CA2915571C - Gravity drainage process for recovering viscous oil using near-azeotropic injection - Google Patents

Abstract

Generally, described herein is a gravity drainage process for recovering viscous oil from an underground reservoir, the process comprising: (a) injecting steam and a solvent into the reservoir to mobilize the viscous oil, wherein the solvent is in a vapor state, and the steam and solvent are injected wherein the solvent molar fraction of the combined steam and solvent is 70-100% of the azeotropic solvent molar fraction of the steam and the solvent as measured at the reservoir operating pressure; and (b) producing at least a fraction of the mobilized oil, the solvent, and water.

Description

GRAVITY DRAINAGE PROCESS FOR RECOVERING VISCOUS OIL USING
NEAR-AZEOTROPIC INJECTION
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] Solvents have been used for both in situ and surface extraction processes to dilute viscous oil. Solvents 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.

[0007] 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).

[0008] Other steam-based thermal processes include Solvent-Assisted Steam-Assisted Gravity Drainage (SA-SAGD), an example of which is described in Canadian Patent No. 2,323,029 (Nasr); 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. These processes employ a solvent with steam.

[0009] Solvent-dominated recovery processes (SDRPs) are another category of in situ processes, where solvent is used to reduce the viscosity of the viscous oil. At the present time, solvent-dominated recovery processes (SDRPs) are rarely used to produce highly viscous oil. Vapor Extraction (VAPEX) is an example of a SDRP, which is described in U.S.
Patent No. 5,899,274 (Frauenfeld). In certain described SDRPs, the solvent is heated as in, for example, heated-VAPEX (H-VAPEX), which is a VAPEX process using a heated solvent (Butler 1991 and 1993).

[0010] It is desirable to provide an improved or alternative gravity drainage process 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 comprising: (a) injecting steam and a solvent into the reservoir to mobilize the viscous oil, wherein the solvent is in a vapor state, and the steam and solvent are injected wherein the solvent molar fraction of the combined steam and solvent is 70-100% of the azeotropic solvent molar fraction of the steam and the solvent as measured at the reservoir operating pressure; and (b) producing at least a fraction of the mobilized oil, the solvent, and water.

[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 for recovering viscous oil from an underground reservoir.

[0015] Fig. 2 is a plot of the phase behavior for a steam-hexane system.

[0016] Fig. 3 is a series of contour plots comparing reservoir properties for heated pentane (C5 H-VAPEX) and heated pentane with steam at the azeotrope concentration (C5 Azeotropic H-VAPEX), at the same operating pressure.

[0017] Fig. 4 is a graph of cumulative solvent to oil ratio (CS010R) versus time for H-VAPEX and Azeotropic H-VAPEX utilizing C5 and C7 injection.

[0018] Fig. 5 is a graph of cumulative produced oil over retained solvent versus time for Heated Vapex and Azeotropic H-VAPEX utilizing C5 and C7 injection.

[0019] Fig. 6 is a graph of oil recovery versus time for H-VAPEX and Azeotropic Heated Vapex utilizing C5 and 07 injection.

[0020] Fig. 7 is a graph of semi-azeotropic behaviour of a steam-multicomponent solvent (diluent) system.

[0021] Fig. 8 is a graph of cumulative solvent to oil ratio (CSõIOR) versus time in high and low initial water saturation reservoir conditions.

[0022] Fig. 9 graph of produced oil to retained solvent versus time in high and low initial water saturation reservoir conditions.

[0023] Fig. 10 is a collective dew point temperature plots for vapor mixtures of individual hydrocarbon solvents of C4-C9 with water as a function of solvent mole fraction.

[0024] 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

[0025] 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.

[0026] 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.

[0027] 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.

[0028] "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%).
In addition, bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. A 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.

[0029] "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.

[0030] 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 22.3 to about 100. The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes.

[0031] 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.

[0032] 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.

[0033] "Pressure" is the force exerted per unit area by the gas on the walls of the volume. Pressure may be shown in this disclosure as pounds per square inch (psi), kilopascals (kPa) or megapascals (MPa). "Atmospheric pressure" refers to the local pressure of the air. "Absolute pressure" (psia) refers to the sum of the atmospheric pressure (14.7 psia at standard conditions) plus the gauge pressure. "Gauge pressure"
(psig) refers to the pressure measured by a gauge, which indicates only the pressure exceeding the local atmospheric pressure (i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia). The term "vapor pressure" has the usual thermodynamic meaning.
For a pure component in an enclosed system at a given pressure, the component vapor pressure is essentially equal to the total pressure in the system. Unless otherwise specified, the pressures in the present disclosure are absolute pressures.

[0034] 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.

[0035] 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.

[0036] "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.

[0037] 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.

[0038] 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.

[0039] Steam to Oil Ratio ("SOR") is the ratio of a volume of steam (in cold water equivalents) required to produce a volume of oil. Cumulative SOR ("CSOR") is the average volume of steam (in cold water equivalents) over the life of the operation required to produce a volume of oil. Instantaneous ("ISOR") is the instantaneous rate of steam (in cold water equivalents) required to produce a volume of oil. SOR, CSOR, and ISOR are calculated at standard temperature and pressure ("STP", 15 C and 100kPa or 60 F and 14.696 psi).

[0040] Likewise, Solvent to Oil Ratio ("SoIOR") is the ratio of a volume of solvent (in cold liquid equivalents) required to produce a volume of oil. Cumulative SoIOR
("CSolOR") is the average volume of solvent (in cold liquid equivalents) over the life of the operation required to produce a volume of oil. Instantaneous ("ISolOR") is the instantaneous rate of solvent required to produce a volume of oil. SolOR, CS010R, and ISolOR are calculated at STP.

[0041] "Azeotrope" means the thermodynamic azeotrope" as described further herein.

[0042] Described herein, with reference to Fig. 1, is a gravity drainage process for recovering viscous oil from an underground reservoir, the process comprising:
(a) injecting (102) steam and a solvent into the reservoir to mobilize the viscous oil, wherein the solvent is in a vapor state, and the steam and solvent are injected wherein the solvent molar fraction of the combined steam and solvent is 70-100% of the azeotropic solvent molar fraction of the steam and the solvent as measured at the reservoir operating pressure; and (b) producing (104) at least a fraction of the mobilized oil, the solvent, and water.

[0043] For ease of reference, the above described injection is referred to herein as "near-azeotropic injection".

[0044] Prior to step (a), a target reservoir operating pressure may be selected and a solvent may be selected which is a vapor at this pressure. Then, an azeotropic solvent molar fraction at the target reservoir operating pressure and the azeotropic temperature at the target reservoir operating pressure may be determined. By way of example, Fig.

graphically illustrates the azeotrope for a hexane-water system at a pressure of 2.5 MPA
where the azeotropic solvent molar ratio is 0.64 and the azeotropic temperature is 182 C.
Continuing with this example, 70-100% of an azeotropic solvent molar fraction of 0.64 is 0.45-0.64. In this example, near-azeotropic injection means using a solvent molar fraction of 0.45-0.64 in vapor mixture of hexane and steam.

[0045] The solvent molar fraction may alternatively be 80-100% or 90-100%
of the azeotropic solvent molar fraction at the reservoir operating pressure.

[0046] For practical purposes, the selection of the solvent molar fraction and the operating pressure constrains the temperature of the vapor phase assuming saturated conditions.

[0047] In practice, as will become more apparent by the description below, one may select a solvent that has a favorable operating temperature and solvent molar fraction at the azeotrope condition when combined with steam. A favorable operating temperature is a temperature that results in economic production rates while delivering adequate or good thermal efficiency. A favorable solvent molar fraction is one that reduces the Solvent to Oil Ratio (SolOR) as compared, for instance, with a heated VAPEX process.

[0048] A physical phenomenon that increases the 5010R for heated VAPEX
and therefore reduces the efficiency of the process is that when a heated solvent is injected, it vaporizes all the in-situ water, including a large fraction of the bound or irreducible water, in the vicinity of the injector.

[0049] As a result of this vaporization, at the boundary of the VAPEX
chamber, both water and solvent condense together under conditions that are at or close to the azeotrope.
This is a lower temperature than that of the injected heated solvent.
Furthermore, because the boundary is relatively narrow, the idealistic benefits of a solvent-only process with no flowing water are not practically achieved.

[0050] An important feature of the azeotrope pressure-temperature conditions is that the two fluids largely behave as a single fluid. That is, both fluids condense together in the same molar ratios of concentrations as they exist in the gas. Additionally, there is no tendency for either fluid to preferentially flash from the liquid state into the vapor state (i.e.
vaporize additional in-situ water in the vicinity of the injector well). As such, the combined fluids can behave effectively as a single fluid with modified properties compared to either single fluid.

[0051] Water is a very effective working fluid for transferring heat whereas hydrocarbon solvents tend to be relatively inefficient working fluids for that purpose.
Conversely, hydrocarbon solvents are very effective viscosity reducing agents for heavy oils whereas water is practically immiscible. However, mixtures of hydrocarbons and water at the azeotrope behave largely as a single fluid with beneficial qualitative features of both the water and the hydrocarbon solvent.

[0052]
Without intending to be bound by theory, a near optimal injection ratio of solvent and steam vapor, where the fluid enters the reservoir, may be a ratio that is at or close to the azeotrope for the solvent-water mixture. Consider the case of injecting a mixture of water and hexane at 2.5 MPa. As shown in Figure 2, the molar fraction of solvent at the azeotrope is approximately 0.64 or 64% so that the water molar fraction is 0.36 or 36%. On mass basis, this converts to a 10.5% water fraction and on a volumetric basis this converts to a 7% water fraction. The heat of vaporization of hexane at the azeotrope temperature is approximately 220 kJ/kg and that for water is about 2000 kJ/kg. The combined fluids have an effective heat capacity of about 410 kJ/kg. As a result, the mass of fluid required to deliver the same heat to the reservoir is approximately half and accordingly the operating solvent-to-oil ratio would be expected to be about half.

[0053] If hexane vapor at 2.5 MPa is injected into the reservoir it will be at a temperature of 220 C (see Figure 2). As the hot hydrocarbon vapor enters the reservoir and enters pore spaces with liquid water, the water will vaporize and a fraction of the solvent will condense. The temperature will also decline until the water-hydrocarbon system in vapor phase finds an equilibrium point near the azeotrope. At that point, any additional condensation will result in the water and solvent condensing with the mole fraction ratio of the azeotrope. The solvent-steam mixture that progresses to the boundary of the vapor chamber will be a mixture at or close to the azeotrope. This phenomenon has several of important implications:

[0054] 1.
A significant volume of reservoir rock will be increased in temperature to as much as 220 C which is an additional heat sink compared to injection at the azeotrope temperature of 182 C.

[0055] 2.
Due to the hotter injection fluids and conductive heating in the vicinity of the producer, produced fluids will be at a higher temperature. Hence more heat will be produced back from the reservoir which is less thermally efficient.

[0056] 3.
Vaporized solvent is condensing in the reservoir in order to vaporize water which is then carrying the heat to the boundary of the steam chamber, which is not effectively using the benefits of the solvent. That is, as described above, hydrocarbon solvents tend to be relatively inefficient working fluids for transferring heat but are very effective viscosity reducing agents.

[0057] 4. A region will develop around the injector which is nearly completely water free (sometimes called a desiccation zone). It is possible that this could be advantageous in some circumstances. However it could also be a disadvantage due to factors such as salt or scale deposition and pore plugging, fines movement causing pore plugging and a shift from a water wet system to an oil wet system resulting in less favorable residual oil saturations and relative permeabilities.

[0058] Practical implications of using near-azeotropic injection are partly illustrated by the results of some analyses that are provided in Tables 1 and 2. Table 1 shows the azeotropic temperatures and molar concentrations for pentane, hexane and heptane at 1 MPa and 2.5 MPa pressures. Table 1 also provides mass fractions, standard volumetric fractions and enthalpies for steam and solvent at their respective, ideal partial pressures for the azeotropic temperature. It can be seen from Table 1 that the azeotrope molar concentration of steam increases significantly from lighter to heavier solvents. However, for a given solvent there is limited variation with pressure. It can also be seen from Table 1 that the heat of vaporization for the combined fluids increases much more substantially for heavier solvents at the azeotrope than it does for the lighter solvents. Table 2 lists an assumed injected solvent-to-oil ratio (SolOR) for each of the cases shown in Table 1. For illustrative purposes, the assumed SolOR increases with solvent type and pressure proportionally to the difference between the azeotrope operating temperature and an assumed initial reservoir temperature of 7 C. The fifth and sixth columns of the Table 2 show the equivalent combined steam to oil ratio (SOR) and SoIOR when operating with azeotropic injection. In all cases, the required solvent recirculation is significantly reduced.
For pentane, it is estimated to be about a 23% reduction at 1 MPa. The benefit is predicted to increase with pressure and with the use of heavier solvents. The required solvent recycling is predicted to be reduced by 50% or more for heavier solvents.

[0059] Table 1. Properties for steam-solvent Design Parameters Azeotrope Properties (Approximate) Steam -Solvent Ratios Thermal Properties Solvent Pressure Temperature Steam Solvent Steam Solvent Steam Solvent Steam Heat Solvent Heat Combined Molar Molar Mass Mass Volume Volume of of Fluid Heat of Fraction Fraction Fraction Fraction Fraction Fraction Vaporization Vaporization Vaporization Mpa deg. C. kJ/kg kJ/kg kJ/kg Pentane 1 116 0.16 0.84 0.045 0.955 0.029 0.971 Hexane , 1 140.5 0.34 0.66 0.097 0.903 0.066 0.934 Heptane 1 155.7 0.54 0.46 0.174 0.826 0.125 0.875 Pentane 2.5 157.7 0.2 0.8 0.059 0.941 0.038 0.962 Hexane 2.5 182 0.36 0.64 0.105 0.895 0.071 0.929 Heptane 2.5 196.9 0.54 0.46 0.174 0.826 0.125 0.875 1951 210 513

[0060] Table 2. Representative Solvent-only and Isotropic Steam-Solvent Ratios Solvent Pressure Temperature Solvent-only Azeotrope Combined SolOR Reduction Mpa deg. C. SdOR Steam SOR Solvent SoiOR %
Pentane 1 116 8.8 0.20 6.8 23 Hexane 1 140.5 12.1 0.49 7.0 42 Heptane 1 155.7 15.6 0.86 6.0 61 Pentane 2.5 157.7 18.6 0.46 11.9 36 Hexane 2.5 182 19.4 0.78 10.1 48 Heptane 2.5 196.9 21.4 1.18 8.3 61

[0061] Simulation Results

[0062] The concept described herein is examined by a numerical simulation in a typical Athabasca reservoir. Figure 3 shows the reservoir properties map for single component solvent H-VAPEX (n-05 or normal-pentane) and Azeotropic H-VAPEX
("AH-VAPEX") at the same operating pressure condition. As seen in the temperature map, the average temperature in the depleted zone for AH-VAPEX with no near wellbore heating is lower than the H-VAPEX case. It is also noted from the water saturation map that in AH-Vapex, the co-injected steam at the azeotropic concentrations inhibited the vaporization of the initial in-situ water and minimized solvent condensation to provide the required energy for water vaporization. The improvement in SolOR for this case is shown in Figure 4. Figure 4 also shows the improvement in the SoIOR for AH-VAPEX in azeotropic steam-nC7 (steam-normal-heptane) system. As described above, the azeotropic systems for heavier solvents results in a higher energy content in the injected azeotropic fluid compared to lighter solvents and therefore results in a higher reduction in SolOR, as is shown Table 1 and Table 2 and in Figure 4.

[0063] The vaporized in-situ water in H-VAPEX in the depleted zone is replaced with hydrocarbon liquid phase which is mainly condensed liquid solvent. Prevention (or limitation) of in-situ water vaporization in the AH-VAPEX results in reduction of liquid hydrocarbon phase in the depleted chamber and therefore reduction in solvent retention in the depleted reservoir. This is seen in the liquid phase saturation map in Figure 3 as a reduced residual liquid phase saturation region within depleted chamber in AH-VAPEX compared to H-VAPEX. The reduction in solvent retention in reservoir is reflected in Figure 5 in terms of an increase in produced oil-to-retained solvent ratio (PBRSR). It is noted that nC7 AH-VAPEX has a higher increase in PBRSR compared to the nC5 AH-VAPEX. The oil recovery rates in the azeotropic H-VAPEX and H-VAPEX is generally similar as shown in Figure 6.

[0064] For field applications, the commercially available solvents are generally a mixture of hydrocarbon compounds rather than a pure single compound.
Commercial gas condensate, diluents, and naphtha are among the used solvents. The phase behavior of these multicomponent solvents with steam is more complicated than the single compound solvents. However, their phase behavior when mixed with steam can be considered as superposition of individual pure compounds behavior. These systems exhibit a semi-azeotropic behavior with a minimum boiling characteristic similar to single compound solvents. Figure 7 shows the semi-azeotropic behavior of steam-diluent system.
The minimum dew point temperature in this system is the co-condensation point of steam-solvent components at a semi-azeotriopic water concentration similar to azeotropic point in a single component solvent-steam system. Figures 8 and 9 show the enhancement effects in SoIOR
and PBRSR of semi-azeotropic steam-diluent AH-VAPEX compared to diluent H-VAPEX.
Figures 8 and 9 also compare the SoIOR and PBRSR improvement in a high initial water saturation reservoir (lean reservoir, So=0.61), compared to an Athabasca reservoir with typical initial water saturation (So=0.87). Oil saturation of "So" is a fraction of oil volume based on pore volume.

[0065] Potential advantages in terms of efficiency of near-azeotropic injection in AH-VAPEX relative to heated VAPEX include:

[0066] 1. The average temperatures in the vapor chamber are reduced while the temperature at the chamber boundary remains near the azeotrope temperature.

[0067] 2. The temperatures at the top of the steam chamber will also be reduced resulting in less heat loss to the overburden.

[0068] 3. There is virtually no thermodynamic tendency to vaporize water (mobile, immobile or bound) within the vapor chamber. This eliminates (or reduces) the complexities and potential problems associated with a dry (or desiccation) zone.

[0069] 4. Preventing in-situ water (mobile, immobile or bound) vaporization in the near-azeotropic injection results in a reduction of the liquid hydrocarbon phase in the depleted chamber, reduction in solvent concentration in the vapor phase in the depleted chamber, and therefore a reduction in solvent retention in reservoir.

[0070] 5. Since water is a much more effective thermal working fluid than hydrocarbon solvents, the combined fluids have a greater average working enthalpy associated with the condensation of the vapor.

[0071] 6. Oil rates from the process will remain largely unchanged since in either process water is condensing at the boundary with the solvent at similar water to solvent ratios.

[0072] 7. Heat loss from the wellbore can result in significant condensation of fluids.
An additional volume or molar concentration of water can be added to the injected stream at surface such that water preferentially condenses in the wellbore and injection at the sand face is then near the azeotrope.

[0073] 8. It may also be advantageous to inject vapor at the sand face with a water concentration marginally above the azeotrope concentration so that, for example, in later life, primarily water condenses at the top of the reservoir. In particular, solvent that condenses on the top of the steam chamber and drains down is not as effective as solvent that condenses on the oil interface. If one injects above the steam azeotrope concentration, it will be water that condenses first at the top of the steam chamber. As a result, the optimal molar fraction of steam may start at or near the azeotrope and increase with time.
There will likely be a reduction in the volume of vapor being injected into the reservoir which may allow for smaller wellbore sizes and tubulars.

[0074] Since thermal separation will be required in order to recycle solvent, process facilities may be designed to flash water at a desired concentration.

[0075] Overall, advantages of near-azeotropic injection may include reductions in the solvent-to-oil ratio (SolOR) relative to solvent-only heated VAPEX, a potentially broader applicability to higher initial water saturation resources, a reduction in solvent storage, and an improvement in the produced oil-to-retained solvent ratio.

[0076] The solvent 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 950 kg/m3 at 15 C and at a pressure high enough to make it liquid. The mixture or the blend of solvent and viscous oil may have a viscosity and a density that is in between those of the solvent and the viscous oil. The solvent may or may not precipitate asphaltenes if its concentration exceeds a critical concentration.

[0077] The solvent may be a single hydrocarbon compound or a mixture of hydrocarbon compounds having a number of carbon atoms in the range of Cl to C30+. The solvent may have at least one hydrocarbon in the range of C3 to C12 and this at least one hydrocarbon may comprise at least 50 wt. % of the solvent. The mixture may have aliphatic, naphthenic, aromatic, and/or olefinic fractions.

[0078] The solvent may comprise at least at least 50 wt. A) of one or more C3-C12 hydrocarbons, at least 50 wt. % of one or more C4-C10 hydrocarbons, at least 50 wt. % of one or more C5-C7 hydrocarbons, or a natural gas condensate or a crude oil refinery naphtha.

[0079] The solvent may comprise alkanes, iso-alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and/or olefin hydrocarbons. In general, normal alkanes may have a highest tendency of causing phase separation of asphaltenes, with a decreasing tendency for phase separation being observed when moving from iso-alkanes to naphthenic hydrocarbons to aromatic hydrocarbons.

[0080] Upon selecting an operating temperature range (for instance 60-140 C), a solvent may be selected that has a vapor pressure that does not exceed a selected maximum pressure.

[0081] The solvent may be chosen to be compatible with the desired reservoir operating pressure such that economics of the process will be optimized through a combination maximizing the producing oil rate, minimizing the injected solvent to oil ratio, minimizing the injected steam to oil ratio, maximizing the produced oil-to-retained solvent ratio, and selecting lower cost-of-supply solvents.

[0082] The steam may have a quality (defined as the wt. % of total steam present as steam vapour, and the remainder as liquid) of at least 5%, or 10-100%. The steam may be present in a near-azeotropic injection stream in an amount of 2-85 vol. % and solvent may be present in an amount of 15-98 vol.%, both calculated at standard temperature and pressure (STP) and in cold liquid equivalents. The volume percentage range must be determined for each solvent at given pressure. By way of example, the cold liquid equivalent volume percentage range for C4 is 2-7 vol% and for C12 is 80-85 vol%.

[0083] The solvent molar fraction may be decreased over time.

[0084] The steam and solvent may be injected with other components, such as:
diesel, aromatic light catalytic gas oil, or another solvent, to provide flow assurance, or CO2, natural gas, C3+ hydrocarbons, ketones, or alcohols.

[0085] The process may further comprise separating and reusing the solvent and water in a separation, purification, revaporization and reinjection facility.

[0086] 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 solvent and steam may be injected into the upper well to dilute and reduce the viscosity of the viscous oil. The viscous oil, solvent, 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, all or a fraction of the solvent or a mixture of reduced-viscosity hydrocarbons may be separated from the produced fluids and reused as the solvent for injection with the steam.
All or a fraction of the solvent or reduced-viscosity hydrocarbons may also remain mixed with the oil to aid in transport to a refinery or an upgrader.

[0087] 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 solvent and steam prior to injection.

[0088] The operating pressure for the process may be informed by many external factors such as needing to be close to the pressure of nearby water zones, gas zones or other operations such that the injected fluids do not migrate away from the production well and unwanted fluids do not migrate to the production well. Additionally, the potential for formation fracturing may limit the maximum pressure. As such, the choice of solvent may be driven by the acceptable range of operating pressures

[0089] A
threshold maximum pressure also may be related to and/or based upon the characteristic pressure of the subterranean formation. The reservoir operating pressure may be 5-95% of a fracture pressure of the reservoir, or 0.2 to 4 MPa, or 1 to 2.5 MPa.

[0090] The injection temperature of the solvent and steam, when it is injected into the injection well, may be affected by the selection of the molar concentration of the steam and the solvent once the optimal solvent has been selected. The thermodynamic phase behavior will dictate that injection temperature is the saturation temperature corresponding to the molar concentration of the steam and the solvent in absence of any degrees of superheat.
The molar concentration of the steam will most often be higher than the azeotropic concentration in order to most efficiently manage heat losses.
Correspondingly, the temperature will be higher than the azeotropic temperature as well. The injection temperature may be 30-250 C or 80-150 C.

[0091] The heat of vaporization of the hydrocarbon solvents is much smaller than steam. Therefore, one may add excess steam to an azeotropic mixture of hydrocarbon vapor and steam. The thermodynamic phase behavior dictates that the excess steam will condense first to provide the required energy for heat losses. By way of example, a mixture of steam and hydrocarbon vapor may be prepared at a central processing facility with a solvent molar fraction (X1) less than the azeotropic vapor solvent molar fraction (Xaz) and a temperature (Ti) greater than the azeotropic temperature (Taz). As the mixture flows through the pipelines toward the wellhead, some of excess steam will condense due to heat losses. At the wellhead, the vapor mixture may have a higher solvent molar fraction (X2, i.e.
X2>X1>Xaz) and a lower temperature (T2, i.e. T2<T1). At the wellhead, preferably X2>Xaz and T2>Taz. As the mixture flows down the well, some of the excess steam will again condense due to heat losses. At the sand face, the vapor mixture may have a solvent molar fraction (X3) where X3>X2 and a temperature (T3) where T3<T2. Preferably, at the sand face X3>Xaz and T3>Taz. In this way, one can inject the mixture at the sand face with some extra steam as compared to an azeotropic mixture to provide the energy required to account for heat losses to the overburden. Heaters can also be utilized on the surface or downhole to add some degree of superheat to the solvent and vapor mixture in order to ensure single phase flow. Examples are surface heaters and downhole electrical heaters.
Therefore, the solvent and steam vapor mixture may be injected at 1-50 C or 1-20 C of superheat, measured at the sand face, with respect to the saturation temperature of the solvent molar fraction at the reservoir operating pressure.

[0092] As described above, near-azeotropic injection of solvent and steam means using a solvent molar fraction of 70-100% of the azeotropic solvent molar fraction.
Simulation results have shown than the total injected energy per volume of bitumen produced and the bitumen production rate are not be considerably affected by varying the composition of the injected fluid in this range. As an example, for C5 (pentane) one may inject with a solvent molar fraction of 0.62-0.88, and for C9 (nonane) one may inject with a solvent molar fraction of 0.13-0.18, both at a pressure of 500 kPa. These compositions translate to different dew point temperature ranges for each solvent, and as illustrated in Figure 10, namely, 87-119 C for C5, and 145-147 C for C9. In general, as pressure increases the temperature range corresponding to 70% to 100% of the azeotropic solvent molar fraction becomes narrower.

[0093] 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.

[0094] Purification of the solvent 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.

[0095] Vaporization of the solvent may be effected by any suitable system or structure above ground or downhole.

[0096] The injection well may be spaced apart from the production well.
The production well may extend at least partially below the injection well, may extend at least partially vertically below the injection well, and/or 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.

[0097] 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 solvent and steam.

[0098] Heating the solvent may include directly heating the solvent in a surface region or using the co-injection with the steam.

[0099] Condensing the solvent and steam within the subterranean formation may include condensing any suitable portion of the solvent and steam to release a latent heat of condensation of the solvent and steam, 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. %, at least 80 wt. %, at least 90 wt. %, at least 95 wt. %, at least 99 wt. %, or substantially all of the solvent and steam within the subterranean formation.
The condensing may include regulating a temperature within the subterranean formation to facilitate, or permit, the condensing.

[00100] Producing the reduced-viscosity hydrocarbons 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.

[00101] 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. The fractions of the asphaltenes that are produced and left in the reservoir is a function of the operating temperature, pressure and the choice of solvents. The determination of these parameters may be influenced by the fraction of asphaltenes that is produced and associated value of the produced hydrocarbons.

[00102] Recycling the solvent may include recycling the solvent in any suitable manner. The recycling may include separating at least a separated portion of the solvent 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 solvent 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 solvent prior to utilizing the recycled portion of the solvent and/or prior to returning the recycled portion of the solvent to the subterranean formation.

[00103] The properties of the azeotropic mixture which condenses at the boundary of the vapour chamber are strongly influenced by the lightest hydrocarbons present in the injected solvent so the recycling process may have facilities designed to specifically remove the lightest components.

[00104] 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 (20)

CLAIMS:

1. A gravity drainage process for recovering viscous oil from an underground reservoir, the process comprising:
(a) injecting steam and a solvent into the reservoir to mobilize the viscous oil, wherein the solvent is in a vapor state, and the steam and solvent are injected wherein the solvent molar fraction of the combined steam and solvent is 70-100% of the azeotropic solvent molar fraction of the steam and the solvent as measured at the reservoir operating pressure; and (b) producing at least a fraction of the mobilized oil, the solvent, and water;
wherein the solvent comprises at least 50 wt. % of one or more C3-C12 hydrocarbons.

2. The process of claim 1, further comprising, prior to step (a):
selecting a target reservoir operating pressure;
selecting a solvent which is a vapor at the target reservoir operating pressure; and determining the azeotropic solvent molar fraction at the target reservoir operating pressure.

3. The process of claim 1, wherein the solvent molar fraction is 80-100% of the azeotropic solvent molar fraction at the reservoir operating pressure.

4. The process of claim 1 or 2, wherein the solvent molar fraction is 90-100% of the azeotropic solvent molar fraction at the reservoir operating pressure.

5. The process of any one of claims 1 to 4, wherein the steam and solvent are injected in volume percentages of 15-98 vol. % solvent and 2-85 vol. % steam, in cold liquid equivalents, calculated at standard temperature and pressure.

6. The process of any one of claims 1 to 5, wherein the solvent molar fraction is decreased over time.

7. The process of any one of claims 1 to 6, wherein the solvent and steam are injected at 1-50°C of superheat, measured at a sand face, with respect to saturation temperature at the solvent molar fraction at the reservoir operating pressure.

8. The process of any one of claims 1 to 7, wherein the solvent and steam are injected at 1-20°C of superheat, measured at a sand face, with respect to saturation temperature at the solvent molar fraction at the reservoir operating pressure.

9. The process of any one of claims 1 to 8, wherein the solvent comprises aliphatic, naphthenic, aromatic, and/or olefinic fractions.

10. The process of any one of claims 1 to 8, wherein the solvent comprises at least 50 wt. % of one or more C4-C10 hydrocarbons.

11. The process of any one of claims 1 to 8, wherein the solvent comprises at least 50 wt. % of one or more C5-C7 hydrocarbons.

12. The process of any one of claims 1 to 8, wherein the solvent comprises a natural gas condensate or a crude oil refinery naphtha.

13. The process of any one of claims 1 to 12, wherein the steam has a quality of at least 5%.

14. The process of any one of claims 1 to 12, wherein the steam has a quality of 10-100%.

15. The process of any one of claims 1 to 14, further comprising separating and reusing the solvent and water in a separation, purification, revaporization and reinjection facility.

16. The process of any one of claims 1 to 15, wherein the injection temperature is 30-250°C.

17. The process of any one of claims 1 to 15, wherein the injection temperature is 80-150°C.

18. The process of any one of claims 1 to 16, wherein the reservoir operating pressure is 5% to 95% of a fracture pressure of the reservoir.

19. The process of any one of claims 1 to 16, wherein the reservoir operating pressure is 0.2 MPa to 4 MPa.

20. The process of any one of claims 1 to 16, wherein the reservoir operating pressure is 1 MPa to 2.5 MPa.