CA3027074C - Integrated approach to enhance the performance of gravity drainage processes - Google Patents

Abstract

Methods of recovering bitumen from a reservoir are provided herein. The methods include operating a first injector-first producer well pair under a first gravity drainage process to form a first gravity drainage chamber and operating a second injector-second producer well pair under a second gravity drainage process to form a second gravity drainage chamber. An infill well is provided in an unswept region formed between the first gravity drainage chamber and the second gravity drainage chamber and the infill well is operated under a cyclic process utilizing a mobilizing fluid to form a mobilized region of the infill well. The infill well is then operated under a flooding process utilizing a driving fluid to displace bitumen in the mobilized region towards the first and second producer wells of the first injector-first producer well pair and the second injector-second producer well pair. The bitumen is then recovered.

Description

, , INTEGRATED APPROACH TO ENHANCE THE PERFORMANCE OF GRAVITY
DRAINAGE PROCESSES
Technical Field [0001] The present disclosure relates generally to methods of recovering hydrocarbons, and more specifically to methods of enhancing gravity drainage 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] Hydrocarbon resources continue to be heavily relied on for fuels and chemical feedstock. Hydrocarbons are generally recovered from subsurface formations known as "reservoirs." Different methods for removing or extracting hydrocarbons from reservoirs are used depending on the physical properties of the reservoir, 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.

[0004] One exemplary method for removing (or extracting) hydrocarbons from reservoirs is steam-assisted gravity drainage (SAGD). SAGD is an enhanced oil recovery technology for producing heavy crude oil and bitumen. It is an advanced form of steam stimulation in which a pair of horizontal wells is drilled into the oil reservoir, one a few metres above the other. Steam is continuously injected into the upper wellbore to heat the oil and reduce its viscosity, causing the heated oil to drain into the lower wellbore, where it is pumped out. SAGD and SAGD-based processes have been widely applied for hydrocarbon recovery from oil sands reservoirs.

[0005] Gravity drainage processes such as SAGD are usually operated at lower pressures when compared to cyclic processes (e.g. cyclic steam stimulation (CSS), liquid , addition to steam for enhancing recovery (LASER) and cyclic solvent process (CSP)) and are therefore more sensitive to reservoir heterogeneities, particularly vertical flow barriers.

[0006] Start-up processes utilizing steam to establish well communication in SAGD
and SAGD-based operations typically require months, which delays recovery of bitumen.
Further, small spacing between neighbouring SAGD wells is required to achieve high estimated ultimate recovery (EUR) which can lead to high initial capital expenses (CAPEX) and communication between neighbouring chambers. Once steam reaches the top of top of the reservoir, the steam efficiency will start to drop (i.e.
steam to oil ratio, or SOR, will rise) due to heat loss to the overburden (non-reservoir rock).

[0007] Further, as shown in Figure 1, unswept regions form between neighbouring SAGD well pairs that are hard to target after SAGD extraction is exhausted.
InfiII drilling between SAGD well pairs has been employed by some operators to target unswept bitumen, maintain or increase oil rate, and increase the EUR. Most of the infill methods, however, involve either drilling a well pair for similar gravity-drainage operation or drilling a single well to inject a non-condensable gas (NCG) for a flooding-based process.

[0008] Accordingly, there is a need for improved methods of enhancing gravity drainage for bitumen recovery from oil sands reservoirs.
Summary

[0009] The present disclosure provides methods of recovering bitumen from a reservoir. In some embodiments, the methods include operating a first injector-first producer well pair under a first gravity drainage process, the first injector-first producer well pair forming a first gravity drainage chamber in the subterranean reservoir; operating a second injector-second producer well pair under a second gravity drainage process, the second injector-second producer well pair forming a second gravity drainage chamber in the subterranean reservoir; providing an infill well in an unswept region formed between the first gravity drainage chamber and the second gravity drainage chamber;
operating the infill well under a cyclic process utilizing a mobilizing fluid to form a mobilized region of the infill well, the operating including injecting the mobilizing fluid into the infill well and producing a mixture of the injected mobilizing fluid and bitumen from the infill well;

operating the infill well under a flooding process utilizing a driving fluid to displace bitumen in the mobilized region towards the first and second producer wells of the first injector-first producer well pair and the second injector-second producer well pair;
and recovering the bitumen from the first and second producer wells of the first injector-first producer well pair and the second injector-second producer well pair.

[0010] The operating the infill well under the cyclic process may begin during either an early stage or a mid-stage of the first and second gravity drainage processes when the first gravity drainage chamber and the second gravity drainage chamber are spaced from each other.

[0011] The operating the infill well under the cyclic process may begin during a late stage of the first and second gravity drainage processes when the first gravity drainage chamber and the second gravity drainage chamber are in communication with each other.

[0012] The operating the infill well under the flooding process may begin during a late stage of the first and second gravity drainage processes when the first gravity drainage chamber and the second gravity drainage chamber are in communication with each other.

[0013] The providing the infill well in the unswept region formed between the first gravity drainage chamber and the second gravity drainage chamber may include providing the infill well at a position vertically offset from the first and second producer wells of the first injector-first producer well pair and the second injector-second producer well pair.

[0014] The providing the infill well at a position vertically offset from the first and second producer wells of the first injector-first producer well pair and the second injector-second producer well pair may include providing the infill well at a position vertically offset from the first and second producer wells in a direction towards overburden of the reservoir.

[0015] The mobilizing fluid may include a light hydrocarbon or a combination of light hydrocarbons in vapor or liquid form.

[0016] The mobilizing fluid may include steam.

,

[0017] The mobilizing fluid may include primarily the light hydrocarbon or the combination of light hydrocarbons.

[0018] The mobilizing fluid may include primarily the steam.

[0019] The driving fluid may include a light hydrocarbon or a combination of light hydrocarbons, primarily in vapor phase.

[0020] The driving fluid may include steam.

[0021] The driving fluid may include primarily the light hydrocarbon or the combination of light hydrocarbons.

[0022] The driving fluid may include primarily the steam.

[0023] The light hydrocarbon may be one of 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.

[0024] The cyclic process may be one of a liquid addition to steam for enhancing recovery (LASER) process, a cyclic steam stimulation (CSS) process, and a cyclic solvent process (CSP).

[0025] The one or both of the first gravity drainage process and the second gravity drainage process may be a steam-assisted gravity drainage (SAGD) process, a solvent-assisted-steam-assisted gravity drainage (SA-SAGD) process, a heated solvent vapor-assisted petroleum extraction (H-VAPEX) process, or any combination thereof.

[0026] The one or both of the first gravity drainage process and the second gravity drainage process may be a SA-SAGD process and the solvent in the SA-SAGD
process is one of a light hydrocarbon, a mixture of light hydrocarbons, dimethyl ether (DME), and a mixture of light hydrocarbons with DME.

[0027] The solvent in the SA-SAGD process 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.

[0028] The one or both of the first gravity drainage process and the second gravity drainage process may be an H-VAPEX process and the solvent may be one of a light hydrocarbon, a mixture of light hydrocarbons, dimethyl ether (DME), and a mixture of light hydrocarbons with DME.

[0029] The solvent may be a C2 to C7 alkane.

[0030] The method may further include operating one well or both wells of the first injector-first producer well pair under a first cyclic process at a first pressure below a fracture pressure of the reservoir prior to the operating of the first injector-first producer well pair under the first gravity drainage process.

[0031] The method may further include operating one well or both wells of the second injector-second producer well pair under a second cyclic process at a second pressure below a fracture pressure of the reservoir prior to the operating of the second injector-second producer well pair under the second gravity drainage process.

[0032] The providing the infill well in the unswept region formed between the first gravity drainage chamber and the second gravity drainage chamber may include injecting the mobilizing fluid into the infill well through flow control devices in the infill well to control delivery of the mobilizing fluid to target regions along the infill well.

[0033] In some embodiments, the methods of enhancing a gravity drainage process of recovering bitumen from a reservoir include providing a first injector-first producer well pair in the reservoir; providing a second injector-second producer well pair in the reservoir, the second injector-second producer well pair spaced from the first injector-first producer well pair; operating one or both wells of the first injector-first producer well pair under a first cyclic process utilizing a first mobilizing fluid at a first pressure below a fracture pressure of the reservoir; operating one or both wells of the second injector-second producer well pair under a second cyclic process utilizing a second mobilizing fluid at a second pressure below a fracture pressure of the reservoir;
operating the first injector-first producer well pair under a first gravity drainage process, the first injector-first producer well pair forming a first gravity drainage chamber in the subterranean reservoir; operating a second injector-second producer well pair under a second gravity drainage process, the second injector-second producer well pair forming a second gravity drainage chamber in the subterranean reservoir; and recovering the , , bitumen from the first and second producer wells of the first injector-first producer well pair and the second injector-second producer well pair.

[0034] The first injector well may be operated under the first cyclic process and the second injector well may be operated under the second cyclic process.

[0035] The first producer well may be operated under the first cyclic process and the second producer well may be operated under the second cyclic process.

[0036] Both wells of the first injector-first producer well pair may be operated under the first cyclic process.

[0037] Both wells of the second injector-second producer well pair may be operated under the second cyclic process.

[0038] The first cyclic process may include three or less cycles.

[0039] The second cyclic process may include three or less cycles.

[0040] 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.

[0041] 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

[0042] 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.

,

[0043] FIG. 1A is a schematic axial cross section of two pairs of horizontal wellbores in a typical SAGD recovery process showing a pair of gravity drainage chambers and an unswept region therebetween during an early stage of the SAGD
recovery;

[0044] FIG. 1B is a schematic axial cross section of two pairs of horizontal wellbores in a typical SAGD recovery process showing a pair of gravity drainage chambers and an unswept region therebetween during a late stage of the SAGD
recovery;

[0045] FIG. 2 is a longitudinal cross-sectional view of the two pairs of horizontal wellbores shown in FIGs. 1A and 1B;

[0046] FIG. 3 is a block diagram showing a method of recovering bitumen from a reservoir, according to one embodiment;

[0047] FIG. 4A is a diagram showing a pair of gravity drainage chambers during an early to mid-stage of a gravity drainage process and an unswept region during an early stage of an infill cyclic process between the pair of gravity drainage chambers of the method of recovering bitumen from a reservoir of FIG. 3, according to one embodiment;

[0048] FIG. 4B is a diagram showing the pair of gravity drainage chambers during late stage of a gravity drainage process and an unswept region during a late stage of the infill cyclic process between the pair of gravity drainage chambers of the method of recovering bitumen from a reservoir of FIG. 3, according to one embodiment;

[0049] FIG. 5 is a diagram showing expansion of the unswept region during the continuous flooding stage following the infill cyclic process of the method of recovering bitumen from a reservoir of FIG. 3, according to one embodiment;

[0050] FIG. 6 is a diagram showing a cyclic solvent process (CSP) as a startup of a gravity-drainage process of the method of recovering bitumen from a reservoir of FIG.
3, according to one embodiment; and

[0051] FIG. 7 is a plane view of targeted delivery of steam/solvent based on gravity drainage chamber conformance.

=

[0052] 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

[0053] 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.

[0054] 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.

[0055] 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."

, ,

[0056] 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.

[0057] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a range from 1 to 9.

[0058] "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. A or higher);
and - some amount of sulfur (which can range in excess of 7 wt. %), based on the total bitumen weight.

[0059] 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.

[0060] "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 10.00 API (density of 1,000 kg/m3 or 1 g/cm3).

An extra heavy oil, in general, has an API gravity of less than 10.00 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.

[0061] 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 100 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.

[0062] 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.

[0063] 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.

[0064] 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."

[0065] The term "gravity drainage process" refers to an oil recovery technique in which gravity acts as the main driving force for the displacement of oil into the wellbore and the voidage volume of oil in the reservoir is replaced by a gas. Gravity drainage processes for heavy oil recovery may include a steam-assisted gravity drainage (SAGD) process, a solvent-assisted-steam-assisted gravity drainage (SA-SAGD) process, a , heated solvent vapor-assisted petroleum extraction (H-VAPEX) process, or any combination thereof.

[0066] 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.

[0067] 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.

[0068] 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.

[0069] "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.

[0070] 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.

[0071] 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.

[0072] In spite of the technologies that have been developed, there remains a need in the field for methods of recovering bitumen from a reservoir.

[0073] An integrated approach to mitigate some of above-mentioned challenges in the gravity-drainage process targeting startup enhancement, accelerating production, increasing EUR, as well as reduction of energy intensity is provided herein.
The proposed approach involves utilizing and integrating different solvent-assisted or solvent-dominated processes and recovery mechanisms (such as a CSP, a LASER process, a solvent assisted (SA)-steam flood or solvent flood process, or a combination thereof) at different stages of a base gravity-drainage process, which could be steam assisted gravity drainage (SAGD), solvent-assisted-steam assisted gravity drainage (SA-SAGD), heated vapor extraction (H-VAPEX) or a combination thereof.

[0074] Referring now to Figures 1A and 1B, illustrated therein are schematic axial cross-sections of typical SAGD recovery processes. Two pairs of horizontal wellbores 100, 110 are provided in a formation or reservoir 10 and are spaced apart vertically by a distance d. Steam is generally pumped down from the surface through the overburden 1 and along the upper wellbores 100a, 110a, where it passes into the formation 10 via one of a number of apertures provided in the wellbore casing. Upper wellbores 100a, 110a may also be referred to as an injector wellbore or, simply an injector. As steam is injected, thermal energy from the steam is transferred to the formation. This thermal energy increases the temperature of petroleum products present in the formation 10 (e.g. heavy crude oil or bitumen), which reduces their viscosity and allows them to flow downwards under the influence of gravity towards the lower wellbores 100b, 110b, respectively, where it passes into the wellbores 100b, 110b via one of a number of apertures provided in the wellbore casing. Lower wellbores 100b, 110b may also be referred to as producer wellbores or, simply as a producer.

[0075] As shown in Figure 1A, as the steam enters the reservoir, gravity drainage chambers 20a and 20b are formed and an unswept region 30 forms therebetween.
While during normal operation lower wellbores 100b, 110b act as producers (i.e.
fluid is extracted from the formation via the wellbores 100b, 110b), it will be appreciated that wellbores 100b, 110b may alternatively act as an injector. For example, during start-up of a SAGD process, steam may be pumped into both wellbores of each pair of wellbores to initially heat the formation proximate both the upper 100a, 110a and lower 100b, 110b wellbores, respectively, following which wellbores 100b, 110b may be transitioned to producers by discontinuing the steam flow in these wellbores.

[0076] Turning to Figure 1B, as the SAGD process continues and steam is pumped through the upper wellbores 100a, 110a, petroleum products present in the formation 10 flow downwards under the influence of gravity towards the lower wellbores 100b, 110b and the gravity drainage chambers 20a and 20b grow. Eventually, at a late phase of the SAGD process, the gravity drainage chambers 20a and 20b merge and form a common gravity drainage chamber. At this point, removal of additional petroleum products present in the formation 10 using the SAGD process becomes inefficient.

[0077]
Figure 2 illustrates a schematic longitudinal cross-section of the typical SAGD recovery process shown in Figure 1. As described above, steam is pumped down from the surface through the heels 104, 114 of the injector wellbores 100, 110 and along the horizontal segments 106, 116 towards the toes 108, 118. A number of oufflow locations (e.g. screens, perforations, or other apertures) are provided along the injector wellbore casings to allow the steam to access the formation. Heated petroleum products and condensate from the injected fluids flow down through the formation 10 and into producer wellbores 100b, 110b through one of a number of inflow locations (e.g. screens, perforations, or other apertures) provided along the horizontal segments 106, 116 of the producer wellbore casings between the heels 104, 114 of the producer wellbores and the toes 108, 118, respectively. One or more artificial lift devices (not shown) (e.g.
electrical submersible pumps) is used to pump fluids collected along the horizontal segments of the producer wellbores 100b, 110b up to the surface.

[0078]
Referring now to Figure 3, illustrated therein is a method 300 of recovering bitumen from a reservoir. Method 300 builds upon the typical SAGD process described in Figures 1 and 2 and includes providing an infill well between the two pairs of injector-producer wells to extract petroleum products form the unswept region therebetween.

[0079]
At a step 302 of the method 300, a first injector-first producer well pair is operated under a first gravity drainage process. At a step 304 of the method 300, a second injector-second producer well pair is operated under a second gravity drainage process.
It should be noted that steps 302 and 304 may occur concurrently in the method 300.

[0080]
Optionally, prior to the steps 302 and 304 of operating the first injector-first producer well pair and the second injector-second producer well pair under a gravity drainage process, one or both of the first injector-first producer well pair and the second injector-second producer well pair may be operated in a cyclic mode. In some embodiments, operating one or both of the first injector-first producer well pair and the , , second injector-second producer well pair in a cyclic mode may enhance startup (e.g.
reduce time to producing of oil from the producer wells).

[0081] As shown in Figure 4, in one example, a first injector-first producer well pair 400 is spaced apart from a second injector-first producer well pair 410.
Operation of the first injector-first producer well pair 400 under a first gravity drainage process forms a first gravity drainage chamber 420a in the formation or reservoir 403 and operation of the second injector-second producer well pair 410 under a second gravity drainage process forms a second gravity drainage chamber 420b in the formation or reservoir 403.

[0082] The first gravity-drainage process and the second gravity-drainage process may be the same gravity-drainage process or may be differing gravity-drainage processes. In some embodiments, one or both of the first gravity drainage process and the second gravity drainage process is a SAGD process, a solvent-assisted-steam-assisted gravity drainage (SA-SAGD) process, a heated solvent vapor-assisted petroleum extraction (H-VAPEX) process, or any combination thereof.

[0083] In the aforementioned gravity drainage processes, solvents may be used to enhance the extraction of petroleum products from the reservoir 403. For instance, solvents are used in SA-SAGD processes to enhance the extraction of petroleum products from the reservoir 403. In some embodiments where one or both of the first gravity drainage process and the second gravity drainage process is a SA-SAGD
process, the solvent used in the SA-SAGD may be a light hydrocarbon, a mixture of light hydrocarbons or dimethyl ether. In other embodiments, the solvent may be a C2-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, one or both of the first gravity drainage process and the second gravity drainage process may be an H-VAPEX process. In these embodiments, the solvent used in the H-VAPEX process may also be one of a light hydrocarbon, a mixture of light hydrocarbons and dimethyl ether. In one specific example, the solvent used in an H-VAPEX process may be a C2 to C7 alkane.

[0085] In other embodiments, 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% C2-05 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.

[0086]
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.

[0087]
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.

[0088]
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.

[0089]
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.

[0090]
The solvent composition may comprise at least 5 mol A) of a high-aromatics component (based upon total moles of the solvent composition) comprising at least 60 wt. A 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).

[0091]
At a third step 306, an infill wellbore 440 is provided (e.g. drilled) in an unswept region 430 formed between the first gravity drainage chamber 420a and the second gravity drainage chamber 420b that form during the steps 302 and 304.

[0092]
The infill wellbore 440 is generally a horizontal wellbore similar in structure to the wellbores 100a, 100b, 110a and 110b, described above.

[0093]
The infill wellbore 440 may be provided in the reservoir 403 during an early stage, a mid-stage or a late stage of at least one of the gravity-drainage processes that occur during steps 302 and 304. For instance, in some embodiments, infill wellbore 440 may be provided during an early stage of at least one of the gravity-drainage processes that occur during steps 302 and 304. In these embodiments, an infill cyclic process can be operated in the infill wellbore 440 while the gravity-drainage processes that occur during steps 302 and 304 at relatively higher pressure.

[0094] In step 306, a single infill well 440 is drilled in the unswept region 430 between the first and second gravity drainage chambers 420a, 420b. In some embodiments, the infill well 440 is provided in the unswept region 430 at a position that is vertically offset from the first 400b and second 410b producer wells of the first injector-first producer well pair 400 and the second injector-second producer well pair 410, respectively. For instance, as shown in Figure 4A, the infill well 440 may be provided at a position that is vertically offset from both of the first producer well 400b of the first injector-first producer well pair 400 and from the second producer well 410b of the second injector-second producer well pair 410 in a direction towards overburden 401 of the reservoir 403. By providing the infill well 440 at a position that is vertically offset from both of the first producer well 400b and the second producer well 410b in a direction towards the overburden 401 of the reservoir 400, the cyclic process can be at least partially gravity driven in displacing the mobilized region 442 towards the producer wells 400b and 410b.

[0095] At a fourth step 308, the infill well 440 is operated under a cyclic process utilizing a mobilizing fluid to form a mobilized region 442 of the infill well 440. In this step, operating the infill well 440 includes injecting the mobilizing fluid into the infill well 440 and producing a mixture of the injected mobilizing fluid and bitumen from the infill well 440.
Operation of the infill well 440 provide for the formation of the mobilized region 442 around the infill well and between the gravity drainage chambers 420a, 420b.

[0096] Infill well 440 is operated using a cyclic process to extract petroleum products (e.g. bitumen) in the unswept region 430 between the gravity drainage chambers 420a and 420b. For instance, the cyclic process could be a pure solvent process like CSP, or a CSP-based process with the addition of steam, or a steam process with solvent addition such as LASER or a pure steam process such as a cyclic steam stimulation (CSS) process.

[0097] The cyclic process may start during an early stage or during a mid-stage of the gravity drainage processes that occur during steps 302 and 304. For instance, as shown in Figure 4A, the cyclic process may begin at an early stage of the gravity drainage processes, "early stage" being from startup of the gravity drainage process to the steam chamber reaching about halfway to the top of the reservoir. Further, the cyclic process , , may begin at a mid-stage of the gravity drainage process, the mid-stage being from when the steam chambers reaches about halfway to the top of the reservoir to when neighboring steam chambers (e.g. 420a, 420b) touch each other (i.e. are in fluid communication with each other). Alternatively, the cyclic process may start at a late stage of the gravity drainage processes that occur during steps 302 and 304. For instance, as shown in Figure 4B, the cyclic process may begin at a late stage of the gravity drainage processes when the gravity drainage chambers 420a, 420b are in communication with each other.

[0098] The mobilizing fluid may be a liquid or vapor solvent, a solvent mixed with steam, or pure steam. In embodiments where the mobilizing fluid includes a solvent, the solvent can be any solvent described above with respect to the solvents that can be used during the gravity drainage processes.

[0099] At a fifth step 310, the infill well 440 is operated under a flooding process utilizing a driving fluid to displace bitumen in the mobilized region 442 towards the first and second producer wells 400b, 410b for collection. As shown in Figure 5, the cyclic process is transitioned into the flooding process when the mobilized region 442 is in communication with the first and second producer wells 400b, 410b. During this step 310, the driving fluid is continuously injected into the infill well 440 and passes through apertures in the infill well 440 into the reservoir 403 to displace the mobilized region 442 outwardly from the infill well 440 towards the producer wells 400b, 410b.

[0100] In some embodiments, the flooding process can be described as being both gravity and pressure driven when there is vertical offset between the infill well 440 and the first and second producer wells 400b, 410b (e.g. when the infill well 440 is positioned between the first and second producer wells 400b, 410b and vertically offset from the first and second producer wells 400b, 410b in a direction towards the overburden 401).

[0101] The driving fluid may be a vapor solvent, a solvent mixed with steam or pure steam. In embodiments where the driving fluid includes a solvent, the solvent can be any solvent described above with respect to the solvents that can be used during the gravity drainage processes.

[0102] According to some embodiments, when the flooding process starts, steam injection through the original injector wells (400a and 410a in Figures 4A and 4B) of the well pairs may stop or may continue at a reduced flow rate. In some embodiments, when the flooding process starts, steam injection through the original injector wells (400a and 410a in Figures 4A and 4B) of the well pairs may switch to injection of a non-condensable gas (NCG). The NCG could be methane, CO2, nitrogen, produced gas, flue gas, or a combination of thereof.

[0103] At a sixth step 312, the bitumen is recovered from the first producer well 400b and the second producer well 410b.

[0104] In some embodiments, one or both wells of each of the first injector-first producer well pair 400 and the second injector-second producer well pair 410 may be operated by a cyclic process before being operated by the first gravity drainage process and the second gravity drainage process, respectively. For clarity, each well 400a and 400b of pair 400 and each well 410a and 410b of pair 410 can be operated alone or together as a pair by the cyclic process. By operating one or both wells of each of the first injector-first producer well pair 400 and the second injector-second producer well pair 410 by a cyclic process before each well pair 400, 410 being operated by the first gravity drainage process and the second gravity drainage process, respectively, a start-up process of the first and second gravity drainage processes may be improved. As noted above, cyclic processes such as a pure solvent process like CSP, or a CSP-based process with the addition of steam, or a steam process with solvent addition such as LASER or a pure steam process such as a cyclic steam stimulation (CSS) process are typically operated at higher pressures than gravity drainage processes like SAGD.
Referring to Figure 6, operating one or both wells of each of the first injector-first producer well pair 400 and the second injector-second producer well pair 410 by a cyclic process before each well pair 400, 410 being operated by the first gravity drainage process and the second gravity drainage process, respectively, may lead to the formation of a region of mobilized fluid 425 around the injector wells 400a, 410a quicker than would occur under a strict gravity-drainage process.

[0105] According to some embodiments, the start-up of the first and second gravity drainage processes may be enhanced by starting with alew short cycles (e.g. up to three cycles) of a cyclic process to condition a near well region around the wells 400a, 400b, 410a and 410b, and also to accelerate initial production.

[0106] The cyclic process is operated at a pressure below a fracture pressure of the reservoir 403. In one example, a CSP using a light hydrocarbon solvent may be operated as the cyclic process. In another example, a low-pressure CSS or LASER
process may also be operated as the cyclic process. In some examples, two or three cycles of a cyclic process may be operated in one or more of the wells 400a, 400b, 410a and 410b prior to the gravity drainage process over a period of time ranging from one month to twelve months, during which the producer wells 400b and 410b may be producing bitumen when not under injection

[0107] According to some embodiments, fluid distribution in the infill well may be better understood when the infill well is operated using a cyclic process by understanding steam/solvent vapor conformance in the gravity-drainage processes. Due to geologic heterogeneities, the steam/solvent vapor conformance is typically non-uniform in the gravity drainage processes, particular when employed in long (e.g. >800 metre) horizontal wells. An example of non-uniform conformance is shown by the shapes of the gravity drainage chambers 20a and 20b in Figure 2.

[0108] Referring now to Figure 7, in some embodiments, prior to drilling the infill well 740 between the two pairs of horizontal wellbores 700 and 710, an understanding of the chamber shape (e.g. chambers 720a and 720b) in the gravity drainage processes may be developed by applying 4D seismic or other surveillance techniques.
Based on a mapped chamber shape, the infill well 740 may be completed with flow control devices (FCDs) 750 with different density and/or sizes along the infill well 740 to control the delivery of fluid into target regions. For example, fluid delivery may be targeted to force more fluid delivered into a bypassed region 760 where chambers 720a and 720b do not extend as close to the infill well 740 as they do in neighboring regions.
Forcing fluid into regions such as a bypassed region 760 may improve the solvent utilization in the cyclic process and may also increase sweep efficiency and EUR in the infill well 740.

,

[0109]
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 (23)

Claims What is claimed is:

1. A method of recovering bitumen from a reservoir, the method comprising:
operating a first injector-first producer well pair under a first gravity drainage process, the first injector-first producer well pair forming a first gravity drainage chamber in the subterranean reservoir;
operating a second injector-second producer well pair under a second gravity drainage process, the second injector-second producer well pair forming a second gravity drainage chamber in the subterranean reservoir;
providing an infill well in an unswept region formed between the first gravity drainage chamber and the second gravity drainage chamber;
operating the infill well under a cyclic process utilizing a mobilizing fluid to form a mobilized region of the infill well, the operating including injecting the mobilizing fluid into the infill well and producing a mixture of the injected mobilizing fluid and bitumen from the infill well, wherein the mobilizing fluid primarily comprises a light hydrocarbon or a combination of light hydrocarbons in vapor or liquid form;
operating the infill well under a flooding process utilizing a driving fluid to displace bitumen in the mobilized region towards the first and second producer wells of the first injector-first producer well pair and the second injector-second producer well pair; and recovering the bitumen from the first and second producer wells of the first injector-first producer well pair and the second injector-second producer well pair.

2. The method of claim 1, wherein the operating the infill well under the cyclic process begins during either an early stage or a mid-stage of the first and second gravity drainage processes when the first gravity drainage chamber and the second gravity drainage chamber are spaced from each other.

3. The method of claim 1, wherein the operating the infill well under the cyclic process begins during a late stage of the first and second gravity drainage processes when the first gravity drainage chamber and the second gravity drainage chamber are in communication with each other.

4. The method of any one of claims 1 to 3, wherein the operating the infill well under the flooding process begins during a late stage of the first and second gravity drainage processes when the first gravity drainage chamber and the second gravity drainage chamber are in communication with each other.

5. The method of any one of claims 1 to 4, wherein the providing the infill well in the unswept region formed between the first gravity drainage chamber and the second gravity drainage chamber includes providing the infill well at a position vertically offset from the first and second producer wells of the first injector-first producer well pair and the second injector-second producer well pair.

6. The method of claim 5, wherein the providing the infill well at a position vertically offset from the first and second producer wells of the first injector-first producer well pair and the second injector-second producer well pair includes providing the infill well at a position vertically offset from the first and second producer wells in a direction towards an overburden of the reservoir.

7. The method of any one of claims 1 to 6, wherein:
operating the first injector-first producer well pair under the first gravity drainage process includes injecting steam into the first injector well;
operating the second injector-second producer well pair under the second gravity drainage process includes injecting steam into the second injector well; and upon operating the infill well under the flooding process, reducing a flow rate of steam being injected into one or both of the first injector well and the second injector well.

8. The method of claim 7, wherein the method further comprises, after reducing the flow rate of steam being injected into one or both of the first injector well and the second injector well, injecting a non-compressible gas into one or both of the first injector well and the second injector well.

9. The method of any one of claims 1 to 8, wherein the driving fluid comprises a light hydrocarbon or a combination of light hydrocarbons.

10. The method of claim 9, wherein the driving fluid comprises steam.

11. The method of claim 10, wherein the driving fluid comprises primarily the light hydrocarbon or the combination of light hydrocarbons.

12. The method of claim 10, wherein the driving fluid comprises primarily the steam.

13. The method of any one of claims 1, 9 or 10, wherein the light hydrocarbon of the mobilizing and/or the light hydrocarbon of the driving fluid is one of 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.

14. The method of any one of claims 1 to 8, wherein the cyclic process is one of a liquid addition to steam for enhancing recovery (LASER) process, a cyclic steam stimulation (CSS) process and a cyclic solvent process (CSP).

15. The method of any one of claims 1 to 14, wherein one or both of the first gravity drainage process and the second gravity drainage process is a steam-assisted gravity drainage (SAGD) process, a solvent-assisted-steam-assisted gravity drainage (SA-SAGD) process, a heated solvent vapor-assisted petroleum extraction (H-VAPEX) process, or any combination thereof.

16. The method of any one of claims 1 to 15, wherein one or both of the first gravity drainage process and the second gravity drainage process is a SA-SAGD process and the solvent in the SA-SAGD process is one of a light hydrocarbon, a mixture of light hydrocarbons, dimethyl ether (DME), and a mixture of light hydrocarbons with DME.

17. The method claim 16, wherein the solvent in the SA-SAGD process 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.

18. The method of any one of claims 1 to 15, wherein the one or both of the first gravity drainage process and the second gravity drainage process is an H-VAPEX process and the solvent is one of a light hydrocarbon, a mixture of light hydrocarbons, dimethyl ether (DME), and a mixture of light hydrocarbons with DME.

19. The method claim 18, wherein the solvent is a C2 to C7 alkane.

20. The method of any one of claims 1 to 19 further comprising operating one well or both wells of the first injector-first producer well pair under a first cyclic process at a first pressure below a fracture pressure of the reservoir prior to the operating of the first injector-first producer well pair under the first gravity drainage process.

21. The method of any one of claims 1 to 20 further comprising operating the first injector-producer well pair in a cyclic mode at a pressure below a fracture pressure of the subterranean reservoir prior to the operating of the first injector-producer well pair in the gravity drainage mode.

22. The method of claim 21 further comprising operating one well or both wells of the second injector-second producer well pair under a second cyclic process at a second pressure below a fracture pressure of the reservoir prior to the operating of the second injector-second producer well pair under the second gravity drainage process.

23. The method of any one of claims 1 to 22, wherein the providing the infill well in the unswept region formed between the first gravity drainage chamber and the second gravity drainage chamber includes injecting the mobilizing fluid into the infill well through flow control devices in the infill well to control delivery of the mobilizing fluid to target regions along the infill well.