CA3036171C

CA3036171C - Optimization of cyclic solvent processes

Info

Publication number: CA3036171C
Application number: CA3036171A
Authority: CA
Inventors: Cory Silva; Chen Fang; Jianlin Wang
Original assignee: Imperial Oil Resources Ltd; ExxonMobil Upstream Research Co
Current assignee: Imperial Oil Resources Ltd; ExxonMobil Upstream Research Co
Priority date: 2019-03-08
Filing date: 2019-03-08
Publication date: 2020-05-26
Anticipated expiration: 2039-03-08
Also published as: CA3036171A1

Abstract

Methods of recovering bitumen from an underground reservoir are described herein. The methods include injecting a first mobilizing fluid into the underground reservoir through a first well, producing a first produced fluid from the underground reservoir through the first well, the first produced fluid including bitumen and at least a portion of the first mobilizing fluid injected into the underground reservoir, mixing at least a portion of the first produced fluid with a make-up fluid to form a second mobilizing fluid, injecting the second mobilizing fluid into the underground reservoir through a second well and producing a second produced fluid from the underground reservoir through the second well, the second produced fluid including bitumen and at least a portion of the second mobilizing fluid injected into the underground reservoir.

Description

OPTIMIZATION OF CYCLIC SOLVENT PROCESSES
Technical Field [0001] The present disclosure relates generally to methods of recovering hydrocarbons, and more specifically to methods of optimizing cyclic solvent processes for recovering bitumen and heavy oil from underground reservoirs.
Background

[0002] 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.

[0003] A cyclic solvent process (CSP) is an in-situ bitumen and heavy oil recovery process that consists of alternating cycles of solvent injection and solvent/bitumen mixture production through the same horizontal well. The solvent, injected in the liquid state, fingers into the bitumen and mixes with it, reducing its viscosity to provide for the bitumen to be extracted from the reservoir.

[0004] Generally, in CSPs, cycles grow progressively in length and volume as the reservoir becomes depleted. In later cycles, larger volumes of solvent must be injected to fill the voidage created by bitumen and water production and to re-pressurize the formation.

[0005] After production begins, the early-stage produced fluid is the uncontacted, mostly-pure solvent. Generally, the produced fluid is sent through a separation facility where the solvent is separated from the bitumen using single or multi-stage separator processes. However, separating the solvent from the small amount of bitumen in the produced fluid is generally not a very efficient process, and thus it drastically increases energy use in the form of compression and pumping costs for the facility and requires larger separator equipment sizes to accommodate the larger throughput.

[0006] Accordingly, there is a need for improved methods optimizing solvent use in CSPs.

Summary

[0007] The present disclosure provides methods of recovering bitumen from a reservoir. In some embodiments, the methods include injecting a first mobilizing fluid into the underground reservoir through a first well, the first mobilizing fluid having a pressure that is above a liquid/vapor phase change pressure of the first mobilizing fluid; producing a first produced fluid from the underground reservoir through the first well, the first produced fluid including bitumen and at least a portion of the first mobilizing fluid injected into the underground reservoir; mixing at least a portion of the first produced fluid with a make-up fluid to form a second mobilizing fluid; injecting the second mobilizing fluid into the underground reservoir through a second well, the second mobilizing fluid having a pressure that is above a liquid/vapor phase change pressure of the second mobilizing fluid; and producing a second produced fluid from the underground reservoir through the second well, the second produced fluid including bitumen and at least a portion of the second mobilizing fluid injected into the underground reservoir.

[0008] In some embodiments, the first mobilizing fluid has a temperature in a range of about 10 C to about 90 C.

[0009] In some embodiments, the make-up fluid has a temperature in a range of about 10 C to about 90 C.

[0010] In some embodiments, the first mobilizing fluid comprises propane.

[0011] In some embodiments, the first mobilizing fluid is propane.

[0012] In some embodiments, the first mobilizing fluid comprises propane and dimethyl ether (DME).

[0013] In some embodiments, the first mobilizing fluid comprises natural gas liquid (NGL).

[0014] In some embodiments, the first mobilizing fluid comprises liquefied petroleum gas (LPG).

[0015] In some embodiments, the first mobilizing fluid comprises light catalytic gas oil.

, = , ,

[0016] In some embodiments, the first mobilizing fluid comprises propane and a non-condensable gas (NCG) such as Cl, CO2, flue gas, or a combination of thereof.

[0017] In some embodiments, the make-up fluid comprises DME.

[0018] In some embodiments, the make-up fluid is DME.

[0019] In some embodiments, the make-up fluid comprises propane.

[0020] In some embodiments, the make-up fluid is propane.

[0021] In some embodiments, the make-up fluid comprises propane and dimethyl ether (DME).

[0022] In some embodiments, the make-up fluid comprises natural gas liquid (NGL).

[0023] In some embodiments, the make-up fluid comprises liquefied petroleum gas (LPG).

[0024] In some embodiments, the make-up fluid comprises light catalytic gas oil.

[0025] In some embodiments, the first mobilizing fluid and the make-up fluid are different fluids.

[0026] In some embodiments, the second mobilizing fluid is injected into the underground reservoir through the first well.

[0027] In some embodiments, the second mobilizing fluid is injected into the underground reservoir through the second well.

[0028] In some embodiments, the first well and the second well are located on a same pad.

[0029] In some embodiments, the first well and the second well are located on different pads.

[0030] In some embodiments, the first produced fluid has a concentration of the first mobilizing fluid of at least 60 vol%.

[0031] In some embodiments, the first produced fluid has a concentration of the first mobilizing fluid of at least 70 vol%.

: = , ,

[0032] In some embodiments, the first produced fluid has a concentration of the first mobilizing fluid of at least 80 vol%.

[0033] In some embodiments, the first produced fluid has a concentration of the first mobilizing fluid of at least 90 vol%.

[0034] In some embodiments, the method further comprises mixing at least a portion of the second produced fluid with a second make-up fluid to form a third mobilizing fluid, injecting the third mobilizing fluid into the underground reservoir through a third well, the third mobilizing fluid having a pressure that is above a liquid/vapor phase change pressure of the third mobilizing fluid, and producing a third produced fluid from the underground reservoir through the third well, the third produced fluid including bitumen and at least a portion of the third mobilizing fluid injected into the underground reservoir.

[0035] In some embodiments, the second well and the third well are different wells.

[0036] In some embodiments, the second well and the third well are located on a same pad.

[0037] In some embodiments, producing the first produced fluid from the underground reservoir includes collecting the produced fluid directly from the first well and directing at least a portion of the first produced fluid around separation units of a surface facility, the separation units used to separate the bitumen and the at least a portion of the first mobilizing fluid of the first produced fluid.

[0038] In some embodiments, the at least a portion of the first produced fluid that is directed around the separation units of the surface facility is compositionally unprocessed.

[0039] In some embodiments, mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than about 30 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

[0040] In some embodiments, mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than about 40 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

[0041] In some embodiments, mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than about 50 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

[0042] In some embodiments, mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than about the first 30 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

[0043] In some embodiments, mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than about the first 40 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

[0044] In some embodiments, mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than about the first 50 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

[0045] In some embodiments, prior to injecting the first mobilizing fluid into the underground reservoir through the first well, the first well has been used to perform at least one cycle of a cyclic solvent process of recovering bitumen from the underground reservoir, each cycle including: injecting a mobilizing fluid into the underground reservoir through the first well; and producing a produced fluid from the underground reservoir through the first well, the produced fluid including bitumen and at least a portion of the mobilizing fluid injected into the underground reservoir.

[0046] In some embodiments, the first well has been used to perform at least two cycles of a cyclic solvent process of recovering bitumen from the underground reservoir.

[0047] In some embodiments, the first well has been used to perform at least three cycles of a cyclic solvent process of recovering bitumen from the underground reservoir.

= L

[0048] 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.

[0049] These and other features and advantages of the present application will become apparent from the following detailed description taken together with the accompanying drawings. However, it should be understood that the detailed description and the specific examples, while indicating preferred embodiments of the application, are given by way of illustration only, since various changes and modifications within the spirit and scope of the application will become apparent to those skilled in the art from this detailed description.
Brief Description of the Drawings

[0050] For a better understanding of the various embodiments described herein, and to show more clearly how these various embodiments may be carried into effect, reference will be made, by way of example, to the accompanying drawings which show at least one example embodiment, and which are now described. The drawings are not intended to limit the scope of the teachings described herein.

[0051] FIG. 1 is a schematic axial cross-section of a horizontal wellbore undergoing a typical CSP showing solvent fingers extending from the wellbore into the reservoir during early-stage cycles;

[0052] FIG. 2 is schematic axial cross-section of a horizontal wellbore undergoing a typical CSP showing solvent fingers extending from the wellbore into the reservoir during mid-stage cycles;

[0053] FIG. 3 is a graph showing production rate over time of solvent and bitumen in typical CSPs;

[0054] FIG. 4 is a schematic diagram of a typical bitumen production and separation facility;

[0055] FIG. 5 is a graph showing rates of solvent recycling over time for CSPs;

[0056]
FIG. 6 is a schematic diagram showing a modified CSP according to one embodiment where a make-up solvent is added to a produced fluid to be reinjected into a wellbore;

[0057]
FIG. 7 is a graph showing a production profile for solvent cut as a function of hydrocarbons produced per cycle; and

[0058]
FIG. 8 is a block diagram of a method of recovering bitumen from an underground reservoir penetrated by at least one well.

[0059]
The skilled person in the art will understand that the drawings, further described below, are for illustration purposes only. The drawings are not intended to limit the scope of the applicant's teachings in any way. Also, it will be appreciated that for simplicity and clarity of illustration, elements shown in the figures have not necessarily been drawn to scale. For example, the dimensions of some of the elements may be exaggerated relative to other elements for clarity. Further aspects and features of the example embodiments described herein will appear from the following description taken together with the accompanying drawings.
Detailed Description

[0060]
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.

[0061]
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, L
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.

[0062] 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."

[0063] 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.

[0064] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a range from 1 to 9.

[0065] "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.

[0066] 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.

[0067] "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.

[0068] 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.

[0069] 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.

[0070] 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.

, .
,

[0071] 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."

[0072] The term "cyclic process" refers to an oil recovery technique in which the injection of a viscosity reducing agent into a wellbore to stimulate displacement of the oil alternates with oil production from the same wellbore and the injection-production process is repeated at least once. Cyclic processes for heavy oil recovery may include a cyclic steam stimulation (CSS) process, a liquid addition to steam for enhancing recovery (LASER) process, a cyclic solvent process (CSP), or any combination thereof.

[0073] 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.

[0074] "Facility" or "surface facility" is one or more tangible pieces 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, processing plants, and delivery outlets. In some instances, the term "surface facility"
is used to distinguish from those facilities other than wells.

[0075] 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.

[0076] 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 I = I
k 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.

[0077] "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.

[0078] 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.

[0079] 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, = I
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.

[0080] In spite of the technologies that have been developed, there remains a need in the field for methods of optimizing cyclic solvent processes (CSPs).

[0081] Herein, methods of optimizing the solvent use in the CSPs are described.
The methods include recycling a produced fluid within a process facility, particularly when the produced fluid has a high solvent concentration such as when produced during early-cycle production. In some embodiments, the methods include a repressurization and mixing of the produced fluid with a make-up solvent prior to reinjection into neighboring wells to begin an injection period therein.

[0082] Figure 1 shows a schematic axial cross-section of a system 100 including a horizontal wellbore 102 provided in a formation or reservoir 104. A mobilizing fluid such as but not limited to a solvent or a mixture of solvents is generally pumped down from a surface through overburden 106 and along the wellbore 102 where it passes into the formation 104 via, for example, one of a number of apertures provided in a wellbore casing of the wellbore 102.

[0083] In the aforementioned CSPs, solvents may be used to enhance the extraction of petroleum products from the reservoir 104. In some embodiments, the solvent used in the CSPs may be a light hydrocarbon, a mixture of light hydrocarbons or dimethyl ether. In other embodiments, the solvent 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.

[0084] In other embodiments, the solvent may be a light, but condensable, hydrocarbon or mixture of hydrocarbons comprising ethane, propane, butane, or pentane.

I = I
k The solvent may comprise at least one of ethane, propane, butane, pentane, and carbon dioxide. The solvent may comprise greater than 50% C2-05 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.

[0085]
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.

[0086]
To reach a desired injection pressure of the solvent composition, a viscosifier 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.

[0087]
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.

[0088]
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 05 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.

[0089]
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). 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).

[0090]
As the mobilizing fluid is injected, the mobilizing fluid passes into the formation 104 and reduces the viscosity of the petroleum products therein and allows them to flow towards the wellbore 102, where it passes into the wellbore 102 via one of a number of apertures provided in the wellbore casing (not shown).

[0091]
In some embodiments, during early-stage cycles, after injection of a mobilizing fluid through the wellbore 102, the mobilizing fluid forms "fingers" such as the fingers 108 shown in Figure 1 extending from the wellbore 102 into the reservoir 104;

[0092]
In some embodiments, in later injection cycles, larger volumes of mobilizing fluid need to be injected into wellbore 102 to extract bitumen and/or petroleum products therefrom. Figure 2 is schematic axial cross-section of horizontal wellbore 102 during a later cycle of a CSP, showing solvent fingers 108 extending from the wellbore 102 into the reservoir 104. In this embodiment, a region 110 of mobilizing fluid generally forms . . .
around the wellbore 102. Mobilizing fluid present in the region 110 generally does not interact with the bitumen and/or petroleum products present in the reservoir 104 and therefore, this portion of the injected solvent is not efficiently utilized for extracting bitumen from the reservoir. Accordingly, upon extraction of a produced fluid from the wellbore 102, the produced fluid in these later injection cycles of CSP process generally has a high concentration of mobilizing fluid.

[0093] Referring now to Figure 3, illustrated therein is a graph 300 showing typical production rate curves of mobilizing fluid 302 and bitumen 304 over time in the life cycle of a well utilizing a typical CSP. The life cycle of a well is utilizing a typical CSP is generally in the range of 5-10 years. Region 306 shows an optimum time frame in the early life cycle (e.g. first 0-2 years) for recycling mobilizing fluid produced from a CSP as it indicates the period of time where the production rate of mobilizing fluid from the reservoir is greatest.

[0094] Referring now to Figure 4, illustrated therein is a schematic diagram of a layout of a facility 400 for for recovering fluid from an underground reservoir and separating it into bitumen and a mobilizing fluid, according to one embodiment. Facility 400 includes a CSP pad 402 that includes one or more wellbores (such as wellbore 102), surface facilities 404 and a production pipeline 406. In some embodiments, CSP
pad 402 includes about 24 wells. In other embodiments, CSP pad 402 includes about 28 wells.

[0095] CSP pad 402 is used to perform cyclic injection and production operations to recover bitumen from an underground reservoir. In the embodiment shown in Figure 4, during injection cycles, mobilizing fluid stored in a unit of the surface facilities 404 (e.g.
storage unit 408) is injected through a wellhead and into the underground reservoir via a wellbore. In some embodiments, a flow assurance solvent stored in the surface facilities 404 may also be injected with the mobilizing fluid into the underground reservoir.

[0096] In the embodiment shown in Figure 4, during production cycles, a produced fluid is recovered from the underground reservoir via a wellbore of wellbore CSP pad 402.
The produced fluid generally includes hydrocarbons such as but not limited to bitumen and the mobilizing fluid. The hydrocarbons recovered from the underground reservoir are generally processed in one or more units in the surface facilities 404 to separate the injected mobilizing fluid from the bitumen.

[0097] Herein, the surface facilities 404 includes a collection of mobilizing fluid processing units 404a and associated pipeline that carries the mobilizing fluid and/or the flow assurance solvent to the CSP pad 402 to be injected into the underground reservoir.
Surface facilities 404 also includes a collection of produced fluid processing units 404b used to process the produced fluid from the underground reservoir and associated pipeline that carries the produced fluid from the CSP pad 402 towards the production pipeline 406.

[0098] In the embodiment shown in Figure 4, mobilizing fluid processing units 404a include but are not limited to storage unit(s) 408, a mobilizing fluid pump and/or compressor 409 and an injection heater 411. In other embodiments, the mobilizing fluid processing units 404a may also include a makeup pump/compressor (not shown).

[0099] In the embodiment shown in Figure 4, produced fluid processing units 404b include but are not limited to a casing gas compressor 410, a production heater 412, a separator 414, a mobilizing fluid compressor 415, a mobilizing fluid condenser 416 and a bitumen product pump 417.

[0100] Production pipeline 406 generally refers to a pipeline for carrying bitumen to a bitumen processing plant for further processing.

[0101] Facility 400 also includes an unprocessed recycle stream 418.
Herein, "unprocessed" refers to the notion that recycle stream 418 has not been seprated into individual compositional components such as may occur in separator 414 as shown in Figure 4. Recycle stream 418 generally connects the produced fluid processing units 404b and the mobilizing fluid processing units 404a to provide for at least a portion of the produced fluid recovered from a wellbore of the CSP pad 402 to bypass any separation and processing and be recycled to the mobilizing fluid processing units 404a to be, subsequently, reinjected into a wellbore of the CSP pad 402. In some embodiments, the portion of the produced fluid that is recycled through the recycle stream 418 to the mobilizing fluid processing units 404a can be reinjected into the same wellbore of the CSP pad 402 as it was originally produced. In some embodiments, the portion of the produced fluid that is recycled through the recycle stream 418 to the mobilizing fluid processing units 404a can be reinjected into a different wellbore of the CSP
pad 402 from that which it was originally injected. In other embodiments, the portion of the produced fluid that is recycled through the recycle stream 418 to the mobilizing fluid processing units 404a can be reinjected into a different pad than CSP pad 402 (separate pad not shown in figure).

[0102] Specifically, as shown in Figure 4, recycle stream 418 directs at least a portion of the produced fluid received by the produced fluid processing units 404b from the CSP pad 402 to the mobilizing fluid processing units 404a upstream (i.e.
prior to) the produced fluid being separated into a mobilizing fluid and bitumen by separator 414. For instance, the recycle stream 418 can intersect a pipeline positioned between an outlet from the CSP pad 402 and an inlet to the separator 414. In this manner, in the embodiments described herein, separator 414 may be sized to only separate a portion of the produced fluid received by the produced fluid processing units 404b from the CSP
pad 402. An example of this reduced capacity of the separator 414 is shown in Figure 5, which shows an exemplary graph 500 of solvent produced and recycled over time for a CSP. As shown therein, the solvent separation and compression capacity of facility 400 could be reduced from a peak capacity shown by line 502 to a reduced capacity shown by line 504 when a recycle stream such as recycle stream 418 shown in Figure 4 redirects at least a portion of the produced fluid received by the produced fluid processing units 404b from the CSP pad 402 to the mobilizing fluid processing units 404a upstream of the separator 414.

[0103] In some embodiments, recycle stream 418 directs at least a portion of the produced fluid received by the produced fluid processing units 404b from the CSP pad 402 to a position within the mobilizing fluid processing units 404a upstream of an inlet to the CSP pad 402. In some embodiments, recycle stream 418 directs at least a portion of the produced fluid received by the produced fluid processing units 404b from the CSP
pad 402 to a position within the mobilizing fluid processing units 404a downstream of an outlet of the storage unit(s) 408.

[0104] Turning now to Figure 6, illustrated therein is a schematic diagram of a system 600 of using a first produced fluid 603 from a first wellbore 602 of a pad 601 operated under a CSP, according to one embodiment. In the system 600, the produced fluid 603 is combined with a first make-up fluid 604 to form a second mobilizing fluid 605 that is injected into a second wellbore 606 of the pad 601 operated under a CSP. The first produced fluid 603 comprises bitumen and at least a portion of a first mobilizing fluid injected into the first wellbore 602. In the embodiment shown, a second produced fluid 607 is produced from the second wellbore 606 and is mixed with a second make-up fluid 608 to form a third mobilizing fluid 609 that is injected into a third wellbore 610 of the pad 601 operated under a CSP.

[0105] It should be noted that in some embodiments, first wellbore 602 and second wellbore 606 can be a same wellbore or can be different wellbores. Further, in some embodiments, second wellbore 606 and third wellbore 610 can be the same wellbore or can be different wellbores. Further still, in some embodiments, the first wellbore 602 and the third wellbore 610 can be a same wellbore or different wellbores. First, second and third wellbores 602, 606 and 610 respectively, can be located on a same pad (e.g. pad 601) or can be located on separate pads, provided that the wells share processing facilities.

[0106] It should be noted that first and second produced fluids 603 and 607, respectively, can be produced during early production cycles, where herein "early production cycles" refers to the first two cycles of the CSP, or during later production cycles, where herein "later production cycles" refers to a third cycle or greater of the CSP.
In some embodiments, the use of the first and second produced fluids 603 and 607, respectively, may be more feasible during later production cycles, after the near-wellbore bitumen has been depleted. Generally, later production cycles of a CSP produce mostly-pure (e.g. >90% by volume) mobilizing fluid (e.g. solvent) for extended periods of time, as shown in Figure 7 where line 702 represents a first CSP cycle, line 704 represents a second CSP cycle, line 706 represents a third CSP cycle and line 708 represents a fourth CSP cycle for a single well. These curves show that the well experiences an increase in recovered solvent as the well goes through additional CSP cycles.

[0107] The first mobilizing fluid injected into the first wellbore 602 may have a temperature in a range of about 30 C to about 90 C and the first make-up fluid 604 may also have a temperature in a range of about 30 C to about 90 C. The first mobilizing fluid may be propane or may comprise propane. The first mobilizing fluid may also comprise dimethyl ether (DME). The first make-up fluid 604 may be or may comprise DME. The second make-up fluid 608 may also have a temperature in a range of about 30 C to about 90 C and may be or may comprise DME. The second make-up fluid 608 may be the same fluid as the first make-up fluid 604 or may be a different fluid.

[0108] In some embodiments, the first produced fluid 603 may have a concentration of the first mobilizing fluid of at least 60 vol%. In some embodiments, the first produced fluid 603 may have a concentration of the first mobilizing fluid of at least 70 vol%. In some embodiments, the first produced fluid 603 may have a concentration of the first mobilizing fluid of at least 80 vol%. In some embodiments, the first produced fluid 603 may have a concentration of the first mobilizing fluid of at least 90 vol%.

[0109] In some embodiments, the second mobilizing fluid 605 may include less than about 30 vol%, less than about 40 vol% or less than about 50 vol% of the first produced fluid 603 produced during that cycle. In some embodiments, the second mobilizing fluid 605 may include less than about 30 vol%, less than about 40 vol% or less than about 50 vol% of the first produced fluid 603 produced during that cycle.

[0110] Similarly, in some embodiments, the third mobilizing fluid 609 may only include about the first 40 vol% of the second produced fluid 607 produced during that cycle.

[0111] In some embodiments, prior to injecting the first mobilizing fluid into the underground reservoir through the first well 602, the first well 602 may be used to perform at least one cyclic solvent process of recovering bitumen from the underground reservoir.
Each cyclic solvent process for bitumen recovery includes injecting a mobilizing fluid into the underground reservoir through the first well 602 and producing a produced fluid from the underground reservoir through the first well 602, the produced fluid including bitumen and at least a portion of the mobilizing fluid injected into the underground reservoir.

,

[0112] In some embodiments, prior to injecting the first mobilizing fluid into the underground reservoir through the first well 602, the first well 602 may be used to perform two cyclic solvent processes of recovering bitumen from the underground reservoir.

[0113] In some embodiments, prior to injecting the first mobilizing fluid into the underground reservoir through the first well 602, the first well 602 may be used to perform three cyclic solvent processes of recovering bitumen from the underground reservoir.

[0114] Figure 8 is a block diagram of a method 800 of recovering bitumen from an underground reservoir penetrated by at least one well. Method 800 includes a step 802 of injecting a first mobilizing fluid into the underground reservoir through a first well. The first mobilizing fluid has a pressure that is above a liquid/vapor phase change pressure of the first mobilizing fluid.

[0115] Method 800 also includes a step 804 of producing a first produced fluid from the underground reservoir through the first well. The first produced fluid includes bitumen and at least a portion of the first mobilizing fluid injected into the underground reservoir.
In some embodiments, at least a portion of the first produced fluid from the underground reservoir is

[0116] Method 800 also includes a step 806 of mixing at least a portion of the first produced fluid with a make-up fluid to form a second mobilizing fluid. In some embodiments, the portion of the produced fluid that is mixed with the make-up fluid is un-separated (i.e. bypasses a separator of surface facility units) when it is mixed with the make-up fluid. In this manner, the portion of the produced fluid may also be referred to as being compositionally unprocessed after it is produced from the underground reservoir when it is mixed with the make-up fluid.

[0117] Method 800 also includes a step 808 of injecting the second mobilizing fluid into the underground reservoir through a second well. The second mobilizing fluid has a pressure that is above a liquid/vapor phase change pressure of the second mobilizing fluid.

[0118] Method 800 also includes a step 810 of producing a second produced fluid from the underground reservoir through the second well. The second produced fluid -includes bitumen and at least a portion of the second mobilizing fluid injected into the underground reservoir.

[0119] While the applicant's teachings described herein are in conjunction with various embodiments for illustrative purposes, it is not intended that the applicant's teachings be limited to such embodiments as the embodiments described herein are intended to be examples. On the contrary, the applicant's teachings described and illustrated herein encompass various alternatives, modifications, and equivalents, without departing from the embodiments described herein, the general scope of which is defined in the appended claims.

Claims

Claims What is claimed is:

1. A method of recovering bitumen from an underground reservoir penetrated by at least two wells, the method comprising:
injecting a first mobilizing fluid into the underground reservoir through a first well, the first mobilizing fluid being injected into the reservoir at a pressure that is above a liquid/vapor phase change pressure of the first mobilizing fluid;
producing a first produced fluid from the underground reservoir through the first well, the first produced fluid including bitumen and at least a portion of the first mobilizing fluid injected into the underground reservoir;
mixing at least a portion of the first produced fluid with a make-up fluid to form a second mobilizing fluid;
injecting the second mobilizing fluid into the underground reservoir through the first well or a second well, the second mobilizing fluid being injected into the reservoir at a pressure that is above a liquid/vapor phase change pressure of the second mobilizing fluid; and producing a second produced fluid from the underground reservoir through the second well, the second produced fluid including bitumen and at least a portion of the second mobilizing fluid injected into the underground reservoir.

2. The method of claim 1, wherein the first mobilizing fluid has a temperature in a range of 10 °C to 90 °C.

3. The method of claim 1 or claim 2, wherein the make-up fluid has a temperature in a range of 10 °C to 90 °C.

4. The method of any one of claims 1 to 3, wherein the first mobilizing fluid comprises propane.

5. The method of any one of claims 1 to 3, wherein the first mobilizing fluid is propane.

6. The method of any one of claims 1 to 4, wherein the first mobilizing fluid comprises propane and dimethyl ether (DME).

7. The method of any one of claims 1 to 3, wherein the first mobilizing fluid comprises natural gas liquid (NGL).

8. The method of any one of claims 1 to 3, wherein the first mobilizing fluid comprises liquefied petroleum gas (LPG).

9. The method of any one of claims 1 to 3, wherein the first mobilizing fluid comprises light catalytic gas oil.

10. The method of any one of claims 1 to 9, wherein the first mobilizing fluid comprises propane and a non-condensable gas (NCG) selected from C1, CO2, flue gas, and a combination thereof.

11. The method of any one of claims 1 to 10, wherein the make-up fluid comprises DME.

12. The method of claim 10, wherein the make-up fluid is DME.

13. The method of any one of claims 1 to 11, wherein the make-up fluid comprises propane.

14. The method of any one of claims 1 to 10, wherein the make-up fluid is propane.

15. The method of any one of claims 1 to 10, wherein the make-up fluid comprises propane and dimethyl ether (DME).

16. The method of any one of claims 1 to 10, wherein the make-up fluid comprises natural gas liquid (NGL).

17. The method of any one of claims 1 to 10, wherein the make-up fluid comprises liquefied petroleum gas (LPG).

18. The method of any one of claims 1 to 10, wherein the make-up fluid comprises light catalytic gas oil.

19. The method of any one of claims 1 to 18, wherein the first mobilizing fluid and the make-up fluid are different fluids.

20. The method of any one of claims 1 to 19, wherein the second mobilizing fluid is injected into the underground reservoir through the first well.

21. The method of any one of claims 1 to 19, wherein the second mobilizing fluid is injected into the underground reservoir through the second well.

22. The method of any one of claims 1 to 21, wherein the first well and the second well are located on a same pad.

23. The method of any one of claims 1 to 21, wherein the first well and the second well are located on different pads.

24. The method of any one of claims 1 to 23, wherein the first produced fluid has a concentration of the first mobilizing fluid of at least 60 vol%.

25. The method of any one of claims 1 to 24, wherein the first produced fluid has a concentration of the first mobilizing fluid of at least 70 vol%.

26. The method of any one of claims 1 to 25, wherein the first produced fluid has a concentration of the first mobilizing fluid of at least 80 vol%.

27. The method of any one of claims 1 to 26, wherein the first produced fluid has a concentration of the first mobilizing fluid of at least 90 vol%.

28. The method of any one of claims 1 to 27, further comprising:
mixing at least a portion of the second produced fluid with a second make-up fluid to form a third mobilizing fluid;
injecting the third mobilizing fluid into the underground reservoir through a third well, the third mobilizing fluid having a pressure that is above a liquid/vapor phase change pressure of the third mobilizing fluid; and producing a third produced fluid from the underground reservoir through the third well, the third produced fluid including bitumen and at least a portion of the third mobilizing fluid injected into the underground reservoir.

29. The method of claim 28, wherein the first well, the second well and the third well are different wells.

30. The method of claim 28, wherein first well, the second well and the third well are located on a same pad.

31. The method of any one of claims 1 to 28, wherein producing the first produced fluid from the underground reservoir includes collecting the produced fluid directly from the first well and directing at least a portion of the first produced fluid around separation units of a surface facility, the separation units used to separate the bitumen and the at least a portion of the first mobilizing fluid of the first produced fluid.

32. The method of claim 31, wherein portion of the first produced fluid that is directed around the separation units of the surface facility is compositionally unprocessed.

33. The method of any one of claims 1 to 32, wherein the mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than 30 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

34. The method of any one of claims 1 to 32, wherein the mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than 40 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

35. The method of any one of claims 1 to 32, wherein the mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than 50 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

36. The method of any one of claims 1 to 32, wherein the mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than the first 30 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

37. The method of any one of claims 1 to 32, wherein the mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than the first 40 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

38. The method of any one of claims 1 to 32, wherein the mixing at least a portion of the first produced fluid with the make-up fluid to form the second mobilizing fluid includes mixing less than the first 50 vol% of fluid produced per cycle with the make-up fluid to form the second mobilizing fluid.

39. The method of any one of claims 1 to 38, wherein, prior to the injecting the first mobilizing fluid into the underground reservoir through the first well, the first well has been used to perform at least one cycle of a cyclic solvent process of recovering bitumen from the underground reservoir, each cycle including:
injecting a mobilizing fluid into the underground reservoir through the first well; and producing a produced fluid from the underground reservoir through the first well, the produced fluid including bitumen and at least a portion of the mobilizing fluid injected into the underground reservoir.

40. The method of claim 39, wherein the first well has been used to perform at least two cycles of a cyclic solvent process of recovering bitumen from the underground reservoir.

41. The method of claim 39, wherein the first well has been used to perform at least three cycles of a cyclic solvent process of recovering bitumen from the underground reservoir.