraction assembly, any suitable gas-gas separation or extraction assembly, a single stage separation vessel, and/or any suitable multistage distillation assembly.

[0066] Producing the viscous oil and at least a fraction of the mobilizing composition may include producing the reduced-viscosity hydrocarbons via any suitable production well, which may extend within the subterranean formation and/or may be spaced apart from the injection well. This may include flowing the reduced-viscosity hydrocarbons from the subterranean formation, through the production well, and to, proximal to, and/or toward the surface region.

[0067] The producing may include producing asphaltenes. The asphaltenes may be present within the subterranean formation and/or within the viscous oil. The asphaltenes may be produced as a portion of the reduced-viscosity hydrocarbons (and/or the reduced-viscosity hydrocarbons may include, or comprise, asphaltenes). The injecting may include injecting into a stimulated region of the subterranean formation that includes asphaltenes, and the producing may include producing at least a threshold fraction of the asphaltenes from the stimulated region. This may include producing at least 10 wt%, at least 20 wt%, at least 30 wt%, at least 40 wt%, at least 50 wt%, at least 60 wt%, at least 70 wt%, at least 80 wt%, or at least 90 wt% of the asphaltenes that are, or were, present within the stimulated region prior to the injecting.

[0068] Simulation

[0069] A simulation was run by comparing the IBDL (incremental bitumen per unit volume diluent left) of a process as described herein (labelled CD-SAGD in Figure 2) with a SA-SAGD process. For the present process, the DSR1 was set at 0.4 during a 300-day , period, followed by a DSR2 of 0 in a subsequent 300-day period. For SA-SAGD, the DSR
was set at 0.2 throughout the process. Figure 2 illustrates the results showing average IBDL
as a function of time. An IBDL uplift of as high as 8 STm3 bitumen/ STm3 diluent (absolute) over SA-SAGD is achieved early in the process. During DSR2 injection, the steam rate increases to offset the lack of diluent so as to keep a constant pressure of 1500 kPa.
Increased steam rate delivers more latent heat than in DSR1 injection. The vapor chamber is depleted in a short time frame (about 5 days) after diluent is halted.

[0070] It should be understood that numerous changes, modifications, and alternatives to the preceding disclosure can be made without departing from the scope of the disclosure. The preceding description, therefore, is not meant to limit the scope of the disclosure. Rather, the scope of the disclosure is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.

Claims (45)

CLAIMS:

1. A gravity drainage process for recovering viscous oil from an underground reservoir, the process comprising:
(a) injecting a mobilizing composition comprising steam and a diluent through an injection well into the reservoir to mobilize the viscous oil;
wherein the mobilizing composition is alternated between:
a first diluent to steam volume ratio DSR1 of 0.05-0.5; and a second diluent to steam volume ratio DSR2 of 0-0.3; and wherein the DSR1 is at least 0.05 greater than the DSR2; and (b) producing the viscous oil and at least a fraction of the mobilizing composition from the reservoir through a production well.

2. The process of claim 1, wherein the DSR1 is at least 0.1 greater than DSR2.

3. The process of claim 1 or 2, wherein the DSR2 is less than 0.2.

4. The process of claim 1 or 2, wherein the DSR2 is less than 0.1.

5. The process of claim 1 or 2, wherein the DSR2 is less than 0.01.

6. The process of claim 1 or 2, wherein the DSR2 is 0.

7. The process of any one of claims 1 to 7, wherein the DSR1 is greater than 0.2.

8. The process of any one of claims 1, wherein the DSR1 is greater than 0.3.

9. The process of any one of claims 1 to 8, wherein (i) and (ii) use injection pressures within 20% of each other.

10. The process of any one of claims 1 to 8, wherein (i) and (ii) use injection pressures within 10% of each other.

11. The process of any one of claims 1 to 8, wherein (i) and (ii) use injection pressures within 5% of each other.

12. The process of any one of claims 1 to 8, wherein (i) and (ii) use injection rates within % of each other, by volume.

13. The process of any one of claims 1 to 8, wherein a duration of (i) is within 10% of that of (ii).

14. The process of any one of claims 1 to 8, wherein a duration of (i) is at least four times longer than that of (ii).

15. The process of any one of claims 1 to 8, wherein a duration of (i) is at least three times longer than that of (ii).

16. The process of any one of claims 1 to 8, wherein a duration of (i) is at least two times longer than that of (ii).

17. The process of any one of claims 1 to 8, wherein a duration of (i) is at least 1.5 times longer than that of (ii).

18. The process of any one of claims 1 to 8, wherein a duration of (i) is at least 1.2 times longer than that of (ii).

19. The process of any one of claims 1 to 8, wherein a duration of (i) is at least 1.1 times longer than that of (ii).

20. The process of any one of claims 1 to 8, wherein a duration of (ii) is at least 15 days.

21. The process of any one of claims 1 to 8, wherein a duration of (ii) is at least 30 days.

22. The process of any one of claims 1 to 8, wherein a duration of (ii) is at least 45 days.

23. The process of any one of claims 1 to 8, wherein a duration of (ii) is at least 60 days.

24. The process of any one of claims 1 to 8, wherein a duration of (ii) is at least 90 days.

25. The process of any one of claims 1 to 8, wherein a duration of (ii) is at least 150 days.

26. The process of any one of claims 1 to 8, wherein a duration of (ii) is at least 200 days.

27. The process of any one of claims 1 to 8, wherein a duration of (ii) is at least 300 days.

28. The process of any one of 1 to 27, wherein the steam has a quality of at least 5%.

29. The process of any one of claims 1 to 27, wherein the steam has a quality of 10-95 %.

30. The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt. % of at least one non-polar hydrocarbon with 2 to 30 carbon atoms.

31. The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt. % of at least one C2-C30 alkane.

32. The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt. % of at least one C2-C30 n-alkane.

33. The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt. % of at least one C2-C20 alkane.

34. The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt. % of at least one C2-C20 n-alkane.

35. The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt % of at least one C3-C7 alkane.

36. The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt. % propane.

37. The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt. % of at least one C5-C7 cycloalkane.

38. The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt. % cyclohexane.

39 The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt. % of a mixture of non-polar hydrocarbons, the non-polar hydrocarbons being alkanes, the mixture being substantially aliphatic and substantially non-halogenated.

40. The process of any one of claims 1 to 29, wherein the diluent comprises at least 50 wt % of a mixture of non-polar hydrocarbons and is a gas plant condensate comprising at least one C3-C17 n-alkane, at least one C5-C7 cycloalkane, and at least one C6-aromatic hydrocarbon

41. The process of any one of claims 1 to 29, wherein the mobilizing composition comprises at least 1 wt. % of n-propyl acetate or iso-propyl acetate or a mixture thereof.

42. The process of any one of claims 1 to 29, wherein the diluent composition varies in at least one diluent injection period.

43 The process of any one of claims 1 to 42, wherein the mobilizing composition is injected into the injection well at a temperature of 120-280°C.

44. The process of any one of claims 1 to 43, wherein the mobilizing composition is injected at a pressure of 20% to 95% of a fracture pressure of the reservoir.

45 The process of any one of claims 1 to 44, wherein the mobilizing composition is injected at a pressure of 400 to 6000 kPa.