US20190032460A1

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

Info

Publication number: US20190032460A1
Application number: US16/036,392
Authority: US
Inventors: Rahman Khaledi; Forough Farshidi; Hamed R. Motahhari; Nima Saber; B. Karl Pustank; Ernesto C. Dela Rosa; Wenqiang Han
Original assignee: Individual
Current assignee: Individual
Priority date: 2017-07-27
Filing date: 2018-07-16
Publication date: 2019-01-31
Also published as: CA2974711C; CA2974711A1

Abstract

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 (i.e., “late life”) of heavy oil from a solvent-based heavy oil extraction process. The process include converting at least some of the wells in the subterranean reservoir, and injecting gas phase dilution agent into the reservoir, converting at least a portion of the liquid solvent to a gas phase, and recovering, in the vapor phase, at least a portion of the solvent remaining in the reservoir.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority from Canadian patent application 2,974,711 filed 27 Jul. 2017 entitled METHOD OF SOLVENT RECOVERY FROM A SOLVENT BASED HEAVY OIL EXTRACTION PROCESS, the entirety of which is incorporated by reference herein.

BACKGROUND

Field of Disclosure

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.

Description of Related Art

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 techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
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. 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.
Easily produced sources of hydrocarbons are dwindling, leaving less conventional sources to satisfy future 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 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. However, the hydrocarbons produced from the less conventional sources may be difficult to recover using conventional techniques. For example, 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.
Several conventional processes for the extraction of heavy oils, such as but not limited to thermal extraction processes, have been utilized to decrease the viscosity of the heavy oil. Decreasing the viscosity of the heavy oil may decrease a resistance of the heavy oil to flow and/or permit production of the heavy oil from the subterranean reservoir by piping, flowing, and/or pumping the heavy oil from the subterranean reservoir. While each of these extraction processes may be effective under certain conditions, each possess inherent limitations.
One of the conventional extraction processes utilizes steam injection. 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. However, 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. At the end (or near the end) of the reservoir's production, typically 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. Additionally, 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. As such, 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.

SUMMARY

It is an object of the present disclosure to provide systems and methods for improving the recovery of solvents from a subterranean reservoir remaining in the reservoir at the end (or near the end, i.e. “late life”) of the production stage of a reservoir that has been subjected to a solvent based heavy oil extraction process.
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:
a) recovering a heavy oil from a subterranean reservoir utilizing a solvent-assisted gravity drainage process wherein a portion of a solvent from the solvent-assisted gravity drainage process remains located in the subterranean reservoir;
b) injecting a gas phase dilution agent into the subterranean reservoir;
c) contacting at least a portion of the gas phase dilution agent with the solvent;
d) vaporizing at least a portion of the solvent that is in the liquid phase to produce a vaporized solvent; and
e) extracting at least a portion of the gas phase dilution agent and the vaporized solvent from the subterranean reservoir.
In a preferred embodiment, the gas phase dilution agent comprises a non-condensable gas which remains in vapor phase at pressure and temperature of the subterranean reservoir.
Another embodiment disclosed herein includes the process wherein 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.
Another embodiment disclosed herein includes the process wherein 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):

- converting at least one of the injection wells or production wells to an NCG injection well; and
- converting at least one of the injection wells or production wells to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injected into the subterranean reservoir via the NCG injection well; and 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 the process wherein 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):

- converting at least two of the injection wells to NCG injection wells; and
- converting at least one of the injection wells or production wells to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injected into the subterranean reservoir via the NCG injection wells; and 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 the process wherein 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):

- converting at least one of the injection wells to NCG injection wells; and
- converting at least two of the injection wells or production wells to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injected into the subterranean reservoir via the NCG injection well; and 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 wells.
Another embodiment disclosed herein includes the process wherein 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):

- converting an existing infill well or installing a new infill well in the subterranean reservoir located in a horizontal direction between the two well pairs for use as an NCG/vaporized solvent production well; and
- converting the two injection wells or the two production wells to NCG injection wells;

wherein at least a portion of the gas phase dilution agent is injected into the subterranean reservoir via the NCG injection well; and 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 the process wherein 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):

- converting an existing infill well or installing a new infill well in the subterranean reservoir located in a horizontal direction between the two well pairs for use as an NCG injection well; and
- converting the two injection wells or the two production wells to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injected into the subterranean reservoir via the NCG injection well; and 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 wells.
Another embodiment disclosed herein includes the process wherein 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):

- converting at least one of the injection well or the production well in each well pair to a NCG/vaporized solvent production well;
- injecting the gas phase dilution agent into the top of the subterranean reservoir or into an existing top zone of the subterranean reservoir;
- creating a gas cap in the subterranean reservoir comprising the gas phase dilution agent; and
- expanding the gas cap downward into the subterranean reservoir to at least a point wherein gas cap is in contact with the NCG/vaporized solvent production wells;

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:

- a subterranean reservoir containing an existing solvent comprising a liquid phase and a heavy oil;
- a first injector fluidly connected to the subterranean reservoir, wherein the 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; and
- a first NCG/vaporized solvent production well located within the subterranean reservoir and fluidly connected to the first injector;

wherein 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.
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.

DESCRIPTION OF THE DRAWINGS

These and other features, aspects and advantages of the present disclosure will become apparent from the following description and the accompanying drawings, which are briefly discussed below.

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.

DETAILED DESCRIPTION

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.
At the outset, for ease of reference, certain terms used in this application 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 of 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 processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.
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 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:
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. %).
The percentage of the hydrocarbon types found in bitumen can vary. 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, 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.
The term “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. In general, a heavy oil has an API gravity between 22.3° API (density of 920 kilograms per meter cubed (kg/m³) or 0.920 grams per centimeter cubed (g/cm³)) and 10.0° API (density of 1,000 kg/m³or 1 g/cm³). An extra heavy oil, in general, has an API gravity of less than 10.0° API (density greater than 1,000 kg/m³or greater than 1 g/cm³). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water, and bitumen. 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.
The term “asphaltenes” or “asphaltene content” refers to pentane insolubles (or the amount of pentane insoluble in a sample) according to 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. Examples of heavy hydrocarbon molecules include, but are not limited to, molecules having greater than or equal to 30 carbon atoms (C₃₀+). 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 C₃₀+ 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. In its broadest sense, 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. In some instances, 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” (or “subterranean formation”) 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.
A “thermal extraction process” (or “thermal recovery 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. For example, 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” (or “solvent-based recovery 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. In 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), 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.
Steam to Oil Ratio (“SOR”) is the ratio of a volume of steam (in cold water equivalents) required to produce a volume of oil. Cumulative SOR (“CSOR”) is the average volume of steam (in cold water equivalents) over the life of the operation required to produce a volume of oil. Instantaneous (“ISOR”) is the instantaneous rate of steam (in cold water equivalents) required to produce a volume of oil. SOR, CSOR, and ISOR are calculated at standard temperature and pressure (“STP”, 15° C. and 100 kPa or 60° F. and 14.696 psi).
Likewise, Solvent to Oil Ratio (“S_olOR”) is the ratio of a volume of solvent (in cold liquid equivalents) required to produce a volume of oil. Cumulative S_olOR (“CS_olOR”) is the average volume of solvent (in cold liquid equivalents) over the life of the operation required to produce a volume of oil. Instantaneous (“IS_olOR”) is the instantaneous rate of solvent required to produce a volume of oil. S_olOR, CS_olOR, and IS_olOR are calculated at STP.
“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.” 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.
“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. In practice, 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.
A “non-condensable gas” or “NCG” is a compound that is in a vapor phase at reservoir pressure and temperature conditions. The term NCG may be used in this disclosure for the purposes as a shorthand reference to the term “gas phase dilution agent”.
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”.
“Produced Bitumen to Retained Solvent ratio” or “PBRS” is the amount of bitumen (by standard condition liquid volume equivalent) extracted from the well or reservoir divided by the amount of unrecovered solvent (by standard condition liquid volume equivalent) injected into the well or reservoir. It is used to measure the solvent recovery efficiency of a solvent assisted production process or solvent recovery process.
“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.
A “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 C₁to C₃₀+. A hydrocarbon mixture is often at least hydrocarbons in the range of C₃to C₁₂or higher. For industrial applications, 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 terms “approximately,” “about,” “substantially,” and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure. These terms when used in reference to a quantity or amount of a material, or a specific characteristic of the material, refer 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.
The articles “the”, “a” and “an” are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.
As used herein, 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. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.
As used herein, 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. Thus, as a non-limiting example, 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.
As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, 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. It is also within the scope of the present disclosure that 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.
As used herein, the phrase, “for example,” the phrase, “as an example,” and/or simply the term “example,” when used with reference to one or more components, features, details, structures, 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. Thus, the described component, feature, detail, structure, embodiment, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, embodiments, and/or methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, embodiments, and/or methods, are also within the scope of the present disclosure.
Any of the ranges disclosed may include any number within and/or bounded by the range given.
In the illustrative figures herein, in general, elements that are likely to be included are illustrated in solid lines, while elements that are optional are illustrated in dashed lines. However, elements that are shown in solid lines may not be essential. Thus, an element shown in solid lines may be omitted without departing from the scope of the present disclosure.
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. Similarly, 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. In 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
In these solvent based recovery processes, a large quantity of solvent is retained in the reservoir that is trapped under thermodynamic equilibrium and fluid flow behaviors in the depleted zone under the reservoir conditions. This trapped solvent, at the end of bitumen recovery, can be a considerable portion of the process cost, often amounting to over millions of dollars of trapped/unrecovered solvent. Economical or operational conditions may require the recovery of this solvent during or at the end of the bitumen recovery. The recovery of trapped solvent in late life of a reservoir operation, or progressively as ultimate recoverable bitumen is approaching in the life of a reservoir operation, or when otherwise economically or operationally necessary, can significantly reduce the process cost and improve the economics of solvent based recovery processes. Additional environmental benefits may be achieved by reducing the amount of solvent in a reservoir after end of life (i.e., shut in).
When considering the general economic values of unrecovered solvents in a typical heavy oil reservoir at near the end of the production phase (i.e., late life) of a solvent based heavy oil recovery process, the value of the remaining solvent can amount to millions of dollars of stranded solvent in the reservoir and can be one of the largest overall costs in a solvent based heavy oil process. High solvent usage processes (such as VAPEX) may have significantly higher quantities of unrecovered or unrecoverable solvents during the process and thus at late life. “PBRS”, a measure of economic viability, 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. 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.
In the methods discovered and herein disclosed, recovery of the trapped solvent can be achieved by changing the phase behavior conditions in the reservoir by introducing a gas phase dilution agent. Preferably, 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. Alternatively, 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. In preferred embodiments, the gas phase dilution agent contains or is substantially comprised of a non-condensable gas under reservoir pressure and temperature conditions. For simplicity purposes herein, 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.
In the present disclosure, a gas phase dilution agent, preferably a non-condensable gas, and associated processes, methods, and configurations are utilized to improve solvent recovery from subterranean reservoirs at late life of solvent based heavy oil recovery processes. In the majority of the embodiments herein, 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. In conventional solvent recovery systems, 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. As an example, a solvent based thermal gravity drainage-based heavy oil recovery process, for example 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). In this setup, steam evaporates the liquid phase solvent, which then condenses at the edge of the chamber and is produced mainly as a liquid phase. In contrast, 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. For simplicity herein, the term “solvent” as used 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.
To simplify the discussions in this disclosure, 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. As will be obvious to one of skill in the art in light of this disclosure, 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 production cycle of a heavy oil reservoir, or otherwise due to other factors such as operational or economic considerations.
To help illustrate the present concepts, 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.
This concept is further illustrated in FIG. 2 which depicts the injected solvent content of a reservoir as an example. Here, on the left hand side, illustrates the amount of solvent in the reservoir in both the liquid phase (x_i: the molar fraction of solvent in the liquid phase) and the vapor phase (y_i: the molar fraction of solvent in the vapor phase), as well as the bitumen in the liquid phase. By adding the non-condensable gas (NCG) to the reservoir, a greater portion of the liquid solvent vaporizes and increases the solvent concentration in the vapor phase of the reservoir. This vaporized fraction of the solvent can then be extracted from the reservoir by the various methods described herein. These methods, as will be shown, result in significantly increased amounts of overall solvent recovery, as well as significantly increased rates in overall solvent recovery, and are particularly beneficial for application in late life solvent recovery applications.
Following are specific methods for employing the concept of this invention. Most of these methods have been modeled using state-of-the-art techniques and shown to produce significant improvement in solvent recovery, both in reduction of time of recovery as well as the total amount of solvent recovered. While not explicitly illustrated or quantified herein, these methods additionally have the benefit of significantly reducing the overall cost of solvent recovery, as these methods require significantly less time for recovery of the solvent (therefore reducing manhours, capital employed, maintenance, etc.), as well as not requiring the installation or operation of large steam generation systems. These methods as described herein, particularly where the solvent is substantially recovered in the vapor phase, 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 does not mean that 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. Here, the well pair consists of an injection well (401) and a production well (405).
Generally in a solvent assisted gravity-based drainage process the injection well will be located at a location above the production well as shown. It should also be mentioned that the methods herein are not limited to well pairs that only have a vertical offset component. In embodiments, 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.
In FIG. 3, 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. In other embodiments, 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. In the first case, the NCG, as well as the retained solvent, take advantage of the residual heat stored in the reservoir to improve solvent recovery. In this single well configuration, 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).
State-of-the-art reservoir production modeling was performed to show the improved solvent recovery rates in conjunction with an embodiment of the present invention, as well compare the solvent recovery rates and efficiencies to conventional techniques for solvent recovery utilizing steam, such as switching to Steam-Assisted Gravity Drainage (SAGD) process near the end of the production life (i.e., late life) of the reservoir. In this modeled comparison, the NCG injection process was utilized in conjunction with a thermal solvent vapor extraction (VAPEX) process, at “late-life” reservoir conditions. For the comparison models, the reservoir temperature, reservoir pressure and well spacing all were modeled at the same value. The case shown in FIG. 6A operated a thermal VAPEX process for the heavy oil production period, followed by injecting only steam for solvent recovery according to the prior art. The case shown in FIG. 6B operated the same thermal VAPEX process for the heavy oil production period, however, followed by injecting a NCG gas according to an embodiment herein. The solvent used in all of the models herein was a mixture of essentially C₃-C₉hydrocarbons which exemplifies a typical diluent solvent mixture utilized in a solvent-based heavy oil recovery process (such as thermal VAPEX, or SA-SAGD process). The NCG utilized in all of the models herein was a 50%/50% by mole mixture of C₁(methane) and CO₂(carbon dioxide) which is exemplary of a production gas that may be used, readily obtainable, or easily obtainable, in reservoir heavy oil recovery processes. 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).
The results for the single well pair embodiment are shown in FIGS. 6A and 6B. 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. On the other hand, 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. As a result, there is a significant increase in the overall solvent recovery rate (i.e., the sum of the “liquid” and “gas” production lines), especially on the front-end of the timeline. This results in not only additional solvent recovered, but more solvent recovered in a significantly shorter amount of time when utilizing the methods herein.
Even though 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. However, 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. In addition to enhancing solvent recovery at the end of life of a VAPEX process, it will be shown herein that 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. In fact, 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.
We start here with a discussion on a few different configuration embodiments of implementations of the present invention to multiple well pair configurations. It has been discovered that embodiments of the present invention can be very effectively used in reservoirs with multiple wells or multiple well pairs, especially in certain, distinct flow patterns or “modes”. FIGS. 4A, 4B & 4C will be utilized to illustrate these preferred modes using a typical, but non-limiting, example well configurations. In these figures, the subterranean reservoir or “reservoir” (600) contains a five well pair configuration is shown 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), wherein each well in the well pair run in a substantially horizontal direction within the subterranean reservoir, and wherein the injection well and the production well of each of the well pairs are oriented in a substantially vertical direction with respect to one another, and further wherein the top well is 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) 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).
Starting with the reservoir and well configuration description as illustrated in FIG. 4A, each of the five horizontal well pairs comprises an injection well (601) and a production well (605). During normal operation of a solvent-based gravity drainage process, 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). Here the injected vapor pushes out from the injection well (601) and forms the reservoir chamber (610) wherein the flow is generally outward from injection well (601), wherein the reservoir chamber flow boundaries (615) are illustrated in 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). 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.
In FIGS. 4A, 4B, and 4C, will illustrate different NCG “sweep” configurations of the present invention in late life production/solvent recovery. Starting with FIG. 4A, alternative existing injection wells (the first, third and fifth elements 601 starting from the left in FIG. 4A) are converted to, and utilized as “NCG injection wells”, while the intermediate existing injection wells (the second and fourth elements 601 starting from the left in FIG. 4A) and all production wells (the elements 605 in FIG. 4A) are converted to, and utilized as “NCG/vaporized solvent and liquid production wells”. In this embodiment, the NCG is injected via the NCG injection wells. As noted prior, 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. In such embodiment, 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. For simplicity purposes in the figures and description herein, the diluting/heating agent (or “D/HA”) containing a non-condensable gas may be referred to interchangeably as “NCG”.
Returning to FIG. 4A, in this embodiment, a substantial amount of NCG is injected into the now converted NCG injection wells. By the term “substantial amount of NCG injected” (or similar) 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%. In preferred embodiments, 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. After injecting the NCG, 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). Instead of condensing and moving down the reservoir chambers as discussed and operated in the production cycle (to be recovered by the lower located production wells), here, a significant portion of the solvent vaporizes and moves upward through the alternate reservoir chambers (i.e., the chambers now containing the NCG injection wells). The pressure gradient in the reservoir is maintained such that the pressure near the NCG/vaporized solvent production wells is lower than the pressure of at least one, and preferably all, of the NCG injection well(s). 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. It is noted that 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. In FIG. 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 (wherein 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). 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.
In FIG. 4B, an embodiment of the late life production/solvent recovery NCG sweep configuration is illustrated as follows. In this embodiment, 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). Also, all of the production wells are converted to liquid production wells (shown in FIG. 4B as 605). In this embodiment, the NCG is injected via the four NCG injection wells. As noted prior, 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 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.
Returning to FIG. 4B, 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 gas phase (as used here to also include the solvent components, especially the lower boiling point solvent components). Instead of condensing and moving down the reservoir chambers as discussed in the production cycle (to be recovered by the lower located production wells), 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. In FIG. 4C, 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.
In FIG. 4C, an embodiment of a late life production/solvent recovery NCG sweep configuration is illustrated as follows. In this embodiment, 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). Also all of the production wells are converted to liquid production wells. In this embodiment, the NCG is injected via the four NCG injection wells. As noted prior, 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.
Returning to FIG. 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 to also include the solvent components, especially the lower boiling point solvent components). Instead of condensing and moving down the reservoir chambers as discussed in the production cycle (to be recovered by the lower located production wells), 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.
It is noted herein that while these embodiments as illustrated in 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.
The results for the inter-well pair NCG flood case of the present invention, as shown in FIG. 6C, the dilution and stripping once again take place, but now the gas phase sweeps the reservoir area between two chambers and allows for more effective stripping of the solvent into the gas and more effective and faster sweeping of solvent in gas and liquid phases to the production wells. As can be seen comparing the results from FIGS. 6A, 6B and 6C, there is a significant increase in the overall solvent recovery rate (i.e., the sum of the “liquid” and “gas” production lines) over the base case steam injection recovery (shown in FIG. 6A), especially on the front-end of the timeline for the embodiments of both the single well pair NCG injection process (results shown in FIG. 6B), as well as the inter-well pair NCG flood process (results shown in FIG. 6C) of the present invention. This results in not only additional solvent recovered, but more solvent recovered in a significantly shorter amount of time when utilizing the methods herein. It can also be seen that the Solvent Production Rate of the inter-well pair NCG flood process (FIG. 6C) of the present invention shows significant recovery results over the single well NCG injection embodiment (FIG. 6B).
FIG. 7 shown the total Solvent Recovery, for all three (3) cases described in FIGS. 6A-6C. As can be seen from FIG. 7, 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. However, what is taken away here is that the process according to the present invention, the NCG injection was able to ultimately recover nearly as much (or more) solvent from the reservoir as the conventional steam injection case (SAGD) Considering the high cost associated with steam generation, water treatment, and other limitations of the steam only case as discussed before, this comparable final solvent recovery easily economically justifies the additional NCG production and injection costs for implementing the methods of the present invention over the steam only late life process (SAGD). The SAGD process, as discussed prior, requires significantly additional capital equipment and energy costs, mainly due to the SAGD's process requirement to install and operate substantial onsite steam generation facilities, which are not already existing in solvent assisted heavy oil recovery operations. This makes the present invention significantly more desirable than conventional SAGD processes when all of the costs in implementing the processes are factored in.
In the 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. 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 CO₂, in a sequestration mode. The NCG may be comprised of C₁, C₂, C₃, N₂, CO₂, natural gas, produced gas, flue gas or any combination thereof. In contrast, in a solvent-based extraction process, 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). In order to perform the SAGD 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). When these additional costs are factored in between the NCG injection case of the present invention and the steam injection (SAGD mode) solvent recovery of the prior art, the NCG injection recovery process of the present invention possess significantly improved economics.
This basic embodiment and associated methods can be expanded by using infill wells. 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. However, in this embodiment, the use of an infill well (630), or multiple infill wells (not shown) may be used in the solvent recovery process. Here, 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. Although 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. 4D, the existing or installed infill well is utilized as an NCG/vaporized solvent production well for the late life solvent recovery processes herein. Here, 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). Instead of condensing and moving down the reservoir chambers as discussed in the production cycle (to be recovered by the lower located production wells), 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 infill well (630) which has been installed as, or has been converted to a NCG/vaporized solvent production well. The majority of the NCG and recovered vaporized solvent are recovered through the now NCG/vaporized solvent production well (prior infill well) and the existing production wells (605) continue to produce mainly liquid solvent recovery as well as additional heavy oil (bitumen). 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). However, alternatively (not shown), 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.
State-of-the-art reservoir production modeling was performed to show the improved solvent recovery rates in conjunction with the flood embodiment of the present invention, as well compare the solvent recovery rates and efficiencies to conventional techniques for solvent recovery utilizing steam, such as in a Steam-Assisted Gravity Drainage (SAGD) process. In this modeled comparison, the NCG injection process was utilized in conjunction with a solvent vapor extraction (VAPEX) process, at near end-of-life (i.e., “late life”) reservoir conditions. For the comparison models, the reservoir temperature, reservoir pressure and well spacing all were modeled at the same value. In this example, the model utilized a two well pair configuration which basis for the model is simply illustrated in FIG. 5. Here, an existing injection well (shown as 601 on the right hand side of FIG. 5) is converted to an NCG injection well, and an existing injection well (shown as 601 on the left hand side of FIG. 5) is converted to an NCG/vaporized solvent production well. Illustrated here, the existing production wells (shown as 605 on the bottom of FIG. 5) 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 (P₂) at the NCG injection well as shown in FIG. 5 is greater than the pressure (P₁) 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 C₃-C₉hydrocarbons 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 C₁(methane) and CO₂(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).
As can be seen by comparing FIGS. 6A, 6B and 6C, 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). Additionally, it can be seen that in this multiple well pair embodiment of the present invention that there is a significant increase in the overall solvent recovery rate (i.e., the sum of the “liquid” and “gas” production lines), especially on the front-end of the timeline resulting in a very short timeframe required for near full recoverable solvent production.
This results in not only additional solvent recovered, but more solvent recovered in a significantly shorter amount of time when utilizing the methods herein. FIG. 7 further illustrates the significant impact of using this embodiment of solvent recovery in a VAPEX process for late life solvent recovery. In 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.
While not wishing to be held to any particular theory, as discussed prior, it is believed that significantly more solvent can be achieved by converting the solvent into a vapor phase and recovering the solvent as a vapor. It is further believed that while steam injection provides heat and vaporize the liquid solvent from depleted chamber, the condensation of the steam and solvent at the edge of the chambers results in solvent to be recovered as a draining liquid through only the bottom production wells which is a slower process. In the present invention both converted injection wells, as well as existing production wells can be utilized for production, wherein a substantial amount of the existing liquid solvent that remained in the reservoir is now produced and recovered in a vapor phase. Also, it is believed that in the present invention, a significant amount of solvent in the reservoir is converted to vapor, leaving a smaller volume of the liquid solvent in the well, which is much more difficult to displace and achieve high solvent recovery in the liquid phase. As such, the present invention offers significant improvements in solvent recovery over the conventional methods in the art.
In another embodiment of the present invention, 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. In this embodiment, 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. In the cases where the facilities for a gas cap may already be established in the reservoir, facilities for injecting and maintaining the gas cap may be utilized or modified for the present NCG gas cap expansion description.
In 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. In this embodiment, during late life production, 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. As illustrated in FIG. 8, 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). As per prior embodiments, 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.
Returning to FIG. 8, in this embodiment, 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). Instead of condensing and moving down the reservoir chambers as discussed in the production cycle (to be recovered by the lower located production wells), some of the solvent begins vaporizing and is expanded/pushed downward towards the production wells which are now utilized as the NCG/vaporized solvent production well(s) (605). This floods additional liquid solvent and bitumen to NCG/vaporized solvent production well(s) as well as vaporized solvent and NCG which are also recovered from the NCG/vaporized solvent production well(s). Alternatively, or in conjunction with the converted existing production well(s) (605), at least one, or all of the existing injection wells (601) may be converted to NCG/vaporized solvent production well(s). 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.
State-of-the-art reservoir production modeling was performed to show the improved solvent recovery rates in conjunction with the gas cap expansion embodiment of the present invention, as well as to compare the solvent recovery rates and efficiencies to conventional techniques for solvent recovery utilizing steam injection, such as in a Steam-Assisted Gravity Drainage (SAGD) process. In this modeled comparison, the NCG injection process was utilized in conjunction with a solvent vapor extraction (VAPEX) process, at late life (i.e., near end-of-life) reservoir conditions. For the comparison models, the reservoir temperature, reservoir pressure and well spacing all were modeled at the same value. In this example, the model utilized a two well pair configuration which basis for the model is simply illustrated by using only two of the well pairs shown in FIG. 8. Here, the existing injection wells (shown as 601 in FIG. 8) are shut in, and existing production wells (shown as 605 in FIG. 8) are converted to an NCG/vaporized solvent production well. 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. As the 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. Liquid solvent, vaporized solvent, NCG and bitumen are recovered from the NCG/vaporized solvent production well(s) (605). For simplicity and consistency, 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.
As noted, the model was run with a two well pair model and the results are shown in FIG. 9. 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 C₁hydrocarbon 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 C₃-C₉hydrocarbons 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 C₁(methane) and CO₂(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 existing injection wells were modeled as shut in. All products measured from the model were recovered from the two converted NCG/vaporized solvent production wells.
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. As can be seen from the model results shown in FIG. 9, the gas cap expansion embodiment of the present invention resulted in very high solvent recovery in a very short time. As seen in FIG. 9, the outcome of gas cap expansion scheme is very favorable, and is similar to the inter-well pair NCG flood case.
While not wishing to be held to any particular theory, as discussed prior, it is believed that even though the majority of the solvent is recovered in the liquid phase, that significantly more solvent can be recovered, as compared to conventional methods (such as steam injection/SAGD) due to the vaporization of the solvent, and thereby creating a vapor expansion in the reservoir chambers promoting recovery of the liquid phase solvent in the NCG/vaporized solvent production wells. The NCG not only provides a driving expansion/push, but also promotes additional expansion of gas in the reservoir chambers by reducing the partial pressure of the solvent in the reservoir chambers, thereby vaporizing a significant portion of the solvent into a gas phase. In contrast, it is believed that 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.
These state-of-the-art reservoir production models were also used to compare the use of the current methods and embodiments for solvent recovery vs. the conventional approach of switching to SAGD methods for solvent recovery in a late life solvent assisted gravity drainage operation (such as SA-SAGD or VAPEX processes). Here, similar well configurations as utilized in the examples for the sweep (or “flood”) and gas cap expansion embodiments herein which results are in shown in FIGS. 7 and 9, respectively were compared with taking the same reservoir configurations and applying SAGD for late life solvent recovery. The comparative results between these embodiments of the invention and the steam injection/SAGD solvent recovery methods are shown in FIG. 10. Here it can be seen that both the flood (sweep) configuration and the gas cap expansion configuration of the present invention resulted in very similar solvent recovery rate profiles. The same reservoir model, run under conventional late life steam injected gravity drainage (SAGD) process achieved far less total solvent recovery. Additionally, while the conventional SAGD method recovered slightly more total heavy oil (bitumen) from the reservoir, the Produced Bitumen to Retained Solvent ratio (PBRS) was still low due to the large amount of unrecovered solvent left in the reservoir as a result of this method. In significant contrast, the methods of the present invention were able to surprisingly achieve very high PBRS, which results in not only significant overall cost savings, but significantly more efficient use of solvents in the overall production & solvent recovery process of reservoir use and natural resources management.
In preferred embodiments herein, the solvent may be a single hydrocarbon compound or a mixture of hydrocarbon compounds having a number of carbon atoms in the range of C₁to C₃₀+. The solvent may have at least one hydrocarbon in the range of C₃to C₁₂and 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 C₃-C₁₂hydrocarbons, at least 50 wt. % of one or more C₄-C₁₀hydrocarbons, at least 50 wt. % of one or more C₅-C₉hydrocarbons, or a natural gas condensate or a crude oil refinery naphtha.
In preferred embodiments, 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. Preferably, the reservoir pressure is measured at the injection well(s).
In preferred embodiments, the injection temperature of the gas phase dilution agent may be from 10 to 250° C. or 50-150° C. Preferably, the temperature of the gas phase dilution agent is measured at the injection well. In other preferred embodiments, the reservoir temperature may be from 50 to 250° C. or 75-150° C. Preferably, the reservoir temperature is measured at the injection well(s).
In preferred embodiments, 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. In this embodiment, 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. In these processes, 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. In Azeo-VAPEX processes, 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. Alternatively, 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. Preferably, the injection conditions should be the temperature and pressure of the subterranean reservoir at the injection well(s).

EMBODIMENTS

Additional embodiments of the invention herein are as follows:

Embodiment 1

A process for the recovery of a solvent from a subterranean reservoir containing a solvent and a heavy oil, the process comprising:

- a) recovering a heavy oil from a subterranean reservoir utilizing a solvent-assisted gravity drainage process wherein a portion of a solvent from the solvent-assisted gravity drainage process remains located in the subterranean reservoir;
- b) injecting a gas phase dilution agent into the subterranean reservoir;
- c) contacting at least a portion of the gas phase dilution agent with the solvent;
- d) vaporizing at least a portion of the solvent that is in the liquid phase to produce a vaporized solvent; and
- e) extracting at least a portion of the gas phase dilution agent and the vaporized solvent from the subterranean reservoir.

Embodiment 2

The process of embodiment 1, wherein, prior to the injecting of the gas phase dilution agent, the solvent in the subterranean reservoir comprises both the liquid phase and a gas phase.

Embodiment 3

The process of embodiment 2, wherein step e) includes extracting at least a portion of the liquid phase of the solvent from the subterranean reservoir.

Embodiment 4

The process of any one of embodiments 1-3, wherein the gas phase dilution agent comprises a non-condensable gas which remains in vapor phase at pressure and temperature of the subterranean reservoir.

Embodiment 5

The process of embodiment 4, wherein the gas phase dilution agent comprises at least 50 wt % of the non-condensable gas at the operating pressure and temperature of the subterranean reservoir.

Embodiment 6

The process of any one of embodiments 4-5, wherein the gas phase dilution agent comprises at least 75 wt % of the non-condensable gas at the pressure and temperature of the subterranean reservoir.

Embodiment 7

The process of any one of embodiments 4-6, wherein the non-condensable gas comprises C₁, C₂, C₃, N₂, CO₂, natural gas, produced gas, flue gas or any combination thereof.

Embodiment 8

The process of embodiment 7, wherein the non-condensable gas comprises CO₂.

Embodiment 9

The process of any one of embodiments 1-8, wherein the 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.

Embodiment 10

The process of embodiment 9, wherein heating agent is comprised of the non-condensable gas, steam or a combination thereof.

Embodiment 11

The process of embodiment 10, wherein heating agent is the non-condensable gas.

Embodiment 12

The process of any one of embodiments 1-11, wherein gas phase dilution agent utilizes existing heat in the reservoir to provide heat of vaporization to vaporize the liquid solvent.

Embodiment 13

The process of embodiment 12, wherein the existing heat in the subterranean reservoir is residual heat from the solvent-assisted gravity drainage process.

Embodiment 14

The process of any one of embodiments 1-13, wherein 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.

Embodiment 15

The process of embodiment 14, 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.

Embodiment 16

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.

Embodiment 17

The process of embodiment 16, wherein at least a portion of the liquid phase of the solvent is extracted from the subterranean reservoir via the NCG/vaporized solvent production well.

Embodiment 18

The process of any one of embodiments 1-13, wherein 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):

wherein at least a portion of the gas phase dilution agent is injected into the subterranean reservoir via the NCG injection well; and 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.

Embodiment 19

The process of embodiment 18, comprising:

- converting at least one of the injection wells to an NCG injection well;
- converting at least one of the injection wells to an NCG/vaporized solvent production well.

Embodiment 20

The process of embodiment 19, wherein at least a portion of the solvent and the heavy oil are extracted in a liquid phase from the two production wells.

Embodiment 21

The process of any one of embodiments 1-13, wherein 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):

wherein at least a portion of the gas phase dilution agent is injected into the subterranean reservoir via the NCG injection wells; and 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.

Embodiment 22

The process of embodiment 21, comprising:

- converting at least one of the injection wells to an NCG/vaporized solvent production well.

Embodiment 23

wherein at least a portion of the gas phase dilution agent is injected into the subterranean reservoir via the NCG injection well; and 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 wells.

Embodiment 24

The process of embodiment 23, comprising:

- converting at least two of the injection wells to an NCG/vaporized solvent production well.

Embodiment 25

The process of embodiment 22 or 24, wherein at least a portion of the solvent and the heavy oil are extracted in a liquid phase from the three production wells.

Embodiment 26

The process of any one of embodiments 18-25, wherein 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.

Embodiment 27

The process of any one of embodiments 18-25, wherein 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.

Embodiment 28

Embodiment 29

The process of embodiment 28, comprising:

- converting at least the two injection wells to NCG injection wells.

Embodiment 30

Embodiment 31

The process of embodiment 30, comprising:

- converting the two injection wells to NCG/vaporized solvent production wells.

Embodiment 32

The process of embodiment 29 or 31, wherein at least a portion of the liquid phase of the solvent is extracted from the subterranean reservoir via the NCG/vaporized solvent production wells.

Embodiment 33

The process of embodiment 29 or 31, wherein at least a portion of the solvent and the heavy oil are extracted in a liquid phase from the two production wells.

Embodiment 34

The process of any one of embodiments 28-33, wherein 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 two well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir.

Embodiment 35

The process of any one of embodiments 28-33, wherein 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.

Embodiment 36

The process of any one of embodiments 1-13, wherein 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):

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.

Embodiment 37

The process of embodiment 36, comprising at least two well pairs.

Embodiment 38

The process of embodiment 36, comprising at least three well pairs.

Embodiment 39

The process of any one of embodiments 36-38, comprising:

- converting the production well in at least one of the well pairs to an NCG/vaporized solvent production well.

Embodiment 40

The process of embodiment 39, comprising:

- converting all of the production wells in the well pairs to NCG/vaporized solvent production wells.

Embodiment 41

The process of any one of embodiments 37-40 wherein at least a portion of the liquid phase of the solvent is extracted from the subterranean reservoir via the NCG/vaporized solvent production wells.

Embodiment 42

The process of embodiment 36, wherein the at least one injection well is converted to the NCG/vaporized solvent production well, and at least a portion of the solvent and the heavy oil are extracted in a liquid phase from the at least one production well.

Embodiment 43

The process of any one of embodiments 36-42, wherein 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.

Embodiment 44

The process of any one of embodiments 36-42, wherein 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.

Embodiment 45

The process of any one of embodiments 36-44, wherein the gas cap comprises C₁.

Embodiment 46

The process of any one of embodiments 36-45, wherein the gas phase dilution agent is introduced into the top of the subterranean reservoir utilizing existing gas cap facilities.

Embodiment 47

The process of any one of embodiments 36-45, further comprising prior to, or in conjunction with, step b), installing gas cap facilities for use to inject the gas phase dilution agent into the top of the subterranean reservoir.

Embodiment 48

The process of any one of embodiments 36-47, wherein the gas cap is expanded downward into the subterranean reservoir to at least a point below the NCG/vaporized solvent production wells.

Embodiment 49

The process of any one of embodiments 1-48, wherein the 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%.

Embodiment 50

The process of any one of embodiments 1-49, wherein the 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.

Embodiment 51

The process of any one of embodiments 1-50, wherein the solvent comprises at least 50 wt % of one or more of C₃-C₁₂hydrocarbons.

Embodiment 52

The process of any one of embodiments 1-51, wherein the solvent comprises an aliphatic fraction, a naphthenic fraction, an aromatic fraction, an olefinic fraction, or a combination thereof.

Embodiment 53

The process of any one of embodiments 1-52, wherein the solvent comprises natural gas condensate or a crude oil refinery naphtha.

Embodiment 54

The process of any one of embodiments 1-53, wherein pressure of the subterranean reservoir is 0.2 to 5 MPa.

Embodiment 55

The process of any one of embodiments 1-54, wherein the temperature of the subterranean reservoir is from 10 to 250° C.

Embodiment 56

The process of any one of embodiments 1-55, wherein the solvent-assisted gravity drainage process is a SA-SAGD, VAPEX, H-VAPEX, Azeo-VAPEX process.

Embodiment 57

The process of any one of embodiments 1-56, wherein during the solvent-assisted gravity drainage process, a steam and the solvent is injected as a mixture into the subterranean reservoir in a vapor phase, wherein the solvent volume fraction in the steam and solvent mixture is 0.01-100% at injection conditions.

Embodiment 58

The process of embodiment 57, wherein during the solvent-assisted gravity drainage process, the solvent molar fraction of the combined steam and solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and solvent mixture at injection conditions.

Embodiment 59

A system for the recovery of a solvent from a subterranean reservoir containing a solvent and a heavy oil, the system comprising:

wherein 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.

Embodiment 60

The system of embodiment 59, wherein

- the first injector is an NCG injection well which was previously configured as a first existing injection well to inject the existing solvent into the subterranean reservoir, and wherein the NCG injection well is configured to inject the gas phase dilution agent into the subterranean reservoir; and
- the first NCG/vaporized solvent production well which was previously configured as a first existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir is configured to additionally recover a portion of the existing solvent in the liquid phase and a portion of the heavy oil.

Embodiment 61

The system of embodiment 59, comprising at least two well pairs located in the subterranean reservoir, wherein

- a first well pair is comprised of the first injector which was previously configured as a first existing injection well to inject the existing solvent into the subterranean reservoir and a first existing production well; and
- a second well pair is comprised of the first NCG/vaporized solvent production well, wherein the first NCG/vaporized solvent production well was previously configured as a second existing injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a second existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir.

Embodiment 62

The system of embodiment 59, comprising at least three well pairs located in the subterranean reservoir, wherein

- a first well pair is comprised of the first injector which was previously configured as a first existing injection well to inject the existing solvent into the subterranean reservoir, and a first existing production well;
- a second well pair is comprised of a second injector which was previously configured as a second existing injection well to inject the existing solvent into the subterranean reservoir wherein the second injector is an NCG injection well, and wherein the NCG injection well has been configured to inject the gas phase dilution agent into the subterranean reservoir, and a second existing production well; and
- a third well pair is comprised of the first NCG/vaporized solvent production well which was previously configured as a third existing injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a third existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir;

wherein 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.

Embodiment 63

- a first well pair is comprised of the first injector which was previously configured as a first existing injection well to inject the existing solvent into the subterranean reservoir, and a first existing production well;
- a second well pair is comprised of the first NCG/vaporized solvent production well which was previously configured as a second existing injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a second existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir; and
- a third well pair is comprised of a second NCG/vaporized solvent production well which was previously configured as a third existing injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a third existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir;

wherein 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.

Embodiment 64

The system of any one of embodiments 61-63, wherein the existing injection well and the existing production well of each of the well pairs are oriented substantially vertical with respect to one another.

Embodiment 65

The system of any one of embodiments 61-63, wherein the existing injection well and the existing production well of each of the well pairs are oriented with a vertical offset and a horizontal offset with respect to one another.

Embodiment 66

The system of embodiment 59, comprising at least two well pairs and an infill well located in the subterranean reservoir, wherein

- a first well pair is comprised of the first injector which was previously configured as a first existing injection well to inject the existing solvent into the subterranean reservoir, and a first existing production well;
- a second well pair is comprised of a second injector which was previously configured as a second existing injection well to inject the existing solvent into the subterranean reservoir wherein the second injector is an NCG injection well, and wherein the NCG injection well is configured to inject the gas phase dilution agent into the subterranean reservoir, and a second existing production well; and
- an infill well is utilized as the first NCG/vaporized solvent production well

wherein 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.

Embodiment 67

- a first well pair is comprised of the first NCG/vaporized solvent production well which was previously configured as a first existing injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a first existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir; and
- a second well pair is comprised of a second NCG/vaporized solvent production well which was previously configured as a second original injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a second existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir, wherein the second NCG/vaporized solvent production well is configured to recover a portion of the gas phase dilution agent and a portion of the vaporized solvent;

wherein the first injector is an infill well which is utilized as a first NCG injection well; and
wherein 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.

Embodiment 68

The system of any one of embodiments 66-67, wherein the injection well and the production well of each of the well pairs are oriented substantially vertical with respect to one another.

Embodiment 69

The system of any one of embodiments 66-67, wherein 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.

Embodiment 70

The system of embodiments 59, wherein

- the first injector is fluidly connected to the top of the reservoir to provide a gas cap; and
- the reservoir contains at least one well pair comprising a first existing injection well and a first existing production well;

wherein the 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.

Embodiment 71

The system of embodiments 70, wherein 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.

Embodiment 72

The system of any one of embodiments 70-71, wherein 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.

Embodiment 73

The system of any one of embodiments 70-72, wherein 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.

Embodiment 74

The system of any one of embodiments 70-73, wherein 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.

Embodiment 75

The system of any one of embodiments 70-74, wherein 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.

Embodiment 76

The system of any one of embodiments 70-75, wherein each of the wells run in a substantially horizontal direction within the subterranean reservoir.

Embodiment 77

The system of any one of embodiments 70-76, wherein the existing injection well and the existing production well of each of the well pairs are oriented substantially vertical with respect to one another.

Embodiment 78

The system of any one of embodiments 70-76, wherein the existing injection well and the existing production well of each of the well pairs are oriented with a vertical offset and a horizontal offset with respect to one another.

Embodiment 79

The system of any one of embodiments 72-78, wherein the well pairs are oriented in a substantially horizontal direction with respect to each other in the subterranean reservoir.

Embodiment 80

The system of any one of embodiments 59-79, further comprising a surface facility, wherein the surface facility comprises:

- a separation facility, that is fluidly connected to at least the first NCG/vaporized solvent production well, wherein at least a portion of the recovered vaporized solvent is separated from the recovered gas phase dilution agent, forming a separated vaporized solvent and a separated gas phase dilution agent;
- a compression facility, that is fluidly connected to the separation facility, wherein at least a portion of the separated gas phase dilution agent is compressed to a higher pressure to form a compressed gas phase dilution agent; and
- a heating facility, that is fluidly connected to the separation facility, wherein at least a portion of the compressed gas phase dilution agent is heated to a higher temperature to form a heated gas phase dilution agent;

wherein the 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.

Embodiment 81

The system of embodiment 80, wherein the separation facility is further configured wherein a produced liquid is separated from the recovered vaporized solvent and the recovered gas phase dilution agent.

Embodiment 82

The system of embodiment 81, wherein:

- the produced liquid is comprised of a dissolved NCG, recovered liquid solvent, and heavy oil; and
- the separation facility is further configured to separate the dissolved NCG, the recovered liquid solvent, and the heavy oil to form a separated NCG, a separated recovered liquid solvent, and a separated heavy oil.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed in the present disclosure are applicable to the oil and gas industry.
It is believed that the following claims particularly point out certain combinations and subcombinations that are novel and non-obvious. Other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the present disclosure.

Claims

1. A process for the recovery of a solvent from a subterranean reservoir containing a solvent and a heavy oil, the process comprising:

a) recovering a heavy oil from a subterranean reservoir utilizing a solvent-assisted gravity drainage process wherein a portion of a solvent from the solvent-assisted gravity drainage process remains located in the subterranean reservoir;

b) injecting a gas phase dilution agent into the subterranean reservoir;

c) contacting at least a portion of the gas phase dilution agent with the solvent;

d) vaporizing at least a portion of the solvent that is in the liquid phase to produce a vaporized solvent; and

e) extracting at least a portion of the gas phase dilution agent and the vaporized solvent from the subterranean reservoir.

2. The process of claim 1, wherein, prior to the injecting of the gas phase dilution agent, the solvent in the subterranean reservoir comprises both the liquid phase and a gas phase.

3. The process of claim 2, wherein step e) includes extracting at least a portion of the liquid phase of the solvent from the subterranean reservoir.

4. The process of claim 1, wherein the gas phase dilution agent comprises a non-condensable gas which remains in vapor phase at pressure and temperature of the subterranean reservoir.

5. The process of claim 4, wherein the gas phase dilution agent comprises at least 50 wt % of the non-condensable gas at the operating pressure and temperature of the subterranean reservoir.

6. The process of claim 4, wherein the non-condensable gas comprises C₁, C₂, C₃, N₂, CO₂, natural gas, produced gas, flue gas or any combination thereof.

7. The process of claim 6, wherein the non-condensable gas comprises CO₂.

8. The process of claim 1, wherein the 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.

9. The process of claim 8, wherein heating agent is comprised of the non-condensable gas, steam or a combination thereof.

10. The process of claim 9, wherein heating agent is the non-condensable gas.

11. A system for the recovery of a solvent from a subterranean reservoir containing a solvent and a heavy oil, the system comprising:

a subterranean reservoir containing an existing solvent comprising a liquid phase and a heavy oil;

a first injector fluidly connected to the subterranean reservoir, wherein the 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; and

a first NCG/vaporized solvent production well located within the subterranean reservoir and fluidly connected to the first injector;

12. The system of claim 11, wherein

the first injector is an NCG injection well which was previously configured as a first existing injection well to inject the existing solvent into the subterranean reservoir, and wherein the NCG injection well is configured to inject the gas phase dilution agent into the subterranean reservoir; and

the first NCG/vaporized solvent production well which was previously configured as a first existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir is configured to additionally recover a portion of the existing solvent in the liquid phase and a portion of the heavy oil.

13. The system of claim 11, comprising at least two well pairs located in the subterranean reservoir, wherein

a first well pair is comprised of the first injector which was previously configured as a first existing injection well to inject the existing solvent into the subterranean reservoir and a first existing production well; and

a second well pair is comprised of the first NCG/vaporized solvent production well, wherein the first NCG/vaporized solvent production well was previously configured as a second existing injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a second existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir.

14. The system of claim 11, comprising at least three well pairs located in the subterranean reservoir, wherein

a first well pair is comprised of the first injector which was previously configured as a first existing injection well to inject the existing solvent into the subterranean reservoir, and a first existing production well;

a second well pair is comprised of a second injector which was previously configured as a second existing injection well to inject the existing solvent into the subterranean reservoir wherein the second injector is an NCG injection well, and wherein the NCG injection well has been configured to inject the gas phase dilution agent into the subterranean reservoir, and a second existing production well; and

a third well pair is comprised of the first NCG/vaporized solvent production well which was previously configured as a third existing injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a third existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir;

15. The system of claim 11, comprising at least three well pairs located in the subterranean reservoir, wherein

a second well pair is comprised of the first NCG/vaporized solvent production well which was previously configured as a second existing injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a second existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir; and

a third well pair is comprised of a second NCG/vaporized solvent production well which was previously configured as a third existing injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a third existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir;

16. The system of claim 11, comprising at least two well pairs and an infill well located in the subterranean reservoir, wherein

a second well pair is comprised of a second injector which was previously configured as a second existing injection well to inject the existing solvent into the subterranean reservoir wherein the second injector is an NCG injection well, and wherein the NCG injection well is configured to inject the gas phase dilution agent into the subterranean reservoir, and a second existing production well; and

an infill well is utilized as the first NCG/vaporized solvent production well

17. The system of claim 11, comprising at least two well pairs and an infill well located in the subterranean reservoir, wherein

a first well pair is comprised of the first NCG/vaporized solvent production well which was previously configured as a first existing injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a first existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir; and

a second well pair is comprised of a second NCG/vaporized solvent production well which was previously configured as a second original injection well to inject the existing solvent into the subterranean reservoir or was previously configured as a second existing production well to recover the existing solvent and the heavy oil in the liquid phase from the subterranean reservoir, wherein the second NCG/vaporized solvent production well is configured to recover a portion of the gas phase dilution agent and a portion of the vaporized solvent;

wherein the first injector is an infill well which is utilized as a first NCG injection well; and

wherein 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.

18. The system of claim 11, wherein

the first injector is fluidly connected to the top of the reservoir to provide a gas cap; and

the reservoir contains at least one well pair comprising a first existing injection well and a first existing production well;

19. The system of claim 18, wherein 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.

20. The system of claim 11, further comprising a surface facility, wherein the surface facility comprises:

a separation facility, that is fluidly connected to at least the first NCG/vaporized solvent production well, wherein at least a portion of the recovered vaporized solvent is separated from the recovered gas phase dilution agent, forming a separated vaporized solvent and a separated gas phase dilution agent;

a compression facility, that is fluidly connected to the separation facility, wherein at least a portion of the separated gas phase dilution agent is compressed to a higher pressure to form a compressed gas phase dilution agent; and

a heating facility, that is fluidly connected to the separation facility, wherein at least a portion of the compressed gas phase dilution agent is heated to a higher temperature to form a heated gas phase dilution agent;