US20190032460A1 - Method of solvent recovery from a solvent based heavy oil extraction process - Google Patents

Method of solvent recovery from a solvent based heavy oil extraction process Download PDF

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US20190032460A1
US20190032460A1 US16/036,392 US201816036392A US2019032460A1 US 20190032460 A1 US20190032460 A1 US 20190032460A1 US 201816036392 A US201816036392 A US 201816036392A US 2019032460 A1 US2019032460 A1 US 2019032460A1
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solvent
well
existing
ncg
subterranean reservoir
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Rahman Khaledi
Forough Farshidi
Hamed R. Motahhari
Nima Saber
B. Karl Pustank
Ernesto C. Dela Rosa
Wenqiang Han
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/241—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection combined with solution mining of non-hydrocarbon minerals, e.g. solvent pyrolysis of oil shale
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
    • E21B43/168—Injecting a gaseous medium
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/164—Injecting CO2 or carbonated water
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2406—Steam assisted gravity drainage [SAGD]
    • E21B43/2408—SAGD in combination with other methods

Definitions

  • the present disclosure relates to production of a bitumen product from a subterranean reservoir with improved processes for solvent recovery at end of production or near end of production of heavy oil from a solvent-based heavy oil extraction process.
  • Subterranean rock formations that can be termed “reservoirs” may contain resources such as hydrocarbons that can be recovered. Removing hydrocarbons from the subterranean 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 rock formations, and the proportion of hydrocarbons present, among other things.
  • the hydrocarbons produced from less conventional sources may have relatively high viscosities, for example, ranging from 1000 centipoise (cP) to 20 million cP, with American Petroleum Institute (API) densities ranging from 8 degree (°) API, or lower densities, up to 20° API, or higher densities.
  • the hydrocarbons recovered from less conventional sources may include heavy oil.
  • the hydrocarbons produced from the less conventional sources may be difficult to recover using conventional techniques.
  • the heavy oil may be sufficiently viscous that economical production of the heavy oil from a subterranean formation (also referred to as a “subterranean reservoir” herein) is precluded.
  • the steam injection may be utilized to heat the heavy oil to decrease the viscosity of the heavy oil.
  • Water and/or steam may represent an effective heat transfer medium, but the pressure required to produce saturated steam at a desired temperature may limit the applicability of steam injection to high pressure operation and/or require a large amount of energy to heat the steam.
  • Another group of the conventional extraction processes utilizes cold and/or heated solvents.
  • Cold and/or heated solvents may be injected into a subterranean reservoir as liquids and/or vapors to decrease the viscosity of heavy oil present within the subterranean reservoir.
  • the injected solvent may dissolve the heavy oil, dilute the heavy oil, and/or transfer thermal energy to the heavy oil.
  • Some processes combine both steam injection and solvent injection to obtain improved extraction from both the use of the heat of the steam as well as the solvency of the heavy oils in the injected solvent to decrease the viscosity of the heavy oil. While these processes using a combination of steam and solvent are effective, they are also hampered by the associated capital and maintenance costs of having to produce and supply both steam and solvent to the process.
  • the solvent based extraction processes (which include the use of an injected solvent alone or with another fluid such as steam as described above) tend to have the benefit of improving the overall extraction of heavy oil from a subterranean reservoir or formation.
  • a significant cost in these solvent based processes is the cost of the solvents themselves which are difficult to recover from the subterranean reservoir during heavy oil recovery, as well as after the well has neared or is at the end of its economically useful life.
  • a significant volume of solvent, worth millions of dollars of solvent value, that has been injected to assist in the extraction of the heavy oil may be remaining in the reservoir.
  • Conventional process for solvent recovery at near end of life of reservoirs in solvent based extraction processes generally involves reducing or cutting off the solvent injection and utilizing steam injected through an upper injection well as a mechanism to recover the solvent with bitumen from the reservoir.
  • the injected steam evaporates the retained solvent and condenses it at the edge of the chamber where it gravity drains to a lower production well along with extracted bitumen.
  • the steam injection process thus recovers the solvent as a liquid through the process of gravity drainage. This technique can result in very slow and inefficient solvent recovery.
  • the production of the large amounts of steam required is very energy intensive as well as requiring large amounts of water, which not only needs to be significantly treated (e.g., water softening, pH control, etc.) in order to produce the steam but requires a large amount of water which may not be readily available in a solvent-based extraction processes location.
  • Even more of an impediment to conventional steam-based solvent recovery processes is typically that the solvent-based extraction processes require little or essentially no steam for use in injection process.
  • the solvent-based extraction processes typically have significantly undersized steam capacity (if any) to perform the steam flooding recovery processes. Therefore, extensive capital and construction is required to employ large steam generation systems at these sites to employ these conventional steam injection based solvent recovery processes to resources previously utilizing solvent-based heavy oil recovery processes.
  • Improved processes that can recover the remaining solvent from a subterranean reservoir can significantly reduce the overall cost of producing heavy oil from solvent based extraction processes. Additionally, removal of remaining solvents in a subterranean reservoir may provide environmental improvements by reducing the amount of remaining solvents in a shut-in reservoir from a solvent based heavy oil recovery process. Therefore, a need exists in the industry for improved technology, including technology that improves the recovery of solvents remaining in a subterranean reservoir at the end (or near the end, i.e., “late life”) of the reservoir's production stage.
  • An embodiment disclosed herein includes a process for the recovery of a solvent from a subterranean reservoir containing a solvent and a heavy oil, the process comprising:
  • the gas phase dilution agent comprises a non-condensable gas which remains in vapor phase at pressure and temperature of the subterranean reservoir.
  • the solvent-assisted gravity drainage process step comprises a well pair located in the subterranean reservoir, wherein the well pair is comprised of at least one injection well and at least one production well and further wherein the at least one injection well is converted to an NCG injection well prior to, or in conjunction with, step b), and injecting the gas phase dilution agent into the subterranean reservoir via the NCG injection well.
  • the solvent-assisted gravity drainage process step comprises at least two well pairs located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), prior to, or in conjunction with, step b):
  • the solvent-assisted gravity drainage process step comprises at least three well pairs located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), prior to, or in conjunction with, step b):
  • the solvent-assisted gravity drainage process step comprises at least three well pairs located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), prior to, or in conjunction with, step b):
  • the solvent-assisted gravity drainage process step comprises at least two well pairs located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), prior to, or in conjunction with, step b):
  • the solvent-assisted gravity drainage process step comprises at least two well pairs located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), prior to, or in conjunction with, step b):
  • the solvent-assisted gravity drainage process step comprises at least one well pair located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), and prior to, or in conjunction with, step b):
  • step e) wherein in step e), the at least a portion of the gas phase dilution agent and the vaporized solvent is extracted from the subterranean reservoir via the NCG/vaporized solvent production well.
  • Another embodiment disclosed herein includes a system for the recovery of a solvent from a subterranean reservoir containing a solvent and a heavy oil, the system comprising:
  • the first NCG/vaporized solvent production well is configured to recover a portion of the gas phase dilution agent and a portion of the vaporized solvent.
  • FIG. 1 illustrates the solvent stripping mechanism due to dilution and partial pressure reduction by non-condensable gases.
  • FIG. 2 illustrates the solvent vaporization due to dilution and partial pressure reduction by non-condensable gases.
  • FIG. 3 is a simplistic diagram of a single well pair configuration in a subterranean reservoir as used in an embodiment of the invention herein.
  • FIGS. 4A-4E illustrate reservoir well configurations and flow patterns for various gas sweep embodiments of the present invention.
  • FIG. 5 is a simplified illustration of the well configuration utilized in modeling embodiments of the gas sweep configurations of the present invention.
  • FIG. 6A is a graph of the solvent production rate as a function of time for the steam injection model (SAGD mode) of an embodiment of the present invention for a single well pair configuration.
  • FIG. 6B is a graph of the solvent production rate as a function of time for the NCG injection model of an embodiment of the present invention for a single well pair configuration.
  • FIG. 6C is a graph of the solvent production rate as a function of time for the inter-well pair NCG flood model of an embodiment of the present invention for a multiple well pair configuration using a gas flood/sweep configuration.
  • FIG. 7 is a graph comparing the solvent recovery (in percentage of total solvent) for different solvent recovery methods. It includes the steam only (switch to SAGD), NCG injection for a single well pair configuration, and an inter-well pair NCG flood case of the present invention for a multiple well pair configuration using a gas flood/sweep configuration.
  • FIG. 8 illustrates a reservoir well configuration and flow patterns for a gas cap expansion embodiment of the present invention.
  • FIG. 9 is a graph comparing the solvent recovery (in percentage of total solvent) for the present invention for a multiple well pair configuration using the gas cap expansion configuration and inter-well pair NCG flood configuration.
  • FIG. 10 is a graph comparing the solvent recovery (in percentage of total solvent) for two models of the present invention using the gas flood/sweep configuration and the gas cap expansion configuration, in comparison with a steam injection only (SAGD) solvent recovery model of the prior art for a multiple well pair configuration.
  • SAGD steam injection only
  • 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 subterranean reservoirs. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.
  • 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:
  • 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, may be removed to avoid contamination of synthetic crude oil.
  • Nickel can vary from less than 75 ppm (parts per million) to more than 200 ppm.
  • Vanadium can range from less than 200 ppm to more than 500 ppm.
  • Heavy oil includes bitumen, as well as lighter materials that may be found in a sand or carbonate reservoir. “Heavy oil” includes oils that are classified by the American Petroleum Institute (API), as heavy oils, extra heavy oils, or bitumens. Thus the term “heavy oil” includes bitumen. Heavy oil may have a viscosity of about 1000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more or 1,000,000 cP or more.
  • cP centipoise
  • a heavy oil has an API gravity between 22.3° API (density of 920 kilograms per meter cubed (kg/m 3 ) or 0.920 grams per centimeter cubed (g/cm 3 )) and 10.0° API (density of 1,000 kg/m 3 or 1 g/cm 3 ).
  • An extra heavy oil in general, has an API gravity of less than 10.0° API (density greater than 1,000 kg/m 3 or greater than 1 g/cm 3 ).
  • a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water, and bitumen.
  • the recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature and/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.
  • a heavy oil may include heavy end components and light end components.
  • asphaltenes or “asphaltene content” refers to pentane insolubles (or the amount of pentane insoluble in a sample) according to ASTM D3279.
  • ASTM D3279 Other examples of standard ASTM asphaltene tests include ASTM test numbers D4055, D6560, and D7061.
  • Heavy end components” in heavy oil may comprise a heavy viscous liquid or solid made up of heavy hydrocarbon molecules.
  • heavy hydrocarbon molecules include, but are not limited to, molecules having greater than or equal to 30 carbon atoms (C 30 +).
  • the amount of molecules in the heavy hydrocarbon molecules may include any number within or bounded by the preceding range.
  • the heavy viscous liquid or solid may be composed of molecules that, when separated from the heavy oil, have a higher density and viscosity than a density and viscosity of the heavy oil containing both heavy end components and light end components. For example, in Athabasca bitumen, about 70 weight (wt.) % of the bitumen contains C 30 + molecules with about 18 wt. % of the Athabasca bitumen being classified as asphaltenes.
  • the heavy end components may include asphaltenes in the form of solids or viscous liquids.
  • Light end components” in heavy oil may comprise those components in the heavy oil that have a lighter molecular weight than heavy end components.
  • the light end components may include what can be considered to be medium end components.
  • Examples of light end components and medium end components include, but are not limited to, light and medium hydrocarbon molecules having greater than or equal to 1 carbon atom and less than 30 carbon atoms.
  • the amount of molecules in the light and medium end components may include any number within or bounded by the preceding range.
  • the light end components and medium end components may be composed of molecules that have a lower density and viscosity than a density and viscosity of heavy end components from the heavy oil.
  • a “fluid” includes a gas or a liquid and may include, for example, a produced or native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold water, or a mixture of these among other materials.
  • “Vapor” refers to the gas phase which may contain various materials. Vapor may consist of solvent in the gas form, steam, wet steam, and mixtures of steam and wet steam, any of which could possibly be used with a solvent and other substances, and any material in the vapor phase.
  • “Facility” or “surface facility” is a tangible piece of physical equipment through which hydrocarbon fluids are either produced from a subterranean reservoir or injected into a subterranean reservoir, or equipment that can be used to control production or completion operations.
  • the term facility is applied to any equipment that may be present along the flow path between a subterranean 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, solvent vaporizers, processing plants, and delivery outlets.
  • the term “surface facility” is used to distinguish from those facilities other than wells.
  • Pressure is the force exerted per unit area on the walls of a 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.
  • a “subterranean reservoir” is a subsurface rock, for example carbonate or sand reservoir, from which a production fluid, or resource, can be harvested.
  • a subterranean reservoir may interchangeably be referred to as a subterranean formation.
  • the subterranean formation may include sand, granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy oil (e.g., bitumen), oil, gas, or coal, among others.
  • Subterranean reservoirs can vary in thickness from less than one foot (0.3048 meters (m)) to hundreds of feet (hundreds of meters).
  • the resource is generally a hydrocarbon, such as a heavy oil impregnated into a sand bed.
  • thermal extraction process includes any type of hydrocarbon extraction process that uses a heat source to enhance the extraction/recovery of heavy oils, including bitumen, from a subterranean reservoir or formation, for example, by lowering the viscosity of a hydrocarbon.
  • the processes may use injected mobilizing fluids, such as but not limited to hot water, wet steam, dry steam, or solvents, alone or in any combination, to lower the viscosity of the hydrocarbon.
  • Any of the thermal recovery processes may be used in concert with solvents.
  • thermal recovery processes may include cyclic steam stimulation (CSS), steam assisted gravity drainage (SAGD), steam flooding, in-situ combustion and other such processes.
  • a “solvent-based extraction process” includes any type of hydrocarbon extraction process that uses a solvent to enhance the extraction/recovery of heavy oils, including bitumen, from a subterranean reservoir or formation, for example, by diluting or lowering a viscosity of the hydrocarbon.
  • Solvent-based recovery processes may be used in combination with other recovery processes, such as, for example, thermal recovery processes.
  • a solvent is injected into a subterranean reservoir. The solvent may be heated or unheated prior to injection, may be a vapor or liquid and may be injected with or without steam.
  • Solvent-based recovery processes may include, but are not limited to, solvent assisted cyclic steam stimulation (SA-CSS), solvent assisted steam assisted gravity drainage (SA-SAGD), solvent assisted steam flood (SA-SF), vapor extraction process (VAPEX), thermal variations of VAPEX such as heated vapor extraction process (H-VAPEX) and azeotropic heated vapor extraction process (Azeo-VAPEX), cyclic solvent process (CSP), heated cyclic solvent process (H-CSP), solvent flooding, heated solvent flooding, liquid extraction process, heated liquid extraction process, solvent-based extraction recovery process (SEP), thermal solvent-based extraction recovery processes (TSEP), liquid addition to steam for enhanced recovery (LASER), and any other such recovery process employing solvents either alone or in combination with steam.
  • a solvent-based recovery process may be a thermal recovery process if the solvent is heated prior to injection into the subterranean reservoir.
  • the solvent-based recovery process may employ gravity drainage.
  • SOR Steam to Oil Ratio
  • CSOR Cumulative SOR
  • ISOR Instantaneous
  • SOR, CSOR, and ISOR are calculated at standard temperature and pressure (“STP”, 15° C. and 100 kPa or 60° F. and 14.696 psi).
  • S ol OR Solvent to Oil Ratio
  • CS ol OR Cumulative S ol OR
  • IS ol OR Instantaneous
  • Azeotrope means the “thermodynamic azeotrope” as described further herein.
  • 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 or reservoir, may be used interchangeably with the term “wellbore.”
  • 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.
  • Permeability is the capacity of a rock structure to transmit fluids through the interconnected pore spaces of the structure.
  • the customary unit of measurement for permeability is the milliDarcy (mD).
  • “Reservoir matrix” refers to the solid porous material forming the structure of the subterranean reservoir.
  • the subterranean reservoir is composed of the solid reservoir matrix, typically rock or sand, around pore spaces in which resources such as heavy oil may be located.
  • the porosity of a subterranean reservoir is defined by the percentage of volume of void space in the rock or sand reservoir matrix that potentially contains resources and water.
  • a “solvent extraction chamber” is a region of a subterranean reservoir containing heavy oil that forms around a well that is injecting solvent into the subterranean reservoir.
  • the solvent extraction chamber has a temperature and a pressure that is generally at or close to a to temperature and pressure of the solvent injected into the subterranean reservoir.
  • the solvent extraction chamber may form when heavy oil has, due to heat from the solvent, dissolution within the solvent, combination with the solvent, and/or the action of gravity, at least partially mobilized through the pore spaces of the reservoir matrix.
  • the mobilized heavy oil may be at least partially replaced in the pore spaces by solvent, thus forming the solvent chamber.
  • layers in the subterranean reservoir containing heavy oil may not necessarily have pore spaces that contain 100 percent (%) heavy oil and may contain only 70-80 volume (vol.) % heavy oil with the remainder possibly being water or gas.
  • a water and/or gas containing layer in the subterranean reservoir may comprise 100% water and/or gas in the pore spaces, but generally contains 5-70 vol. % gas and 20-30 vol. % water with any remainder possibly being heavy oil.
  • a “vapor chamber” is a solvent extraction chamber that includes a vapor, or vaporous solvent. Thus, when the solvent is injected into the subterranean reservoir as a vapor, a vapor chamber may be formed around the well.
  • a “reservoir chamber” is a region of the subterranean reservoir that generally contains heavy oil and is affected by (such as increased in temperature or modified in pressure) and mobilized by the oil recovery process. It is generally a region near the wells, surrounding the wells, as well as intermediate locations between the wells, especially between the injection wells and production wells that are under fluid communication. This not only includes the reservoir matrix wherein the heavy oil is located, but also includes rock and mineral deposits that may surround the area but may be affected by the heavy oil recovery process (such as experiencing an increase in temperature). Where solvent extraction chamber(s) and/or vapor chamber(s) exist, these are part of the overall reservoir chamber.
  • NCG non-condensable gas
  • a “gas phase dilution agent” is an agent, composition or stream containing at least some amount, preferably at least 50% by weight in amount, of “non-condensable gas” or “NCG”.
  • PBRS Protein to Retained Solvent ratio
  • a late life or “end of life” phase as it refers to solvent based heavy oil recovery processes herein can include the later stages of heavy oil production during such processes, a switch from heavy oil production mode to a solvent recovery mode during such processes, or a combination thereof. These generally will not be distinct phases in such processes, but a gradual, or multi-step, shift from the general heavy oil production mode of the heavy oil extraction process to a solvent recovery process mode, generally performed near the end of the useful/economic production cycle of a heavy oil reservoir.
  • hydrocarbon solvent or “hydrocarbon mixture” as used herein means a pure component or near pure component solvent or a mixture of at least two, and more usually, at least three, hydrocarbon compounds having a number of carbon atoms from the range of C 1 to C 30 +.
  • a hydrocarbon mixture is often at least hydrocarbons in the range of C 3 to C 12 or higher.
  • the commercially available solvents are generally are a mixture of hydrocarbon compounds.
  • Commercial grade ethane, propane, butane, LPG, gas condensate, diluents, and naphtha are among the used hydrocarbon solvent.
  • the phrase “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.
  • “at least one of A and 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).
  • the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation.
  • 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.
  • the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity.
  • Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined.
  • Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified.
  • a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer to A only (optionally including entities other than B); to B only (optionally including entities other than A); to both A and B (optionally including other entities).
  • These entities may refer to elements, actions, structures, steps, operations, values, and the like.
  • adapted and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function.
  • the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function.
  • elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.
  • 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, embodiments, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, embodiment, and/or method is an illustrative, non-exclusive example of components, features, details, structures, embodiments, and/or methods according to the present disclosure.
  • any of the ranges disclosed may include any number within and/or bounded by the range given.
  • FIGS. 1-10 provide illustrative, non-exclusive examples of systems according to the present disclosure, components of systems, data that may be utilized to select a composition of a hydrocarbon solvent mixture and or a reservoir injection mixture that may be utilized with systems, and/or methods, according to the present disclosure, of operating and/or utilizing systems.
  • Elements that serve a similar, or at least substantially similar, purpose are labeled with like numbers in each of FIGS. 1-10 , and these elements may not be discussed in detail herein with reference to each of FIGS. 1-10 .
  • all elements may not be labeled in each of FIGS. 1-10 , but associated reference numerals may be utilized for consistency.
  • Elements, components, and/or features that are discussed herein with reference to one or more of FIGS. 1-10 may be included in and/or utilized with any of FIGS. 1-10 without departing from the scope of the present disclosure.
  • Solvent based heavy oil extraction (or “recovery”) processes can be utilized over conventional non-solvent based heavy oil extraction processes (such as steam assisted gravity drainage, or SAGD processes) to improve extraction of heavy oil from a subterranean reservoir.
  • Solvent-based recovery processes may be used in combination with other recovery processes, such as, for example, thermal recovery processes, such as SAGD.
  • solvent-based recovery processes a solvent is injected into a subterranean reservoir. The solvent may be heated or unheated prior to injection, may be a vapor or liquid and may be injected with or without steam.
  • Solvent-based recovery processes may include, but are not limited to, solvent assisted cyclic steam stimulation (SA-CSS), solvent assisted steam assisted gravity drainage (SA-SAGD), solvent assisted steam flood (SA-SF), vapor extraction process (VAPEX), thermal variations of VAPEX such as heated vapor extraction process (H-VAPEX) and azeotropic heated vapor extraction process (Azeo-VAPEX), cyclic solvent process (CSP), heated cyclic solvent process (H-CSP), liquid addition to steam enhanced recovery (LASER), solvent flooding, heated solvent flooding, liquid extraction process, heated liquid extraction process, solvent-based extraction recovery process (SEP), thermal solvent-based extraction recovery processes (TSEP), and any other such recovery process employing solvents either alone or in combination with steam.
  • a solvent-based recovery process may be a thermal recovery process if the solvent is heated prior to injection into the subterranean reservoir.
  • the solvent-based recovery process may employ gravity drainage
  • PBRS a measure of economic viability
  • bitumen to Retained Solvent is the “Produced Bitumen to Retained Solvent” ratio and is the amount of bitumen (by standard condition volume) from the well or reservoir divided by the amount of unrecovered solvent (by standard condition volume) from the well or reservoir.
  • the PBRS In reservoirs undergoing the VAPEX process, near the end of the production life of the reservoir, the PBRS depends on many factors such as the geometry and geology of the reservoir, the type and geometry of the wells, operating conditions, selection of solvent ratios and/or solvent concentrations, as well as many other possible factors. However, a significant magnitude of lost potential resources and lost economics are subject to recovery by improved solvent recovery processes.
  • recovery of the trapped solvent can be achieved by changing the phase behavior conditions in the reservoir by introducing a gas phase dilution agent.
  • a heating agent may also utilized or otherwise present as stored heat in the reservoir from solvent-based thermal recovery process to provide vaporization energy for stripping of the solvent.
  • the gas phase dilution agent can also serve as a, or the, heating agent as well.
  • the heating agent may be comprised of the non-condensable gas, steam or a combination thereof.
  • the heat stored in the reservoir during a solvent-based thermal heavy oil recovery process may serve as the heating agent as well.
  • the gas phase dilution agent contains or is substantially comprised of a non-condensable gas under reservoir pressure and temperature conditions.
  • the gas phase dilution agent (which may also be referred to as the “dilution/heating agent” or designated as “D/HA”) may be described as a non-condensable gas or NCG herein.
  • a gas phase dilution agent preferably a non-condensable gas
  • the gas phase dilution agent will be utilized, at least in part, to reduce the partial pressure of the liquid phase solvent in the reservoir and thus vaporize the solvent, or at least a portion of the solvent by the various methods and configurations disclosed herein. This includes vaporizing at least a portion of the lower boiling point components of the solvent.
  • the recovery mode is to recover the solvent mainly in the liquid phase, preferably by “pushing” the solvent, or by evaporating and then condensing the solvent, and recovering the primarily liquid solvent from the production well.
  • a solvent based thermal gravity drainage-based heavy oil recovery process for example thermal VAPEX
  • thermal VAPEX may switch to steam injection at the end of the life of the economical production, which is also known as switching to steam assisted gravity drainage (SAGD).
  • SAGD steam assisted gravity drainage
  • steam evaporates the liquid phase solvent, which then condenses at the edge of the chamber and is produced mainly as a liquid phase.
  • the methods disclosed herein are designed to vaporize, in-situ, the solvent (or components of solvent) and recover the solvent from the reservoir primarily in the vapor phase by injection and production of gas (preferably a non-condensable gas) as discussed further herein. It has been discovered herein, and as will be shown, that recovering the solvent primarily in the vapor phase according to the methods herein, results in a distinctly improved recovery rate (i.e., solvent recovery percentage) over methods of recovering the solvent in the liquid phase.
  • solvent refers to the solvent which is targeted to be recovered from the reservoir, and includes the previously injected solvent that is to be recovered from the reservoir, or a portion of the components thereof unless otherwise noted.
  • the term “late life” as it refers to solvent based heavy oil recovery processes herein can include the later stages of heavy oil production during such processes, a switch from heavy oil production mode to a solvent recovery mode during such processes for example due to operational or economic factors, or a combination thereof.
  • FIG. 1 illustrates the solvent stripping mechanism due to dilution.
  • Introduction of a non-condensable diluting agent into the pore space results in a drop in the solvent partial pressure, thus reducing its molar fraction in the liquid phase.
  • the smaller liquid phase molar fraction implies stripping of the solvent from the liquid phase into a gas phase.
  • the solvent is thus easier to displace due to the gas phase mobility.
  • Continuous injection of the diluting agent into the reservoir and production of the solvent vapor results in the removal of much of the solvent. This is demonstrated on FIG. 1 by the dashed arrows, where the solvent stored during the thermal solvent-based recovery (shown by the triangles) is reduced to much lower values (shown by the circles) at the end of the solvent striping process.
  • FIG. 2 depicts the injected solvent content of a reservoir as an example.
  • NCG non-condensable gas
  • solvent can more easily be separated from the NCG utilized in the injection and recovery techniques discussed herein, than is prior art recovery methods such as steam injection at late life wherein the solvent is recovered in a liquid phase generally mixed with both water and recovered bitumen.
  • These methods are also very effective in maintaining reservoir pressure during the solvent recovery and shut-in phases of the reservoir to prevent intrusion or unwanted cross flow from other reservoirs or reservoir chambers in the region.
  • These methods may additionally have ecological benefits, by reducing the amount of water utilized (i.e., by reducing overall steam demand during recovery), reducing the amount of unrecoverable water (i.e., by reducing the amount of water, from steam, left in the reservoir at the end of the reservoir production/recovery), enhancing solvent recovery percentage, as well as reducing the cost of solvent recovery (thereby making the solvent recovery from the reservoir even more feasible).
  • One embodiment of the present invention is to utilize the NCG injection recovery process in a “single well pair” configuration. It should be noted that the term “single well pair” as used herein, is meant to use where the primary implementation of this embodiment is to induce recovery between an injector and a producer in a well pair.
  • this method may not be utilized where there is more than one well pair (or infill wells) in the reservoir or in the vicinity of the “single well pair”, but only that the primary mode of the recovery operation described in this embodiment is to induce recovery between an injector and a producer in a well pair as compared to other embodiments of the methods disclosed herein, where the primary mode of the recovery operation in these other embodiments may be to induce recovery between or with multiple well pairs (and/or infill wells).
  • FIG. 3 is a simplistic diagram of a single well pair configuration in a subterranean reservoir ( 400 ) which may be utilized to illustrate the current NCG injection recovery process as applied to a single well pair configuration.
  • the well pair consists of an injection well ( 401 ) and a production well ( 405 ).
  • the injection well will be located at a location above the production well as shown.
  • the methods herein are not limited to well pairs that only have a vertical offset component.
  • the well pair may be staggered (i.e., contain an offset between the two wells in the well pair contains both a lateral, as well as a vertical, component).
  • the basic operation of the methods herein may also apply between pairs that only have a significantly horizontal offset component. While most of the single well pair and multiple well pair configurations illustrated herein will show the wells in the well pairs (i.e., the original injection and production) as significantly vertically oriented with respect to one another, the principles of the concepts may additionally apply to these other configurations unless otherwise noted.
  • the diluting/heating agent (or “D/HA”) containing a non-condensable gas (which, for simplicity purposes in the figures and descriptions herein, the diluting/heating agent may be referred to alternatively herein as “NCG”) is injected into the reservoir via the injection well ( 401 ).
  • the NCG can be injected at approximately ambient surface temperature or can be heated prior to injection into the reservoir. Heating the NCG prior to injection can improve the solvent recovery by providing heat for the evaporation of the solvent in the reservoir.
  • the temperature of the well can be raised prior to, or with, the injection of the NCG into the reservoir. This can be done during normal recovery operations or as part of preparation for the solvent recovery stage.
  • the NCG as well as the retained solvent, take advantage of the residual heat stored in the reservoir to improve solvent recovery.
  • the NCG and evaporated solvent tend to move upward in the reservoir chamber ( 410 ) prior to moving down at the interface of the reservoir chamber towards the production well ( 405 ) as illustrated by flow arrows ( 415 ).
  • the flow arrows show the path of the NCG and vaporized solvent in the reservoir chamber ( 410 ).
  • FIGS. 6A and 6B show the solvent production rates in both liquid and gas phases from the start of solvent recovery stage for the case of single well pair based on single well pair steam injection ( FIG. 6A ) and on single well pair NCG injection ( FIG. 6B ).
  • FIGS. 6A and 6B The results for the single well pair embodiment are shown in FIGS. 6A and 6B .
  • FIG. 6A In the case of utilizing steam injection for solvent recovery, FIG. 6A , most of the solvent is vaporized by hot steam and moved to the edge of the chamber where it condenses and is then produced as a liquid phase.
  • FIG. 6B In the case when using NCG injection for solvent recovery as shown in FIG. 6B , the processes described herein allow for some diluting of the gas phase and as a result stripping of the solvent into the gas phase, which results in recovery of some of the solvent in the gas form, and an overall higher solvent recovery.
  • the present invention is economically beneficial for late life recovery of solvent in a solvent-based bitumen recovery process (such as VAPEX) in single well pair configuration such as was exemplified in the models described prior (and results illustrated in comparative FIGS. 6A and 6B ), it is seen that the use of the present invention in certain multiple well-pair configurations and “sweep” configurations can provide even significantly greater improvements in solvent recovery (as shown in FIG. 6C and FIG. 7 and processes as will be described further herein). Additionally, the hydrocarbon solvents are generally and primarily in vapor form when injected in a thermal solvent-assisted heavy oil recovery process, for example VAPEX and SA-SAGD.
  • the solvent then condenses as it heat up the oil and the formation, which means that some of it is left behind as a liquid phase.
  • the present invention also provides more significant solvent recovery when utilized for solvent recovery in a reservoir which has utilized an SA-SAGD process during production.
  • the present invention even eclipses the overall solvent recovery as compared to when a steam only (SAGD) process is utilized in late life recovery of solvent from solvent-assisted gravity drainage process.
  • FIGS. 4A, 4B & 4C will be utilized to illustrate these preferred modes using a typical, but non-limiting, example well configurations.
  • the subterranean reservoir or “reservoir” ( 600 ) contains a five well pair configuration is shown for purposes of illustration.
  • Each of the five horizontal well pairs comprises an injection well ( 601 ) and a production well ( 605 ) wherein, in FIGS. 4A-4C (and additionally as in later figures as will be discussed), these wells are shown in an elevation view, as viewed down the axis of the horizontally running injection and production wells ( 601 ) and ( 605 ).
  • each of the five horizontal well pairs comprises an injection well ( 601 ) and a production well ( 605 ).
  • solvent is injected into the injection well ( 601 ).
  • This solvent (as well as other components such as steam) is utilized to reduce the viscosity of the heavy oil (or “bitumen”) that is present in the reservoir ( 600 ).
  • the solvent and reduced viscosity heavy oil flow in a pattern which forms the reservoir chamber(s) ( 610 ).
  • FIG. 4A the condensed solvent and reduced viscosity heavy oil liquid drainage is through the reservoir chamber ( 610 ) and the exterior of the liquid flow pattern ( 620 ) follows the bottom outer boundaries follow the outer contour of reservoir chamber ( 610 ) and is recovered primarily as a liquid from the production well ( 605 ).
  • FIGS. 4B and 4C These figure elements shown in FIG. 4A of the operating (or production) portion of the solvent assisted gravity drainage are typically the same for FIGS. 4B and 4C for the purposes of these illustrations.
  • FIGS. 4A, 4B, and 4C will illustrate different NCG “sweep” configurations of the present invention in late life production/solvent recovery.
  • alternative existing injection wells the first, third and fifth elements 601 starting from the left in FIG. 4A
  • the intermediate existing injection wells the second and fourth elements 601 starting from the left in FIG. 4A
  • all production wells the elements 605 in FIG. 4A
  • the NCG is injected via the NCG injection wells.
  • the NCG may comprise any gas that is non-condensable under the reservoir pressure and temperature conditions.
  • the NCG may also be heated prior to injection to improve solvent recovery.
  • the NCG may also use existing stored heat in the reservoir to obtain an increase in temperature which improves solvent recovery.
  • the reservoir temperature is raised during the normal thermal production cycle of the reservoir, which increases heavy oil production and in these illustrated late life cycles, provides additional heating to the injected NCG in the present solvent recovery processes.
  • the diluting/heating agent (or “D/HA”) containing a non-condensable gas may be referred to interchangeably as “NCG”.
  • a substantial amount of NCG is injected into the now converted NCG injection wells.
  • substantially amount of NCG injected it is meant that a volume or volume rate of NCG is injected into the reservoir sufficient to vaporize at least a portion of the components in the liquid solvent (due to a decrease in partial pressure of the solvent in the vapor phase) thereby decreasing the partial pressure of at least some of the components in the solvent in the vapor phase by at least 5%, at least 10%, at least 25%, at least 50%, at least 75%, or more preferably at least 99%.
  • At least 10 wt %, at least 25 wt %, at least 50 wt %, or more preferably at least 98 wt % of the liquid solvent in the reservoir is converted to a vapor.
  • at least a portion of the solvent in the reservoir chambers ( 610 ) begins to vaporize due to an imposed decrease in the partial pressure of the solvent in the reservoir chamber (as used here the term “solvent” is to also include the solvent components, especially the lower boiling point solvent components).
  • This provides a flooding or sweeping effect across the reservoir providing the mechanism to both 1) lower the partial pressure of the solvent in the reservoir chamber(s), thereby converting at least a portion of the liquid solvent to a vapor, and 2) moving the now vaporized solvent and NCG across the reservoir from the NCG injection well(s) to the NCG/vaporized solvent production well for recovery.
  • This embodiment herein utilizes at least one existing production/injection well as a now converted NCG injection well and at least two existing production/injection wells as a now converted NCG/vaporized solvent production wells as described above. This creates an NCG/vaporized solvent sweep flow pattern ( 625 ) as shown in FIG. 4A .
  • the produced NCG with the vaporized solvent from the production wells is separated in a surface facility the separated NCG is recompressed and re heated to a desired temperature if required and is re-injected (recycled) in the NCG injection wells. Any additionally required NCG for solvent recovery process may be added to the recycled NCG stream.
  • the separated solvent from the produced NCG/solvent gas is the recovered solvent from the gas phase stream.
  • the produced liquid from production wells also contain some dissolved NCG, solvent and heavy oil which is treated in the surface facility to separate heavy oil, solvent, and NCG from each other.
  • FIG. 4B illustrates another embodiment of the NCG sweep technique in a well pattern similar to that in FIGS. 4A & 4C .
  • the elements in FIGS. 4A, 4B and 4C are numbered similarly.
  • the reservoir ( 600 ) contains a five well pair configuration for purposes of illustration.
  • each well pair is shown in these figures for illustrative purposes wherein the injector well and the production well are in a substantially vertical orientation to each other, i.e., “vertical well pair”, and where each well pair is located in a substantially horizontal direction relative to at least one adjacent well pair) are utilized in a solvent-assisted gravity drainage process (such as VAPEX or SA-SAGD), wherein the wells of each well pair is oriented in a vertical orientation to one another with the top well utilized as an injection well and the bottom well used as a production well in each pair.
  • Each of the five horizontal well pairs comprises an injection well ( 601 ) and a production well ( 605 ).
  • solvent is injected into the injection wells ( 601 ) similarly to as described in FIG. 4A .
  • This solvent (as well as other components such as steam) is utilized to reduce the viscosity of the heavy oil (or “bitumen”) that is present in the reservoir ( 600 ).
  • the production process and elements ( 610 ) through ( 620 ) operate in a similar manner to as described in FIG. 4A during normal production life of the reservoir under solvent assisted gravity drainage conditions.
  • FIG. 4B an embodiment of the late life production/solvent recovery NCG sweep configuration is illustrated as follows.
  • one of the injection wells at one end of the series of wells is converted to, and utilized as an “NCG/vaporized solvent production well” (shown in FIG. 4B as the first element 601 starting from the left), while the other existing injection wells in a series are converted to, and utilized as “NCG injection wells” (shown in FIG. 4B as the second, third, fourth and fifth elements 601 starting from the left).
  • all of the production wells are converted to liquid production wells (shown in FIG. 4B as 605 ).
  • the NCG is injected via the four NCG injection wells.
  • the NCG may comprise any gas that is non-condensable under the reservoir pressure and temperature conditions.
  • the NCG may also be heated prior to injection to improve solvent recovery.
  • the NCG may also use existing stored heat in the reservoir to obtain an increase in temperature to improve solvent recovery.
  • the reservoir temperature is raised during the normal thermal production cycle of the reservoir, which increases heavy oil production and in these illustrated late life cycles, provides additional heating to the injected NCG in the present solvent recovery processes.
  • a substantial amount of NCG is injected into now converted NCG injection wells.
  • the solvent in the reservoir chambers ( 610 ) begins to vaporize due to a decrease in the partial pressure of the solvent in the gas phase (as used here to also include the solvent components, especially the lower boiling point solvent components).
  • a significant portion of the solvent in the reservoir chambers vaporizes and moves upward through the reservoir chambers while additionally moving with a horizontal component direction toward the now converted NCG/vaporized solvent production well which is located on one side of the series of now converted NCG injection wells.
  • This embodiment herein utilizes at least one existing injection well as a now converted NCG injection well and at least one existing injection well as a now converted NCG/vaporized solvent production well as described above. This creates an NCG/vaporized solvent sweep flow pattern ( 625 ) as shown in FIG. 4B .
  • FIG. 4C illustrates another embodiment of the NCG flood technique in a well pattern similar to that in FIGS. 4A & 4B .
  • the reservoir ( 600 ) contains, a five well pair configuration for purposes of illustration. This may illustrate a typical reservoir wherein five horizontal well pairs are utilized in a solvent-assisted gravity drainage process (such as VAPEX or SA-SAGD). Each of the five horizontal well pairs comprises an injection well ( 601 ) and a production well ( 605 ). During normal operation of a solvent assisted gravity drainage process, solvent is injected into the injection wells ( 601 ) similarly to as described in FIG. 4A .
  • This solvent (as well as other components such as steam) is utilized to reduce the viscosity of the heavy oil (or “bitumen”) that is present in the reservoir ( 600 ).
  • the production process and elements ( 610 ) through ( 620 ) operate in a similar manner to as described in FIG. 4A during normal production life of the reservoir under solvent assisted gravity drainage conditions.
  • FIG. 4C an embodiment of a late life production/solvent recovery NCG sweep configuration is illustrated as follows.
  • one of the existing injection wells at one end of the series of wells is converted to an “NCG/vaporized solvent production well” (shown in FIG. 4C as the third element 601 starting from the left), while the other existing injection wells in a series are converted to “NCG injection wells” (shown in FIG. 4B as the first, second, fourth and fifth elements 601 starting from the left).
  • all of the production wells are converted to liquid production wells.
  • the NCG is injected via the four NCG injection wells.
  • the NCG may comprise any gas that is non-condensable under the reservoir pressure and temperature conditions.
  • the NCG may also be heated prior to injection to improve solvent recovery.
  • the NCG may also use existing stored heat in the reservoir to obtain an increase in temperature to improve solvent recovery.
  • the reservoir temperature is raised during the normal thermal heavy oil production cycle of the reservoir, which increases heavy oil production and in these illustrated late life cycles, provides additional heating to the injected NCG in the present solvent recovery processes.
  • a substantial amount of NCG is injected into now converted NCG injection wells.
  • the solvent in the reservoir chambers ( 610 ) begins to vaporize due to a decrease in the partial pressure of the solvent in the vapor phase (as used here to also include the solvent components, especially the lower boiling point solvent components).
  • a significant portion of the solvent in the reservoir chambers vaporizes and moves upward through the reservoir chambers while additionally moving with a horizontal component direction toward the now converted NCG/vaporized solvent production well which is located within the series of NCG injection wells (i.e., at least one well pair containing a NCG injection well is located on each side of the converted NCG/vaporized solvent production well). Also, any draining liquid is produced from the production wells that are located in the bottom of drainage chamber.
  • This embodiment herein utilizes at least two existing production or injection wells as a now converted NCG injection well and at least one existing production or injection well as a now converted NCG/vaporized solvent production well as described above. This creates an NCG/vaporized solvent sweep flow pattern ( 625 ) as shown in FIG. 4C .
  • FIGS. 4A-4C contemplate utilizing the existing production wells as liquid production wells (as well as the data from the models herein are based on utilizing the existing production wells as liquid production wells), in embodiments of the inter-well pair (or multi-well pair) processes herein, some, or all of the production wells may be converted to NCG/vaporized solvent production wells or NCG injection wells.
  • FIG. 7 shown the total Solvent Recovery, for all three (3) cases described in FIGS. 6A-6C .
  • the process employing the NCG injection embodiment of the invention as well as the inter-well pair NCG flood embodiment recovered more solvent than the steam injection (SAGD) case in the early days, even though the SAGD case did ultimately recover slightly more overall solvent than the NCG injection embodiment.
  • SAGD steam injection
  • NCG injection case of the present invention only NCG is required, no steam is required even as a heating agent, as the heat stored in the reservoir is sufficient to maintain the process of liquid solvent stripping into the injected diluting agent. Even if some steam may be added to the process, mainly if heating is required, the amount of steam used would be only a small fraction of what would be required for a steam only (SAGD mode) recovery operation; and existing facilities in a solvent assisted heavy oil recovery operation may be sufficient for these purposes without the need to install and operate additional costly steam generation facilities.
  • SAGD mode steam only
  • Much of this NCG utilized in the present methods may be readily available from site operations, can be obtained or supplemented by pipelines, or can be utilized NCGs, such as CO 2 , in a sequestration mode.
  • the NCG may be comprised of C 1 , C 2 , C 3 , N 2 , CO 2 , natural gas, produced gas, flue gas or any combination thereof.
  • the steam facilities required to perform the steam only (SAGD) process as modeled are not already present (at least not in the capacity that they would be in a non-solvent SAGD type operation).
  • highly capital intensive, energy intensive and manpower intensive steam generation facilities must be physically brought to the near vicinity of the well site and connected to the injection well(s).
  • FIGS. 4D and 4E illustrate these embodiments.
  • the elements ( 600 ) through ( 625 ) in these two figures are essentially the same as described in FIG. 4A .
  • the use of an infill well ( 630 ), or multiple infill wells (not shown) may be used in the solvent recovery process.
  • an existing infill well ( 630 ) may be utilized or an infill well may be installed specifically to be used in the solvent recovery methods as disclosed and described herein.
  • the infill well as illustrated in FIGS. 4D and 4E is shown located near the bottom of the reservoir, it may be installed at any vertical level within the reservoir between two well pairs. In the embodiment shown in FIG.
  • the existing or installed infill well is utilized as an NCG/vaporized solvent production well for the late life solvent recovery processes herein.
  • the two adjacent existing injection wells ( 601 ) are converted to NCG injection wells. Similar as described in prior FIGS. 4A-4C , in this embodiment, a substantial amount of NCG is injected into now converted NCG injection wells. After injecting the NCG, at least a portion of the solvent in the reservoir chambers ( 610 ) begins to vaporize due to a decrease in the partial pressure of the solvent in the vapor phase (as used here “solvent” to also include the solvent components, especially the lower boiling point solvent components).
  • This embodiment herein utilizes at least two existing production injection wells as a now converted NCG injection wells and an infill well as an NCG/vaporized solvent production wells as described above. This creates an NCG/vaporized solvent sweep flow pattern ( 625 ) as shown in FIG. 4D . It is herein noted in the embodiments described herein that the NCG/vaporized solvent production well(s) may also recover liquid phase solvent from the subterranean reservoir. Alternatively, in embodiments, one or more of the existing production wells ( 605 ) can be converted to an NCG injection well.
  • FIG. 4E illustrates a similar configuration and method of operation as shown in FIG. 4D , but in this embodiment, a substantial amount of NCG is injected into the infill well ( 630 ) which has been installed as, or converted into an NCG injection well.
  • the existing injection wells ( 601 ) have been converted into NCG/vaporized solvent production wells, which now recover the majority of the NCG and recovered vaporized solvent, while the existing to production wells now recover the majority of the liquid solvent as well as heavy oil (bitumen).
  • the two adjacent existing production wells ( 605 ) can be converted to NCG/vaporized solvent production wells.
  • This embodiment herein utilizes at least two existing production or injection wells as now converted NCG/vaporized solvent production wells and at least one infill well as an NCG injection well as described above. This creates an NCG/vaporized solvent sweep flow pattern ( 625 ) as shown in FIG. 4E .
  • NCG injection well is converted to an NCG injection well
  • an existing injection well shown as 601 on the left hand side of FIG. 5
  • NCG/vaporized solvent production well is converted to an NCG/vaporized solvent production well.
  • the existing production wells are also converted to liquid production well (solvent and as well as heavy oil).
  • the pressure at the NCG injection well is increased (and/or the pressure at the NCG/vaporized solvent production well is decreased) such that the pressure (P 2 ) at the NCG injection well as shown in FIG. 5 is greater than the pressure (P 1 ) at the NCG/vaporized solvent production well.
  • the NCG is injected through the now converted NCG injection well and NCG and vaporized solvent are produced by the now converted NCG/vaporized solvent production well.
  • Heavy oil and primarily liquid solvent are additionally produced from the production wells ( 620 ).
  • the NCG injection case as shown in FIGS. 6B and 6C were operating a thermal VAPEX process, followed by a late life process consisting of injecting NCG gas according to an embodiment herein.
  • the solvent used in all of the models was a mixture of essentially C 3 -C 9 hydrocarbons which exemplifies a typical solvent mixture utilized in a solvent-based heavy oil recovery process (such as VAPEX, or SA-SAGD process).
  • the NCG utilized in the models was a 50%/50% by mole mixture of C 1 (methane) and CO 2 (carbon dioxide) which is exemplary of a production gas that may be used, readily obtainable, or easily obtainable, in reservoir heavy oil recovery processes.
  • the models were run after the reservoir had been in thermal VAPEX service, and FIGS. 6B and 6C show the solvent production rates from the start of the late life recovery processes described herein (i.e., start of NCG injection).
  • the process according to the invention in the inter-well pair flooding model shows a significant increase in the solvent recovery in both the gas phase and the liquid phase over the single well pair steam injection of the prior art, as well as the single well pair NCG injection embodiment of the present invention.
  • This NCG flood embodiment utilizing a flood (or “sweep”) from at least one well pair to at least another well pair in the reservoir, resulted in significant enhancement in solvent recovery in both the gas phase and the liquid phase, as well as the total solvent recovery (sum of gas and liquid phase solvent recovery).
  • FIG. 7 further illustrates the significant impact of using this embodiment of solvent recovery in a VAPEX process for late life solvent recovery.
  • FIG. 7 it can be seen in the inter-well pair NCG flood model of the present invention, that a higher solvent recovery compared to steam injection case (SAGD mode) and NCG injection in single well pair configuration is achieved. Additionally, it can be seen that the inter-well pair NCG flood embodiment of the present invention can achieve very high total solvent recovery, and notably, it can also be seen that this recovery plateau is reached in a very short time frame in the inter-well pair NCG flood case.
  • the present invention offers significant improvements in solvent recovery over the conventional methods in the art.
  • the solvent recovery processes herein can be utilized in a reservoir containing one or more wells or well pairs preferably under a gas cap.
  • FIG. 8 illustrates this embodiment in a five well pair arrangement similar to those described in the production life stages discussed with respect to FIGS. 4A, 4B and 4C , wherein the well(s) are operating under a natural or induced gas cap.
  • the production process and elements ( 600 ) through ( 620 ) operate in a similar manner to as described in FIG. 4A during normal production life of the reservoir under solvent assisted gravity drainage conditions.
  • a gas cap may be naturally present, or it may already have been established in the reservoir, or may be established as a step in performing the processes as described in this embodiment.
  • facilities for injecting and maintaining the gas cap may be utilized or modified for the present NCG gas cap expansion description.
  • FIG. 8 an embodiment of a late life production/solvent recovery NCG gas cap flood configuration according to the invention herein is illustrated as follows.
  • the existing injection wells ( 601 ) are shut in.
  • a stream containing a substantial amount of NCG is injected into the top of the reservoir through injection facilities in fluid communication with the top of the reservoir, such as, and preferably when, gas cap injection facilities are already in place during the production phase.
  • FIG. 8 illustrates an embodiment of a late life production/solvent recovery NCG gas cap flood configuration according to the invention herein is illustrated as follows.
  • the existing injection wells ( 601 ) are shut in.
  • a stream containing a substantial amount of NCG is injected into the top of the reservoir through injection facilities in fluid communication with the top of the reservoir, such as, and preferably when, gas cap injection facilities are already in place during the production phase.
  • an existing gas cap, or newly established gas cap, now containing NCG and vaporized solvent is expanded via dropping the reservoir pressure or injection of the NCG containing stream and flows in a pattern ( 630 ) from the top of the reservoir through the to reservoir chamber(s) to the production well(s) ( 605 ).
  • NCG, heavy oil, liquid solvent and vaporized solvent are recovered via the production well(s) which have been converted to NCG/vaporized solvent production well(s) ( 605 ).
  • the NCG may comprise any gas that is non-condensable under the reservoir pressure and temperature conditions.
  • the NCG may also be heated prior to injection to improve solvent recovery.
  • the NCG may also use existing stored heat in the reservoir to obtain an increase in temperature to improve solvent recovery. In such embodiment, the reservoir temperature is raised during the normal thermal heavy oil production cycle of the reservoir, which increases heavy oil production and in these illustrated late life cycles, provides additional heating to the injected NCG in the present solvent recovery processes.
  • a substantial amount of NCG is injected into the reservoir through existing, or newly installed gas cap injectors. These injectors are preferably located at, or near, the top of the reservoir. After injecting the NCG, at least a portion of the solvent in the reservoir chambers ( 610 ) begins to vaporize due to an induced decrease in the partial pressure of the solvent (as used here to also include the solvent components, especially the lower boiling point solvent components). The gas cap is extended in volume and begins to push downward with the NCG and now vaporized solvent in the reservoir chambers ( 610 ).
  • This embodiment herein utilizes at least one existing injection well or at least one existing production well as a now converted NCG/vaporized solvent production well.
  • This embodiment creates an NCG/vaporized solvent gas cap expansion flow pattern ( 1025 ) as shown in FIG. 8 . While the process and the models for the gas cap expansion are described herein wherein the existing injection wells ( 601 ) are converted to NCG/vaporized solvent production wells and the existing production wells ( 605 ) are utilized as liquid production wells (solvent and as well as heavy oil), in alternative embodiments herein, one or more, including all, of the production wells ( 605 ) can be converted to NCG/vaporized solvent production wells. In some embodiments of the gas cap expansion processes disclosed herein, both the existing injection wells ( 601 ) and the existing production wells ( 605 ) can be converted to NCG/vaporized solvent production wells.
  • NCG is injected at the top of the reservoir using existing facilities, modified facilities, and/or newly installed facilities to allow the injection of the NCG stream into the top of the reservoir.
  • gas cap expands/grows in the reservoir
  • NCG and now vaporized solvent is expanded/pushed downwards in the reservoir chambers ( 610 ) as shown by the NCG/vaporized solvent gas cap expansion flow pattern ( 1025 ) as shown in FIG. 8 .
  • NCG/vaporized solvent production wells Liquid solvent, vaporized solvent, NCG and bitumen are recovered from the NCG/vaporized solvent production well(s) ( 605 ).
  • NCG/vaporized solvent production wells we will refer to the recovery or production wells in this gas cap expansion recovery embodiment by the term “NCG/vaporized solvent production wells” even though these wells, preferably existing production wells, will be used to recover liquid solvent, vaporized solvent, NCG and bitumen.
  • the “Gas Cap Expansion” case was run utilizing NCG as the gas cap injection gas.
  • the gas cap (either naturally occurring or established otherwise) was assumed to consist of C 1 hydrocarbon which may be considered to exemplify a typical gas cap in heavy oil reservoirs after the solvent-assisted gravity drainage process and beginning of the late life solvent recovery process.
  • the solvent used in the model was a mixture of essentially C 3 -C 9 hydrocarbons which exemplifies a typical solvent mixture utilized in a solvent-based heavy oil recovery process (such as VAPEX, or SA-SAGD process).
  • NCG utilized in the models was a 50%/50% by mole mixture of C 1 (methane) and CO 2 (carbon dioxide) which is exemplary of a production gas that may be used, readily obtainable, or easily obtainable, in reservoir heavy oil recovery processes.
  • C 1 methane
  • CO 2 carbon dioxide
  • FIG. 9 shows the solvent recovery rate (in liquid equivalents) of the solvent (in both liquid and gas components) for this gas cap expansion model.
  • FIG. 9 illustrates the total solvent recovery for this model as a function of time as compared to the case of the inter-well pair NCG flood.
  • the gas cap expansion embodiment of the present invention resulted in very high solvent recovery in a very short time.
  • the outcome of gas cap expansion scheme is very favorable, and is similar to the inter-well pair NCG flood case.
  • SAGD solvent recovery (which relies primarily on steam injection/gravity drainage) of the prior art does not promote solvent vaporization/expansion. While the steam injected in SAGD provides some heat to promote solvent vaporization, the condensation of steam with solvent on the edge of the chamber drives the solvent to a liquid phase draining to the production well which is a slower solvent recovery process as compared to the present gas cap expansion solvent recovery invention.
  • the solvent may be a single hydrocarbon compound or a mixture of hydrocarbon compounds having a number of carbon atoms in the range of C 1 to C 30 +.
  • the solvent may have at least one hydrocarbon in the range of C 3 to C 12 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.
  • the solvent may comprise at least at least 50 wt. % of one or more C 3 -C 12 hydrocarbons, at least 50 wt. % of one or more C 4 -C 10 hydrocarbons, at least 50 wt. % of one or more C 5 -C 9 hydrocarbons, or a natural gas condensate or a crude oil refinery naphtha.
  • the reservoir operating pressure may be 5-95% of a fracture pressure of the reservoir, or 0.2 to 5 MPa, or 1 to 2.5 MPa.
  • the reservoir pressure is measured at the injection well(s).
  • the injection temperature of the gas phase dilution agent may be from 10 to 250° C. or 50-150° C.
  • the temperature of the gas phase dilution agent is measured at the injection well.
  • the reservoir temperature may be from 50 to 250° C. or 75-150° C.
  • the reservoir temperature is measured at the injection well(s).
  • the solvent recovery process is performed on a reservoir that has been subjected to a solvent-assisted gravity drainage process, which comprises injecting steam and hydrocarbon solvent mixture into the reservoir.
  • a solvent-assisted gravity drainage process which comprises injecting steam and hydrocarbon solvent mixture into the reservoir.
  • the range of solvent concentration may be 5 to 40% cold liquid equivalent volume in SA-SAGD processes or it may be 80 to 100% by volume in H-VAPEX process.
  • a steam and hydrocarbon solvent mixture is injected into the subterranean reservoir in a vapor phase, wherein the hydrocarbon solvent volume fraction in the steam and hydrocarbon solvent mixture is 0.01-100% at injection conditions.
  • the steam and hydrocarbon solvent mixture is within 30%+/ ⁇ , 20%+/ ⁇ , or 10%+/ ⁇ of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent as measured at the reservoir operating pressure.
  • the hydrocarbon solvent molar fraction of the combined steam and solvent mixture is 70-110%, 70-100%, 80-100%, or 90 to 100% of the azeotropic solvent molar fraction of the steam and hydrocarbon solvent mixture as measured at the injection conditions.
  • the injection conditions should be the temperature and pressure of the subterranean reservoir at the injection well(s).
  • a process for the recovery of a solvent from a subterranean reservoir containing a solvent and a heavy oil comprising:
  • step e) includes extracting at least a portion of the liquid phase of the solvent from the subterranean reservoir.
  • gas phase dilution agent comprises a non-condensable gas which remains in vapor phase at pressure and temperature of the subterranean reservoir.
  • gas phase dilution agent comprises at least 50 wt % of the non-condensable gas at the operating pressure and temperature of the subterranean reservoir.
  • gas phase dilution agent comprises at least 75 wt % of the non-condensable gas at the pressure and temperature of the subterranean reservoir.
  • non-condensable gas comprises C 1 , C 2 , C 3 , N 2 , CO 2 , natural gas, produced gas, flue gas or any combination thereof.
  • gas phase dilution agent comprises a heating agent, wherein the heating agent is injected at a temperature greater than the operating temperature of the subterranean reservoir.
  • heating agent is comprised of the non-condensable gas, steam or a combination thereof.
  • heating agent is the non-condensable gas.
  • gas phase dilution agent utilizes existing heat in the reservoir to provide heat of vaporization to vaporize the liquid solvent.
  • the solvent-assisted gravity drainage process step comprises a well pair located in the subterranean reservoir, wherein the well pair is comprised of at least one injection well and at least one production well.
  • step b The process of any one of embodiments 14-15, wherein the at least one production well is converted to an NCG/vaporized solvent production well prior to, or in conjunction with, step b), and extracting at least a portion of the gas phase dilution agent and the vaporized solvent from the subterranean reservoir via the NCG/vaporized solvent production well.
  • the solvent-assisted gravity drainage process step comprises at least two well pairs located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), prior to, or in conjunction with, step b):
  • the solvent-assisted gravity drainage process step comprises at least three well pairs located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), prior to, or in conjunction with, step b):
  • the solvent-assisted gravity drainage process step comprises at least three well pairs located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), prior to, or in conjunction with, step b):
  • each of the wells run in a substantially horizontal direction within the subterranean reservoir, and the injection well and the production well of each of the well pairs are oriented substantially vertical with respect to one another, and wherein the three well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir.
  • each of the wells run in a substantially horizontal direction within the subterranean reservoir, and the injection well and the production well of each of the well pairs are oriented with a vertical offset and a horizontal offset with respect to one another, and wherein the three well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir.
  • the solvent-assisted gravity drainage process step comprises at least two well pairs located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), prior to, or in conjunction with, step b):
  • the solvent-assisted gravity drainage process step comprises at least two well pairs located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), prior to, or in conjunction with, step b):
  • each of the wells run in a substantially horizontal direction within the subterranean reservoir, and the injection well and the production well of each of the well pairs are oriented with a vertical offset and a horizontal offset with respect to one another, and wherein the two well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir.
  • the solvent-assisted gravity drainage process step comprises at least one well pair located in the subterranean reservoir, wherein each well pair is comprised of an injection well and a production well in step a), and prior to, or in conjunction with, step b):
  • step e) wherein in step e), the at least a portion of the gas phase dilution agent and the vaporized solvent is extracted from the subterranean reservoir via the NCG/vaporized solvent production well.
  • each of the wells run in a substantially horizontal direction within the subterranean reservoir, and the injection well and the production well of each of the well pairs are oriented substantially vertical with respect to one another, and wherein the well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir.
  • each of the wells run in a substantially horizontal direction within the subterranean reservoir, and the injection well and the production well of each of the well pairs are oriented with a vertical offset and a horizontal offset with respect to one another, and wherein the well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir.
  • step b installing gas cap facilities for use to inject the gas phase dilution agent into the top of the subterranean reservoir.
  • gas phase dilution agent comprises an amount of non-condensable gas sufficient to decrease the partial pressure of at least some of the components of the solvent in the gas phase by at least 10%.
  • gas phase dilution agent comprises an amount of non-condensable gas sufficient to convert at least 25 wt % of the liquid solvent to a vapor phase.
  • the solvent comprises an aliphatic fraction, a naphthenic fraction, an aromatic fraction, an olefinic fraction, or a combination thereof.
  • a system for the recovery of a solvent from a subterranean reservoir containing a solvent and a heavy oil comprising:
  • the first NCG/vaporized solvent production well is configured to recover a portion of the gas phase dilution agent and a portion of the vaporized solvent.
  • each of the wells run in a substantially horizontal direction within the subterranean reservoir, and the three well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir and the third well pair is between the first well pair and the second well pair in the substantially horizontal direction.
  • each of the wells run in a substantially horizontal direction within the subterranean reservoir, and the three well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir and the first well pair is between the second well pair and the third well pair in the substantially horizontal direction.
  • each of the wells run in a substantially horizontal direction within the subterranean reservoir, and the two well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir and the first NCG/vaporized solvent production well is located between the first well pair and the second well pair in the substantially horizontal direction and is in fluid connection with both the first injector and the second injector.
  • first injector is an infill well which is utilized as a first NCG injection well
  • each of the wells run in a substantially horizontal direction within the subterranean reservoir, and the two well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir and the first NCG injection well is located between the first well pair and the second well pair in the substantially horizontal direction and is in fluid connection with both the first NCG/vaporized solvent production well and the second NCG/vaporized solvent production well.
  • first existing injection well or the first existing production well is converted to the first NCG/vaporized solvent production well which was previously configured as an existing injection well to inject the existing solvent into the subterranean reservoir or which was previously configured as an existing production well to inject the existing solvent into the subterranean reservoir.
  • the subterranean reservoir comprises more than one injector fluidly connected to the top of the reservoir to provide the gas cap; wherein each injector is located to inject a gas phase dilution agent into the subterranean reservoir, so as to contact at least a portion of the gas phase dilution agent with the existing solvent and vaporize at least a portion of the existing solvent to produce a vaporized solvent.
  • the reservoir contains at least two well pairs each comprising an existing injection well and an existing production well; wherein each of the existing injection wells or each of the existing production wells are converted to the first NCG/vaporized solvent production wells.
  • the reservoir contains at least two well pairs each comprising an existing injection well and an existing production well; wherein each of the existing injection wells are converted to the first NCG/vaporized solvent production wells.
  • the reservoir contains at least three well pairs each comprising an existing injection well and an existing production well; wherein each of the existing injection wells or each of the existing production wells are converted to the first NCG/vaporized solvent production wells.
  • the reservoir contains at least two well pairs each comprising an existing injection well and an existing production well; wherein each of the existing injection wells and each of the existing production wells has been converted to the first NCG/vaporized solvent production wells.
  • heating facility is fluidly connected to the first fluid injector, wherein at least a portion of the heated gas phase dilution agent is injected into the subterranean reservoir.

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US11002123B2 (en) 2017-08-31 2021-05-11 Exxonmobil Upstream Research Company Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation
US11142681B2 (en) 2017-06-29 2021-10-12 Exxonmobil Upstream Research Company Chasing solvent for enhanced recovery processes
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US11261725B2 (en) 2017-10-24 2022-03-01 Exxonmobil Upstream Research Company Systems and methods for estimating and controlling liquid level using periodic shut-ins

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US11142681B2 (en) 2017-06-29 2021-10-12 Exxonmobil Upstream Research Company Chasing solvent for enhanced recovery processes
US10487636B2 (en) 2017-07-27 2019-11-26 Exxonmobil Upstream Research Company Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes
US11002123B2 (en) 2017-08-31 2021-05-11 Exxonmobil Upstream Research Company Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation
US11261725B2 (en) 2017-10-24 2022-03-01 Exxonmobil Upstream Research Company Systems and methods for estimating and controlling liquid level using periodic shut-ins
US20210396111A1 (en) * 2020-06-18 2021-12-23 Cenovus Energy Inc. Methods for recovering solvent and producing hydrocarbons from subteranean reservoirs
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