CA3058775C - Integrated processes utilizing steam and solvent for bitumen recovery - Google Patents

Abstract

Methods of recovering bitumen from an underground reservoir penetrated by a wellbore are described herein. The methods include injecting a first mobilizing fluid through the wellbore into the underground reservoir, shutting in the first mobilizing fluid that is in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir, holding the first mobilizing fluid in the reservoir, recovering bitumen of lowered viscosity from the reservoir, detecting an issue in the wellbore, in response to detecting the issue, injecting a second mobilizing fluid through the wellbore into the reservoir, shutting in the second mobilizing fluid that is in the reservoir, holding the second mobilizing fluid in the reservoir, and recovering bitumen of lowered viscosity from the reservoir. The first mobilizing fluid includes steam and the second mobilizing fluid includes a hydrocarbon solvent. The issue may be a casing integrity issue, a fluid excursion issue or a pump issue.

Description

INTEGRATED PROCESSES UTILIZING STEAM AND SOLVENT FOR BITUMEN
RECOVERY
Technical Field [0001] The present disclosure relates generally to methods of recovering hydrocarbons from underground reservoirs, and more specifically to integrated processes utilizing steam and solvent for recovering hydrocarbons 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] Historically commercial in-situ oil sands processes have included:
cyclic steam stimulation (CSS), steam assisted gravity drainage (SAGD), and steam-flood (SF).
These processes have extracted oil from underground reservoirs using steam.
The next generation of in-situ processes may use solvent-steam or pure solvent to extract oil from similar reservoirs. The benefits of these processes are lower energy intensity, lower water usage, ability to access previously uneconomic resource, and higher reservoir recovery rates.

[0004] In steam-based processes, increased temperatures in the reservoir lower the viscosity of oil allowing it to flow and be produced. In solvent-based process, the solvent dilutes the oil and lowers its viscosity to allow it to flow.

[0005] Steam-based oil sands extraction processes use water sourced from nearby local supplies to fill central processing facilities (CPF). These sources of water may include: surface water, aquifers; freshwater or brackish, and produced water from other operations. For steam-based processes, the CPF is generally sized for the resources that are available and to bring steam online quickly.

[0006] In contrast, as production or extraction of solvent may not be possible at the oil extraction location, solvent generally needs to be transported to site.
Transportation can be by truck, train, or pipeline. Once the solvent has been brought to site, a high percentage of solvent (>75%) will be recycled and continuously used in the solvent processes. There is a commercial tradeoff with bringing solvent to site. The supply must be sized to balance cost, quantity required, and delivery dependability.
Therefore, due to inability to bring large quantity of solvent to site initially, there will be a longer time period for solvent processes to achieve plateau injection rates. This slower ramp to peak solvent injection leads to lower oil production and a decrease in economics.

[0007] Previous studies have shown that steam-based process and solvent-based processes can target the same resource. However, steam-based processes can have inferior performance in solvent specific resources due to thinner pay, lower bitumen saturation, and pressure restrictions and/or limitations. One of the primary reasons is due to heat losses to non-pay (e.g. cap rock, low bit-sat sands). The performance downgrade with steam processes would be more pronounced in mid-to-late life as the steam chamber grows. For solvent-based processes, heat in the near wellbore area could improve performance.

[0008] Accordingly, there is a need for improved methods of enhancing cyclic solvent processes with steam for bitumen recovery from oil sands reservoirs.
Summary

[0009] The present disclosure described methods of recovering bitumen from an underground reservoir. According to at least one broad aspect, a method of recovering bitumen from an underground reservoir penetrated by a wellbore, the wellbore including a casing, is described, the method includes injecting a first mobilizing fluid through the wellbore into the reservoir, the first mobilizing fluid including steam;
shutting in the first mobilizing fluid that is in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir; holding the first mobilizing fluid in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir; recovering bitumen of lowered viscosity from the reservoir; during a subsequent step of injecting first mobilizing fluid into the reservoir, detecting a casing integrity issue in the wellbore; in response to detecting the casing integrity issue in the wellbore, injecting a second mobilizing fluid through the wellbore into the reservoir to reduce a pressure of the reservoir and to reduce thermal ..
cycling, the second mobilizing fluid including a hydrocarbon solvent; shutting in the second mobilizing fluid that is in the reservoir; holding the second mobilizing fluid in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

[0010] According to another aspect, the second mobilizing fluid differs from the first mobilizing fluid.

[0011] According to another aspect, the steps of injecting the first mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid that is in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir, and recovering bitumen of lowered viscosity from the reservoir are part of a cyclic steam stimulation (CSS) process for recovering bitumen from the underground reservoir.

[0012] According to another aspect, the steps of injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the second mobilizing fluid that is in the reservoir, holding the second mobilizing fluid in the reservoir and recovering bitumen of lowered viscosity from the reservoir are part of a cyclic solvent process (CSP) for recovering bitumen from the underground reservoir.

[0013] According to another aspect, detecting the at least one casing integrity issue is by a monitoring system.

[0014] According to another aspect, the monitoring system is a passive seismic monitoring system, a differential flow pressure monitoring system and/or an N2 soak monitoring system.

[0015] According to another aspect, detecting the at least one casing integrity issue is by performing casing integrity checks.

[0016] According to another aspect, the casing integrity checks include measuring ovalities in the casing.

[0017] According to another aspect, the casing integrity issue includes a decline in a structural integrity of an intermediate casing of the wellbore.

[0018] According to another aspect, the method further includes, after detecting the casing integrity issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid in the reservoir and holding the first mobilizing fluid in the reservoir.

[0019] According to another aspect, the step of holding the first mobilizing fluid in the reservoir after detecting the casing integrity issue is for a period of time in a range of about 24 to 48 hours.

[0020] According to another aspect, the step of holding the first mobilizing fluid in the reservoir after detecting the casing integrity issue includes analyzing data collected from the wellbore and/or the reservoir prior to detecting the casing integrity issue to confirm the casing integrity issue.

[0021] According to another aspect, the step of holding the first mobilizing fluid in the reservoir after detecting the casing integrity issue includes analyzing data collected from the wellbore and/or the reservoir after detecting the casing integrity issue to confirm the casing integrity issue.

[0022] According to another aspect, the method includes, after detecting the casing integrity issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, recovering fluid from the reservoir to reduce the pressure of the reservoir.

[0023] According to another aspect, the step of holding the first mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

[0024] According to another aspect, the step of holding the second mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

[0025] According to another broad aspect, a method of recovering bitumen from an underground reservoir penetrated by at a wellbore is described herein. The method includes injecting a first mobilizing fluid through the wellbore into the reservoir, the first mobilizing fluid including steam; shutting in the first mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir;
holding the first mobilizing fluid in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir; recovering bitumen of lowered viscosity from the reservoir;
during a subsequent step of injecting first mobilizing fluid into the reservoir, detecting at least one fluid excursion issue from the wellbore; in response to detecting the at least one fluid excursion issue from the wellbore, injecting a second mobilizing fluid into the reservoir, the second mobilizing fluid including a hydrocarbon solvent; shutting in the second mobilizing fluid that is in the reservoir; holding the second mobilizing fluid in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

[0026] According to another aspect, the second mobilizing fluid differs from the first hydrocarbon fluid.

[0027] According to another aspect, the steps of injecting the first mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid that is in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir, and recovering bitumen of lowered viscosity from the reservoir are part of a cyclic steam stimulation (CSS) process for recovering bitumen from the underground reservoir.

[0028] According to another aspect, the steps of injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the second mobilizing fluid that is in the reservoir, holding the second mobilizing fluid in the reservoir and recovering bitumen of lowered viscosity from the reservoir are part of a cyclic solvent process (CSP) for recovering bitumen from the underground reservoir.

[0029] According to another aspect, the detecting the at least one fluid excursion issue is by monitoring a pressure of the reservoir via one or more observation wellbores offset from a production pad including the wellbore and detecting an increase in the pressure of the reservoir of target reservoir or other geologic zone.

[0030] According to another aspect, the detecting the at least one fluid excursion issue is by analyzing injection and production pressure profiles.

[0031] According to another aspect, the method also includes, after detecting the fluid excursion issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid in the reservoir and holding the first mobilizing fluid in the reservoir.

[0032] According to another aspect, the step of holding the first mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

Date Recue/Date Received 2021-04-07

[0033] According to another aspect, the step of holding the first mobilizing fluid in the reservoir includes performing diagnostic work to confirm the fluid excursion issue in the wellbore.

[0034] According to another aspect, the method also includes, after detecting the fluid excursion issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, recovering fluid from the reservoir to reduce the pressure of the reservoir.

[0035] According to another aspect, the step of holding the first mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

[0036] According to another aspect, the step of holding the second mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

[0037] According to another broad aspect, a method of recovering bitumen from an underground reservoir penetrated by at least one well is described. The method includes injecting a first mobilizing fluid into the reservoir, the first mobilizing fluid including steam; shutting in the first mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; holding the first mobilizing fluid in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir; recovering bitumen of lowered viscosity from the reservoir; during a subsequent step of injecting first mobilizing fluid into the reservoir, detecting at least one pump issue in the wellbore; in response to detecting the at least one pump issue, injecting a second mobilizing fluid into the reservoir, the second mobilizing fluid including a hydrocarbon solvent;
shutting in the second mobilizing fluid that is in the reservoir; holding the second mobilizing fluid in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

[0038] According to another aspect, the second mobilizing fluid differs from the first mobilizing fluid.

[0039] According to another aspect, the steps of injecting the first mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid that is in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir, and Date Recue/Date Received 2021-04-07 recovering bitumen of lowered viscosity from the reservoir are part of a cyclic steam stimulation (CSS) process for recovering bitumen from the underground reservoir.

[0040] According to another aspect, the steps of injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the second mobilizing fluid that is in the reservoir, holding the second mobilizing fluid in the reservoir and recovering bitumen of lowered viscosity from the reservoir are part of a cyclic solvent process (CSP) for recovering bitumen from the underground reservoir.

[0041] According to another aspect, the detecting pump issues in the at least one well includes detecting a low fillage rate of a pump of the well.

[0042] According to another aspect, the detecting pump issues in the at least one well includes detecting flashing of a fluid within a pump of the well.

[0043] According to another aspect, the detecting pump issues in the at least one well includes detecting a gaseous fluid in production tubing of the wellbore.

[0044] According to another aspect, the detecting pump issues in the at least one well includes detecting failure of a pump of the well.

[0045] According to another aspect, the method includes, after detecting the at least one pump issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid in the reservoir and holding the first mobilizing fluid in the reservoir.

[0046] According to another aspect, the step of holding the first mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

[0047] According to another aspect, the step of holding the first mobilizing fluid in the reservoir includes performing diagnostic work to confirm the at least one pump issue in the wellbore.

[0048] According to another aspect, the method includes, after detecting the at least one pump issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, recovering fluid from the reservoir to reduce the pressure of the reservoir.

[0049] According to another aspect, the step of holding the first mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

[0050] According to another aspect, the step of holding the second mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

[0051] According to another broad aspect, a method of recovering bitumen from an underground reservoir penetrated by at least one well is described. The wellbore includes a casing. The method includes injecting a first mobilizing fluid through the wellbore into the reservoir, the first mobilizing fluid including steam;
shutting in the first mobilizing fluid that is in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir; holding the first mobilizing fluid in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir; recovering bitumen of lowered viscosity from the reservoir; during a subsequent step of shutting in the first mobilizing fluid into the reservoir or holding the first mobilizing fluid in the reservoir, detecting a casing integrity issue in the wellbore; in response to detecting the casing integrity issue in the wellbore, injecting a second mobilizing fluid through the wellbore into the reservoir to reduce a pressure of the reservoir and to reduce thermal cycling, the second mobilizing fluid including a hydrocarbon solvent; shutting in the second mobilizing fluid that is in the reservoir; holding the second mobilizing fluid in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

[0052] According to another broad aspect, a method of recovering bitumen from an underground reservoir penetrated by at a wellbore is described The method includes injecting a first mobilizing fluid through the wellbore into the reservoir, the first mobilizing fluid including steam; shutting in the first mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; holding the first mobilizing fluid in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir;
recovering bitumen of lowered viscosity from the reservoir; during a subsequent step of shutting in the first mobilizing fluid into the reservoir or holding the first mobilizing fluid in the reservoir, detecting at least one fluid excursion issue in the wellbore;
in response to detecting the at least one fluid excursion issue from the wellbore, injecting a second mobilizing fluid into the reservoir, the second mobilizing fluid including a hydrocarbon solvent; shutting in the second mobilizing fluid that is in the reservoir;
holding the second mobilizing fluid in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

[0053] According to another broad aspect, a method of recovering bitumen from an underground reservoir penetrated by at least one well is described. The method includes injecting a first mobilizing fluid into the reservoir, the first mobilizing fluid including steam; shutting in the first mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; holding the first mobilizing fluid in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir; recovering bitumen of lowered viscosity from the reservoir; during a subsequent step of shutting in the first mobilizing fluid into the reservoir or holding the first mobilizing fluid in the reservoir, detecting at least one pump issue in the wellbore; in response to detecting the at least one pump issue, injecting a second mobilizing fluid into the reservoir, the second mobilizing fluid including a hydrocarbon solvent; shutting in the second mobilizing fluid that is in the reservoir; holding the second mobilizing fluid in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

[0054] According to another aspect, the first mobilizing fluid is a steam-dominated mobilizing fluid.

[0055] According to another aspect, the first mobilizing fluid is steam with a quality between 0% and 100%.

[0056] According to another aspect, the first mobilizing fluid is steam with a quality of about 70%.

[0057] According to another aspect, the first mobilizing fluid is steam having a temperature above about 25 C.

[0058] According to another aspect, the first mobilizing fluid is steam having a temperature above about 200 C.

[0059] According to another aspect, the first mobilizing fluid is steam having a temperature above about 325 C.

[0060] According to another aspect, the second mobilizing fluid is a solvent.

[0061] According to another aspect, the second mobilizing fluid is one of:
a C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, and a gas plant condensate comprising alkanes, naphthenes, and aromatics.

[0062] According to another aspect, the first mobilizing fluid is about 75%
by mass steam.

[0063] According to another aspect, the first mobilizing fluid is about 85%
by mass steam.

[0064] According to another aspect, the first mobilizing fluid is about 95%
by mass steam.

[0065] According to another aspect, the second mobilizing fluid is about 75% by mass solvent.

[0066] According to another aspect, the second mobilizing fluid is about 85% by mass solvent.

[0067] According to another aspect, the second mobilizing fluid is about 95% by mass solvent.

[0068] According to another aspect, the first mobilizing fluid is about 75%
by mass steam and the second mobilizing fluid is about 75% by mass solvent.

[0069] According to another aspect, the first mobilizing fluid is about 85%
by mass steam and the second mobilizing fluid is about 85% by mass solvent.

[0070] According to another aspect, the first mobilizing fluid is about 95%
by mass steam and the second mobilizing fluid is about 95% by mass solvent.

[0071] According to another broad aspect, a method of recovering bitumen from an underground reservoir penetrated by at least one well is described herein.
The method includes operating a first cyclic solvent process for recovering bitumen from an underground reservoir in the at least one well. The first cyclic solvent process includes injecting a mobilizing fluid into the reservoir, the mobilizing fluid including a hydrocarbon solvent; shutting in the mobilizing fluid that is in the reservoir, holding the mobilizing fluid in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir and, during a subsequent cyclic solvent process, when a pressure of the underground reservoir is less than 50% of a lithostatic pressure during the step of injecting the mobilizing fluid into the reservoir, converting the at least one well to be a producer well of a solvent flooding process, where one or more neighboring wells are injector wells and bitumen from the underground reservoir is produced from the at least one well.

[0072] According to another aspect, the mobilizing fluid includes steam, and/or a hydrocarbon solvent.

[0073] According to another broad aspect, a method of recovering bitumen from an underground reservoir penetrated by at least one well is described. The method includes operating a cyclic solvent process for recovering bitumen from an underground reservoir in the at least one well. The cyclic solvent process includes injecting a first mobilizing fluid into the reservoir, the first mobilizing fluid including a hydrocarbon solvent;
shutting in the first mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir. The method also includes providing an infill well in an unswept region of the underground reservoir formed between the at least one well and a neighboring well operating a cyclic solvent process; and operating a cyclic process for recovering bitumen from the underground reservoir in the infill well, the cyclic process including injecting a second mobilizing fluid into the reservoir, the second mobilizing fluid including steam;
shutting in the second mobilizing fluid that is in the reservoir; holding the second mobilizing fluid in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

[0074] According to another aspect, the step of injecting the second mobilizing fluid into the reservoir includes injecting the second mobilizing fluid into the reservoir at a pressure that is greater than 80% of a lithostatic pressure of the reservoir.

[0075] According to another aspect, the step of injecting the second mobilizing fluid into the reservoir includes injecting the second mobilizing fluid into the reservoir at a pressure that is in a range of about 50% to about 80% of a lithostatic pressure of the reservoir.

[0076] 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

[0077] 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.

[0078] FIG. 1A is a schematic cross sectional view of a underground reservoir, a vertical wellbore and a horizontal wellbore showing an example of dispersion of solvent and steam from along the horizontal wellbore after integrating solvent-based injection with cyclic steam stimulation processes;

[0079] FIG. 1B is a schematic cross sectional view of a underground reservoir, vertical wellbore and a horizontal wellbore showing an example of dispersion of solvent and steam from along the horizontal wellbore during a cyclic process;

[0080] FIG. 1C is a schematic cross sectional view of a underground reservoir, vertical wellbore and a horizontal wellbore showing an example of dispersion of solvent and steam from along the horizontal wellbore during a cyclic process;

[0081] FIG. 1D is a schematic cross sectional view of a underground reservoir, vertical wellbore and a horizontal wellbore showing an example of dispersion of solvent and steam from along the horizontal wellbore during a cyclic process;

[0082] FIG. 2 is a block diagram of a method of recovering bitumen from an underground reservoir, according to one embodiment;

[0083] FIG. 3 is a block diagram of a method of recovering bitumen from an underground reservoir, according to another embodiment;

[0084] FIG. 4 is a block diagram of a method of recovering bitumen from an underground reservoir, according to another embodiment;

[0085] FIG. 5 is a block diagram of a method of recovering bitumen from an underground reservoir, according to another embodiment;

[0086] FIG. 6 is a block diagram of a method of recovering bitumen from an underground reservoir, according to another embodiment; and

[0087] FIG. 7 is a graph comparing reservoir pressure over time for two extraction techniques: 1) seven cycles of CSS, and 2) four cycles of CSS followed by three cycles of CSP.

[0088] 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

[0089] 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.

[0090] 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.

[0091] 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."

[0092] 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.

[0093] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a range from 1 to 9.

[0094] "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. A) 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.
[00951 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.
[0096] "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.
[0097] 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 100. The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes.
[0098] 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.
[0099] 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.
[0100] 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."
[0101] 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.
[0102] The term "continuous process" as used herein refers to an oil recovery technique in which the injection of a viscosity reducing agent occurs in an injector wellbore to stimulate displacement of the oil alternatives with oil production occurring in a separate producer wellbore. The injector wellbore continuously injects the viscosity reducing agent into the reservoir and the producer wellbore continuously produces oil.
Continuous processes for heavy oil recovery may include steam-assisted gravity drainage (SAGD) process, solvent-assisted-steam-assisted gravity drainage (SA-SAGD) process, heated solvent vapor-assisted petroleum extraction (H-VAPEX) process, solvent flooding process, or any combination thereof.
[0103] The term "forecast injection volume" as used herein means an anticipated or expected volume of a fluid to be injected into the reservoir.

[0104] The term "lithostatic fracture pressure" as used herein means a pressure at which the rock above the reservoir (overburden) fractures. The lithostatic fracture pressure is the relationship between depth and increasing stress required to fracture/fail rock. The deeper a well, the higher the stress required to fail rock.
[0105] 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.
[0106] 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.
[0107] "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.
[0108] 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.
[0109] 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.
[0110] In spite of the technologies that have been developed, there remains a need in the field for methods of enhancing the recovery of bitumen.
[0111] Various approaches of enhancing solvent-based extraction processes with the addition of steam are described herein. The proposed approaches involve utilizing and integrating different steam processes and recovery mechanisms at different stages of solvent-based extraction processes to enhance the bitumen recovery from a reservoir.
[0112] Referring now to Figures 1A to 1D, illustrated therein are schematic cross sectional views of an underground reservoir, a vertical wellbore and a horizontal wellbore showing an example of dispersion of solvent and steam along the horizontal wellbore after integrating one or more cyclic solvent processes (CSPs) with one or more cyclic steam stimulation processes (CSSs).

[0113] For instance, FIG. 1A shows a schematic cross sectional view of an underground reservoir 100, a vertical wellbore 102 and a horizontal wellbore 104 showing an example of dispersion of solvent and steam along the horizontal wellbore after performing each a first cycle using a cyclic solvent process (CSP) 106, followed by a second cycle using a CSP 108, followed by a third cycle using a cyclic steam stimulation process (CSS) 110.
[0114] FIG. 1B is a schematic cross sectional view of an underground reservoir 100, a vertical wellbore 102 and a horizontal wellbore 104 showing an example of dispersion of solvent and steam along the horizontal wellbore after performing each a first cycle of a CSS 112, followed by a second cycle using a CSP 114, followed by a third cycle using a CSP 116, followed by a fourth cycle using a CSS 118.
[0115] FIG. 1C is a schematic cross sectional view of an underground reservoir 100, a vertical wellbore 102 and a horizontal wellbore 104 showing an example of dispersion of solvent and steam along the horizontal wellbore after performing each a first cycle of a CSP 120, followed by a second cycle of a CSS 122, followed by a third cycle of a CSS 124, followed by a fourth cycle using a CSP 126.
[0116] FIG. 1D is a schematic cross sectional view of an underground reservoir 100, a vertical wellbore 102 and a horizontal wellbore 104 showing an example of dispersion of solvent and steam along the horizontal wellbore after each a first cycle of a CSS 128, followed by a second cycle using a CSS 130, followed by a third cycle using CSP 132, followed by a fourth cycle using a CSP 134.
[0117] In the aforementioned CSPs, solvents may be used as a mobilizing fluid to enhance the extraction of petroleum products from the reservoir. Herein, the term "second mobilizing fluid" generally refers to a solvent for enhancing the extraction of petroleum products from the reservoir. The solvent 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.
[0118] 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 mol% C2-05 hydrocarbons on a mass basis. The solvent may be greater than 50 mor/0 propane, optionally with diluent when it is desirable to adjust the properties of the injectant to improve performance.
[0119] 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.
[0120] 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.
[0121] 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.
[0122] The solvent composition may comprise (i) an ether with 2 to 8 carbon atoms;
and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms. Ether may have 2 to 8 carbon atoms. Ether may be di-methyl ether, methyl ethyl ether, di-ethyl ether, methyl iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether, methyl iso-butyl ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-propyl butyl ether, propyl butyl ether, di-isobutyl ether, or di-butyl ether. Ether may be di-methyl ether. The non-polar hydrocarbon may a C2-C30 alkane. The non-polar hydrocarbon may be a C2-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.
[0123] 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).
[0124] In some embodiments, different steam processes and recovery mechanisms can be integrated with solvent-based extraction processes by initiating the steam processes prior to a first cycle of a solvent-based extraction process.
[0125] Referring now to FIG. 2, illustrated therein is a method 200 of recovering bitumen from an underground reservoir penetrated by at least one well. The method 200 includes at a step 202, injecting a first mobilizing fluid into the reservoir.
Generally, herein the term "first mobilizing fluid" refers to a steam-dominated fluid, where "steam-dominated" refers to a fluid that is primarily (e.g. greater than 50% by mass) steam.
Herein, "steam" refers to water in vapor form with a quality between 0% (i.e.
saturated steam) and 100% (i.e. dry steam). In some embodiments, the steam of the methods described herein has a quality of about 70 /o.The first mobilizing fluid may also be pure steam or water having a temperature above about 25 C. In some embodiments, the first mobilizing fluid may have a temperature of about 200 C. In other embodiments, the first mobilizing fluid may have a temperature of about 325 C.
[0126] The method 200 also includes, at a step 204, shutting in the first mobilizing fluid that is in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir. Shutting in the first mobilizing fluid that is in the reservoir generally includes stopping injecting the first mobilizing fluid into the reservoir and sealing the reservoir. For instance, stopping injecting the first mobilizing fluid into the reservoir may include shutting a steam valve at a steam injection header on the pad, for CSP it would be turning off injection pumps in the injection system. In another example, after turning off injection, the valves on the wellhead of injection/production well would be closed. This would be on the production tubing and casing system.
[0127] At step 206, the first mobilizing fluid in the reservoir is held in the reservoir for a period of time. For example, the period of time may be in a range of about 4 hours to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0128] At step 208, bitumen of a lowered viscosity (e.g. relative to bitumen that remains in the reservoir) is recovered from the reservoir.
[0129] It should be understood that in some embodiments of the method 200, the steps 202-208 are repeated one or more times prior to proceeding to step 210.
[0130] At step 210, at least one casing integrity issue in the wellbore is detected.
Herein, casing integrity issues generally include any physical indication that damages or threatens to damage the wellbore casing. In some instances, the casing integrity issues may be detected by a person performing a casing integrity check of the wellbore (e.g. on a scheduled basis) with quantitative measure of ovalities in the casing and shift used to classify damage and allowable wellbore service. Herein, the term "ovality"
refers to a measure of mechanical damage that can be used to interpret strain, offset, and deformation shape within a wellbore. Ovality is specifically defined as a difference between a shape of an inner wellbore and an ideal circular shape (e.g. same inner diameter throughout wellbore). Ovality can also be considered to be a difference between a maximum inner diameter and a minimum inner diameter of a wellbore. Ovality is typically measured in millimeters with higher ovality measurements (ovalities) leading to higher impairment classifications.
[0131] Generally, the integrity of a wellbore, or more specifically of the casing of a wellbore, has four components: detection, prevention, response and recover. In detection, monitoring systems (as described below) and/or casing integrity checks may be performed to detect a casing integrity issue. In prevention, design of the wellbore (e.g.
casing, threaded connection, materials, etc.), operating practices and shear stress management and well environmental control (H2S purge) are all parameters that can contribute to the prevention of casing integrity issues of a wellbore. In response, well control capability (e.g. well kill procedures) and casing repair (e.g. patch, slim hole, and other repair) are each common responses to casing integrity issues. Finally, in recover, regulatory compliance and improved well utility (e.g. producer only, injector only, redeploy well and re-drill) are all important considerations for recovering from well integrity issues.
[0132] Some examples of casing integrity detection include, but are not limited to, differential flow pressure (DFP) issues. For example, DFP issues may arise when a wellbore is injecting with elevated pressure while steaming and experiences sudden increase in flow rate with a drop in instantaneous pressure. DFP issues may be indicative of a break in the casing. In some embodiments, the monitoring system described herein may be a DFP monitoring system. DFP monitoring systems may be used to identify a potential casing integrity issue during steam injection for CSS, for example.
During normal steam injection, a steam manifold pressure and wellhead pressure increase or remain constant with steady to increasing steam injection rates. There is pressure and rate measurement on wells and manifold. If the injection rate increases and wellhead and/or manifold pressure declines it could be indicative of a casing integrity issue.
[0133] Casing integrity issues may vary in severity. For example, casing integrity issues may be higher consequence issues, such as, but not limited to a high pressure failure outside the target reservoir with fluids (e.g. steam, water, oil) entering out of zone.
[0134] In other examples, casing integrity issues may be an inability to steam well at high pressure as casing integrity doesn't allow high pressure steam (i.e.
greater than 6 MPa bottom hole pressure).

[0135] In other examples, casing integrity issues may be an inability to steam well at any pressure.
[0136] In other examples, casing integrity issues may be an inability to steam or produce from well.
[0137] In other examples, casing integrity issues may include well failure and inability to steam wells in immediate area (e.g. within one or greater well spacing at 4 or 8 acre) [0138] In some embodiments, the at least one casing integrity issue in the wellbore is detected by a monitoring system. For instance, in some embodiments, the monitoring system may be a passive seismic monitoring system. Passive seismic monitoring systems generally include a dedicated monitoring well on a pad with geophones installed downhole (e.g. below the surface and within wellbore 102). Geophones convert movement (e.g. of the ground) into voltage that can be recorded at a recording station.
By dispersing a plurality of geophones downhole within the monitoring well, the geophones can triangulate movement of the ground to identify a well integrity event and/or a casing integrity issue within a neighboring wellbore. For instance, a casing failure can be identified by distinctive events with seismic signatures (p-waves & s-waves). In some embodiments, passive seismic monitoring systems can identify events during injection and soaking period for CSS wells.
[0139] In some embodiments, the monitoring system may be an N2 soak monitoring system. N2 soak monitoring systems may be used to detect a casing integrity issue in a wellbore after injection of a mobilizing fluid into the wellbore and before production of bitumen from the wellbore. N2 soak monitoring systems utilize a process where N2 is injected down the casing of a wellbore and left to soak (i.e. for a period of time in a range of about 24 to 48 hours). The fluid level and pressure in casing can be monitored. Significant pressure changes for the shut-in well could indicate casing integrity issues.
[0140] In some embodiments, the monitoring system may be casing integrity checks. Herein, the term "casing integrity checks" is used as a catch all phrase for a suite of tests. For instance, in one example of a casing integrity check, the tubing and bottom-hole pump can be pulled out of the well for testing with concern about the intermediate casing and not the tubing. For example, in instances where the structural integrity of an intermediate casing of the wellbore is of concern, the tests may include a pressure test on the tubing and casing of a wellbore to see if the tubing and/or the casing can hold required pressures. The tests may also include running tools on a wire line truck (e.g.
such as but not limited to a scraper / drift) to identify obstructions or changes in well shape (e.g. circular vs. oval) and depth of the obstruction that is located. This test can include other wire line tools such as but not limited to calipers that will provide details of shape of casing and areas of casing integrity issues. The tests can also include other wire line tools such as but not limited to a corrosion logging tool. This a tool that can produce a corrosion log report that measures corrosion in the casing (e.g. external and internal).
If the thickness of the casing is below a predetermined threshold for the pressure, then casing integrity may be an issue. Examples of a corrosion logging tool may include but are not limited to Vertilog, DVERT, MVERT, and HVERT.
[0141] In some embodiments, the casing integrity issues may be found by performing casing integrity checks on a scheduled basis with quantitative measure of ovalities and shift used to classify damage and allowable wellbore service.
[0142] At a step 212, in response to detecting the casing integrity issue in the wellbore, a second mobilizing fluid is injected through the wellbore into the reservoir.
Injecting the second mobilizing fluid through the wellbore into the reservoir can reduce a pressure of the reservoir and reduce thermal cycling. Generally, the second mobilizing fluid includes a hydrocarbon solvent (as described above).
[0143] In some embodiments, the second mobilizing fluid differs from the first hydrocarbon fluid.
[0144] In some embodiments, detecting the casing integrity issue may occur during an injection step of a subsequent CSS. Here, in response to detecting the casing integrity issue and prior to injecting the second mobilizing fluid, injection of the first mobilizing fluid into the underground reservoir may be shut in and held for a period of time.
For example, holding the first mobilizing fluid in the underground reservoir may be for a period of time in a range of about 24 to 48 hours. Shutting in and holding the first mobilizing fluid in the underground reservoir may provide for performing diagnostic work to confirm the casing integrity issue in the wellbore. For instance, holding the first mobilizing fluid in the reservoir after detecting the casing integrity issue may include analyzing data collected from the wellbore and/or the reservoir prior to detecting the casing integrity issue to confirm the casing integrity issue and/or analyzing data collected from the wellbore and/or the reservoir after detecting the casing integrity issue to confirm the casing integrity issue.
[0145] An effect of switching from the first mobilizing fluid (e.g. steam) to the second mobilizing fluid (e.g. solvent) (e.g. switching from a CSS to a CSP) is reducing the pressure of the underground reservoir. Switching to a CSP from a CSS may therefore help alleviate and/or mitigate issues with wellbores undergoing a CSS, particularly in CSSs that are mid to late life (e.g. after about 3 -4 cycles of CSS). For instance, FIG. 7 is a graph comparing reservoir pressure over time for two extraction techniques:
1) seven cycles of CSS, and 2) four cycles of CSS followed by three cycles of CSP, at a same injection rate. This example shows that CSPs can significantly lower the operating pressure of an underground reservoir and thus help mitigate pump, fluid excursion and/or casing integrity issues associated with extracting bitumen from the underground reservoir.
The decrease in pressure of the reservoir during a CSP may be due to one or more of a number of factors. For instance, generally, mobilizing fluids used in CSPs have less thermal energy than mobilizing fluids used in CSSs (e.g. solvent used in a CSP
may be about 50 C with no phase change and steam used in a CSS may be about 300 C
with a phase change to water). In another example, there is a sub-fracture pressure requirement for CSP technology. In another example, solvents used in CSPs are generally partially miscible in bitumen. Any one or more of these factors may help in lowering the underground reservoir pressure and limit casing integrity issues, as well as, an out of zone fluid excursion.
[0146] At step 214, the second mobilizing fluid is shut into the reservoir. Shutting in the second mobilizing fluid into the reservoir generally lowers the viscosity of at least a portion of the bitumen in the reservoir.

[0147] At step 216, the second mobilizing fluid in the reservoir is held in the reservoir for a period of time. For example, the period of time may be in a range of about 4 hours to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0148] At step 218, bitumen of lowered viscosity is recovered from the reservoir.
[0149] In some embodiments of the method 200, step 202 of injecting the first mobilizing fluid through the wellbore into the reservoir, step 204 of shutting in the first mobilizing fluid that is in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir, step 206 of holding the first mobilizing fluid in the reservoir and step 208 of recovering bitumen of lowered viscosity from the reservoir are all part of a CSS process for recovering bitumen from the underground reservoir.
[0150] In some embodiments of the method 200, step 212 of injecting the second mobilizing fluid through the wellbore into the reservoir, step 214 of shutting in the second mobilizing fluid that is in the reservoir, step 216 of holding the second mobilizing fluid in the reservoir and step 218 of recovering bitumen of lowered viscosity from the reservoir are part of a CSP for recovering bitumen from the underground reservoir.
[0151] In another aspect, a method 300 of recovering bitumen from an underground reservoir penetrated by at least one wellbore is also described herein. This method includes, at a step 302, injecting a first mobilizing fluid through the wellbore into the reservoir. As discussed above with reference to the method 200, the first mobilizing fluid generally includes steam.
[0152] At step 304, the first mobilizing fluid is shut into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir.
[0153] At step 306, the first mobilizing fluid in the reservoir is held in the reservoir for a period of time. For example, the period of time may be in a range of about 4 hours to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0154] At a step 308, bitumen of lowered viscosity is recovered from the reservoir.
[0155] At a step 310, at least one fluid excursion issue in the wellbore is detected.
Herein, "fluid excursion issue" generally refers to fluid injected into the production interval that leaves the target interval. The injected fluid can be determined to come from a specific well. It is the fluid already injected from the well leaving a geologic zone that is of concern. Fluid already injected from the well leaving a geologic zone implies fluid has left the target injection and production reservoir interval and migrated through an isolating geologic feature (i.e. normally non-permeable shale layer) to another zone/interval. The cause of fluid excursion can vary and include but is not limited to: casing failure, vertical fracture, fault in isolating geologic feature (shale), and/or flow outside casing.
[0156] In some embodiments, fluid excursion issues can be found using monitoring wells. In some embodiments, detecting the at least one fluid excursion issue at step 310 is by monitoring a pressure of the reservoir via one or more observation wellbores offset from a production pad including the wellbore and detecting an increase in the pressure of the reservoir.
[0157] In some embodiments, detecting the at least one fluid excursion issue at step 310 is by analyzing injection and production pressure profiles of pad or pressure profiles of offset observation wellbores. For instance, sudden changes (or responses) in pressure over time may be referred to as "sharp" responses and may be indicative of fluid excursion. Sharp responses may be typified by a quick increase in dP/dt to a peak followed by an equally quick drop off. For instance, a typical range for a "quick" increase may be an increase in pressure over time in a range of about 50 to about 100 kPa/day followed by a decrease in a range of about 50 to about 100 kPa/day over a period of about 12 hours. Sharp response such as those described herein may be self-correcting and can generally be identified through DFPs, seismic activity or response triangulation.
[0158] "Dull" responses may also be indicative of fluid excursion. Dull responses are typified by a slow increase in baseline changes in pressure over time. For instance, dull responses generally fall in the range of 0-50 kPa/day. Dull responses are generally not self-correcting. This can be conceptually visualized as a "leaker hose".
Dull responses may be identified through seismic activity or response triangulation and are not generally associated with DFPs.
[0159] In some embodiments, detecting the at least one fluid excursion issue may occur during an injection step of the CSS. Here, in response to detecting the at least one fluid excursion issue and prior to injecting the second mobilizing fluid, the first mobilizing fluid may be shut in and held in the reservoir. Shutting in and holding the first mobilizing fluid in the reservoir may be for a period of time in a range of about 24 to 48 hours.
Shutting in and holding the first mobilizing fluid in the reservoir may provide for performing diagnostic work to confirm the at least one fluid excursion issue in the wellbore. Shutting in and holding the first mobilizing fluid in the reservoir may provide for analyzing data collected from the wellbore and/or the underground reservoir prior to detecting the fluid excursion issue to confirm the fluid excursion issue. Shutting in and holding the first mobilizing fluid in the reservoir may provide for analyzing data collected from the wellbore and/or the underground reservoir after detecting the fluid excursion issue to confirm the fluid excursion issue. In some embodiments, detecting the fluid excursion issue may occur during the shutting in and/or the holding step of a subsequent CSS.
[0160] At a step 312, in response to detecting the at least one fluid excursion issue in the wellbore, a second mobilizing fluid is injected into the reservoir. As noted above with reference to method 200, the second mobilizing fluid includes a hydrocarbon solvent.
[0161] Generally, during injection of the second mobilizing fluid, the wellbore has a lower bottom-hole pressure relative to injection of the first mobilizing fluid due to the second mobilizing fluid having, for example, a lower thermal energy. Further, the sub-fracture pressure nature of CSP and partial miscibility of the second mobilizing fluid in bitumen also may contribute to the pressure of the underground reservoir decreasing during CSPs relative to CSSs.
[0162] At step 314, the second mobilizing fluid is shut into the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir.
[0163] At step 316, the second mobilizing fluid in the reservoir is held in the reservoir for a period of time. For example, the period of time may be in a range of about 4 hours to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0164] At a step 318, bitumen of lowered viscosity is recovered from the reservoir.
[0165] In some embodiments, step 302 of injecting the first mobilizing fluid through the wellbore into the reservoir, step 304 of shutting in the first mobilizing fluid that is in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir, step 306 of holding the first mobilizing fluid in the reservoir and step 308 of recovering bitumen of lowered viscosity from the reservoir are part of a CSS process for recovering bitumen from the underground reservoir.
[0166] In some embodiments, step 312 of injecting the second mobilizing fluid through the wellbore into the reservoir, step 314 of shutting in the second mobilizing fluid that is in the reservoir, step 316 of holding the second mobilizing fluid in the reservoir and step 318 of recovering bitumen of lowered viscosity from the reservoir are part of a CSP
for recovering bitumen from the underground reservoir.
[0167] In another aspect, a method 400 of recovering bitumen from an underground reservoir penetrated by at least one well is also described herein. Method 400 includes at a step 402, injecting a first mobilizing fluid into the reservoir, the first mobilizing fluid including steam;
[0168] At step 404, method 400 includes shutting in the first mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir.
[0169] At step 406, the first mobilizing fluid in the reservoir is held in the reservoir for a period of time. For example, the period of time may be in a range of about 4 hours to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0170] At a step 408, method 400 includes recovering bitumen of lowered viscosity from the reservoir.
[0171] At a step 410, method 400 includes detecting a pump issue in the wellbore.
Detecting pump issues in the at least one well may include detecting a low fillage rate of a pump of the well. For instance, an exemplary low fillage rate may be in a range of about 25% or lower. Detecting pump issues in the at least one well may also include detecting flashing of a fluid within a pump of the well and/or detecting a gaseous fluid in production tubing of the casing.
[0172] Pump issues may be caused by operating conditions of the produced fluid being in a lower pressure and high temperature regime, which, for example, may result in flashing of liquid water to vapor in the underground reservoir or within the pump itself.
Generally, the second mobilizing fluid being injected into the underground reservoir will have a different liquid/vapor profile when compared to the first mobilizing fluid being injected into the underground reservoir. Specifically, the second mobilizing fluid can be injected at a lower temperature than the first mobilizing fluid, thereby reducing the pressure of the underground reservoir. The second mobilizing fluid, bitumen, and water in the reservoir may therefore be at a lower temperature during the CSP when compared to the CSS, and produced fluids can move out of liquid/vapor window and into the liquid only window. Operating in the liquid only window may increase pump efficiency, increase fillage and improve pump run time, prevent flashing in the pump, and potentially delay pump failure.
[0173] In some embodiments, detecting the pump issue may occur during an injection step of the CSS. Here, in response to detecting the pump issue and prior to injecting the second mobilizing fluid, injection of the first mobilizing fluid into the underground reservoir may be shut in and held. Shutting in and holding the first mobilizing fluid in the reservoir may be for a period of time in a range of about 24 to 48 hours.
Shutting in and holding the first mobilizing fluid in the reservoir may provide for performing diagnostic work to confirm the pump issue in the wellbore. Shutting in and holding the first mobilizing fluid in the reservoir may provide for analyzing data collected from the wellbore and/or the underground reservoir prior to detecting the pump issue to confirm the pump issue. Shutting in and holding the first mobilizing fluid in the reservoir may provide for analyzing data collected from the wellbore and/or the underground reservoir after detecting the pump issue to confirm the pump issue. In some embodiments, detecting the pump issue may occur during the shutting in and/or the holding step of a subsequent CSS.
[0174] At step 412, a second mobilizing fluid is injected into the reservoir. As noted above, the second mobilizing fluid includes a hydrocarbon solvent. Step 412 of injecting a second mobilizing fluid into the reservoir is initiated upon detecting a pump issue in the at least one well.
[0175] At step 414, method 400 includes shutting in the second mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir.

[0176] At step 416, the second mobilizing fluid in the reservoir is held in the reservoir for a period of time. For example, the period of time may be in a range of about 4 hours to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0177] At step 418, method 400 includes recovering bitumen of lowered viscosity from the reservoir.
[0178] In some embodiments, step 402 of injecting the first mobilizing fluid through the wellbore into the reservoir, step 404 of shutting in the first mobilizing fluid that is in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir, step 406 of holding the first mobilizing fluid in the reservoir, and step 408 of recovering bitumen of lowered viscosity from the reservoir are part of a CSS process for recovering bitumen from the underground reservoir.
[0179] In some embodiments, step 412 of injecting the second mobilizing fluid through the wellbore into the reservoir, step 414 of shutting in the second mobilizing fluid that is in the reservoir, step 416 of holding the second mobilizing fluid in the reservoir and step 418 of recovering bitumen of lowered viscosity from the reservoir are part of a CSP
for recovering bitumen from the underground reservoir.
[0180] According to another aspect, a method 500 of recovering bitumen from an underground reservoir penetrated by at least one well is described herein.
Method 500 includes at a step 502, operating a first cyclic solvent process for recovering bitumen from an underground reservoir in the at least one well. The first cyclic solvent process includes, at a step 504, injecting a first mobilizing fluid into the reservoir. As noted above, the first mobilizing fluid includes a hydrocarbon solvent.
[0181] Step 502 of operating the first cyclic solvent process also.
includes, at a step 506, shutting in the first mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir.
[0182] Step 502 of operating the first cyclic solvent process also includes, at a step 508, recovering bitumen of lowered viscosity from the reservoir.
[0183] At a step 510, during a subsequent cyclic solvent process, when a pressure of the underground reservoir is less than 50% of a lithostatic pressure during the step of injecting the first mobilizing fluid into the reservoir, the at least one well is converted to a producer well of a solvent flooding process, where one or more neighboring wells are injector wells and bitumen from the underground reservoir is produced from the converted producer well.
[0184] According to another aspect, a method 600 of recovering bitumen from an underground reservoir penetrated by at least one well is disclosed herein.
Method 600 includes at a step 602 operating a cyclic solvent process for recovering bitumen from an underground reservoir in the at least one well. The cyclic solvent process includes, at a step 604, injecting a first mobilizing fluid into the reservoir. The first mobilizing fluid includes a hydrocarbon solvent.
[0185] Step 602 of operating a cyclic solvent process for recovering bitumen from an underground reservoir in the at least one well also includes, at a step 606, shutting in the first mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir.
[0186] Step 602 of operating a cyclic solvent process for recovering bitumen from an underground reservoir in the at least one well also includes, at a step 608, recovering bitumen of lowered viscosity from the reservoir.
[0187] At a step 610, an infill well is provided in an unswept region of the underground reservoir formed between the at least one well and a neighboring well operating a cyclic solvent process.
[0188] At a step 612, a cyclic process is operated in the infill well for recovering bitumen from the underground reservoir. The cyclic process operated at step includes, at a step 614, injecting a second mobilizing fluid into the reservoir. The second mobilizing fluid includes steam.
[0189] The cyclic process operated at step 612 also includes, at a step 616, shutting in the second mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir and, at a step 618, recovering bitumen of lowered viscosity from the reservoir.

[0190] In some embodiments, the step of injecting the second mobilizing fluid into the reservoir includes injecting the second mobilizing fluid into the reservoir at a pressure that is greater than 50% of a lithostatic pressure of the reservoir, within a range of about 50% to about 80% of a lithostatic pressure of the reservoir, or greater than 80% of a lithostatic pressure of the reservoir.
[0191] FIG. 7 is a graph comparing reservoir pressure over time for two extraction techniques: 1) seven cycles of CSS, and 2) four cycles of CSS followed by three cycles of CSP, each having the same injection rate. This example shows that CSPs can significantly lower the operating pressure of an underground reservoir and thus help mitigate pump, fluid excursion and/or casing integrity issues associated with extracting bitumen from the underground reservoir.
[0192] 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 (65)

Claims What is claimed is:

1. A method of recovering bitumen from an underground reservoir penetrated by a wellbore, the wellbore including a casing, the method comprising:
injecting a first mobilizing fluid through the wellbore into the reservoir, the first mobilizing fluid including steam;
shutting in the first mobilizing fluid that is in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir;
holding the first mobilizing fluid in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir;
recovering bitumen of lowered viscosity from the reservoir;
during a subsequent step of injecting first mobilizing fluid into the reservoir, shutting in the first mobilizing fluid into the reservoir, or holding the first mobilizing fluid in the reservoir, detecting a casing integrity issue in the wellbore;
in response to detecting the casing integrity issue in the wellbore, injecting a second mobilizing fluid through the wellbore into the reservoir to reduce a pressure of the reservoir and to reduce thermal cycling, the second mobilizing fluid including a hydrocarbon solvent;
shutting in the second mobilizing fluid that is in the reservoir;
holding the second mobilizing fluid in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir; and recovering the bitumen of lowered viscosity from the reservoir.

2. The method of claim 1, wherein the second mobilizing fluid differs from the first mobilizing fluid.

3.
The method of claim 1 or claim 2, wherein the steps of injecting the first mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid that is in the reservoir to lower the viscosity of the at least a portion of the bitumen in the reservoir, and recovering the bitumen of lowered viscosity from the reservoir are part of a cyclic steam stimulation (CSS) process for recovering bitumen from the reservoir.

4. The method of any one of claims 1 to 3, wherein the steps of injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the second mobilizing fluid that is in the reservoir, holding the second mobilizing fluid in the reservoir and recovering the bitumen of lowered viscosity from the reservoir are part of a cyclic solvent process (CSP) for recovering bitumen from the reservoir.

5. The method of any one of claims 1 to 4, wherein detecting the at least one casing integrity issue is by a monitoring system.

6. The method of claim 5, wherein the monitoring system is a passive seismic monitoring system, a differential flow pressure monitoring system and/or an N2 soak monitoring system.

7. The method of any one of claims 1 to 6, wherein detecting the casing integrity issue is by performing casing integrity checks.

8. The method of claim 7, wherein the casing integrity checks include measuring ovalities in the casing.

9. The method of any one of claims 1 to 8, wherein the casing integrity issue includes a decline in a structural integrity of an intermediate casing of the wellbore.

10. The method of any one of claims 1 to 9, further comprising, after detecting the casing integrity issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid that is in the reservoir and holding the first mobilizing fluid in the reservoir.

11. The method of claim 10, wherein the step of holding the first mobilizing fluid in the reservoir after detecting the casing integrity issue is for a period of time in a range of about 24 to 48 hours.

12. The method of claim 10 or claim 11, wherein the step of holding the first mobilizing fluid in the reservoir after detecting the casing integrity issue includes analyzing data collected from the wellbore and/or the reservoir prior to detecting the casing integrity issue to confirm the casing integrity issue.

13. The method of any one of claims 10 to 12, wherein the step of holding the first mobilizing fluid in the reservoir after detecting the casing integrity issue includes analyzing data collected from the wellbore and/or the reservoir after detecting the casing integrity issue to confirm the casing integrity issue.

14. The method of any one of claims 1 to 13 further comprising, after detecting the casing integrity issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, recovering fluid from the reservoir to reduce the pressure of the reservoir.

15. The method of any one of claims 1 to 14, wherein the step of holding the first mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

16. The method of any one of claims 1 to 15, wherein the step of holding the second mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

17. A method of recovering bitumen from an underground reservoir penetrated by at a wellbore, the method comprising:
injecting a first mobilizing fluid through the wellbore into the reservoir, the first mobilizing fluid including steam;
shutting in the first mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir;
holding the first mobilizing fluid in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir;
recovering bitumen of lowered viscosity from the reservoir;
during a subsequent step of injecting first mobilizing fluid into the reservoir, shutting in the first mobilizing fluid into the reservoir or holding the first mobilizing fluid in the reservoir, detecting at least one fluid excursion issue from the wellbore;

in response to detecting the at least one fluid excursion issue from the wellbore, injecting a second mobilizing fluid into the reservoir, the second mobilizing fluid including a hydrocarbon solvent;
shutting in the second mobilizing fluid that is in the reservoir;
holding the second mobilizing fluid in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir; and recovering the bitumen of lowered viscosity from the reservoir.

18. The method of claim 17, wherein the second mobilizing fluid differs from the first mobilizing fluid.

19. The method of claim 17 or claim 18, wherein the steps of injecting the first mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid that is in the reservoir to lower the viscosity of the at least a portion of the bitumen in the reservoir, and recovering the bitumen of lowered viscosity from the reservoir are part of a cyclic steam stimulation (CSS) process for recovering bitumen from the reservoir.

20. The method of any one of claims 17 to 19, wherein the steps of injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the second mobilizing fluid that is in the reservoir, holding the second mobilizing fluid in the reservoir and recovering the bitumen of lowered viscosity from the reservoir are part of a cyclic solvent process (CSP) for recovering bitumen from the reservoir

21. The method of any one of claims 17 to 20, wherein the detecting the at least one fluid excursion issue is by monitoring a pressure of the reservoir via one or more observation wellbores offset from a production pad including the wellbore and detecting an increase in the pressure of the reservoir of target reservoir or other geologic zone.

22. The method of any one of claims 17 to 20, wherein the detecting the at least one fluid excursion issue is by analyzing injection and production pressure profiles.

23. The method of any one of claims 17 to 22, further comprising, after detecting the fluid excursion issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid that is in the reservoir and holding the first mobilizing fluid in the reservoir.

24. The method of claim 23, wherein the step of holding the first mobilizing fluid in the reservoir after detecting the fluid excursion issue is for a period of time in a range of about 24 to 48 hours.

25. The method of claim 23 or claim 24, wherein the step of holding the first mobilizing fluid in the reservoir after detecting the fluid excursion issue includes analyzing data collected from the wellbore and/or the reservoir prior to detecting the fluid excursion issue to confirm the fluid excursion issue.

26. The method of any one of claims 23 to 25, wherein the step of holding the first mobilizing fluid in the reservoir after detecting the fluid excursion issue includes analyzing data collected from the wellbore and/or the reservoir after detecting the fluid excursion issue to confirm the fluid excursion issue.

27. The method of any one of claims 17 to 26 further comprising, after detecting the fluid excursion issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, recovering fluid from the reservoir to reduce the pressure of the reservoir.

28. The method of any one of claims 17 to 27, wherein the step of holding the first mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

29. The method of any one of claims 17 to 28, wherein the step of holding the second mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

30. A method of recovering bitumen from an underground reservoir penetrated by at least one well, the method comprising:
injecting a first mobilizing fluid into the reservoir, the first mobilizing fluid including steam;
shutting in the first mobilizing fluid that is in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir;

holding the first mobilizing fluid in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir;
recovering bitumen of lowered viscosity from the reservoir;
during a subsequent step of injecting first mobilizing fluid into the reservoir, shutting in the first mobilizing fluid into the reservoir or holding the first mobilizing fluid in the reservoir, detecting at least one pump issue in the wellbore;
in response to detecting the at least one pump issue, injecting a second mobilizing fluid into the reservoir, the second mobilizing fluid including a hydrocarbon solvent;
shutting in the second mobilizing fluid that is in the reservoir;
holding the second mobilizing fluid in the reservoir to lower the viscosity of at least a portion of the bitumen in the reservoir; and recovering the bitumen of lowered viscosity from the reservoir.

31. The method of claim 30, wherein the second mobilizing fluid differs from the first mobilizing fluid.

32. The method of claim 30 or claim 31, wherein the steps of injecting the first mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid that is in the reservoir to lower the viscosity of the at least a portion of the bitumen in the reservoir, and recovering the bitumen of lowered viscosity from the reservoir are part of a cyclic steam stimulation (CSS) process for recovering bitumen from the reservoir.

33. The method of any one of claims 30 to 32, wherein the steps of injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the second mobilizing fluid that is in the reservoir, holding the second mobilizing fluid in the reservoir and recovering the bitumen of lowered viscosity from the reservoir are part of a cyclic solvent process (CSP) for recovering bitumen from the reservoir.

34. The method of any one of claims 30 to 33, wherein detecting pump issues in the at least one well includes detecting a low fillage rate of a pump of the well.

35. The method of any one of claims 30 to 33, wherein detecting pump issues in the at least one well includes detecting flashing of a fluid within a pump of the well.

36. The method of any one of claims 30 to 33, wherein detecting pump issues in the at least one well includes detecting a gaseous fluid in production tubing of the wellbore.

37. The method of any one of claims 30 to 33, wherein detecting pump issues in the at least one well includes detecting failure of a pump of the well.

38. The method of any one of claims 30 to 37, further comprising, after detecting the at least one pump issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, shutting in the first mobilizing fluid that is in the reservoir and holding the first mobilizing fluid in the reservoir.

39. The method of claim 38, wherein the step of holding the first mobilizing fluid in the reservoir after detecting the pump issue is for a period of time in a range of about 24 to 48 hours.

40. The method of claim 38 or claim 39, wherein the step of holding the first mobilizing fluid in the reservoir after detecting the pump issue includes analyzing data collected from the wellbore and/or the reservoir prior to detecting the pump issue to confirm the pump issue.

41. The method of any one of claims 38 to 40, wherein the step of holding the first mobilizing fluid in the reservoir after detecting the pump issue includes analyzing data collected from the wellbore and/or the reservoir after detecting the pump issue to confirm the pump issue.

42. The method of any one of claims 30 to 41 further comprising, after detecting the at least one pump issue and prior to injecting the second mobilizing fluid through the wellbore into the reservoir, recovering fluid from the reservoir to reduce the pressure of the reservoir.

43. The method of any one of claims 30 to 42, wherein the step of holding the first mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

44. The method of any one of claims 30 to 43, wherein the step of holding the second mobilizing fluid in the reservoir is for a period of time in a range of about 24 to 48 hours.

45. The method of any one of claims 1 to 44, wherein the first mobilizing fluid is a steam-dom inated mobilizing fluid.

46. The method of any one of claims 1 to 44, wherein the first mobilizing fluid is steam with a quality between 0% and 100%.

47. The method of claim 46, wherein the first mobilizing fluid is steam with a quality of about 70%.

48. The method of any one of claims 1 to 47, wherein the first mobilizing fluid is steam having a temperature above about 25 C.

49. The method of any one of claims 1 to 48, wherein the first mobilizing fluid is steam having a temperature above about 200 C.

50. The method of any one of claims 1 to 49, wherein the first mobilizing fluid is steam having a temperature above about 325 C.

51. The method of any one of claims 1 to 50, wherein the second mobilizing fluid is one of: a C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, and a gas plant condensate comprising alkanes, naphthenes, and aromatics.

52. The method of any one of claims 1 to 51, wherein the first mobilizing fluid is about 75% by mass steam.

53. The method of any one of claims 1 to 51, wherein the first mobilizing fluid is about 85% by mass steam.

54. The method of any one of claims 1 to 51, wherein the first mobilizing fluid is about 95% by mass steam.

55. The method of any one of claims 1 to 51, wherein the second mobilizing fluid is about 75% by mass solvent.

56. The method of any one of claims 1 to 51, wherein the second mobilizing fluid is about 85% by mass solvent.

57. The method of any one of claims 1 to 51, wherein the second mobilizing fluid is about 95% by mass solvent.

58. The method of any one of claims 1 to 57, wherein the first mobilizing fluid is about 75% by mass steam and the second mobilizing fluid is about 75% by mass solvent.

59. The method of any one of claims 1 to 57, wherein the first mobilizing fluid is about 85% by mass steam and the second mobilizing fluid is about 85% by mass solvent.

60. The method of any one of claims 1 to 57, wherein the first mobilizing fluid is about 95% by mass steam and the second mobilizing fluid is about 95% by mass solvent.

61. A method of recovering bitumen from an underground reservoir penetrated by at least one well, the method comprising:
operating a first cyclic solvent process for recovering the bitumen from the underground reservoir in the at least one well, the first cyclic solvent process including:
injecting a mobilizing fluid into the reservoir, the mobilizing fluid including a hydrocarbon solvent;
shutting in the mobilizing fluid that is in the reservoir, holding the mobilizing fluid in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir; and recovering the bitumen of lowered viscosity from the reservoir; and during a subsequent cyclic solvent process, when a pressure of the underground reservoir is less than 50% of a lithostatic pressure during the step of injecting the mobilizing fluid into the reservoir, converting the at least one well to be a producer well of a solvent flooding process, where one or more neighboring wells are injector wells and bitumen from the underground reservoir is produced from the at least one well.

62. The method of claim 61, wherein the mobilizing fluid includes steam, and/or a hydrocarbon solvent.

63. A method of recovering bitumen from an underground reservoir penetrated by at least one well, the method comprising:
operating a cyclic solvent process for recovering the bitumen from the underground reservoir in the at least one well, the cyclic solvent process including:
injecting a first mobilizing fluid into the reservoir, the first mobilizing fluid including a hydrocarbon solvent;
shutting in the first mobilizing fluid that is in the reservoir to lower a viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir; and providing an infill well in an unswept region of the underground reservoir formed between the at least one well and a neighboring well operating a cyclic solvent process; and operating a cyclic process for recovering bitumen from the underground reservoir in the infill well, the cyclic process including injecting a second mobilizing fluid into the reservoir, the second mobilizing fluid including steam;
shutting in the second mobilizing fluid that is in the reservoir;
holding the second mobilizing fluid in the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering the bitumen of lowered viscosity from the reservoir.

64. The method of claim 63, wherein the step of injecting the second mobilizing fluid into the reservoir includes injecting the second mobilizing fluid into the reservoir at a pressure that is greater than 80% of a lithostatic pressure of the reservoir.

65. The method of claim 63, wherein the step of injecting the second mobilizing fluid into the reservoir includes injecting the second mobilizing fluid into the reservoir at a pressure that is in a range of about 50% to about 80% of a lithostatic pressure of the reservoir.