CA2854171C - Methods of recovering heavy oil from a subterranean reservoir - Google Patents

Abstract

A method of recovering heavy oil from a subterranean reservoir may include injecting a mixture of steam and solvent into the subterranean reservoir to form a liquid comprising the heavy oil and the solvent in condensed form; recovering the heavy oil and at least a portion of the solvent from the subterranean reservoir by producing the liquid from the subterranean reservoir. The heavy oil is residual heavy oil. The mixture may have a concentration of the solvent close to or above an azeotrope concentration for the mixture at a pressure of the subterranean reservoir.

Description

METHODS OF RECOVERING HEAVY OIL
FROM A SUBTERRANEAN RESERVOIR
FIELD
[0001] The present disclosure relates to methods of recovering heavy oil from a subterranean reservoir. In particular, the disclosure relates to methods of recovering residual heavy oil from a subterranean reservoir.
BACKGROUND

[0002] This section is intended to introduce various aspects of the art.
This discussion is believed 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 including admissions of prior art.

[0003] Modern society is greatly dependent on the use of hydrocarbon resources for fuels and chemical feedstocks. Subterranean rock formations that can be termed "reservoirs", may contain resources, such as hydrocarbons, that can be recovered. Recovering hydrocarbons from such reservoirs depends on numerous physical properties of the subterranean rock formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the subterranean formations, and the proportion of hydrocarbons present, among other things.

[0004] Easily harvested sources of hydrocarbons are dwindling, leaving less conventional sources to satisfy future energy needs. As the costs of hydrocarbons increase, less conventional sources become more economical. One example of less conventional sources becoming more economical is that of oil sand production. The hydrocarbons produced from less conventional sources may have relatively high viscosities, for example, ranging from 1000 centipoise (cP) to 20 million cP with API (American Petroleum Institute) densities ranging from 8 API, or lower, up to 20 API, or higher. The hydrocarbons recovered from less conventional sources may include heavy oil. However, the hydrocarbons, like heavy oil, from less conventional sources are difficult to recover using conventional techniques.

[0005] Several methods have been developed to recover heavy oil from, for example, oil sands. Strip or surface mining may be performed to access the oil sands. Once accessed, the oil sands may be treated with hot water or steam to extract the heavy oil. For subterranean reservoirs where heavy oil is not close to the Earth's surface, heat may be added and/or dilution may be used to reduce the viscosity of the heavy oil and recover the heavy oil from the subterranean reservoir. Heat may be supplied through a heating agent like steam. The heat may be injected into a subterranean reservoir via an injection well. If the heating agent is steam, the steam may be condensed to water at the steam to cooler-oil-sands interface in the subterranean reservoir and supply latent heat of condensation to heat the heavy oil in the oil sands, thereby reducing viscosity of the heavy oil and causing the heavy oil to flow more easily.
The heavy oil recovered from the subterranean reservoir may or may not be produced via a production well. The production well may be the same well as the injection well.

[0006] A number of thermal recovery processes have been developed for the recovery of heavy oil from subterranean reservoirs. These processes may include cyclic steam stimulation (CSS), steam assisted gravity drainage (SAGD), vapor extraction process (VAPEX), heated VAPEX, steam flooding, steam and vapor extraction process (SAVEX), solvent-assisted vapor extraction with steam (SAVES), in-situ combustion, thermal enhanced oil recovery and solvent-assisted steam-assisted gravity drainage (SA-SAGD). The thermal recovery processes may be cyclic recovery processes in which there is intermittent injection of the mobilizing fluid to lower a viscosity of the heavy oil followed by recovery of the reduced viscosity heavy oil.

[0007] CSS techniques that are cyclic steam stimulation techniques use steam to lower the viscosity of the heavy oil. The steam is injected into the subterranean reservoir through a well that raises the temperature of the heavy oil during a heat soak phase, thus lowering the viscosity of the heavy oil. As the viscosity is reduced, the heavy oil may flow down towards the well. The well may then be used to produce heavy oil from the subterranean reservoir.
Solvents may be used in combination with steam in CSS processes, such as in mixtures with the steam or in alternate injections between steam injections. CSS processes are described in U.S.
Patent No. 4,280,559, U.S. Patent No. 4,519,454, and U.S. Patent No.
4,697,642.

[0008] Steam flooding is a process in which steam is injected from a series of vertical or horizontal injection wells and heavy oil is heated and pushed towards a series of vertical or horizontal production wells. Steam flooding can be used as a late life process after a CSS
process. Solvent can be injected with steam to enhance the steam flooding process. Further details may be obtained, for example, from Zhihong Liu and Shane D. Stark, "Reservoir Stimulation Modelling of the Mature Cold Lake Steaming Operations", Society of Petroleum Engineers, SPE 160491, presented in Calgary, Alberta, 12-14 June 2012.

[0009] SAGD is a process where two horizontal wells (a well pair) are completed in a subterranean reservoir. The two wells may be first drilled vertically to different depths within the subterranean reservoir. Thereafter, using directional drilling technology, the two wells may be extended in a horizontal direction that result in two horizontal wells (i.e., a production well and an injection well), each vertically spaced from, but otherwise vertically aligned with, the other. Ideally, the production well may be located above the base of the subterranean reservoir but as close as practical to the bottom of the subterranean reservoir. A horizontal portion of the injection well may be located vertically above, such as, for example, 10 to 30 feet (or 3 to 10 meters) above, the horizontal portion of the production well. The injection well may be supplied with steam from a facility on the surface. The steam may rise from the injection well, permeating the subterranean reservoir to form a vapor chamber (i.e., a steam chamber) above the well pair. As the vapor chamber grows over time towards the top of the subterranean reservoir, the steam may condense at the steam to cooler-oil sands interface, releasing latent heat of steam, thereby reducing the viscosity of the heavy oil in the subterranean reservoir. The heavy oil and condensed steam may then drain downward through the subterranean reservoir under the action of gravity and may flow into the production well. After flowing into the production well, the heavy oil and condensed steam can be pumped to the surface. At the surface, the condensed steam and heavy oil may be separated, and the heavy oil may be diluted with appropriate light hydrocarbons for transportation by pipeline. SAGD processes are described in Canadian Patent No. 1,304,287 and U.S. Patent No. 4,344,485.

, ,

[0010] A number of variations of the SAGD and CSS processes have been developed in an attempt to increase productivity of the process. For example, U.S. Pat. No.
6,230,814 teaches how the SAGD process can be further enhanced through the addition of solvent with the injected steam. The process teaches that as a planned operating pressure declines, a molecular weight of a solvent must be reduced in order to ensure that the solvent is completely vaporized at operating conditions that are planned for the SAGD process. The disclosed approach results in progressive exclusion of heavier solvents as lower operating pressures (and temperatures) are considered.

[0011] Solvents may be used in concert with steam addition, such as but not limited to in SA-SAGD, to increase efficiency of the steam in recovering heavy oil. U.S.
Patent No. 6,230,814, discloses a method for enhancing mobility of heavy oil using a steam additive (e.g., a solvent).
The method includes injecting steam and an additive into the subterranean reservoir. The additive includes a non-aqueous fluid, selected so that an evaporation temperature of the non-aqueous fluid is within about 150 C (degrees Celsius) of a steam temperature at an operating pressure of the process. Suitable additives include C1 to C25 hydrocarbons. At least a portion of the additive condenses in the subterranean reservoir. The mobility of the heavy oil obtained with the steam and additive combination is greater than that obtained using steam alone under substantially similar conditions.

[0012] Canadian Patent No. 2,769,356 discloses the use of a solvent, pentane or hexane, or both, as an additive to, or sole component of, a gravity-dominated process for recovering heavy oil from a subterranean reservoir. However, Canadian Patent No. 2,769,356 teaches that solvents heavier than hexane (such as C7, C8, C9, etc.) are not effective in enhancing the heavy oil recovery process as the solvents precipitate out in the near well vicinity and do not travel to a vapor-liquid interface within the subterranean reservoir.

[0013] SAVEX is another process to improve productivity of a SAGD
process, as disclosed for example in U.S. Patent No. 6,662,872. SAVEX is a combination of SAGD and VAPEX, where the SAGD recovery process is continued until a vapor chamber covers 25 to 75 %
of a height of a subterranean reservoir and then steam injection is replaced with solvent injection. The SAVEX process is limited to SAGD processes. SAVEX is not a follow-up process and does not target residual heavy oil.

[0014] SAVES is very similar to SAVEX, and one example is taught in U.S.
Patent No.
7,464,756. In a SAVES process, instead of a steam only phase at the beginning, there is steam and heavy hydrocarbon solvent during a first phase, which gets replaced with steam and light hydrocarbon solvent during a second phase. In the SAVES process, the third phase uses exclusively light hydrocarbon injections.

[0015] When operating some or all of the above thermal recovery processes, unrecovered heavy oil is left behind in the subterranean reservoir in the form of both unswept heavy oil and residual oil. Unswept heavy oil is heavy oil in the subterranean reservoir that has not been previously mobilized and as such is not in a vapor chamber. Residual heavy oil saturations of 7-15 % have been measured in the thermal recovery processes. It would be desirable to recover at least some of the residual heavy oil once a thermal recovery process is close to an economic limit. The economic limit may be when a ratio between the heavy oil recovered from the subterranean reservoir and the steam injected into the subterranean reservoir falls below a profitable limit (e.g., when the cost of injecting the steam into the subterranean reservoir is greater than the value of the heavy oil recovered from the subterranean reservoir as a result of the injected steam). The economic limit of heavy oil recovery at which heavy oil recovery ceases may vary with different thermal recovery processes.
SUMMARY

[0016] The present disclosure provides methods of recovering heavy oil.

[0017] A method of recovering heavy oil from a subterranean reservoir may comprise injecting a mixture of steam and solvent to form a liquid comprising the heavy oil and the solvent in condensed form and recovering the heavy oil and at least a portion of the solvent from the subterranean reservoir while producing the liquid from the subterranean reservoir.
The heavy oil is residual heavy oil. The mixture may have a concentration of the solvent close to or above an azeotrope concentration for the mixture at a pressure of the subterranean reservoir.

[0018] A method of recovering heavy oil from a subterranean reservoir may comprise performing a steam-based heavy oil recovery process; injecting, at a time equal to at least one of during and after performing the steam-based heavy oil recovery process, a mixture of steam and solvent into the subterranean reservoir to form a liquid comprising heavy oil and the solvent in condensed form; and recovering the heavy oil and at least a portion of the solvent from the subterranean reservoir while producing the liquid from the subterranean reservoir.
The mixture may have a concentration of the solvent close to or above an azeotrope concentration for the mixture at a pressure of the subterranean reservoir.

[0019] The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood. Additional features will also be described herein.
BRIEF DESCRIPTION OF THE DRAWINGS

[0020] These and other features, aspects and advantages of the disclosure will become apparent from the following description, and the accompanying drawings, which are briefly described below.

[0021] FIG. 1A is a graph showing saturation temperatures versus solvent mole fractions of three hydrocarbon solvents.

[0022] FIG. 1B is a graph showing the XY equilibrium (Pxy) curve for n-heptane.

[0023] FIG. 2 is a black-and-white drawing of a color display produced during a simulation of steam/solvent recovery methods.

[0024] FIG. 3 is a graph comparing cumulative heavy oil recovered versus time for a conventional process and a method according to this disclosure.

[0025] FIG. 4 is a graph showing solvent injected, solvent volume remaining in the subterranean reservoir, and the additional volume of heavy oil recovered in the method according to this disclosure illustrated in FIG. 3.

,

[0026] FIG.5A-5D are drawings showing the evolution of heavy oil recovery in a subterranean reservoir by a SAGD process; wherein 5A is a transversal view drawing of a SAGD
vapor chamber, 5B is a RST log taken before the SAGD process, 5C is a RST log taken at the end of the SAGD process and 5D is a RST log after the method according to this disclosure.

[0027] Fig. 6 is a flow diagram of a method of recovering heavy oil.

[0028] It should be noted that the figures are merely examples 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

[0029] 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.

[0030] At the outset, for ease of reference, certain terms used in this disclosure and their meanings as used in this context are set forth. 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 techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope hereof.

[0031] A "hydrocarbon" is an organic compound that primarily includes the elements 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. However, the techniques described herein are not limited to heavy oils, but may also be used with any number of other reservoirs to improve gravity drainage of liquids. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.

[0032] "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). % 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 in excess of 7 wt. %).
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 metals content, while small, must be removed to avoid contamination of the product synthetic crude oil (SCO). Nickel can vary from less than 75 ppm (part per million) to more than 200 ppm. Vanadium can range from less than 200 ppm to more than 500 ppm. The percentage of the hydrocarbon types found in bitumen can vary.

[0033] "Heavy oil" includes oils which are classified by the American Petroleum Institute (API), as heavy oils, extra heavy oils, or bitumen. Thus the term "heavy oil"
includes bitumen and should be regarded as such throughout this description. 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, heavy oil has a API gravity between 22.302 (density of 920 kilograms per cubic meter (kg/m3) or 0.920 grams per cubic centimeter (g/cm3)) and 10.002 API (density of 1,000 kg/m3 or 1 g/cm3). Extra heavy oil, in general, has a API gravity of less than 10.002 API
(density greater than 1,000 kg/m3 or greater than 1 g/cm). For example, a source of heavy oil , includes oil sand or bituminous sand, which is a combination of clay, sand, water, and bitumen.
The thermal recovery of heavy oil is based on the viscosity decrease of fluids with increasing temperature or solvent concentration. Once the viscosity is reduced, the mobilization of fluids by steam, hot water flooding, or gravity is possible. The reduced viscosity makes the drainage quicker and therefore directly contributes to the recovery rate.

[0034] "Facility" is a tangible piece of physical equipment through which hydrocarbon fluids are either produced from a reservoir or injected into a reservoir, or equipment that can be used to control production or injection operations. In its broadest sense, the term facility is applied to any equipment that may be present along the flow path between a reservoir and its delivery outlets. Facilities may comprise production wells, injection wells, well tubulars, wellbore head equipment, gathering lines, manifolds, pumps, compressors, separators, surface flow lines, steam generation plants, processing plants, and delivery outlets.

[0035] A "reservoir" or "subterranean reservoir" is a subsurface rock, sand or soil formation from which a production fluid, or resource, can be harvested. The formation may include sand, granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy oil, oil, gas, or coal, among others. Reservoirs can vary in thickness from less than one foot (0.3048 meter (m)) to hundreds of feet (hundreds of meters). The resource is generally a hydrocarbon, such as heavy oil impregnated into a sand bed.

[0036] A "wellbore" is a hole in the subsurface made by drilling or inserting a conduit into the subsurface. A wellbore may have a substantially circular cross section or any other cross-sectional shape, such as an oval, a square, a rectangle, a triangle, or other regular or irregular shapes. The term "well," when referring to an opening in the formation, may be used interchangeably with the term "wellbore." Further, multiple pipes may be inserted into a single wellbore, for example, as a liner configured to allow flow from an outer chamber to an inner chamber.

[0037] A "fluid" includes a gas or a liquid and may include, for example, hot or cold water, a produced or native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold liquid , hydrocarbon, solvent, steam, wet steam, gas (e.g. C1, CO2, etc.), or a mixture of these, among other materials.

[0038] "Permeability" is the capacity of a rock or other structure to transmit fluids through the interconnected pore spaces of the structure. The customary unit of measurement for permeability is the milliDarcy (mD).

[0039] "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. "Gauge pressure" (psig) refers to the pressure measured by gauge, which indicates only the pressure exceeding the local atmospheric pressure. Unless otherwise specified, the pressures disclosed herein are absolute pressures, i.e. the sum of gauge pressure plus atmospheric pressure (generally 14.7 psi at standard conditions).

[0040] "Steam-based heavy oil recovery processes" or "steam-based processes" include any type of hydrocarbon recovery process that uses a heat source to enhance the recovery, for example, by lowering the viscosity of a hydrocarbon. These processes may use injected mobilizing steam, either wet steam or dry steam, in admixture with solvents, to lower the viscosity of the hydrocarbon. Such processes may include thermal recovery processes.

[0041] "Primary steam-based heavy oil recovery processes" or primary heavy oil recovery processes include any steam-based heavy-oil recovery process in which a certain portion of the heavy oil is left behind as residual heavy oil due to a decrease in the heavy oil mobility within a subterranean reservoir.

[0042] "Substantial" when used in reference to a quantity or amount of a material, or a specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context. When a compound is indicated as "removed" or "substantially removed" from a mixture of compounds, it should be understood that there may remain such an amount of the compound in the mixture that cannot be removed by the technique employed for removal. For example, fractionation may leave small amounts or traces of a compound intended to be removed.

[0043] A "solvent" is an agent that may dilute or dissolve heavy oil and may reduce a viscosity of the heavy oil. Many solvents used for heavy oil recovery, such as single alkanes, mixtures of alkanes and gas plant condensates, may not be solvents of heavy oil according to a precise or narrow definition of the term (i.e., an agent that completely dissolves all components of a solute below its solubility limit concentration). For example, some solvents may not dissolve an asphaltene component of heavy oil. These solvents do dilute the heavy oil and as such function as diluents. Other agents such as xylene and toluene may be solvents in that they may dissolve all components of the heavy oil up to a solubility limit concentration. Solvent includes both solvents as narrowly defined and also diluents as is understood and accepted in the art.

[0044] An "azeotrope" is generally understood to be a composition of liquids having a constant boiling point, in which a vapor phase has the same component proportions as a liquid phase. It follows that the components of an azeotropic composition cannot be separated by fractional distillation. The boiling point of an azeotropic composition may be higher or lower than the boiling points of any of its components. An azeotrope concentration is a concentration at which the liquids forming the azeotrope composition reach a state in which the mixture of the liquids forms the azeotrope composition.

[0045] "Residual heavy oil" generally refers to heavy oil in a vapor chamber of a steam-based heavy oil recovery process that becomes immobile or ceases to flow as the recovery process progresses, so that heavy oil remaining in the vapor chamber can no longer be economically recovered by the steam-based heavy oil recovery process. Metrics may be used for measuring the progress of the steam-based heavy oil recovery process such as, for example, an oil-to-steam ratio and identified values of the oil-to-steam ratio. For example, steam-based heavy oil recovery processes may be considered to no longer be economically recovered and therefore an economic limit when the metrics indicate that the value of recovered heavy oil is below a cost to extract the heavy oil. The economic limit of a primary steam-based heavy oil recovery process may be when a metric indicates that the value of the heavy oil recovered by the primary steam-based heavy oil recovery process is below a cost to run the primary steam-based heavy oil recovery process. One example of the metric is a ratio between the heavy oil recovered from the subterranean reservoir and the steam injected into the subterranean reservoir, or an oil-to-steam ratio (OSR). For example, a SAGD process may be considered at an economic limit when the OSR falls below 0.2. For a cyclic steam stimulation process, an OSR
below 0.13 may be considered to be the economic limit.

[0046] "Incremental heavy oil" is a portion of residual heavy oil that may be recovered after a primary production process. The primary production process may be an initial thermal recovery process or any process used in the first stage of recovering the heavy oil from the subterranean reservoir. The incremental heavy oil may be added to heavy oil recovered by the steam-based heavy oil recovery process that occurs during the primary production process.

[0047] A steam-based heavy oil recovery process for recovering heavy oil from subterranean reservoirs may be employed as a primary production process. If the steam-based heavy oil recovery process is a SAGD process, a viscosity of the heavy oil decreases due to an injection of high temperature steam. The heavy oil temperature may warm the heavy oil, reducing a viscosity of the heavy oil such that the heavy oil may flow down under the influence of gravity. The heavy oil may drain down towards a production well and an upwardly and outwardly expanding vapor chamber may be formed. The vapor chamber may be formed by the steam penetration of the subterranean reservoir. Mobility of the heavy oil may decrease as the saturation of heavy oil declines in the vapor chamber. Eventually any heavy oil remaining may become immobile causing a certain portion of the heavy oil to be left behind as residual heavy oil. The residual heavy oil may amount to 10 volume (vol.%) or more of the heavy oil originally in the subterranean reservoir. The amount of residual heavy oil may include any number within or bounded by the preceding range of residual heavy oil.
Providing a method of recovering some or all of the residual heavy oil once the primary production process has been substantially completed is desired.

[0048] Steam-based heavy oil recovery processes may be operational for a number of years (e.g. 10 years or more) functioning as the primary production process.
Eventually a ratio of recovered-heavy oil to steam-injected begins to fall during the steam-based heavy oil recovery process and becomes so low that the steam-based heavy oil recovery process is considered not to be economically viable. Gases may then be injected into the subterranean reservoir to take advantage of residual heat from the steam of the steam-based heavy oil recovery process, with any resulting fluids recovered from the injection of gas being produced for heavy oil content in the resulting fluids. The phase of the gases being injected may be referred to as "blowdown". Generally very little of the residual heavy oil is recovered in this way.

[0049] Evidence from simulation and physical models indicates that injection of a solvent with steam (e.g., solvent-assisted-SAGD) into a subterranean reservoir containing heavy oil reduces saturation of the residual heavy oil compared with SAGD alone. If a solvent is introduced into the steam-based process, as in SA-SAGD, a large amount of the solvent condensate may exist at a boundary of the vapor chamber and the subterranean reservoir where it can mix with the heavy oil such that the residual heavy oil in the subterranean reservoir is composed of heavy oil and solvent. Some or all of the heavy oil and solvent may continue to drain down, thereby reducing saturation of the residual heavy oil.
The net result may be a reduction in both the heavy oil remaining in the subterranean reservoir and an increase in recovery relative to a steam-based process alone, in addition to faster production rates. Nevertheless, even in the case of SA-SAGD, some heavy oil remains unrecovered from the subterranean reservoir. The SA-SAGD process typically uses a small ratio of solvent to steam as the solvent is expensive, which may limit the extent of recovery of the heavy oil. For example, a mixture of heptanes and steam used for SA-SAGD may employ about 17 to 25% by volume of the heptanes, i.e. around 2 mole (mol.) %. The amount of steam used for SA-SAGD
may include any number within or bounded by the preceding range of steam.

[0050] The present disclosure includes methods of recovering heavy oil from a subterranean reservoir. More specifically, the present disclosure includes methods of enhancing the recovery of heavy oil from a subterranean reservoir that may be performed during or after the primary production process.

[0051] The methods may include performing a steam-based heavy oil recovery process 602 (Figure 6). The steam-based heavy oil recovery process may be the primary production process.
The steam-based heavy oil recovery process may be performed as part of the methods and concurrently with the other steps of the methods. The steam-based heavy oil recovery process may be performed prior to the other steps of the method 600.

[0052] The methods may include injecting a mixture of steam and solvent into the subterranean reservoir to form a liquid comprising heavy oil and the solvent in condensed form, 604 (Figure 6). The mixture of steam and solvent may be injected via an injection well used during the steam-based heavy oil recovery process. The heavy oil may be residual heavy oil.

[0053] The mixture of solvent and steam may be injected into the subterranean reservoir when a steam-based heavy oil recovery process used as the primary production process is close to an economic limit. Injecting the mixture when the steam-based heavy oil recovery process used as the primary production process is close to the economic limit of the steam-based heavy oil recovery process may provide solvent condensates that may sweep the residual heavy oil from the subterranean reservoir. Sweeping the residual heavy oil may be referred to as a "sweeping phase." When the sweeping occurs during the primary production process, the "sweeping phase" may be the "sweeping phase" of the steam-based heavy oil recovery process used as the primary production process.

[0054] The solvent may be any material that is capable of being injected into a subterranean reservoir in admixture with steam so that the solvent can condense and dilute heavy oil within the subterranean reservoir. The solvent may be any material that can form an azeotrope composition with water. The solvent may be a material that can be subsequently recovered from the subterranean reservoir. The solvent may comprise any of the solvents conventionally used for steam-based heavy oil recovery processes. For example, the solvent may include, but is not limited to, any hydrocarbon having a carbon atom number of C3 to C25 or higher (which may be straight-chained, branched, cyclic, aliphatic or aromatic, or a combination thereof), or any mixture of two or more such hydrocarbons in any relative amounts. The hydrocarbon may be an alkane. The solvent may be a gas plant condensate.

[0055] The mixture of the solvent and steam may have a concentration of the solvent close to or above an azeotrope concentration for the mixture at a pressure of the subterranean reservoir. The concentration of solvent and steam may be selected so that solvent is condensed at a boundary of the vapor chamber and inside the vapor chamber to allow the solvent to mix with residual heavy oil throughout the vapor chamber.

[0056] For mixtures of any solvent and steam, there generally exists a certain concentration of solvent at which steam and solvent condense simultaneously when the temperature is decreased at constant pressure (i.e. at the azeotrope concentration.) When the amount of solvent in the mixture of steam and solvent is below the azeotrope concentration, steam condenses before the solvent condenses. When the amount of solvent in the mixture of steam and solvent is above the azeotrope concentration, the solvent condenses before the steam condenses.

[0057] Unlike the mixture of steam and solvent employed by the steam-based heavy oil recovery process used during the primary production process, the solvent used in the mixture may be close to or above the azeotrope concentration for the mixture at the pressure of the subterranean reservoir. During the primary production process, it is typically desired that a vapor chamber formed during the primary production process expand as much as possible since heavy oil within the vapor chamber is heavy oil that is mobilized for recovery by a well of the primary production process. Generally, during the primary production process any injected mixture of solvent and steam is below an azeotropic concentration and steam condenses prior to the solvent. During the primary production process any solvent injected may condense at a boundary of the vapor chamber. In the methods of the present disclosure, solvent is condensed at a boundary of the vapor chamber and inside the vapor chamber to allow the solvent to mix with residual heavy oil throughout the vapor chamber as a result of the mixture being close to or above the azeotropic concentration. As the mixture injected in the method of the present disclosure encounters cooler parts of the subterranean reservoir at the boundary of =

the vapor chamber, the solvent condenses before the steam, and is thus available for mixing with and diluting the residual heavy oil. With the solvent condensing before the steam, the concentration of the solvent within the vapor chamber that is available for diluting the residual heavy oil may be greater than that during the primary production process because the solvent condenses first. A liquid is formed when the mixture mobilizes heavy oil that may drain down to a well to be recovered from the subterranean reservoir.

[0058] Determining an appropriate concentration of solvent and steam so that the mixture is close to or above an azeotropic concentration may be calculated based on a phase behaviour of the mixture. An appropriate concentration is considered to be a lowest ratio between solvent and steam at which the solvent is the first component to condense.

[0059] FIG. 1A shows saturation temperatures versus solvent mole fractions at a pressure of 800 kPa for three solvents, namely n-pentane (n-05), n-heptane (n-C7) and n-decane (n-C10).
In FIG. 1A, the appropriate concentration for n-heptane/steam is about 0.48 mole n-heptane (i.e. about 48 mol. %.) For n-decane, the appropriate concentration is about 12 mol. %, and for n-pentane, the appropriate concentration is about 87 mol. %. The use of heavier solvents, such as but not limited to n-decane (n-C10) and/or solvents having a carbon atom number higher than n-decane, may be appealing since less solvent injection will be required to achieve similar results.

[0060] The curves for all three solvents show inflection points at azeotrope concentrations.
Arrow A shows the part of the curve for solvent n-C7 where water condenses first, arrow B
shows the part of the curve where solvent condenses first, and arrow C
indicates the azeotrope point or concentration at which there is simultaneous condensation of water and solvent.

[0061] FIG. 1B shows the XY equilibrium (Pxy) curve for n-heptane alone at a pressure of 800 kPa. Again, the azeotrope concentration is indicated by arrow C.

[0062] A concentration of the solvent in the mixture with steam may be up to 3 mol. %
above the azeotrope concentration, or within the range of 1-2 mol.% above the azeotrope concentration. The mixture of steam of solvent may have a concentration of solvent slightly below the azeotrope concentration, in an attempt to inject less solvent into the subterranean reservoir, while benefiting from the azeoptrope concentration. A slightly lower concentration of the solvent in the mixture may be as low as 1 mol.% below the azeotrope concentration, but preferably closer to the azeotrope concentration. The concentration of the solvent may be any number within or bounded by the preceding range. While a mixture of steam and solvent employed may have any concentration of solvent close to or above the azeotrope concentration, higher concentrations of solvent may introduce more of the solvent into the subterranean reservoir. Higher concentrations may be desirable for achieving more dilution of residual heavy oil, but undesirable because greater amounts of potentially expensive solvents may then be required. Moreover, the less solvent that is injected into the subterranean reservoir, the less solvent there remains in the subterranean reservoir for subsequent removal.

[0063] The mixture may be injected into the subterranean reservoir at a pressure higher than the pressure of the subterranean reservoir. The mixture may be injected below a pressure at which a matrix of the subterranean reservoir may fracture. The mixture may be injected into the subterranean reservoir at a temperature above a boiling point of the mixture having the solvent close to or above the azeotrope concentration.

[0064] The mixture of steam and solvent may be injected into the subterranean reservoir at a time equal to at least one of during and after performing the steam-based heavy oil recovery process. Referring to Fig. 6, step 602 of performing a steam-based heavy-oil recovery process may be performed before or during step 604 of injecting the mixture of steam and solvent. Injecting the mixture of steam and solvent at a time equal to during the steam-based heavy oil recovery process may slow down the steam-based heavy oil recovery process.
Slowing down the steam-based heavy oil recovery process may allow steam from the steam-based heavy oil recovery process to penetrate further into the subterranean reservoir. Further steam penetration may increase an amount of heavy oil that can be recovered during the steam-based heavy oil recovery process prior to the economic limit of the steam-based heavy oil recovery process being reached. When the mixture is injected during the steam-based heavy oil recovery process, there may be a reduction in down time between the steam-based , heavy oil recovery process reaching the economic limit and the methods of the present disclosure commencing.

[0065] The steam-based heavy oil recovery process used as the primary production process may be performed until the amount of heavy oil recovered from the subterranean reservoir starts to decline. The amount of heavy oil recovered may be considered as starting to decline when the OSR falls below the economic limit.

[0066] The mixture may be injected at a time equal to immediately after the steam-based heavy oil recovery process used as the primary production process is carried out on the subterranean reservoir. A steam-based heavy oil recovery process may operate at a high temperature (e.g., 180 to 250 Celsius ( C)). The temperature may be any number within or bounded by the preceding range. There may be a delay between the end of the steam-based heavy oil recovery process and the injection of the mixture of steam and solvent. If injection of the mixture of steam and solvent immediately follows the steam-based heavy oil recovery process, the subterranean reservoir may be at an elevated temperature that is above an original temperature of the subterranean reservoir (e.g. 5 to 12 C). The temperature may be any number within or bounded by the preceding range. The elevated temperature may be helpful in reducing the viscosity of the residual heavy oil.

[0067] The subterranean reservoir may be left to cool from the operating temperature of the steam-based heavy oil recovery process before injecting the mixture, in which case heat may have to be reintroduced to bring the subterranean reservoir up to a temperature close to the azeotrope temperature of the mixture resulting in greater expenses and delay. A small time delay between stopping the steam-based heavy oil recovery process and injecting the mixture may have an effect of allowing the subterranean reservoir to cool from the operating temperature of the steam-based heavy oil recovery process. The cooling of the subterranean reservoir from the operating temperature of the steam-based heavy oil recovery process to an azeotrope temperature will depend on the operating temperature as well as the solvent used in the mixture, which determines the azeotrope temperature. For example, the subterranean reservoir may be cooled from the operating temperature of the steam-based heavy oil recovery =

process (e.g. 180 C or more) to a temperature around the azeotrope temperature (e.g., about 160 C for heptane at 800kPa (as shown in figure 3)). The temperature may be any number within or bounded by the preceding range. The cooling in the above example of 20 C may require a period of one or two months, but may occur even if the mixture is injected immediately because a smaller volume of steam may be employed which may allow cooling to take place. The injection of the mixture may be continued until the ratio of heavy oil in the liquid from the subterranean reservoir declines below a predetermined value, based on, for example, the OSR.

[0068] A shut-in period may be detected in the steam-based heavy oil recovery process used as the primary production process. The mixture of steam and the solvent may be injected during the shut-in period. A steam-based heavy oil recovery process may encounter one or more shut-in periods. A shut-in period may occur when injection of steam is ceased during the steam-based heavy oil recovery process. Steam can become unavailable for various reasons during the operation of the steam-based heavy oil recovery process, for example, due to problems in steam generation. To maintain recovery of the heavy oil, injection of a high concentration of solvent may be carried out as a shut-in period treatment. Any concentration of solvent may be contemplated, and may be as high as pure solvent (100%). At a time equal to at least one of during or after performing the steam-based heavy oil recovery process, the method of recovering heavy oil may be carried out, which may also recover any high concentration of solvent that could be left from the shut-in period treatment.

[0069] The methods may include recovering the heavy oil and at least a portion of the solvent from the subterranean reservoir by producing the liquid from the subterranean reservoir, 606 (Figure 6). The liquid may be produced via a production well used during the steam-based heavy oil recovery process.

[0070] As a concentration of the solvent increases, so does a cost of using the solvent.
However, the solvent may be at least partially recovered to make the methods more economical overall, which is called the "follow-up phase". Some of the solvent may be produced in the mixture of heavy oil and solvent and may be recovered at the surface (e.g. by fractionation) or the solvent may be left in admixture with the heavy oil to make the product more easily pumpable for transportation by pipeline. Solvent still remaining in the subterranean reservoir after recovery of the heavy oil has finished may be stripped from the subterranean reservoir in several ways.

[0071] A vapor of an inexpensive solvent may be used instead of steam to recover the solvent from the mixture. The inexpensive solvent may be a solvent that is readily available at a site of facilities of the steam-based heavy oil recovery process. The inexpensive solvent may be for example, a by-product of the steam-based heavy oil recovery process that may be used as a solvent without further processing. In contrast, an expensive solvent may be a solvent that is based on a by-product that requires further processing before it can be used as a solvent, such as by isolating, separating or purifying. The expensive solvent may be a material that is not commonly available at the site of facilities of the steam-based heavy oil recovery process.

[0072] The inexpensive solvent may condense at the boundary of the vapor chamber, wash down and mix in the mixture. The mixture of solvents may then be produced and separated at the surface until mainly the inexpensive solvent appears in the produced fluids. The inexpensive solvent may displace the expensive solvent. The inexpensive solvent may be introduced in the form of a liquid, which again mixes with the original solvent and may be produced. The liquid may be heated or not, but the use of a heated solvent may be better to achieve delivery, mixing and production. A non-condensable gas may be introduced into the subterranean reservoir to push any residual original solvent, in liquid or vapor form, to the boundary for better draining and production. The methods of removing or displacing original solvent described above may be applied together in some cases. For example, steam may first be injected and may be followed by the injection of a non-condensable gas.

[0073] Heat may be introduced into the subterranean reservoir (e.g. by injecting a hot fluid.) The heat may vaporize any residual solvent in the subterranean reservoir. The vapor may migrate to the boundary of the vapor chamber and condense and drain down so that the residual solvent may be produced via the production well. The hot fluid employed may be a condensable vapor, such as steam, that delivers latent heat of condensation to the residual solvent as it condenses in the reservoir. The fluid for recovering the solvent may be a gas or vapor having a temperature above a boiling point of the solvent within the subterranean reservoir. The fluid for recovering the solvent may be a gas or vapor able to displace the solvent from the subterranean reservoir. The fluid for recovering the solvent may be steam, a solvent for heavy oil, a non-condensable gas, a steam-solvent mixture having a solvent concentration below the azeotrope concentration of the steam-solvent mixture, or any combination of steam-solvent mixture and non-condensable gases. Examples of non-condensable gases that may be employed in the above methods as stripping fluids include, but are not limited to, methane (Cl), ethane (C2), carbon dioxide, nitrogen, or any mixture of two or more of the above gases in any relative amounts.

[0074] A solvent stripping fluid may be employed in the follow-up phase.
Steam or a steam-solvent may be employed as the stripping fluid and may be injected, or co-injected, into the subterranean reservoir. When a steam-solvent mixture is employed, the mole fraction of solvent is such that the concentration is well to the left of the azeotrope as identified in FIG. 1A
(i.e. about 0 ¨ 2 mol.% for n-heptane.) Solvent-steam mixtures in such proportions may reintroduce the heat and phase behavior environment required to vaporize the residual solvent in the subterranean reservoir, move it toward the vapor chamber boundaries, and produce the solvent back from the subterranean reservoir. High solvent recoveries may be achieved, which may make the method economically appealing.

[0075] Recovering of the solvent may be ceased when an amount of the solvent recovered from the subterranean reservoir falls below a predetermined value.

[0076] A blowdown may be performed after the recovering the at least a portion of the solvent. Performing the blowdown may comprise injecting a non-condensable gas into the subterranean reservoir, producing an additional liquid comprising an additional portion of the solvent and additional heavy oil mobilized by the non-condensable gas and recovering the additional portion of the solvent and the additional heavy oil from the additional liquid.

[0077] A simulation was created for which n-heptane was chosen as the injected solvent.
The simulation was created using software designed to model reservoir conditions. In this simulation, a SAGD process was run in a 2-D homogenous Cold Lake reservoir for about 10 years (as a conventional production process), followed by about 2 years of injection of 50 mole% heptane and 50 mole% steam (as a sweeping phase), followed by a year of steam (alone) injection before blow-down (as a follow-up phase). No attempt was made to optimize the procedure in this case. However, as can be seen from FIG. 2, which illustrates the results, a reduction of oil saturation was demonstrated and, as a result, a clear increase in heavy oil recovery would be achieved by methods of the present disclosure as compared to conventional processes.

[0078] FIG. 2 compares oil saturation resulting from conventional SAGD
(panel [II]) to the method of recovering residual heavy oil (panel [1]). The darker shades in panel [I] indicate a much lower saturation approaching 0.0 with smaller areas of higher saturation, whereas the lighter shades of panel [II] indicate a residual heavy oil content closer to 0.22 with smaller areas of higher saturation.

[0079] FIG. 3 is a graph comparing cumulative oil recovered versus time for these two simulated cases. It can be seen that in the late stages of the operation, the methods of the present disclosure resulted in higher cumulative heavy oil recovery.

[0080] FIG. 4 is a graph showing solvent injected, solvent volume remaining in the subterranean reservoir, and the additional volume of heavy oil recovered during the method of recovering residual heavy oil. The curve for solvent volume remaining clearly shows that much of the solvent was recovered. The solvent recovery after one year of steam injection is about 95%. The additional volume of heavy oil produced was substantial.

[0081] A test may be performed to determine the amount of heavy oil remaining in the subterranean reservoir after the steam-based heavy oil recovery process used as the primary production process. The test may involve a reservoir saturation tool (RST) log test or a coring sample that can be directly tested. The test may provide an indication of saturation of heavy oil in the subterranean reservoir. Results of the test may be compared with results from similar tests that may have been performed prior to the steam-based heavy oil recovery process or during the steam-based heavy oil recovery process. The comparison of test results between the different times can give an indication of how much heavy oil has been recovered from the subterranean reservoir and how much heavy oil remains in the subterranean reservoir. The amounts of residual heavy oil in the subterranean reservoir, the costs of solvent, stripping fluids, etc., and the expected returns from any residual heavy oil thus recovered may determine the suitability of the method for recovering residual heavy oil. For subterranean reservoirs containing amounts of residual heavy oil up to 30 vol.% of the original deposits, typically 20%, or as low as 5-10%, the methods of this disclosure may result in the recovery of up to 80-90% of the residual oil produced by the primary heavy oil recovery process of production. The recovery percentage may be any number within or bounded by the preceding range.

[0082] FIG. 5A-5D are drawings showing the evolution of the recovery of heavy oil in a subterranean reservoir 2 by a SAGD process by a known monitoring method such as an RST.
FIG. 5A is a transversal view drawing of a vapor chamber 4, showing an injection well 6 and a production well 8. The drawing also shows an observation well 10 from which a RST log is taken. The drawings 5B-D illustrate RST logs at different time. The y-axis is in function of the depth of the vapor chamber 4. The heavy oil 12 is shown as oblique lines and water 14 is shown as vertical lines. FIG. 5B is an RST log at time zero, before the SAGD
process. The heavy oil recovery has not started and the space is mainly occupied by heavy oil.
FIG. 5C is an RST log at the end of the SAGD process. The heavy oil 12 left as residual heavy oil is shown. FIG. 5D is an RST log after the method according to this disclosure. It shows that a portion of the residual heavy oil from the SAGD process has been recovered.

[0083] It should also 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 (21)

24What is claimed is:

1. A method of recovering heavy oil from a subterranean reservoir, the method cornprising:
performing a steam-based heavy oil recovery process on the subterranean reservoir and recovering a first portion of the heavy oil from a subterranean reservoir, wherein the steam-based heavy oil recovery process is a process selected from the group consisting of steam assisted gravity drainage, cyclic steam stimulation, and steam flooding;
stopping the steam-based heavy oil recovery process and allowing the temperature of the subterranean reservoir to cool from an operating temperature of steam-based heavy oil recovery process to the azeotropic temperature of a rnixture of steam and solvent;
injecting the mixture of steam and solvent into the subterranean reservoir to form a liquid cornprising a second portion of the heavy oil and the solvent in condensed form, the mixture having a concentration of the solvent close to or above an azeotrope concentration for the mixture at a pressure of the subterranean reservoir;
recovering the second portion of the heavy oil and at least a portion of the solvent from the subterranean reservoir while producing the liquid from the subterranean reservoir, wherein the heavy oil is residual heavy oil.

2. The method of claim 1, wherein the concentration of the solvent is close to the azeotrope concentration.

3. The method of claim 1 or 2, wherein the concentration of the solvent is greater than the azeotrope concentration by up to 3 mole %.
Date Recue/Date Received 2020-10-29

4. The method of claim 1 or 2, wherein the concentration of the solvent is greater than the azeotrope concentration by an amount in a range of 1 to 2 mole %.

5. The method of claim 1 or 2, wherein the concentration of the solvent is below the azeotrope concentration by an amount of 1 mole % or less.

6. The method of any one of claims 1 to 5, wherein the solvent is a hydrocarbon with a carbon atom number of C3 to C25, or a mixture of hydrocarbons with carbon atom numbers of C3 to C25.

7. The method of any one of claims 1 to 5, wherein the solvent is a hydrocarbon with a carbon atom number of C3 to C13 or a mixture of hydrocarbons with carbon atom numbers of C3 to C13.

8. The method of claim 6 or 7, wherein the hydrocarbon is an alkane.

9. The method of any one of claims 1 to 5, wherein the solvent is a gas plant condensate.

10. The method of any one of claims 1 to 9, wherein injecting the mixture comprises injecting the mixture at a pressure higher than the pressure of the subterranean reservoir, and below a pressure at which a matrix of the subterranean reservoir may fracture.

11. The method of any one of claims 1 to 9, wherein injecting the mixture comprises injecting the mixture at a temperature above a boiling point of the mixture.
Date Recue/Date Received 2020-10-29

12. The method of any one of claims 1 to 11, wherein injecting the mixture comprises injecting the mixture until a ratio of the heavy oil in the liquid falls below a predetermined value.

13. The method of any one of claims 1 to 12, wherein recovering the at least a portion of the solvent occurs after the mixture has been injected.

14. The method of any one of claims 1 to 13, wherein recovering the at least a portion of the solvent comprises injecting a fluid into the subterranean reservoir.

15. The method of claim 14, wherein the fluid is one of a gas and vapor having a temperature above a boiling point of the solvent.

16. The method of claim 14, wherein the fluid is one of a gas and vapor configured to displace the solvent from the subterranean reservoir.

17. The method of any one of claims 14 to 16, wherein the fluid is one of a gas and vapor selected from the group consisting of one of steam, a solvent, a non-condensable gas, a steam-solvent mixture having a solvent concentration below an azeotrope concentration of the steam-solvent mixture, and any combination of the steam, the solvent, the non-condensable gas and the steam-solvent mixture.

18. The method of claim 17, wherein the non-condensable gas is selected from the group consisting of methane, ethane, carbon dioxide, nitrogen, and mixture of any two or more of methane, ethane, carbon dioxide, and nitrogen.
Date Recue/Date Received 2020-10-29

19. The method of any one of claims 1 to 18, wherein recovering the at least a portion of the solvent occurs until an amount of the at least a portion of the solvent recovered falls below a predetermined amount.

20. The method of claim 1, further comprising performing a blowdown after recovering the at least a portion of the solvent by injecting a non-condensable gas into the subterranean reservoir, producing an additional liquid comprising additional heavy oil and an additional portion of the solvent mobilized by the non-condensable gas, and recovering the additional portion of the solvent and the additional heavy oil from the additional liquid.

21. The method of claim 1, further comprising detecting a shut-in period in the steam-based heavy oil recovery process, and wherein injecting the mixture occurs during the shut-in period.
Date Recue/Date Received 2020-10-29