Chasing solvent for enhanced recovery processes

Abstract

Methods to optimize solvent use in solvent-dominated processes for recovery of hydrocarbons. Methods include injecting a solvent composition into a reservoir at a pressure above a liquid/vapor phase change of the solvent composition; injecting a chaser into the reservoir at a pressure above the liquid/vapor phase change of the solvent composition; allowing the solvent composition to mix with hydrocarbons in the reservoir and at least partially dissolve into the hydrocarbons to produce a solvent/hydrocarbon mixture; reducing the pressure in the reservoir below the liquid/vapor phase change pressure of the solvent composition thereby flowing at least a fraction of the solvent/hydrocarbon mixture from the reservoir; and repeating these steps as required.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority from Canadian Patent Application 2,972,203 filed Jun. 29, 2017 entitled CHASING SOLVENT FOR ENHANCED RECOVERY PROCESSES.

BACKGROUND

Field of Disclosure

The present disclosure relates generally to the recovery of hydrocarbons. More specifically, the disclosure relates to methods for optimizing solvent use and reducing the solvent volume used per unit of hydrocarbon production in solvent-dominated processes for recovering bitumen and heavy oil from underground reservoirs.

Description of Related Art

This section is intended to introduce various aspects of the art that may be associated with the present disclosure. This discussion aims to provide a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as an admission of prior art.

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

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

At the present time, solvent-dominated recovery processes (SDRPs) are not commonly used as commercial recovery processes to produce highly viscous oil. Solvent-dominated means that the injectant comprises greater than 50 percent (%) by mass of solvent or that greater than 50% of the produced oil's viscosity reduction is obtained by chemical solvation rather than by thermal means. Highly viscous oils are produced primarily using thermal methods in which heat, typically in the form of steam, is added to the reservoir.

Cyclic solvent-dominated recovery processes (CSDRPs) are a subset of SDRPs. A CSDRP may be a non-thermal recovery method that uses a solvent to mobilize viscous oil by cycles of injection and production. One possible laboratory method for roughly comparing the relative contribution of heat and dilution to the viscosity reduction obtained in a proposed oil recovery process is to compare the viscosity obtained by diluting an oil sample with a solvent to the viscosity reduction obtained by heating the sample.

In a CSDRP, a solvent composition may be injected through a well into a subterranean formation, causing pressure to increase. Next, the pressure is lowered and reduced-viscosity oil is produced to the surface of the subterranean formation through the same well through which the solvent was injected. Multiple cycles of injection and production may be used. CSDRPs may be particularly attractive for thinner or lower-oil-saturation reservoirs. In such reservoirs, thermal methods utilizing heat to reduce viscous oil viscosity may be inefficient due to excessive heat loss to the overburden and/or underburden and/or reservoir with low oil content.

References describing specific CSDRPs include: Canadian Patent No. 2,349,234 (Lim et al.); G. B. Lim et al., “Three-dimensional Scaled Physical Modeling of Solvent Vapour Extraction of Cold Lake Bitumen,” The Journal of Canadian Petroleum Technology, 35(4), pp. 32-40 (April 1996); G. B. Lim et al., “Cyclic Stimulation of Cold Lake Oil Sand with Supercritical Ethane,” SPE Paper 30298 (1995); U.S. Pat. No. 3,954,141 (Allen et al.); and M. Feali et al., “Feasibility Study of the Cyclic VAPEX Process for Low Permeable Carbonate Systems,” International Petroleum Technology Conference Paper 12833 (2008).

The family of processes within the Lim et al. references describes a particular SDRP that is also a CSDRP. These processes relate to the recovery of heavy oil and bitumen from subterranean reservoirs using cyclic injection of a solvent in the liquid state which vaporizes upon production.

With reference to FIG. 1, which is a simplified diagram based on Canadian Patent No. 2,349,234 (Lim et al.), one CSDRP process is described as a single well method for cyclic solvent stimulation, the single well preferably having a horizontal wellbore portion and a perforated liner section. A vertical wellbore 101 driven through overburden 102 into reservoir 103 and is connected to a horizontal wellbore portion 104. The horizontal wellbore portion 104 comprises a perforated liner section 105 and an inner bore 106. The horizontal wellbore portion comprises a downhole pump 107. In operation, solvent or viscosified solvent is driven down and diverted through the perforated liner section 105 where it percolates into reservoir 103 and penetrates reservoir material to yield a reservoir penetration zone 108. Oil dissolved in the solvent or viscosified solvent flows into the well and is pumped by downhole pump 107 through an inner bore 106 through a motor at the wellhead 109 to a production tank 110 where oil and solvent are separated and the solvent is recycled to be reused in the process. Each instance of injection of solvent and production of oil dissolved in solvent is considered a “cycle.”

In a SDRP, one of the key metrics to measure the efficiency of the process is solvent intensity (solvent volume used per unit of hydrocarbon production), which may also be expressed as a solvent to oil ratio (ratio of solvent injected to oil produced), similar to the steam to oil ratio used in thermal recovery processes. In a CSDRP, solvent volumes injected grow cycle over cycle, and the efficiency of the process is reduced. Solvents can also vary in price and availability. Therefore, efficient and effective use and recovery of solvents are key to the economics and robustness of a SDRP.

SUMMARY

The present disclosure provides methods for optimizing solvent use and reducing solvent intensity in CSDRP. In some embodiments, the methods include injecting a solvent composition into an underground reservoir at a pressure above a liquid/vapor phase change pressure of the solvent composition; injecting a chaser into the reservoir at a pressure above the liquid/vapor phase change pressure of the solvent composition; allowing the solvent composition to mix with hydrocarbons in the reservoir and at least partially dissolve into the hydrocarbons to produce a solvent/hydrocarbon mixture; reducing the pressure in the reservoir below the liquid/vapor phase change pressure of the solvent composition thereby flowing at least a fraction of the solvent/hydrocarbon mixture from the reservoir; and repeating these steps as required. In other embodiments, the chaser may comprise between 1% and 80% of the total injected volume at any given cycle, wherein “total injected volume” is understood to mean the aggregate volume of solvent composition and chaser injected during a given cycle. The ratio of chaser volume to the total injected volume may increase, decrease or remain the same over consecutive cycles.

The chaser may replace part of the solvent to be injected in CSDRP to help reduce the solvent use, restore or maintain the reservoir pressure, and also to push the solvent further into the reservoir for better mixing with oil. The chaser can be water, gas, or any other non-hydrocarbon fluid. The chaser can be wholly or partially obtained from the same operation of the CSDRP, or derived from other commercial operations (e.g. cyclic steam stimulation, steam-assisted gravity drainage, etc.), or a different source that is readily available on site. For example, produced water from CSDRP, disposal water at elevated temperature from the thermal operations, flue gas, or any other sources that contain one or more components of water, C1, CO₂, N₂, etc. may provide sources of chaser agents.

The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood. Additional features will also be described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 1 is an exemplary schematic of a cyclic solvent-dominated recovery process.

FIG. 2 is an exemplary schematic of solvent composition “fingering” into oil sands during CSDRP.

FIG. 3 is an exemplary schematic of a low utilization zone of solvent composition in CSDRP.

FIG. 4 is an exemplary schematic of chaser replacing solvent composition in a low utilization zone in CSDRP.

FIG. 5 is an exemplary schematic of a CSDRP incorporating solvent chasing according to certain aspects of the present disclosure.

FIG. 6 is a graph of simulated injected solvent composition volumes over CSDRP cycles.

FIG. 7 is a graph of simulated Oil to Injected Solvent Ratios over CSDRP cycles.

FIG. 8 is a graph of simulated solvent recovery percentages over CSDRP cycles.

FIG. 9 is a graph of retained solvent volumes over CSDRP cycles.

FIG. 10 is a flow chart of a method of recovering hydrocarbons according to the present disclosure.

It should be noted that the figures are merely examples and no limitations on the scope of the present disclosure are intended thereby. Further, schematics are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure. Certain features and components herein may be shown exaggerated in scale or in schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. When referring to the figures described herein, the same reference numerals may be referenced in multiple figures for the sake of simplicity.

DETAILED DESCRIPTION

To promote an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and no limitation of the scope of the disclosure is hereby 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. For the sake of clarity, some features not relevant to the present disclosure may not be shown in the drawings.

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 or issued patent. Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.

As one of ordinary skill would appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name only. In the following description and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus, should be interpreted to mean “including, but not limited to.”

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

“Bitumen” is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:

• • 19 weight (wt.) percent (%) aliphatics (which can range from 5 wt. % to 30 wt. % or higher);
  • 19 wt. % asphaltenes (which can range from 5 wt. % to 30 wt. % or higher);
  • 30 wt. % aromatics (which can range from 15 wt. % to 50 wt. % or higher);
  • 32 wt. % resins (which can range from 15 wt. % to 50 wt. % or higher); and
  • some amount of sulfur (which can range in excess of 7 wt. %), based on the total bitumen weight.

In addition, bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found in bitumen can vary. The term “heavy oil” includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.

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

The term “viscous oil” as used herein means a hydrocarbon, or mixture of hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP at initial reservoir conditions. Viscous oil includes oils generally defined as “heavy oil” or “bitumen.” Bitumen is classified as an extra heavy oil, with an API gravity of about 10° or less, referring to its gravity as measured in degrees on the API Scale. Heavy oil has an API gravity in the range of about 22.3° to about 10°. The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes.

In-situ is a Latin phrase for “in the place” and, in the context of hydrocarbon recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For example, in-situ temperature means the temperature within the reservoir. In another usage, an in-situ oil recovery technique is one that recovers oil from a reservoir within the earth.

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

The term “wellbore” as used herein means 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. The term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

The articles “the,” “a” and “an” are not necessarily limited to mean only one, but rather are inclusive and open ended to include, optionally, multiple such elements.

As used herein, 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.

“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.

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

As used herein, the phrases “for example,” “as an example,” and/or simply the terms “example” or “exemplary,” when used with reference to one or more components, features, details, structures, methods and/or figures according to the present disclosure, are intended to convey that the described component, feature, detail, structure, method and/or figure is an illustrative, non-exclusive example of components, features, details, structures, methods and/or figures according to the present disclosure. Thus, the described component, feature, detail, structure, method and/or figure is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, methods and/or figures, including structurally and/or functionally similar and/or equivalent components, features, details, structures, methods and/or figures, are also within the scope of the present disclosure. Any embodiment or aspect described herein as “exemplary” is not to be construed as preferred or advantageous over other embodiments.

CSDRP Process Description

During CSDRP, a reservoir may accommodate injected solvent composition and non-solvent fluid (also referred to as “additional injectants” or “non-solvent injectants”) by dilating a reservoir pore space by applying an injection pressure. As illustrated in FIG. 2, the solvent composition 202 injected through wellbore 204 “fingers” into the oil sands 206. The solvent composition 202 then mixes with the viscous oil to yield a reduced viscosity mixture with higher mobility than the native viscous oil. “Fingering” may occur when two fluids of different viscosities come in contact with one another and one fluid penetrates the other in a finger-like pattern, that is, in an uneven manner.

The primary mixing mechanism of the solvent with the oil may be dispersive mixing, not diffusion. The solvent composition injected in each cycle may replace the volume of previously recovered fluid and may add additional fluid to contact previously uncontacted viscous oil. The injection well and the production well may utilize a common wellbore.

While producing hydrocarbon during CSDRP, pressure may be reduced and the solvent composition, any non-solvent injectant, and viscous oil may flow back to the same well in which the solvent and non-solvent injectant were injected, to be produced to the surface of the reservoir as produced fluid. The produced fluid may be a mixture of the solvent composition and viscous oil (herein referred as “solvent/hydrocarbon mixture”). Each instance of solvent injection and production of a solvent/hydrocarbon mixture is considered a CSDRP cycle.

As the pressure in the reservoir falls, the produced fluid rate may decline with time. Production of the produced fluid may be governed by any of the following mechanisms: gas drive via solvent vaporization and native gas exsolution, compaction drive as the reservoir dilation relaxes, fluid expansion, and gravity-driven flow. The relative importance of the mechanisms depends on static properties such as solvent properties, native GOR (Gas to Oil Ratio), fluid and rock compressibility characteristics, and/or reservoir depth. The relative importance of the mechanism may depend on operational practices such as solvent injection volume, producing pressure, and/or viscous oil recovery to-date, among other factors.

CSDRP—Solvent Composition

The solvent may be a light, but condensable, hydrocarbon or mixture of hydrocarbons comprising ethane, propane, butane, or pentane. The solvent may comprise at least one of ethane, propane, butane, pentane, and carbon dioxide. The solvent may comprise greater than 50% C2-C5 hydrocarbons on a mass basis. The solvent may be greater than 50 mass % propane, optionally with diluent when it is desirable to adjust the properties of the injectant to improve performance.

Additional injectants may include CO₂, natural gas, C5+ hydrocarbons, ketones, and alcohols. Non-solvent injectants that are co-injected with the solvent may include steam, non-condensable gas, or hydrate inhibitors. The solvent composition may comprise at least one of diesel, viscous oil, natural gas, bitumen, diluent, C5+ hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water soluble solid particles, and solvent soluble solid particles.

To reach a desired injection pressure of the solvent composition, a viscosifier and/or a solvent slurry may be used in conjunction with the solvent. The viscosifier may be useful in adjusting solvent viscosity to reach desired injection pressures at available pump rates. The viscosifier may include diesel, viscous oil, bitumen, and/or diluent. The viscosifier may be in the liquid, gas, or solid phase. The viscosifier may be soluble in either one of the components of the injected solvent and water. The viscosifier may transition to the liquid phase in the reservoir before or during production. In the liquid phase, the viscosifiers are less likely to increase the viscosity of the produced fluids and/or decrease the effective permeability of the formation to the produced fluids.

The solvent composition may be as described in Canadian Patent No. 2,645,267 (Chakrabarty, issued Apr. 16, 2013). The solvent composition may comprise (i) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and (ii) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane. The solvent composition may have a Hansen hydrogen bonding parameter of 0.3 to 1.7 (or 0.7 to 1.4). The solvent composition may have a volume ratio of the polar component to non-polar component of 10:90 to 50:50 (or 10:90 to 24:76, 20:80 to 40:60, 25:75 to 35:65, or 29:71 to 31:69). The polar component may be, for instance, a ketone or acetone. The non-polar component may be, for instance, a C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics. For further details and explanation of the Hansen Solubility Parameter System see, for example, Hansen, C. M. and Beerbower, Kirk-Othmer, Encyclopedia of Chemical Technology, (Suppl. Vol. 2nd Ed), 1971, pp 889-910 and “Hansen Solubility Parameters A User's Handbook” by Charles Hansen, CRC Press, 1999.

The solvent composition may be as described in Canadian Patent No. 2,781,273 (Chakrabarty, issued May 20, 2014). The solvent composition may comprise (i) an ether with 2 to 8 carbon atoms; and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms. Ether may have 2 to 8 carbon atoms. Ether may be di-methyl ether, methyl ethyl ether, di-ethyl ether, methyl iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether, methyl iso-butyl ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-propyl butyl ether, propyl butyl ether, di-isobutyl ether, or di-butyl ether. Ether may be di-methyl ether. The non-polar hydrocarbon may a C2-C30 alkane. The non-polar hydrocarbon may be a C2-C5 alkane. The non-polar hydrocarbon may be propane. The ether may be di-methyl ether and the hydrocarbon may be propane. The volume ratio of ether to non-polar hydrocarbon may be 10:90 to 90:10; 20:80 to 70:30; or 22.5:77.5 to 50:50.

The solvent composition may comprise at least 5 mol % of a high-aromatics component (based upon total moles of the solvent composition) comprising at least 60 wt. % aromatics (based upon total mass of the high-aromatics component). As described in Canadian Patent No. 2,900,178 (Wang et al., issued Sep. 6, 2016), one suitable and inexpensive high-aromatics component is gas oil from a catalytic cracker of a hydrocarbon refining process, also known as a light catalytic gas oil (LCGO).

CSDRP—Phase of Injected Solvent

The solvent composition may be injected into the well at a pressure in the underground reservoir above a liquid/vapor phase change pressure such that at least 25 mass % of the solvent enters the reservoir in the liquid phase. At least 50, 70, or even 90 mass % of the solvent may enter the reservoir in the liquid phase. Injection of the solvent composition as a liquid may be preferred for increasing solvent injection pressure. The solvent composition may be injected into the well at rates and pressures such that immediately after completing injection into the well at least 25 mass % of the injected solvent is in a liquid state in the reservoir (e.g., underground).

A fraction of the solvent may be injected in the solid phase in order to mitigate adverse solvent fingering, increase injection pressure, and/or keep the average distance of the solvent closer to the wellbore than in the case of pure liquid phase injection. Less than 20 mass % of the injectant may enter the reservoir in the solid phase. Less than 10 mass % or less than 50 mass % of the solvent may enter the reservoir in the solid phase. Once in the reservoir, the solid phase of the solvent may transition to a liquid phase before or during production to prevent or mitigate reservoir permeability reduction during production.

Injection of the solvent as a vapor may assist uniform solvent distribution along a horizontal well, particularly when variable injection rates are targeted. Vapor injection in a horizontal well may facilitate an upsize in the port size of installed inflow control devices (ICDs) that minimize the risk of plugging the ICDs. Injecting the solvent as a vapor may increase the ability to pressurize the reservoir to a desired pressure by lowering effective permeability of the injected vapor in a formation comprising liquid viscous oil.

A non-condensable gas may be injected into the reservoir to achieve a desired pressure, along with or followed by injection of the solvent. Injecting a primarily non-condensable gas followed by primarily solvent injection (where primarily means greater than 50 mass % of the mixture of non-condensable gas and solvent) may provide a way to maintain the desired injection pressure target. A non-solvent injectant in the vapor phase, such as CO₂ or natural gas, may be injected, followed by injection of the solvent composition.

Although a CSDRP may be predominantly a non-thermal process in that heat is not used principally to reduce the viscosity of the viscous oil, the use of heat is not excluded. Heating may be beneficial to improve performance, improve process start-up, or provide flow assurance during production. For start-up, low-level heating (for example, less than 100° C.) may be appropriate. Low-level heating of the solvent prior to injection may also be performed to prevent hydrate formation in tubulars and in the reservoir. Heating to higher temperatures may benefit recovery. Two non-exclusive scenarios of injecting a heated solvent are as follows. In one scenario, vapor solvent would be injected and would condense before it reaches the bitumen. In another scenario, a vapor solvent would be injected at up to 200° C. and would become a supercritical fluid at downhole operating pressure.

CSDRP—Pore Volume

As described in Canadian Patent No. 2,734,170 (Dawson et al., issued Sep. 24, 2013), one method of managing fluid injection in a CSDRP is for the cumulative volume injected over all injection periods in a given cycle (V_INJECTANT) to equal the net reservoir voidage (V_VOIDAGE) resulting from previous injection and production cycles plus an additional volume (V_ADDITIONAL), for example approximately 2-15%, or approximately 3-8% of the pore volume (PV) of the reservoir volume associated with the well pattern. In mathematical terms, the volume (V) may be represented by:V_INJECTANT=V_VOIDAGE+V_ADDITIONAL

One way to approximate the net in-situ volume of fluids produced is to determine the total volume of non-solvent liquid hydrocarbon fraction produced (V_{PRODUCED OIL}) and aqueous fraction produced (V_{PRODUCED WATER}) minus the net injectant fractions produced (V_{INJECTED SOLVENT}−V_{PRODUCED SOLVENT}). For example, in the case where 100% of the injectant is solvent and the reservoir contains only oil and water, an equation that represents the net in-situ volume of fluids produced (V_VOIDAGE) is:V_VOIDAGE=V_OIL^PRODUCED+V_WATER^PRODUCED−(V_SOLVENT^INJECTED−V_SOLVENT^PRODUCED)CSDRP—Diluent

In the context of this specification, diluent means a liquid compound that can be used to dilute the solvent and can be used to manipulate the viscosity of any resulting solvent/hydrocarbon mixture. By such manipulation of the viscosity of the solvent/hydrocarbon (and diluent) mixture, the invasion, mobility, and distribution of solvent in the reservoir can be controlled so as to increase viscous oil production.

The diluent is typically a viscous hydrocarbon liquid, especially a C4-C20 hydrocarbon, or mixture thereof, may be locally produced and may be used to thin bitumen to pipeline specifications. Pentane, hexane, and heptane may be components of such diluents. Bitumen itself can be used to modify the viscosity of the solvent, often in conjunction with ethane solvent.

The diluent may have an average initial boiling point close to the boiling point of pentane (36° C.) or hexane (69° C.) though the average boiling point (defined further below) may change with reuse as the mix changes (some of the solvent originating among the recovered viscous oil fractions). More than 50% by volume of the diluent may have an average boiling point lower than the boiling point of decane (174° C.). More than 75% by volume, such as more than 80% by volume or more than 90% by weight of the diluent, may have an average boiling point between the boiling point of pentane and the boiling point of decane. The diluent may have an average boiling point close to the boiling point of hexane (69° C.) or heptane (98° C.), or even water (100° C.).

More than 50% by weight of the diluent (such as more than 75% or 80% by weight or more than 90% by weight) may have a boiling point between the boiling points of pentane and decane. More than 50% by weight of the diluent may have a boiling point between the boiling points of hexane (69° C.) and nonane (151° C.), particularly between the boiling points of heptane (98° C.) and octane (126° C.).

CSDRP—Reservoir Performance

As described in Canadian Patent No. 2,900,179 (Wang et al.), CSDRP performance may further be improved by using a solvent mixture that has multiple components with different saturation pressures at a certain temperature, i.e., the solvent mixture exhibits liquid-vapor phase behavior over a range of pressures, to address drops in reservoir pressure changes that increase bitumen viscosity and reduce bitumen production rates.

The solvent composition may comprise multiple components with different saturation pressures at a certain temperature. The solvent composition may be in a liquid phase upon injection. A viscosity-reducing component (greater than 50 mol %) of the solvent composition, such as propane or dimethyl ether, may remain in the liquid phase during most of the production period, playing its role of reducing the bitumen viscosity. The solvent composition may also include more volatile components (e.g., C1 or C2) that can easily vaporize when production pressure drops, providing additional gas drive to enhance production. To enhance the performance further, the difference between the pressure at which gas exsolution initiates and a lower bound where all or most solvent has been vaporized may be maximized. This may be achieved by replacing a small fraction of the viscosity-reducing component (e.g., 5-20 mol %) with a heavier solvent having higher solubility and lower vapor pressure.

The solvent composition may thus have two components having a difference in vaporization pressure (at the temperature of the reservoir) greater than 200 kPa. The first component may comprise greater than 50 mol % ethane, propane, butane, pentane, heptane, hexane, dimethyl ether, or a combination thereof, based upon total moles of the first component. The first component may comprise between 5 mol % and 30 mol % of hydrocarbons with a molecular weight of at least 58 g/mol, based upon total moles of the first component. The first component may comprise at least 50 mol % diluent, based upon total moles of the first component.

The second component may comprise at least 10 mol % methane, based on total moles of the solvent composition. The second component may have an average molecular weight of less than 33 g/mol. The second component may comprise greater than 50 mol % methane, ethane, carbon dioxide, or a combination thereof, based upon total moles of the second component.

The first component may comprise (i) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and (ii) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane. The first component may have a Hansen hydrogen bonding parameter of 0.3 to 1.7 and the volume ratio of the polar component to the non-polar component may be 10:90 to 50:50. The polar component may be a ketone or acetone. The non-polar component may be a C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics.

The first component may comprise (i) an ether with 2 to 8 carbon atoms; and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms. The ether may be di-methyl ether, methyl ethyl ether, di-ethyl ether, methyl iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether, methyl iso-butyl ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-propyl butyl ether, propyl butyl ether, di-isobutyl ether, or di-butyl ether. The non-polar hydrocarbon may be a C2-C30 alkane, a C2-05 alkane, or propane. The volume ratio of the ether to the non-polar hydrocarbon may be 10:90 to 90:10.

TABLE 1
Operating Ranges for a CSDRP
Parameter	Broader Option	Narrower Option
Cumulative	Fill-up estimated pattern pore	Inject a cumulative volume in a
injectant volume	volume plus a cumulative 3-8% of	cycle, beyond a primary pressure
per cycle	estimated pattern pore volume; or	threshold, of 3-8% of estimated
	inject, beyond a primary pressure	pore volume.
	threshold, for a cumulative period of
	time (e.g. days to months); or
	inject, beyond a primary pressure
	threshold, a cumulative of 3-8% of
	estimated pore volume.
Injectant	Main solvent (>50 mass %) C2-C5.	Main solvent (>50 mass %) is
composition,	Alternatively, wells may be	propane (C3) or ethane (C2).
main	subjected to compositions other than
	main solvents to improve well
	pattern performance (i.e. CO2
	flooding of a mature operation or
	altering in-situ stress of reservoir).
	CO2
Injectant	Additional injectants may include	Only diluent, and only when
composition,	CO2 (up to about 30 mass %), C3+,	needed to achieve adequate
additive	viscosifiers (e.g. diesel, viscous oil,	injection pressure. Or, a polar
	bitumen, diluent), ketones, alcohols,	compound having a non-terminal
	sulphur dioxide, hydrate inhibitors,	carbonyl group (e.g. a ketone, for
	steam, non-condensable gas,	instance acetone).
	biodegradable solid particles, salt,
	water soluble solid particles, or
	solvent soluble solid particles.
Injectant phase &	Solvent injected such that at the end	Solvent injected as a liquid, and
Injection	of the injection cycle, greater than	most solvent injected just under
pressure	25% by mass of the solvent exists as	fracture pressure and above
	a liquid and less than 50% by mass	dilation pressure,
	of the injectant exists in the solid	Pfracture > Pinjection > Pdilation > Pvapor
	phase in the reservoir, with no
	constraint as to whether most
	solvent is injected above or below
	dilation pressure or fracture
	pressure.
Injectant	Enough heat to prevent hydrates and	Enough heat to prevent hydrates
temperature	locally enhance wellbore inflow	with a safety margin,
	consistent with Boberg-Lantz mode	Thydrate + 5° C. to Thydrate + 50° C.
Injection rate	0.1 to 10 m3/day per meter of	0.2 to 6 m3/day per meter of
during	completed well length (rate	completed well length (rate
continuous	expressed as volumes of liquid	expressed as volumes of liquid
injection	solvent at reservoir conditions).	solvent at reservoir conditions).
		Rates may also be designed to
		allow for limited or controlled
		fracture extent, at fracture
		pressure or desired solvent
		conformance depending on
		reservoir properties.
Threshold	Any pressure above initial reservoir	A pressure between 90% and
pressure	pressure.	100% of fracture pressure.
(pressure at
which solvent
continues to be
injected for
either a period of
time or in a
volume amount)
Well length	As long of a horizontal well as can	500 m-1500 m (commercial
	practically be drilled; or the entire	well).
	pay thickness for vertical wells.
Well	Horizontal wells parallel to each	Horizontal wells parallel to each
configuration	other, separated by some regular	other, separated by some regular
	spacing of 20-1000 m.	spacing of 50-600 m.
	Also vertical wells, high angle slant
	wells & multi-lateral wells. Also
	infill injection and/or production
	wells (of any type above) targeting
	bypassed hydrocarbon from
	surveillance of pattern performance.
Well orientation	Orientated in any direction.	Horizontal wells orientated
		perpendicular to (or with less
		than 30 degrees of variation) the
		direction of maximum horizontal
		in-situ stress.
Minimum	Generally, the range of the MPP	A low pressure below the vapor
producing	should be, on the low end, a	pressure of the main solvent,
pressure (MPP)	pressure significantly below the	ensuring vaporization, or, in the
	vapor pressure, ensuring	limited vaporization scheme, a
	vaporization; and, on the high-end, a	high pressure above the vapor
	high pressure near the native	pressure. At 500 m depth with
	reservoir pressure. For example,	pure propane, 0.5 MPa (low)-1.5 MPa
	perhaps 0.1 MPa (megapascals)-5 MPa,	(high), values that
	depending on depth and mode	bound the 800 kPa vapor
	of operation (all-liquid or limited	pressure of propane.
	vaporization).
Oil rate	Switch to injection when rate equals	Switch when the instantaneous
	2 to 50% of the max rate obtained	oil rate declines below the
	during the cycle. Alternatively,	calendar day oil rate (CDOR)
	switch when absolute rate equals a	(e.g. total oil/total cycle length).
	pre-set value. Alternatively, well is	Likely most economically
	unable to sustain hydrocarbon flow	optimal when the oil rate is at
	(continuous or intermittent) by	about 0.5 × CDOR.
	primary production against	Alternatively, switch to injection
	backpressure of gathering system or	when rate equals 20-40% of the
	well is “pumped off” unable to	max rate obtained during the
	sustain flow from artificial lift.	cycle.
	Alternatively, well is out of sync
	with adjacent well cycles.
Gas rate	Switch to injection when gas rate	Switch to injection when gas rate
	exceeds the capacity of the pumping	exceeds the capacity of the
	or gas venting system. Well is	pumping or gas venting system.
	unable to sustain hydrocarbon flow	During production, an optimal
	(continuous or intermittent) by	strategy is one that limits gas
	primary production against	production and maximizes liquid
	backpressure of gathering system	from a horizontal well.
	with or without compression
	facilities.
Oil to Solvent	Begin another cycle if the OISR of	Begin another cycle if the OISR
Ratio	the just completed cycle is above	of the just completed cycle is
	0.15 or economic threshold.	above 0.25.
Abandonment	Atmospheric or a value at which all	For propane and a depth of
pressure	of the solvent is vaporized. Steps e)	500 m, about 340 kPa, the likely
(pressure at	and f) (described below) may start	lowest obtainable bottomhole
which well is	from this point at the same or higher	pressure at the operating depth
produced after	pressure.	and well below the value at
CSDRP cycles		which all of the propane is
are completed)		vaporized. Steps e) and f)
		(described below) may start from
		this point at the same or higher
		pressure.

Table 1 outlines the operating ranges for certain CSDRPs. The present disclosure is not intended to be limited by such operating ranges.

In Table 1, the options may be formed by combining two or more parameters and, for brevity and clarity, each of these combinations will not be individually listed.

In CSDRP, cycles may grow progressively in length and the volume of solvent needed for efficient recovery increase accordingly as viscous oil is recovered and the well is depleted. In later cycles, large volumes of solvent composition must often be injected to re-pressurize the formation and fill voidage created as a result of reservoir fluid (oil, gas, water, etc.) production. More specifically, as shown in FIG. 3, as the solvent composition 202 replaces the volume of recovered viscous oil, the solvent composition 202 near the wellbore 204 is not fully utilized for mixing and viscosity reduction. This “low utilization zone” 208 is mainly used to fill voidage and maintain pressurization. Employing solvent (which is relatively expensive compared to other injectants) in the low utilization zone 208 essentially as a filling agent significantly reduces CSDRP efficiency and increases operational costs.

Solvent Chasing

Solvent use in CSDRP may be optimized to reduce solvent intensity by implementing some aspects of the present disclosure. With reference to FIG. 4, as “fingers” grow during CSDRP cycles, part or all solvent composition 202 that would have been injected in a given cycle may be replaced with a “chaser” 210. The chaser 210 may be water, gas, or any other non-hydrocarbon fluid that is different from the solvent composition 202 and safe to operate with. The chaser 210 may be cheaper than the solvent composition or more readily available. Preferably, the chaser 210 may be a non-compressible liquid (e.g., water) or low molecular weight gas (e.g., methane). For example, acceptable chasers 210 may include water (fresh, brackish, procuded, disposal, steam condensate), gas (C1, CO₂, N₂, flue gas from boilers) or any combination thereof.

Injecting a chaser 210 during certain CSDRP cycles may assist in pressure maintenance and forcing solvent composition 202 further into the reservoir for enhancing solvent/oil contact and mixing. By reducing solvent use and utilizing instead a more economical substance as chaser 210, CSDRP process economics may be improved.

The target temperature of the chaser 210 may be higher than the initial temperature of the reservoir or, in some embodiments, between 10 and 300° C., or for water, between 10 and 90° C. In some embodiments, the density of the chaser 210 may be greater than the density of the solvent composition 202 at reservoir conditions, preferably >10% greater than the density of the solvent composition 202.

The chaser 210 may be injected at any CSDRP cycle, and may be omitted during one or more intervening cycles. In some embodiments, the chaser 210 may be injected after the second or third CSDRP cycle or when oil sands 206 near the wellbore 204 have been depleted. Injection of solvent composition 202 and chaser 210 can alternate multiple times within a cycle with the first slug of injection being solvent.

In some embodiments, for cycles including chaser injection, the chaser 210 may be injected toward the end of an injection cycle following injection of solvent composition 202 during the same cycle. In this way, the chaser 210 may fill voidage created by the solvent composition 202 permeating increasing volumes within the reservoir and help maintain a desired pressure and penetration of the solvent composition 202. The amount of chaser 210 relative to the solvent composition 202 volume may be any amount, preferably in the range between 1% and 80% in any given cycle. In some embodiments, the amount of chaser 210 injected into the well relative to the solvent composition 202 volume may remain constant and in others it may progressively increase over cycles, or decrease over cycles, or alternate between periods of gradual increase and gradual decrease. Preferably, the chaser 210 may account for between 1% and 10% of the total injected fluid by volume in the first injection cycle including chaser, and gradually increase to a maximum of 80% of the total injected fluid by volume.

As discussed above, one method of managing chaser injection in a CSDRP is for the cumulative volume injected over all injection periods in a given cycle (V_INJECTANT) to equal the net reservoir voidage (V_VOIDAGE) resulting from previous injection and production cycles plus an additional volume (V_ADDITIONAL). When use of a chaser is incorporated into the process and V_INJECTANT is equal to the sum of the volume of solvent (V_SOLVENT) and the volume of chaser (V_CHASER), the latter may be represented in mathematical terms by:V_CHASER=V_VOIDAJE+V_ADDITIONAL−V_SOLVENT

The chaser 210 may be injected at a pressure above the liquid/vapor change pressure of the solvent composition 202 and, preferably, at a similar or same pressure as the solvent composition, in the range of 1,000-10,000 kPa.

Liquid chaser can be injected into the reservoir using the same injection system as the solvent composition, but one or more separate storage tanks may be used to store the chaser. A gas chaser may benefit from using a compressor and multiphase injection system. A recovered liquid chaser such as water can be separated from the produced solvent/hydrocarbon mixture on the surface by gravity separation and then sent to storage tanks for re-injection. Recovered gas chaser may be mostly produced from the casing and then compressed for re-injection.

For example, as shown in FIG. 5, the chaser may be injected into overburden 102 and reservoir 103 using the same wellbore 101 and horizontal wellbore portion 104 used to inject the solvent composition. The chaser may percolate to the reservoir penetration zone 108 through the perforated liner section 105 following the solvent composition. As does oil dissolved in the solvent, the chaser may flow back into the well and be pumped by the downhole pump 107 through the inner bore 106 through the motor at the wellhead 109 to a production tank 110, where the chaser may be separated from the solvent and oil to be stored in a separate tank from the solvent and reused in the CSDRP process.

In some embodiments, the chaser may be derived from a variety of hydrocarbon recovery processes. In embodiments in which water is employed as chaser, the water may be fresh or recycled water, water produced during a CSDRP process (with some make-up water as needed), or disposal water from other processes. For example, water produced during (i) steam-assisted gravity drainage (SAGD) processes; (ii) solvent-assisted SAGD (SA-SAGD) processes; (iii) expanding solvent SAGD (ES-SAGD) processes; (iv) cyclic steam simulation (CSS) processes; or (v) cyclic solvent processes (CSP) may be utilized in an adjacent CSDRP site as chaser 210. In this way, processes and methods according to the present disclosure may be integrated with existing steam-based operations to utilize disposal water. One benefit of doing so is that disposed water may have a temperature higher than the ambient temperature of the reservoir, which can range between 5 and 30° C. in heavy oil reservoirs in Canada. This residual heat may aid the solvent/oil mixing process in CSDRP by reducing the oil viscosity further, as well as potentially mitigating flow assurance issues.

In some embodiments, the chaser 210 may be heated by other means, such as by utilizing residual heat from separation processes already incorporated into CSDRP. In particular, while the oil and chaser 210 (e.g., water) may be separated using gravity-based processes, the remaining solvent/oil mixture may be separated employing processes that involve heating the mixture. Some of this heat may be further employed to heat the chaser 210. In some embodiments, the chaser 210 may have a temperature anywhere between 10 and 300° C., or between 10 and 90° C. for water, when injected into the well. Alternatively, the chaser 210 may have a temperature between 20 and 250° C. above the ambient temperature of the reservoir, or more preferably about 60° C. above the ambient temperature of the reservoir.

One measure of efficiency in CSDRP is the ratio of produced oil volume to injected solvent volume over a time interval, or “oil to injected solvent ratio” (OISR). The time interval may be one complete injection/production cycle. The time interval may be from the beginning of first injection to the present or some other time interval. When the ratio falls below a certain threshold, further solvent composition injection may become uneconomic. OISR is only one measure of solvent efficiency, and those skilled in the art will recognize there are other measures of solvent recovery, such as solvent storage ratio (SSR), percentage loss, volume of unrecovered solvent per volume of recovered oil, or its inverse, the volume of produced oil to volume of lost solvent ratio (OLSR).

Simulations on an exemplary underground reservoir with horizontal wells of commercial scale (i.e., 1000 meters long at 100 meters well spacing) illustrate the benefits of the disclosed methods over conventional CSDRP. The parameters selected to model a reservoir in this study represent a typical heavy oil reservoir with the following properties:

• • Porosity ˜0.35
  • Gross thickness ˜30 m
  • Bitumen saturation ˜8 wt %
  • Initial temperature 16° C.
  • Initial pressure 3000 KPa
  • In-situ bitumen viscosity 200,000-1,000,000 cP

The simulations are intended as an example only, and the disclosed methods may be utilized with a variety of well configurations and sizes, such as different well lengths and spacings, different well layout and vertical separations, as well as different well orientations. In addition, this disclosure contemplates ratios between chaser and total injected volume that may remain constant or vary over cycles, or may range 1 and 80% over any cycle as discussed above.

Three models were simulated and compared. The first model (Case 1) was a CSDRP utilizing pure propane as the solvent composition for all cycles. In the second model (Case 2) was based on injecting water as chaser at the end of injection cycles, starting with cycle 3. The injected water volume was 20% of the total cycle injection volume. Finally, the third model (Case 3) was similar to the second but the water (i.e., chaser) content was increased from 20% of the total cycle injection volume in cycle 3 to 60% in cycle 7 (in 10% increments over each cycle).

FIG. 6 is a graph illustrating the solvent injection volume (in 10³ m³) for cycles 3 to 7 for each of the models. (Cycles 1 and 2 are not shown as they involve injecting pure solvent [propane] and are identical for the three models.) As can be observed in FIG. 6, the injected solvent volume decreases in Cases 2 and 3 compared to Case 1 over successive cycles. In particular, for Case 2 which involves a constant chaser/solvent ratio (1/4) for cycle 3 and beyond, the injected solvent volume remains 80% of the total volume injected for every cycle after cycle 2 in Case 1, while the amount of injected solvent in Case 3 progressively decreases starting at cycle 3 compared to Case 1 to reach 40% in cycle 7.

FIG. 7 is a graph illustrating the OISR for cycles 3 to 7 in each model. As shown in the graph, the OISR gradually decreases over time for Case 1, given that increasing solvent volumes are necessary to reach viscous oil in the formation as the oil is depleted and the solvent necessarily has to fill larger voidage to mix with the remaining oil. In contrast, Case 2 exhibits higher OISR over time compared to Case 1 because the injected solvent volume is necessarily lower. Notably, the decrease in OISR for Case 2 remains roughly proportionally constant compared to Case 1, suggesting that simply using a constant chaser/solvent ratio may prolong the economic viability of a CSDRP over time.

Even more advantageously, the OISR for Case 3 shown in FIG. 7 initially increased over cycles 3 to 5, and slightly dropped over cycles 6 and 7. The OISR in cycle 3 was the same for Cases 2 and 3, given that both began with a chaser amount of 20% of total injected volume in cycle 3. But as the ratio of chaser to total injected volume increased (from 20% to 60% over five cycles), it can be appreciated in FIG. 7 that the difference in OISR for Cases 2 and 3 continuously increased, suggesting that oil can be recovered with less and less solvent even as the formation gets depleted.

FIG. 8 plots the percentage of solvent that is recovered after each cycle for each model. The percentage for Case 1 slightly increases over time from 80% to about 84-85%. While solvent recovery is marginally lower for Case 2 (about 75% initially) it also increases over time to reach about 82-83% in cycle 7. Unlike Cases 1 and 2, however, Case 3 exhibits a slight decrease in solvent recovery in cycles 4 and 5, returning to roughly the same level in cycle 7 as in cycle 3. In other words, gradually increasing the chaser/solvent ratio as in Case 3 results in a remarkable improvement in OISR over CSDRP cycles while solvent recovery is minimally affected. While only 7-cycle results are presented here for illustration, the ultimate solvent recovery in all the cases after cycle 8 and blow-down reaches above 90%.

These advantages are further appreciated in FIG. 9, which shows that, even though the percentage of solvent recovery may be lower for Case 3 compared to Cases 1 and 2, the absolute amount of solvent lost is still lower for Case 3. In other words, progressively increasing the ratio of chaser to total injected volume over consecutive cycles may further result in overall reduced solvent use in CSDRP processes incorporating solvent chasing.

Given the lower operational costs expected from using inexpensive chasers instead of solvent composition to fill voidage in CSDRP cycles, the advantages of the methods disclosed herein are clearly demonstrated. Although not included in these simulations, the advantages over pure solvent composition CSDRP cycles may be expected to be more significant if the chaser is further heated before injection or hot disposal water from another source is used as chaser.

With reference to FIG. 10, a method for recovering hydrocarbons from an underground reservoir may comprise: (a) injecting a solvent composition into the reservoir at a pressure above a liquid/vapor phase change pressure of the solvent composition (302); (b) injecting a chaser into the reservoir at a pressure above the liquid/vapor phase change pressure of the solvent composition (304); (c) allowing the solvent composition to mix with the hydrocarbons and at least partially dissolve into the hydrocarbons to produce a solvent/hydrocarbon mixture (306); (d) reducing the pressure in the reservoir below the liquid/vapor phase change pressure of the solvent composition thereby flowing at last a fraction of the solvent/hydrocarbon mixture from the reservoir (308); and (e) repeating steps (a) to (d) as required (310). In some embodiments, step 310 may comprise increasing or decreasing the ratio of chaser volume injected in step 308 to the total injected volume of solvent composition and chaser injected in a given cycle. Reducing the pressure in step 308 may further result in flowing at least a portion of the chaser injected in step 304 from the reservoir thereby producing a recovered chaser. In yet other embodiments, step 310 may further include reusing at least a portion of recovered chaser as the chaser injected in step 304 when the process is repeated. Step 310 may be preceded by one or more cycles comprising steps 302, 306 and 308, and omitting step 304.

Additional Description

By way of example, the following clauses are offered as further description of the present disclosure:

Embodiment 1

A method for recovering hydrocarbons from an underground reservoir, the method comprising: (a) injecting a solvent composition into the reservoir at a pressure above a liquid/vapor phase change pressure of the solvent composition; (b) injecting a chaser into the reservoir at a pressure above the liquid/vapor phase change pressure of the solvent composition; (c) allowing the solvent composition to mix with the hydrocarbons and at least partially dissolve into the hydrocarbons to produce a solvent/hydrocarbon mixture; (d) reducing the pressure in the reservoir below the liquid/vapor phase change pressure of the solvent composition thereby flowing at last a fraction of the solvent/hydrocarbon mixture from the reservoir; and (e) repeating steps (a) to (d) as required.

Embodiment 2

The method of embodiment 1, wherein a ratio of the volume of the chaser injected in step (b) to the total injected volume of solvent composition and chaser injected in steps (a) and (b) is between 1% and 80%.

Embodiment 3

The method of embodiments 1 or 2, wherein step (e) comprises increasing or decreasing the ratio of the volume of the chaser injected in step (b) to the total injected volume of solvent composition and chaser injected in steps (a) and (b).

Embodiment 4

The method of any one of embodiments 1 to 3, wherein the chaser includes one of water, steam, methane, CO₂, N₂, flue gas or a combination of thereof.

Embodiment 5

The method of any one of embodiments 1 to 4, wherein at least a portion of the chaser is derived from at least one of:

(i) a steam-assisted gravity drainage (SAGD) process;

(ii) a solvent-assisted SAGD (SA-SAGD) process;

(iii) an expanding solvent SAGD (ES-SAGD) process;

(iv) cyclic steam stimulation (CSS); and

(v) cyclic solvent processes (CSP).

Embodiment 6

The method of any one of embodiments 1 to 5, wherein reducing the pressure in step (d) further results in flowing at least a portion of the volume of the chaser injected in step (b) from the reservoir thereby producing a recovered chaser.

Embodiment 7

The method of embodiment 6, wherein step (e) further includes reusing at least a portion of the recovered chaser as the chaser when step (b) is repeated.

Embodiment 8

The method of any one of embodiments 1 to 7, wherein the chaser is injected into the reservoir in step (b) at a temperature higher than the initial temperature of the reservoir.

Embodiment 9

The method of any one of embodiments 1 to 8, wherein the chaser is injected into the reservoir in step (b) at a temperature between 10 and 90° C.

Embodiment 10

The method of any one of embodiments 1 to 8, wherein the chaser is injected into the reservoir in step (b) at a temperature between 10 and 300° C.

Embodiment 11

The method of any one of claims 1 to 10, wherein the repeating step (e) is preceded by one or more cycles comprising steps (a), (c) and (d), and omitting step (b).

Embodiment 12

The method of any one of the embodiments 1 to 11, wherein the chaser is injected at a pressure between 1,000 and 10,000 kPa.

Embodiment 13

The method of any one of embodiments 1 to 12, wherein the density of the chaser is greater than the density of the solvent composition at reservoir conditions.

Embodiment 14

The method of any one of embodiments 1 to 13, wherein the density of the chaser is more than 10% greater than the density of the solvent composition at reservoir conditions.

Embodiment 15

The method of any one of embodiments 1 to 14, wherein step (e) comprises reducing an average molecular weight of the solvent composition by at least 10%.

Embodiment 16

The method of any one of embodiments 1 to 15, wherein the solvent composition comprises at least 5 mol % of an aromatic species, based upon total moles of the solvent composition.

Embodiment 17

The method of any one of the embodiments 1 to 17, wherein the solvent composition comprises a first component and a second component that have at least 200 kPa difference in their vaporization pressure at the temperature of the reservoir.

Embodiment 18

The method of embodiment 17, wherein the second component comprises at least 10 mol % methane, based on total moles of the solvent composition.

Embodiment 19

The method of embodiment 17, wherein the second component has an average molecular weight of less than 33 g/mol.

Embodiment 20

The method of any one of embodiments 17 to 19, wherein the first component comprises greater than 50 mol % ethane, propane, butane, pentane, heptane, hexane, dimethyl ether, or a combination thereof, based upon total moles of the first component.

Embodiment 21

The method of any one of embodiments 17 to 19, wherein the first component comprises between 5 mol % and 30 mol % of hydrocarbons with a molecular weight of at least 58 g/mol, based upon total moles of the first component.

Embodiment 22

The method of any one of embodiments 17 to 19, wherein the first component comprises at least 50 mol % diluent, based upon total moles of the first component.

Embodiment 23

The method of any one of embodiments 17 to 22, wherein the second component comprises greater than 50 mol % methane, ethane, carbon dioxide, or a combination thereof, based upon total moles of the second component.

Embodiment 24

The method of any one of embodiments 17 to 19, wherein the first component comprises:

(i) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and

(ii) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane;

wherein the first component has a Hansen hydrogen bonding parameter of 0.3 to 1.7; and wherein the first component has a volume ratio of the polar component to the non-polar component of 10:90 to 50:50.

Embodiment 25

The method of embodiment 24, wherein the polar component is a ketone or acetone.

Embodiment 26

The method of embodiment 24, wherein the non-polar component is a C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics.

Embodiment 27

The method of any of the embodiments 17 to 19, wherein the first component comprises:

(i) an ether with 2 to 8 carbon atoms; and

(ii) a non-polar hydrocarbon with 2 to 30 carbon atoms.

Embodiment 28

The method of embodiment 27, wherein the ether is di-methyl ether, methyl ethyl ether, di-ethyl ether, methyl iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether, methyl iso-butyl ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-propyl butyl ether, propyl butyl ether, di-isobutyl ether, or di-butyl ether.

Embodiment 29

The method of any one of embodiments 27 or 28, wherein the non-polar hydrocarbon is a C2-C30 alkane, a C2-C5 alkane, or propane.

Embodiment 30

The method of any one of embodiments 1 to 29, wherein injection in steps (a) and (b) and production of the at least a fraction of solvent/hydrocarbon mixture in step (d) are through a common wellbore.

Advantages of the methods disclosed herein over conventional CSDRP include an increase of solvent utilization and efficiency; reduction of solvent demand and storage, leading to simpler commercial solvent supply logistics and lower operational costs; potential integration with existing CSS operations to reduce CSS costs on disposal water and improve CSDRP performance by utilizing the residual heat of CSS disposal water; and better solvent allocation for faster ramp up of bitumen rate in commercial applications with solvent supply constraints.

Disclosed aspects of the present disclosure may include any combinations of the methods and systems shown in the preceding numbered paragraphs. This is not to be considered a complete listing of all possible aspects, as any number of variations can be envisioned from the description above. It should be understood that the numerous changes, modifications, and alternatives to the preceding disclosure can be made without departing from the scope of the disclosure. The preceding description, therefore, is not meant to limit the scope of the disclosure. Rather, the scope of the disclosure is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.

Claims

1. A method for recovering hydrocarbons from an underground reservoir, the method comprising: (a) injecting a solvent into the reservoir at a pressure above a liquid/vapor phase change pressure of the solvent;(b) injecting a chaser into the reservoir at a pressure above the liquid/vapor phase change pressure of the solvent;(c) allowing the solvent to mix with the hydrocarbons and at least partially dissolve into the hydrocarbons to produce a solvent/hydrocarbon mixture;(d) reducing the pressure in the reservoir below the liquid/vapor phase change pressure of the solvent thereby flowing at last a fraction of the solvent/hydrocarbon mixture from the reservoir; and(e) repeating steps (a) to (d), wherein the composition of the solvent in the repeated steps (a)-(d) is a first solvent composition which is the same as the composition of the solvent in the initial steps (a)-(d), or the composition of the solvent in the repeated steps (a)-(d) is a second solvent further comprising a diluent and has a different composition than the solvent in the initial steps (a)-(d);wherein the entire injection of the solvent and chaser in steps (a) and (b) and the entire production of the solvent/hydrocarbon mixture in step (d) are through a common wellbore; andwherein the volume of chaser in step (b) is between 1% and 10% of the total injected fluid by volume of the combined solvent and chaser, and the volume of the chaser as a percentage of the total injected fluid by volume of the combined solvent and chaser is increased in multiple repeated cycles of step (e) to a maximum of 80% of the total injected fluid by volume.

2. The method of claim 1, wherein the chaser displaces the solvent within the underground reservoir and reduces the amount of total solvent used in a cycle that is required to restore or maintain the pressure of the underground reservoir.

3. The method of claim 2, wherein the chaser is utilized to push the solvent further into the underground reservoir to improve the mixing of the solvent with the hydrocarbons in the underground reservoir.

4. The method of claim 1, wherein the chaser includes one of water, steam, CO2, N2, flue gas or a combination of thereof.

5. The method of claim 4, wherein at least a portion of the chaser is derived from at least one of: (i) a steam-assisted gravity drainage (SAGD) process;(ii) a solvent-assisted SAGD (SA-SAGD) process;(iii) an expanding solvent SAGD (ES-SAGD) process;(iv) cyclic steam stimulation (CSS); and(v) cyclic solvent processes (CSP).

6. The method of claim 1, wherein reducing the pressure in step (d) further results in flowing at least a portion of the volume of the chaser injected in step (b) from the reservoir thereby producing a recovered chaser.

7. The method of claim 6, wherein step (e) further includes reusing at least a portion of the recovered chaser as the chaser when step (b) is repeated.

8. The method of claim 1, wherein the chaser is injected into the reservoir in step (b) at a temperature higher than the initial temperature of the reservoir.

9. The method of claim 1, wherein the chaser is injected into the reservoir in step (b) at a temperature between 10 and 90° C.

10. The method of claim 1, wherein the repeating step (e) is preceded by one or more cycles comprising steps (a), (c) and (d), and omitting step (b).

11. The method of claim 1, wherein the density of the chaser is more than 10% greater than the density of the solvent at reservoir conditions.

12. The method of claim 1, wherein step (e) comprises the second solvent wherein an average molecular weight of the second solvent is at least 10% lower than average molecular weight of the first solvent.

13. The method of claim 1, wherein the solvent comprises at least 5 mol % of an aromatic species, based upon total moles of the solvent.

14. The method of claim 1, wherein the solvent comprises a first component and a second component that have at least 200 kPa difference in their vaporization pressure at the temperature of the reservoir.

15. The method of claim 14, wherein the second component comprises at least 10 mol % methane, based on total moles of the solvent.

16. The method of claim 14, wherein the second component has an average molecular weight of less than 33 g/mol.

17. The method of claim 14, wherein the first component comprises between 5 mol % and 30 mol % of hydrocarbons with a molecular weight of at least 58 g/mol, based upon total moles of the first component.

18. The method of claim 17, wherein the second component comprises greater than 50 mol % methane, ethane, carbon dioxide, or a combination thereof, based upon total moles of the second component.

19. The method of claim 14, wherein the first component comprises: (i) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and(ii) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane;wherein the first component has a Hansen hydrogen bonding parameter of 0.3 to 1.7; and wherein the first component has a volume ratio of the polar component to the non-polar component of 10:90 to 50:50.

20. The method of claim 19, wherein the polar component is a ketone or acetone.

21. The method of claim 19, wherein the non-polar component is a C2-C7 alkane or a gas plant condensate comprising alkanes, naphthenes, and aromatics.

22. The method of claim 14, wherein the first component comprises: (i) an ether with 2 to 8 carbon atoms; and(ii) a non-polar hydrocarbon with 2 to 30 carbon atoms.

23. The method of claim 22, wherein the non-polar hydrocarbon is a C2-C5 alkane.