CA2898943A1

CA2898943A1 - Methods of performing cyclic hydrocarbon production processes

Info

Publication number: CA2898943A1
Application number: CA2898943A
Authority: CA
Inventors: Tapantosh Chakrabarty
Original assignee: Imperial Oil Resources Ltd
Current assignee: Imperial Oil Resources Ltd
Priority date: 2015-07-30
Filing date: 2015-07-30
Publication date: 2015-09-30
Anticipated expiration: 2035-07-30
Also published as: CA2898943C

Abstract

Methods of performing cyclic hydrocarbon production processes are disclosed herein.
The methods include injecting a diluent into a subterranean formation to dilute viscous hydrocarbons that are present within the subterranean formation and generate reduced-viscosity hydrocarbons. The methods further include producing a product hydrocarbon stream from the subterranean formation and monitoring a variable of the product hydrocarbon stream that is indicative of a diluted viscous hydrocarbon fraction. The methods also include adjusting at least one property of the diluent to define a modified diluent. The adjusting is based, at least in part, on the variable of the product hydrocarbon stream and the adjusting includes adjusting to mitigate formation of a heavy liquid hydrocarbon fraction within the subterranean formation.

Description

=
METHODS OF PERFORMING CYCLIC HYDROCARBON PRODUCTION
PROCESSES
FIELD OF THE DISCLOSURE
The present disclosure is directed to methods of performing cyclic hydrocarbon production processes.
BACKGROUND OF THE DISCLOSURE
Cyclic solvent processes (CSP) may be utilized to decrease a viscosity of viscous hydrocarbons, such as bitumen, which may be present within a subterranean formation, thereby permitting production of the viscous hydrocarbons from the subterranean formation via a hydrocarbon well. CSP may be attractive due to relatively low greenhouse gas emissions intensity, which may be defined as tons carbon dioxide emitted per cubic meter of bitumen produced, associated with CSP. In addition, CSP may be utilized to produce viscous hydrocarbons from subterranean formations that may not be readily amenable to other stimulation techniques.
However, traditional CSP generally forms two phase-separated liquid phases within the subterranean founation. These two phase-separated liquid phases include a light phase, which is diluent-rich and includes relatively lighter fractions of the bitumen (i.e., a light liquid hydrocarbon), and a heavy phase, which includes relatively heavier fractions of the bitumen, including asphaltenes (i.e., a heavy liquid hydrocarbon). The heavy phase has a relatively higher viscosity and may face difficulty flowing out from the subterranean formation, may overload pumps that may be utilized to produce the viscous hydrocarbons from the subterranean formation, and/or may plug various components of the hydrocarbon well and/or of surface facilities that support the hydrocarbon well. In addition to founing two liquid phases, traditional CSP may suffer from hydrate formation that may adversely affect the production of hydrocarbons.
To mitigate these issues, a significant portion of the heavy phase, which may account for approximately 70% of the viscous hydrocarbons, may be left within the subterranean formation, thereby significantly decreasing overall hydrocarbon production from a given subterranean formation. Thus, there exists a need for improved methods of performing cyclic hydrocarbon production processes.

2 SUMMARY OF THE DISCLOSURE
Methods of perfoiming cyclic hydrocarbon production processes are disclosed herein.
The methods include injecting a diluent into a subterranean formation to dilute viscous hydrocarbons that are present within the subterranean formation and to thereby generate reduced-viscosity hydrocarbons. The methods further include producing a product hydrocarbon stream from the subterranean formation and monitoring a variable of the product hydrocarbon stream that is indicative of a diluted viscous hydrocarbon fraction of the viscous hydrocarbons. The methods also include adjusting at least one property of the diluent to define a modified diluent.
The adjusting is based, at least in part, on the variable of the product hydrocarbon stream, and the adjusting includes adjusting to mitigate formation of a heavy liquid hydrocarbon fraction within the subterranean fonnation.
The methods further may include determining a critical diluent-to-viscous-hydrocarbon ratio for dilution of the viscous hydrocarbons by the diluent at a given temperature and a given pressure. The methods also may include calculating a quantity of heat required to heat a portion of the subterranean formation to the given temperature and providing the quantity of heat to the subterranean formation. Injecting the diluent may include injecting a predetermined volume of the diluent. The methods further may include ceasing the injecting prior to the producing. The methods also may include regulating a production pressure of the product hydrocarbon stream during the producing. The methods further may include ceasing the producing responsive to a temperature of the product hydrocarbon stream being less than a lower stream temperature threshold. The methods also may include repeating at least a portion of the methods as part of a plurality of stimulation-production cycles.

3 BRIEF DESCRIPTION OF THE DRAWINGS
Fig. 1 is a schematic side view of a hydrocarbon well that may be operated utilizing the methods according to the present disclosure.
Fig. 2 is a schematic cross-sectional view of a portion of the hydrocarbon well of Fig. 1.
Fig. 3 is another schematic cross-sectional view of the portion of the hydrocarbon well of Fig. 1.
Fig. 4 is a bar chart illustrating relative volume fractions of light liquid hydrocarbon, heavy liquid hydrocarbon, and/or diluted viscous hydrocarbons for a sample of bitumen.
Fig. 5 is a ternary phase diagram illustrating phase-behavior of a mixture of bitumen, methane, and propane.
Fig. 6 is a ternary phase diagram illustrating phase-behavior of a mixture of bitumen, methane, and dimethyl ether.
Fig. 7 is a plot of hydrocarbon recovery as a function of injected diluent volume for several different diluents.
Fig. 8 summarizes the results of a simulation in which several stimulation-production cycles were performed utilizing two different cyclic stimulation processes.
Fig. 9 is a flowchart depicting methods, according to the present disclosure, of performing a cyclic stimulation process.

4 DETAILED DESCRIPTION
Fig. 1 is a schematic side view of a hydrocarbon well 50 that may be operated utilizing the methods according to the present disclosure. Hydrocarbon well 50 includes a wellbore 52 that extends within a subterranean formation 40. Subterranean formation 40 may be present within a subsurface region 30, and wellbore 52 may extend between a surface region 20 and the subterranean formation 40. Subterranean formation 40 includes viscous hydrocarbons 42, and hydrocarbon well 50 may be configured to produce the viscous hydrocarbons from the subterranean formation and/or to convey the viscous hydrocarbons to the surface region utilizing the methods disclosed herein.
During operation of hydrocarbon well 50, a diluent stream 60, which includes a diluent 62, may be supplied to subterranean formation 40, such as via wellbore 52. The diluent stream may be supplied for, or during, a supply time interval as part of a stimulation cycle. Diluent stream 60 and/or diluent 62 thereof may physically contact and/or dilute viscous hydrocarbons 42 within a diluent chamber 80 that extends proximal to wellbore 52 and within the subterranean formation 40. This dilution of the viscous hydrocarbons 42 by diluent 62 may generate reduced-viscosity hydrocarbons 44, which may have a lower viscosity than viscous hydrocarbons 42.
Subsequently, supply of the diluent stream may be stopped and a product hydrocarbon stream 70 may flow, or be flowed, from subterranean formation 40 via wellbore 52. The product hydrocarbon stream may be produced for a production time interval and/or as part of a production cycle. The production may include flow of the product hydrocarbon stream from subsurface region 30 to surface region 20. The supply of diluent stream 60 (i.e., the stimulation stage), followed by the production of product hydrocarbon stream 70 (i.e., the production stage), may be repeated any suitable number of times as part of a cyclic stimulation process and/or a

5 cyclic hydrocarbon production process according to the present disclosure. A
corresponding pair of stimulation and production stages may be referred to herein as a stimulation-production cycle, and/or as a hydrocarbon production cycle. The repeating also may be referred to herein as performing a plurality of stimulation-production stages and/or as performing a plurality of stimulation-production cycles.
Product hydrocarbon stream 70 may include a plurality of components, including some of the injected diluent 62, water from subterranean formation 40, diluted viscous hydrocarbons 72, a light liquid hydrocarbon 74, and/or a heavy liquid hydrocarbon 76. Reduced-viscosity hydrocarbons 44 may include diluted viscous hydrocarbons 72 and/or light liquid hydrocarbon 74. As discussed in more detail herein, combination of diluent 62 with viscous hydrocarbons 42 under certain environmental conditions and/or at certain ratios of diluent 62 to viscous hydrocarbons 42 may cause diluent 62 to be absorbed into and/or to dilute the viscous hydrocarbons 42, thereby generating diluted viscous hydrocarbons 72. Diluted viscous hydrocarbons 72, at least when formed, may be a single liquid phase that comprises diluent 62 and viscous hydrocarbons 42, and the single liquid phase may have a distinct density and viscosity compared to the diluent and viscous hydrocarbons from which the phase is fonned.
Such environmental conditions may be referred to herein as a dilution regime (i.e., as a regime in which the viscous hydrocarbons are diluted by the diluent). As discussed in more detail herein, the environmental conditions may include, but are not limited to, diluent type, diluent composition (if diluent is a mixture of more than one diluent), diluent-to-viscous- hydrocarbons ratio, relative concentration of non-condensable gas (e.g., nitrogen, methane, or CO2) relative to diluent and/or to viscous hydrocarbons, non-condensable gas compositionõ
temperature, and/or pressure.

6 In contrast, and as also discussed in more detail herein, combination of diluent 62 with viscous hydrocarbons 42 under other (i.e., different) environmental conditions and/or at other ratios may cause the diluted viscous hydrocarbons to phase-separate into light liquid hydrocarbons 74, which comprise lighter fractions of viscous hydrocarbons 42 and diluent 62, and is diluent-rich, and heavy liquid hydrocarbons 76, which comprise heavier fractions of viscous hydrocarbons 42 and diluent 62, and is diluent-lean. The environmental conditions may again include, but not limited to, those discussed above in connection with the foiniation of diluted viscous hydrocarbons 72. Such environmental conditions may be referred to herein as a viscous region. The systems and methods disclosed herein may be configured to increase formation of diluted viscous hydrocarbons 72 and/or to decrease, or mitigate, formation of light liquid hydrocarbons 74 and heavy liquid hydrocarbons 76.
As a more specific example, the methods disclosed herein may include determining a critical diluent-to-viscous-hydrocarbons ratio for dilution of viscous hydrocarbons 42 by diluent 62 at a given temperature and a given pressure. Subsequently, a quantity of heat required to heat a portion of subterranean formation 40, such as a portion of diluent chamber 80, to the given temperature may be calculated. The quantity of heat then may be provided to the portion of the subterranean formation, such as via a heat source 96, to heat the portion of the subterranean foimation to the given temperature. The heat source 96 may be and/or include steam injected before injecting diluent 62 to the near-wellbore region, heat provided to diluent on the surface or in wellbore 52, and/or electrical or electromagnetic heating of the near well-bore region or away-from-wellbore region. Away-from-wellbore region heating can be achieved by drilling lateral wells from the well 50 or wellbore 52. Once the portion of the subterranean formation has been heated to the given temperature, a predeteiiiiined volume of diluent 62 may be injected into

7 the subterranean formation as part of a stimulation cycle. Diluent 62 may dilute viscous hydrocarbons 42, as discussed herein, and the predeteimined volume of the diluent may be selected to maintain a diluent-to-viscous-hydrocarbons ratio within the portion of the subterranean formation below a critical diluent-to-viscous hydrocarbons ratio, thereby preferentially generating diluted viscous hydrocarbons 72 over light liquid hydrocarbons 74 and heavy liquid hydrocarbons 76. Some examples of the diluent-to-viscous-hydrocarbon ratio and the critical diluent-to-viscous-hydrocarbon ratio, which depend on the diluent and the viscous bitumen, are disclosed herein, including in connection with Figs. 4-6.
The methods may further include injecting a non-condensable gas, such as nitrogen, methane, or carbon dioxide, or a mixture thereof, with the diluent to achieve a diluent-to-viscous-hydrocarbon ratio that is below the critical diluent-to-viscous-hydrocarbon ratio. The incorporation of the non-condensable gas lowers the diluent proportion in the pore space containing the viscous hydrocarbons, thereby lowering the diluent to viscous hydrocarbons to less than the critical diluent-to-viscous-hydrocarbons ratio. This may be advantageous in later cycles of the stimulation-production process, when the proportion of viscous hydrocarbons in the pore spaces is lower than that in early cycles. Lowering the ratio of diluent to viscous hydrocarbons means lowering the ratio to be less than the critical diluent to viscous hydrocarbons, thereby enabling the process to be in the dilution regime, where a single phase of diluted viscous hydrocarbons exists.
The diluent injection then may be stopped, and product hydrocarbon stream 70 may be produced from the subterranean formation as part of a production cycle.
Concurrently with production of the product hydrocarbon stream, a production pressure of the product hydrocarbon stream may be controlled and/or regulated to maintain the production pressure above a threshold

8 production pressure. Also concurrently with production of the product hydrocarbon stream, a variable of the product hydrocarbon stream may be monitored. The variable of the product hydrocarbon stream may be indicative of a diluted viscous hydrocarbon fraction of the product hydrocarbon stream. Production of the product hydrocarbon stream may be stopped and/or ceased responsive to a temperature of the product hydrocarbon stream being less than a stream temperature threshold. Production of the product hydrocarbon stream also may also be stopped , and/or ceased responsive to a product hydrocarbon production rate being less than a product hydrocarbon production rate threshold.
The production cycle may be assessed to compare a composition of the product hydrocarbon stream to a desired, or target, composition of the product hydrocarbon stream.
Then, at least one property of the diluent may be adjusted to define a modified diluent. The adjustment may be made to mitigate fonnation of a heavy liquid hydrocarbon fraction within the subterranean formation and may be based, at least in part, on the monitored variable of the product hydrocarbon stream. At least a portion of the process then may be repeated a plurality of times as part of a plurality of stimulation-production cycles, thereby expanding dilution chamber 80 and/or producing additional viscous hydrocarbons from the subterranean formation.
As illustrated in dashed lines in Fig. 1, hydrocarbon well 50 may include and/or be associated with a detector 90, which may be configured to detect and/or monitor the variable of product hydrocarbon stream 70 and/or a variable that is associated with hydrocarbon well 50.
Detector 90 may include and/or be any suitable detector that may be adapted, configured, designed, and/or constructed to detect any suitable variable. As examples, detector 90 may detect a temperature, a temperature associated with hydrocarbon well 50, a temperature of product hydrocarbon stream 70, a pressure, a pressure associated with hydrocarbon well 50, a

9 pressure within subterranean foimation 40, a pressure of product hydrocarbon stream 70, a chemical composition, a chemical composition associated with hydrocarbon well 50, a chemical composition of product hydrocarbon stream 70, a viscosity, a viscosity associated with hydrocarbon well 50, a viscosity of product hydrocarbon stream 70, a density, a density associated with hydrocarbon well 50, a density of product hydrocarbon stream 70, a color, a color of product hydrocarbon stream 70, a diluent-to-viscous-hydrocarbon ratio in product hydrocarbon stream 70, and/or a light liquid hydrocarbon to a heavy liquid hydrocarbon ratio in product hydrocarbon stream 70.
As also illustrated in dashed lines in Fig. 1, hydrocarbon well 50 additionally or alternatively may include and/or be associated with heat source 96, which may be configured to directly and/or indirectly heat at least a portion of subterranean formation 40, such as diluent chamber 80. Examples of heat source 96 include a combustion heater and/or an electric heater.
Such a heater may be located in any suitable position and/or orientation relative to hydrocarbon well 50, such as at a surface region, in or along a vertical and/or horizontal section of hydrocarbon well 50, and/or extending within subterranean formation 40. As also discussed, heat source 96 may be a supply of steam or hot flue gas that is flowed into the subterranean formation to heat the subterranean foimation.
Subterranean formation 40 may include and/or be any suitable subterranean formation that includes viscous hydrocarbons 42. Examples of subterranean foimation 40 include an oil sands formation, a heavy oil formation, a tar sands formation, a bituminous sands formation, and/or an oil shale formation. Similarly, viscous hydrocarbons 42 may include and/or be any suitable viscous hydrocarbons, examples of which include heavy oil, bitumen, asphaltenes, tar, and/or an unconventional hydrocarbon reserve.

, Diluent 62 may include and/or be any suitable chemical that may combine and/or mix with viscous hydrocarbons 42 to generate product hydrocarbon stream 70, such as diluted viscous hydrocarbons 72, light liquid hydrocarbon 74, and/or heavy liquid hydrocarbon 76. As examples, diluent 62 may include methane, ethane, propane, butane, pentane, hexane, heptane, octane, nonane, decane, dimethyl ether, an alkane, cyclopentane, cyclohexane, naphtha, natural gas condensate, and/or gas plant condensate.
Figs. 2-3 are schematic cross-sectional views of a portion of hydrocarbon well 50 of Fig. I. Figs. 2-3 illustrate wellbore 52 extending within subterranean formation 40, which includes viscous hydrocarbons 42. As discussed, and subsequent to supply of diluent 62 to subterranean formation 40, diluent chamber 80 may be formed within the subterranean formation. Diluent chamber 80 may include subterranean strata 88, such as rock, sand, and/or shale. Diluent 62 and/or viscous hydrocarbons 42 may be present within an interstitial, or pore, space within the subterranean strata, within which pore space water also may be present.
As also discussed, the environmental conditions under which diluent 62 is supplied to the subterranean formation and/or the volume of diluent 62 that is supplied to the subterranean formation may change, vary, and/or dictate the manner in which diluent 62 interacts and/or combines with viscous hydrocarbons 42 and/or may change, vary, and/or dictate the material(s) that are formed by the interaction and/or combination of the diluent with the viscous hydrocarbons.
As an example, and under a first set of environmental conditions and/or after supply of a first volume of diluent, diluent chamber 80 may have the material distribution that is schematically illustrated in Fig. 2. Therein, a diluent-rich region 82 extends around and/or proximal to wellbore 52. The diluent-rich region includes a high concentration of diluent 62, and the diluent has displaced a significant portion of the viscous hydrocarbons from the diluent-rich region. Farther, or more distal, from the wellbore, a two-phase region 84 extends within the subterranean formation. The two-phase region is formed via combination of diluent 62 with viscous hydrocarbons 42 and includes light liquid hydrocarbon 74 and heavy liquid hydrocarbon 76, which may be phase-separated from one another. The conditions illustrated in Fig. 2 are common with conventional CSP, where the diluent chamber generally is flooded with large volumes of solvent. Under these conditions, it may be difficult to produce heavy liquid hydrocarbon 76 from the subterranean formation. In addition, heavy liquid hydrocarbon 76 and/or one or more components that may be present therein may restrict fluid flow within diluent chamber 80, wellbore 52, well 50 or its associated pumps, pipes, or fittings, thereby reducing production of the viscous hydrocarbons from the subterranean formation.
Under a second set of environmental conditions and/or after supply of a second volume of diluent, diluent chamber 80 may have a material distribution that is schematically illustrated in Fig. 3. Therein, a diluent-rich region 82 extends around and/or proximal to wellbore 52. As illustrated, diluent-rich region of 82 of Fig. 3 may be smaller, or may include a smaller volume, when compared to diluent-rich region 82 of Fig. 2; however, this is not required in all embodiments. Similar to Fig. 2, the diluent-rich region of Fig. 3 includes a high concentration of diluent 62, and the diluent has displaced a significant portion of the viscous hydrocarbons from the diluent-rich region.
Farther, or more distal, from the wellbore, a two-phase region 84 extends within the subterranean formation. Similar to Fig. 2, the two-phase region of Fig. 3 is formed via combination of diluent 62 with viscous hydrocarbons 42 and includes light liquid hydrocarbon 74 and heavy liquid hydrocarbon 76. Two-phase region 84 of Fig. 3 may be smaller, or include a smaller volume, when compared to two-phase region 84 of Fig. 2; however, this is not required in all embodiments.
Even farther, or more distal, from wellbore 52, a diluted viscous hydrocarbon region 86 extends within the subterranean formation. The diluted viscous hydrocarbon region may include, or contain, diluted viscous hydrocarbons 72. It is within the scope of the present disclosure that diluted viscous hydrocarbons 72 also may be present under the conditions of Fig. 2; however, a volume of the diluted viscous hydrocarbon region may be significantly larger under the conditions of Fig. 3 when compared to the conditions of Fig. 2.
As discussed in more detail herein, the methods according to the present disclosure may be specifically designed and/or utilized to preferentially form, or increase formation of, diluted viscous hydrocarbon region 86 and/or diluted viscous hydrocarbons 72 within diluent chamber 80. Additionally or alternatively, the methods according to the present disclosure also may be specifically designed and/or utilized to mitigate, or decrease, formation of two-phase region 84 and/or of light liquid hydrocarbon 74 and heavy liquid hydrocarbon 76.
The preferential formation of diluted viscous hydrocarbon region 86 over, or instead of, two-phase region 84 may be accomplished in any suitable manner. As an example, a volume of diluent 62 that is supplied to the subterranean formation during a given stimulation cycle may be regulated and/or varied to cause preferential formation of the diluted viscous hydrocarbon region. As discussed in more detail herein, and under a given set of environmental conditions, a specific diluent may define a critical diluent-to-viscous-hydrocarbon ratio with a given viscous hydrocarbon. For such a system, combination of the diluent with the viscous hydrocarbons at less than the critical diluent-to-viscous-hydrocarbon ratio may generate diluted viscous hydrocarbons 72, while combination of the diluent with the viscous hydrocarbons at greater than the critical diluent-to-viscous-hydrocarbon ratio may generate light liquid hydrocarbon 74 and heavy liquid hydrocarbon 76. As additional examples, a temperature within the subterranean formation, a pressure within the subterranean formation, and/or a chemical composition of the diluent may be varied to cause preferential fointation of the diluted viscous hydrocarbon region.
Figs. 4-8 are more specific examples, in the fomi of experimental data, illustrating mechanisms by which formation of diluted viscous hydrocarbon region 86 may be controlled and/or regulated, thereby permitting preferential formation of diluted viscous hydrocarbons 72 instead of, or in greater quantities than, light liquid hydrocarbon 74 and/or heavy liquid hydrocarbon 76. For each of Figs. 4-8, brief discussions of the experimental conditions and the experimental results are provided. The applicability of these experimental results to control and/or regulate the formation of diluted viscous hydrocarbons then is discussed.
Fig. 4 is a bar chart illustrating relative volume fractions (as indicated on the y-axis) of light liquid hydrocarbon 74, heavy liquid hydrocarbon 76, and/or diluted viscous hydrocarbons 72 for a sample of 35 weight percent propane (i.e., diluent) and 65 weight percent Athabasca bitumen (i.e., viscous hydrocarbons) that was combined in a phase-behavior cell at various temperatures (as indicated on the x-axis). Data were collected at 40 C, 70 C, and 90 C, and the results were extrapolated to arrive at the data for 13 C and 102 C. The viscosity of the heavy liquid hydrocarbon was determined at each temperature. The results were 2708 centipoise (cP) at 13 C, 261 cP at 40 C, 12 cP at 70 C, 3 cP at 90 C, and 0.9 cP at 102 C.
Fig. 4 illustrates that increasing the temperature of propane-bitumen mixture increases the volume percent of the heavy liquid fraction, with the mixture becoming a single liquid phase (i.e., diluted viscous hydrocarbons 72) at temperatures above 102 C. In addition, increasing the temperature also produces a significant decrease in the viscosity of the heavy liquid hydrocarbon.

These experimental results indicate that a portion, or fraction, of diluent chamber 80 that includes diluted viscous hydrocarbons 72 (as illustrated in Fig. 3) and/or a portion, or fraction, of product hydrocarbon stream 70 that includes the diluted viscous hydrocarbons (as illustrated in Fig. 1) may be increased by increasing the temperature within the subterranean formation and/or may be decreased by decreasing the temperature within the subterranean fonnation.
Additionally or alternatively, these results indicate that a portion, or fraction, of diluent chamber 80 that includes light liquid hydrocarbon 74 and/or heavy liquid hydrocarbon 76 and/or a portion, or fraction, of product hydrocarbon stream 70 that includes the light liquid hydrocarbon and/or the heavy liquid hydrocarbon may be increased by decreasing the temperature within the subterranean formation and/or may be decreased by increasing the temperature within the subterranean foiniation. Additionally or alternatively, these results also indicate that the viscosity of product hydrocarbon stream 70 may be decreased by increasing the temperature within the subterranean formation and/or may be increased by decreasing the temperature within the subterranean formation.
Fig. 5 is a ternary phase diagram illustrating phase-behavior of a mixture of Cold Lake bitumen (Bitumen), methane (Cl), and propane (C3) at 5000 kilopascals and 20 C. Both methane and propane are diluents that may be utilized with the methods according to the present disclosure. The phase diagram includes a liquid/vapor transition line 100 and a single-phase/two-phase liquid transition line 102 that together define four regions, including a first region 111, a second region 112, a third region 113, and a fourth region 114.
In first region 111, the mixture exists as a single liquid phase (i.e., diluted viscous hydrocarbons 72 of Figs. 1 and 3). In second region 112, the mixture exists as a single liquid phase in equilibrium with a vapor phase. First region 111 and second region 112 together may be referred to herein as a dilution regime for the ternary system (i.e., bitumen, C3, Cl) at 5000 kilopaseals and 20 C.
In third region 113, the mixture exists as two phase-separated liquid phases (i.e., light liquid hydrocarbon 74 and heavy liquid hydrocarbon 76 of Figs. 1-3). In fourth region 114, the mixture exists as two phase-separated liquid phases in equilibrium with a vapor phase. Third region 113 and fourth region 114 together may be referred to herein as a viscous regime for the ternary system (i.e., bitumen-C1-C3 system) at 5000 kilopascals and 20 C.
Fig. 5 illustrates that, for the bitumen-C1-C3 system, the dilution regime is relatively small when compared to the viscous regime.
As discussed, conventional CSP generally operates in the viscous regime, since, historically, the assumption has been that providing additional solvent to the subterranean formation serves to dissolve additional viscous hydrocarbons, thereby permitting production of the additional viscous hydrocarbons. However, this assumption associated with conventional CSP may not necessarily be valid. For example, the solvent in CSP is not really a solvent for viscous hydrocarbons, as it dilutes, rather than dissolves, the viscous hydrocarbons. Thus, the so-called solvent in conventional CSP perhaps should be called a diluent that dilutes viscous hydrocarbons below a critical diluent to viscous hydrocarbons ratio and forms two liquid phases, one light and the other heavy, with the heavier phase having a higher viscosity than the original viscous hydrocarbons (on a diluent-free basis). Furthermore, the heavy liquid phase that is generated in the subterranean formation is difficult to produce from the subterranean formation.
Hence, more solvent (actually diluent) is detrimental to viscous hydrocarbon production, which may explain why conventional CSP processes may have operated under the belief that more solvent (actually diluent) is better. In contrast, the methods disclosed herein select the composition of the diluent, as well as relative proportions of methane, propane, and bitumen and/or other environmental conditions, such that the mixture is within the dilution regime. Thus a single liquid phase is generated, and this single liquid phase may more readily be produced from the subterranean formation, as its viscosity is lower than that of the heavy liquid phase Fig. 6 is a ternary phase diagram illustrating phase-behavior of a mixture of Cold Lake bitumen (Bitumen), methane (Cl), and dimethyl ether (DME) at 5000 kilopascals and 20 C.
Both DME and methane are diluents that may be utilized with the methods according to the present disclosure. Similar to Fig. 5, the phase diagram includes a liquid/vapor transition line 100 and a single-phase/two-phase liquid transition line 102 that together define four regions, including a first region 111, a second region 112, a third region 113, and a fourth region 114.
The phase(s) that exist in each of the four regions may be at least substantially similar to the phase(s) that exist in the corresponding regions of Fig. 5.
The single-phase/two-phase transition line from Fig. 5 is illustrated in dashed lines in Fig.
6, while the single-phase/two-phase transition line is shown by the solid line. Fig. 6 clearly illustrates a significant increase in the portion of the phase diagram that is occupied by first region 111 and second region 112, together constituting the dilution regime, when compared to the ternary system of Fig. 5. Thus, Fig. 6 illustrates that changes in the chemical composition of the diluent, such as by substituting DME for propane, can produce significant changes in the relative concentration ranges over which the single liquid phase exists.
Stated another way, the single liquid phase exists over a significantly wider range of concentrations in the ternary system of Fig. 6 (i.e., Cl, DME, and Bitumen) when compared to the ternary system of Fig. 5 (i.e., Cl, C3, and Bitumen).

As discussed, Figs. 5-6 include single-phase/two-phase liquid transition line 102. As also discussed, the single liquid phase (i.e., diluted viscous hydrocarbons 72 of Figs. 1 and 3) exists at mixture compositions that are on one side of line 102 (i.e., within first region 111 and/or second region 112) and the two phase-separated liquid phases (i.e., light liquid hydrocarbon 74 and heavy liquid hydrocarbon 76) exist at mixture compositions that are on the other side of line 102 (i.e., within third region 113 and/or fourth region 114).
Thus, line 102 may represent, describe, and/or quantify a critical diluent-to-viscous-hydrocarbon ratio for the indicated mixtures. Stated another way, when the composition of the mixture is such that the diluent-to-viscous-hydrocarbon ratio is greater than the critical diluent-to-viscous-hydrocarbon ratio (i.e., in regions 113 and/or 114), the diluent and the bitumen combine to generate the two phase-separated liquid phases. Conversely, when the composition of the mixture is such that the diluent-to-viscous-hydrocarbon ratio is less than the critical diluent-to-viscous-hydrocarbon ratio (i.e., in regions 111 and/or 112), the diluent and the bitumen combine to generate the single liquid phase.
For a binary system of a single diluent and a single viscous hydrocarbon, the critical diluent-to-viscous-hydrocarbon ratio may be a single ratio. As an example, the critical diluent-to-viscous-hydrocarbon ratio for the binary bitumen-propane (no Cl) system of Fig. 5 is approximately 35 volume percent. As another example, the critical diluent-to-viscous-hydrocarbon ratio for the binary bitumen-DME (no Cl) system of Fig. 6 is approximately 52 volume percent.
Fig. 7 is a plot of viscous hydrocarbon recovery as a function of injected diluent volume.
The data presented in Fig. 7 were collected in a sand pack that was saturated with Cold Lake bitumen at room temperature. The sand pack had a permeability of 5.4 Darcy.
During the experiments, three different diluents were tested. These diluents included propane (which is indicated at 120), DME (which is indicated at 122), and a mixture of 70%
propane and 30%
DME by volume (which is indicated at 124). For each test, a given diluent was provided to the sand pack at a constant rate of 2.7 mL/minute until the pressure reached 9.5 Megapascals absolute pressure (MPaa). The given diluent then was supplied at a rate that maintained the inlet pressure at 9.5 MPaa. The amount of viscous hydrocarbon recovered from the sand pack, expressed as a percentage of the total amount of viscous hydrocarbon initially present within the sand pack, is plotted in Fig. 7 as a function of the number of pore volumes of diluent supplied to the sand pack for each of the three above-described diluent compositions. As may be seen from Fig. 7, the addition of DME, either alone or in combination with propane, produces a significant increase in the viscous hydrocarbon recovery for a given volume of diluent, and the combination of DME and propane, which is indicated at 124, produced the largest increase.
These experimental results suggest that performing cyclic solvent processes by injecting materials other than propane, which is the common injectant for prior art processes, may have the potential to significantly improve viscous hydrocarbon recovery. As an example, the combination of DME and propane increased viscous hydrocarbon recovery by 63%
after injection of approximately 2.5 pore volumes when compared to a similar amount of injected propane alone.
Fig. 8 summarizes the results of a reservoir simulation in which several stimulation-production cycles were perfoinied utilizing two different cyclic stimulation processes. In Fig. 8, cumulative viscous hydrocarbon production is plotted as a function of time for the two different cyclic stimulation processes. For both cyclic stimulation processes, propane was utilized as the diluent. In a first cyclic stimulation process 130, the subterranean formation was not heated over the course of the seven illustrated stimulation-production cycles. In a second cyclic stimulation process 132, the subterranean formation was not heated for the first four stimulation-production cycles, but a near-wellbore portion (50m x 20m x 100m) of the subterranean formation was heated prior to the start of a fifth stimulation-production cycle to a temperature of 77 C by adding 13076 GJ of heat energy, and then was not heated for the remaining sixth and seventh stimulation-production cycles. As illustrated clearly in Fig. 8, the addition of heat during the fifth stimulation-production cycle of second cyclic stimulation process 132 significantly increased the cumulative viscous hydrocarbon production, and the positive impact of the single heating event was evident over the two subsequent stimulation-production cycles (i.e., cycles 6 and 7). Fig. 8 further demonstrates that heat addition improves viscous hydrocarbon production.
In experiments, it has been demonstrated that heat addition may increase direct greenhouse gas (GHG) intensity by only 14% while also reducing (direct and indirect) GHG
intensity by 53%, with this significant reduction stemming from an almost three fold increase in bitumen production and only a 1.4 fold increase in GHG emission. Of this increase, direct GHG
emission, such as results from burning natural gas to make steam at the viscous bitumen production site, may account for only 8% of the total GHG intensity. Indirect GHG intensity may result, for example, from emissions related to emissions while manufacturing the diluent at another site and transporting it to viscous hydrocarbon production site. Thus, cyclic hydrocarbon production methods according to the present disclosure may retain the low-GHG
attractiveness of CSP while also decreasing the propensity for hydrate foimation compared to traditional CSP.
Fig. 9 is a flowchart depicting methods 200, according to the present disclosure, of performing a cyclic stimulation process. The cyclic stimulation process may be utilized to stimulate production of viscous hydrocarbons from a subterranean formation.
Methods 200 may include characterizing viscous hydrocarbons at 205, selecting a diluent property at 210, calculating a quantity of heat at 215, and/or heating the subterranean formation at 220. Methods 200 include injecting diluent into the subterranean formation at 225 and may include ceasing the injecting at 230 and/or regulating a pressure at 235. Methods 200 further include producing a product hydrocarbon stream from the subterranean formation at 240 and may include ceasing the producing at 245. Methods 200 include monitoring a variable of the product hydrocarbon stream at 250 and adjusting at least one property of the diluent to define a modified diluent at 255.
Methods 200 also may include repeating at least a portion of the (previously performed) method at 260.
Characterizing the viscous hydrocarbons at 205 may include characterizing any suitable property and/or parameter of the viscous hydrocarbons in any suitable manner and may be performed prior to the selecting at 210, prior to the heating at 220, and/or prior to the injecting at 225. As an example, the characterizing at 205 may include obtaining a sample of the viscous hydrocarbons from the subterranean foimation and characterizing the sample of the viscous hydrocarbons. As another example, the characterizing at 205 may include determining a critical diluent-to-viscous-hydrocarbon ratio for dilution of the viscous hydrocarbons by a given diluent at given conditions, such as at a given temperature and/or at a given pressure. As yet another example, the characterizing at 205 may include determining at least a portion of an equation of state for a mixture of the given diluent and the viscous hydrocarbons. As another example, the characterizing at 205 may include deteimining a chemical composition of the viscous hydrocarbons.
As used herein, the phrase "critical diluent-to-viscous-hydrocarbon ratio" may refer to a ratio of the given diluent to viscous hydrocarbons below which the resulting mixture generates a single liquid phase and above which the resulting mixture generates two phase-separated liquid phases, at a given temperature and a given pressure. Stated another way, when the given diluent and the viscous hydrocarbons are mixed, or combined at a given temperature and a given pressure, at a ratio that is less than the critical diluent-to-viscous-hydrocarbon ratio, the given diluent and the viscous hydrocarbons combine to generate the single liquid phase, which includes diluted viscous hydrocarbons. In contrast, when the given diluent and the viscous hydrocarbons are mixed, or combined at a given temperature and a given pressure, at a ratio that is greater than the critical diluent-to-viscous-hydrocarbon ratio, the given diluent and the viscous hydrocarbons combine to generate two phase-separated liquid phases, including a heavy liquid hydrocarbon fraction, which includes a heavy liquid hydrocarbon, and a separate light liquid hydrocarbon fraction, which includes a light liquid hydrocarbon. It is within the scope of the present disclosure that the critical diluent-to-viscous-hydrocarbon ratio may include and/or be any suitable measure, or ratio, of an amount, mass, or volume of the given diluent to an amount, mass, or volume of viscous hydrocarbons with which the diluent is combined.
Selecting the diluent property at 210 may include selecting any suitable property. As examples, the selecting at 210 may include selecting a chemical composition of the diluent, selecting a temperature of the diluent, selecting a temperature of the diluent to be utilized during the injecting at 225, selecting a pressure of the diluent, selecting a pressure of the diluent to be utilized during the injecting at 225, selecting a volume of the diluent, selecting a volume of the diluent to be utilized during the injecting at 225, and/or selecting a predeteimined volume of the diluent to be utilized during the injecting at 225. These diluent properties may specify and/or define the given diluent that is utilized during the characterizing at 205 and/or the diluent that is injected during the injecting at 225.

=
As another example, the selecting at 210 may include selecting such that a portion of the product hydrocarbon stream, which is produced during the producing at 240, that comprises diluted viscous hydrocarbons is expected to be greater than a threshold portion of the product hydrocarbon stream. As yet another example, the selecting at 210 may include selecting the predetermined volume of the diluent to maintain the diluent-to-viscous-hydrocarbon ratio within the subterranean formation below the critical diluent-to-viscous-hydrocarbon ratio.
The selecting at 210 may be based upon any suitable criteria. As examples, the selecting at 210 may be based, at least in part, on the critical diluent-to-viscous-hydrocarbon ratio, on the characterizing at 205, and/or on the composition of the viscous hydrocarbons.
The selecting at 210 may be perfoimed with any suitable sequence and/or timing within methods 200. As examples, the selecting at 210 may be performed subsequent to the characterizing at 205 and/or prior to the injecting at 225.
Calculating the quantity of heat at 215 may include calculating the quantity of heat that is required to heat a portion of the subterranean formation to at least a threshold upper temperature and/or to within a target temperature range. The calculating at 215 may be performed in any suitable manner and/or based upon any suitable criteria. As examples, the calculating at 215, the threshold upper temperature, and/or the target temperature range may be selected based, at least in part, on the characterizing at 205, on a volume of the portion of the subterranean formation, on a composition of subterranean strata that is present within the portion of the subterranean formation, and/or on a model of the portion of the subterranean formation.
Heating the subterranean folination at 220 may include heating at least the portion of the subterranean foiniation. The heating at 220 may include providing the quantity of heat, which was calculated during the calculating at 215, to the subterranean formation and/or heating the subterranean formation to the given temperature that was utilized during the characterizing at 205. Additionally or alternatively, the heating at 220 may include selecting the given temperature based, at least in part, on the characterizing at 205.
The heating at 220 may be accomplished in any suitable manner, including those that are conventional to hydrocarbon production and/or stimulation techniques and/or processes. As examples, the heating at 220 may include providing steam or heated flue gas to the portion of the subterranean formation, heating the diluent prior to the injecting at 225, and/or combusting a fuel, such as diluent or methane, within the portion of the subterranean formation. When steam is injected into the subterranean formation to provide at least a portion of the desired heating, the steam may be injected at any suitable time relative to the injection of the diluent. Examples include prior to the injection of the diluent, prior to injection of the modified diluent, concurrent with the injection of the diluent, and/or concurrent with the injection of the modified diluent.
When methods 200 include the heating at 220, the methods further may include monitoring a temperature, such as a temperature associated with the hydrocarbon well, a temperature of the portion of the subterranean formation, and/or a temperature of the product hydrocarbon stream. Under these conditions, the methods further may include repeating the heating at 220 responsive to the temperature being less than a threshold lower temperature.
Injecting the diluent into the subterranean formation at 225 may include injecting any suitable diluent into the subterranean foimation. As an example, the injecting at 225 may include injecting the given diluent that is utilized during the characterizing at 205 and/or injecting the diluent that is specified and/or defined by the selecting at 210. The diluent may, or the injecting at 225 may be performed to, dilute the viscous hydrocarbons and/or to generate reduced-viscosity hydrocarbons within the subterranean formation. The reduced-viscosity hydrocarbons may include a diluted viscous hydrocarbon fraction (i.e., a portion, percentage, and/or subset of the reduced-viscosity hydrocarbons may be defined by diluted viscous hydrocarbons).
The injecting at 225 may be performed in any suitable manner. As examples, the injecting at 225 may include injecting via a wellbore that extends within the subterranean formation, injecting from a surface region into the subterranean formation, and/or pumping the diluent into the subterranean formation.
In addition, the injecting at 225 may be performed at any suitable time and/or with any suitable sequence during methods 200. As examples, the injecting at 225 may be performed subsequent to the characterizing at 205, subsequent to the selecting at 210, subsequent to the calculating at 215, subsequent to the heating at 220, concurrently with the heating at 220, prior to the ceasing at 230, prior to the regulating at 235, and/or prior to the producing at 240.
Ceasing the injecting at 230 may include ceasing injection of the diluent into the subterranean formation and/or ceasing the injecting at 225. The ceasing at 230 may include limiting, restricting, occluding, blocking, and/or stopping flow of the diluent into the subterranean formation and/or stopping supply of the diluent to the wellbore.
When methods 200 include the ceasing at 230, methods 200 further may include waiting at least a threshold soak time subsequent to the ceasing at 230 and prior to the producing at 240. The waiting may permit the diluent to diffuse within the subterranean formation and/or to be absorbed into the viscous hydrocarbons, thereby producing the reduced-viscosity hydrocarbons. Examples of threshold soak times include at least 15 days, at least 30 days, at least 60 days, at least 90 days, and at least 120 days, although threshold soak times may be selected and utilized, such as based on conditions relating to a particular formation, operator preferences, etc.

Regulating the pressure at 235 may include regulating the pressure within the subterranean foimation, such as during the threshold soak time or during production at 240. The regulating at 235 may be accomplished in any suitable manner. As examples, the regulating at 235 may include monitoring the pressure within the subterranean formation, providing a pressurizing fluid to the subterranean formation responsive to the pressure within the subterranean formation being less than a threshold lower formation pressure, and/or releasing fluid from the subterranean foiniation responsive to the pressure within the subterranean formation being greater than a threshold upper formation pressure.
Producing the product hydrocarbon stream from the subterranean formation at 240 may include removing any suitable product hydrocarbon stream from the subterranean formation in any suitable manner. As an example, the producing at 240 may include flowing the product hydrocarbon stream from the subterranean formation, such as via the wellbore.
As another example, the producing at 240 may include permitting the product hydrocarbon stream to flow from the subterranean formation, with a motive force for the flow of the product hydrocarbon stream being provided by a pressure that was generated within the subterranean formation during the injecting at 225. As yet another example, the producing at 240 may include pumping the product hydrocarbon stream from the subterranean foimation.
As discussed in more detail herein, the product hydrocarbon stream generally will include at least a portion of the reduced-viscosity hydrocarbons that were generated as a result of the injecting at 225. Additionally or alternatively, the product hydrocarbon stream also may include diluted viscous hydrocarbons, the light liquid hydrocarbon, and/or the heavy liquid hydrocarbon.
Ceasing the producing at 245 may include ceasing production of the product hydrocarbon stream from the subterranean foi illation and may be accomplished in any suitable manner. As examples, the ceasing at 245 may include blocking flow of the product hydrocarbon stream from the subterranean founation and/or ceasing pumping of the product hydrocarbon stream from the subterranean formation.
The ceasing at 245 may be initiated, or the producing at 240 may be stopped, based upon any suitable criteria. As examples, the ceasing at 245 may be initiated responsive to a temperature of the product hydrocarbon stream being less than a lower stream temperature threshold, responsive to a temperature of the portion of the subterranean formation being less than a lower formation temperature threshold, responsive to a pressure of the product hydrocarbon stream being less than a lower stream pressure threshold, responsive to a pressure within the portion of the subterranean formation being less than a lower formation pressure threshold, and/or responsive to a product hydrocarbon stream rate being less than a lower product hydrocarbon stream rate.
Monitoring the variable of the product hydrocarbon stream at 250 may include monitoring any suitable variable that may be indicative of the diluted viscous hydrocarbon fraction of the reduced-viscosity hydrocarbons that are produced in the product hydrocarbon stream. As an example, the monitoring at 250 may include monitoring a chemical composition of the diluted viscous hydrocarbon fraction of the product hydrocarbon stream.
As another example, the monitoring at 250 may include monitoring a chemical composition of the light liquid hydrocarbon fraction of the product hydrocarbon stream. As yet another example, the monitoring at 250 may include monitoring a chemical composition of the heavy liquid hydrocarbon fraction of the product hydrocarbon stream. As another example, the monitoring at 250 may include determining a portion, fraction, subset, and/or percentage of the product hydrocarbon stream that includes, or comprises, the diluted viscous hydrocarbon fraction (e.g., determining what weight percentage, mass percentage, and/or mole percentage of the product hydrocarbon stream is defined by diluted viscous hydrocarbons).
As yet another example, the monitoring at 250 may include determining a portion, fraction, subset, and/or percentage of the product hydrocarbon stream that includes, or comprises, the light liquid hydrocarbon fraction (e.g., determining what weight percentage, mass percentage, and/or mole percentage of the product hydrocarbon stream is defined by the light liquid hydrocarbon). As yet another example, the monitoring at 250 may include deteimining a portion, fraction, subset, and/or percentage of the product hydrocarbon stream that includes, or comprises, the heavy liquid hydrocarbon fraction (e.g., deteimining what weight percentage, mass percentage, and/or mole percentage of the product hydrocarbon stream is defined by the heavy liquid hydrocarbon. As additional examples, the monitoring at 250 may include monitoring a temperature of the product hydrocarbon stream, monitoring a viscosity of the product hydrocarbon stream, monitoring a density of the product hydrocarbon stream, monitoring a color of the product hydrocarbon stream, and/or monitoring a diluent-to-viscous-hydrocarbon ratio of, or in, the product hydrocarbon stream. As yet another example, the monitoring at 250 may include monitoring the amount of and/or composition of non-condensable gas, such as N2, CH4, or CO2, in the product hydrocarbon stream.
It is within the scope of the present disclosure that the monitoring at 250 may include monitoring an instantaneous value of the variable and/or monitoring a cumulative, or integrated, value of the variable.
Adjusting the at least one property of the diluent to define the modified diluent at 255 may include adjusting such that the modified diluent differs from the diluent that was injected during the injecting at 225 by the at least one property. Additionally or alternatively, the adjusting at 255 also may include adjusting to mitigate, regulate, control, and/or decrease formation of the heavy liquid hydrocarbon fraction within the subterranean formation. The adjusting at 255 may be based, at least in part, on the variable of the product hydrocarbon stream that was monitored during the monitoring at 250.
The at least one property of the diluent may include and/or be any suitable property of the diluent. As examples, the at least one property of the diluent may include and/or be a volume of the modified diluent relative to a volume of the diluent (e.g., a volume of the modified diluent that may be injected into the subterranean formation, such as during the repeating at 260, relative to a volume of the diluent that was injected during the injecting at 225), a chemical composition of the modified diluent relative to a chemical composition of the diluent, and/or a temperature of the modified diluent relative to a temperature of the diluent. Thus, the chemical composition may be adjusted by adding and/or removing a component of the diluent and/or increasing or decreasing the relative proportion of at least one component of the diluent.
Adjusting at 255 may include changing the composition of and/or increasing or decreasing the concentration of non-condensable gases in the diluent.
Similarly, adjusting a temperature or pressure may include increasing or decreasing the corresponding temperature or pressure.
Responsive to the monitoring at 250 indicating that the diluted viscous hydrocarbon fraction of the reduced-viscosity hydrocarbons that are produced in the product hydrocarbon stream (i.e., the portion of the product hydrocarbon stream that comprises the diluted viscous hydrocarbon fraction) is less than a threshold portion of the product hydrocarbon stream, methods 200 further may include increasing a temperature of the subterranean foimation, increasing a concentration and/or changing the composition of a non-condensable gas (such as methane or nitrogen or CO2) in the modified diluent relative to a concentration of the non-condensable gas in the diluent, increasing a concentration of dimethyl ether in the modified diluent relative to a concentration of dimethyl ether within the diluent, and/or decreasing a diluent-to-viscous-hydrocarbon ratio of the modified diluent relative to the diluent. Conversely, and responsive to the monitoring at 250 indicating that the diluted viscous hydrocarbon fraction of the reduced-viscosity hydrocarbons that are produced in the product hydrocarbon stream (i.e., the portion of the product hydrocarbon stream that comprises the diluted viscous hydrocarbon fraction) is greater than the threshold portion of the product hydrocarbon stream, methods 200 further may include decreasing the concentration of the non-condensable gas in the modified diluent relative to the concentration of the non-condensable gas in the diluent, decreasing the concentration of dimethyl ether in the modified diluent relative to the concentration of dimethyl ether within the diluent, and/or increasing the diluent-to-viscous-hydrocarbon ratio of the modified diluent relative to the diluent.
Repeating at least the portion of the methods at 260 may include repeating any suitable portion of methods 200 in any suitable manner. As an example, the repeating at 260 may include repeating the characterizing at 205, the selecting at 210, the calculating at 215, the heating at 220, the injecting at 225, the ceasing at 230, the regulating at 235, the producing at 240, the ceasing at 245, the monitoring at 250, and/or the adjusting at 255 a plurality of times as a part of a plurality of stimulation-production cycles. The repeating at 260 may include repeating at least the calculating at 215, the heating at 220, the injecting at 225, the ceasing at 230, the regulating at 235, the producing at 240, and the monitoring at 250 a plurality of times prior to performing the adjusting at 255.

As another example, the product hydrocarbon stream may be a first product hydrocarbon stream and the diluted viscous hydrocarbon fraction may be a first diluted viscous hydrocarbon fraction. Under these conditions, the repeating at 260 may include repeating the injecting at 225 to inject and/or supply the modified diluent to the subterranean folination, to dilute the viscous hydrocarbons, and/or to generate reduced-viscosity hydrocarbons within the subterranean formation. The reduced-viscosity hydrocarbons generated during the repeating at 260 may include a second diluted viscous hydrocarbon fraction, which may be different from the first diluted viscous hydrocarbon fraction. The repeating at 260 further may include repeating the producing at 240 to produce a second product hydrocarbon stream from the subterranean formation. The repeating at 260 further may include repeating the monitoring at 250 to monitor a variable that is indicative of a portion of the second product hydrocarbon stream that comprises the second diluted viscous hydrocarbon fraction. The repeating at 260 also may include repeating the adjusting at 255 to define another modified diluent to be supplied to the subterranean foimation. The other modified diluent may be defined based, at least in part, on the portion of the second product hydrocarbon stream that comprises the second diluted viscous hydrocarbon fraction.
When methods 200 include the repeating at 260, the adjusting at 255 may include adjusting to increase the portion of the second product hydrocarbon stream that comprises the (second) diluted viscous hydrocarbon fraction relative to the portion of the first hydrocarbon stream that comprises the (first) diluted viscous hydrocarbon fraction.
Additionally or alternatively, the adjusting at 255 also may include adjusting to maintain the portion of the second product hydrocarbon stream that comprises the (second) diluted viscous hydrocarbon fraction above a threshold portion of the second product hydrocarbon stream.
Additionally or alternatively, the adjusting at 255 may include adjusting to decrease a viscosity of the second product hydrocarbon stream relative to the first product hydrocarbon stream, to decrease a portion of the second product hydrocarbon stream that comprises the heavy liquid hydrocarbon fraction relative to a portion of the first product hydrocarbon stream that comprises the heavy liquid hydrocarbon fraction, and/or to maintain the diluent-to-viscous-hydrocarbon ratio in the second product hydrocarbon stream below a threshold, or critical, diluent-to-viscous-hydrocarbon ratio.
In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, it is within the scope of the present disclosure that the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently.
As used herein, the term "and/or" placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity.
Multiple entities listed with "and/or" should be construed in the same manner, i.e., "one or more"
of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the "and/or" clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to "A
and/or B," when used in conjunction with open-ended language such as "comprising" may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B
(optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.
As used herein, the phrase "at least one," in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase "at least one" refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, "at least one of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at least one of A and/or B") may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, 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.
In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the teim or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally.
As used herein the terms "adapted" and "configured" mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms "adapted" and "configured" should not be construed to mean that a given element, component, or other subject matter is simply "capable of' performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function.
It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.
As used herein, the phrase, "for example," the phrase, "as an example," and/or simply the telin "example," when used with reference to one or more components, features, details, structures, embodiments, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, embodiment, and/or method is an illustrative, non-exclusive example of components, features, details, structures, embodiments, and/or methods according to the present disclosure. Thus, the described component, feature, detail, structure, embodiment, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, embodiments, and/or methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, embodiments, and/or methods, are also within the scope of the present disclosure.
Industrial Applicability The methods disclosed herein are applicable to the oil and gas industries.
It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite "a" or "a first"
element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.
It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.

Claims

1. A method of performing a cyclic hydrocarbon production process to stimulate production of viscous hydrocarbons from a subterranean formation, the method comprising:
injecting a diluent into the subterranean formation to dilute the viscous hydrocarbons and generate reduced-viscosity hydrocarbons within the subterranean formation, wherein the reduced-viscosity hydrocarbons include a diluted viscous hydrocarbon fraction;
subsequent to the injecting the diluent, producing a product hydrocarbon stream from the subterranean formation, wherein the product hydrocarbon stream includes at least a portion of the reduced-viscosity hydrocarbons;
monitoring a variable of the product hydrocarbon stream that is indicative of the diluted viscous hydrocarbon fraction; and adjusting at least one property of the diluent to define a modified diluent and to mitigate formation of a heavy liquid hydrocarbon fraction within the subterranean formation, wherein the adjusting is based, at least in part, on the variable of the product hydrocarbon stream.

2. The method of claim 1, wherein the method further includes injecting the modified diluent to the subterranean formation.

3. The method of claim 1 or claim 2, wherein the product hydrocarbon stream is a first product hydrocarbon stream, wherein the diluted viscous hydrocarbon fraction is a first diluted viscous hydrocarbon fraction, and further wherein the method includes:
(i) repeating the injecting to supply the modified diluent to the subterranean formation to dilute the viscous hydrocarbons and generate the reduced-viscosity hydrocarbons within the subterranean formation, wherein the reduced-viscosity hydrocarbons include a second diluted viscous hydrocarbon fraction;
(ii) repeating the producing to produce a second product hydrocarbon stream from the subterranean formation, wherein the second product hydrocarbon stream is generated subsequent to supply of the modified diluent to the subterranean formation and includes at least a portion of the reduced-viscosity hydrocarbons;
(iii) repeating the monitoring to monitor a variable that is indicative of a portion of the second product hydrocarbon stream that comprises the second diluted viscous hydrocarbon fraction; and (iv) repeating the adjusting to define another modified diluent to be supplied to the subterranean formation based, at least in part, on the portion of the second product hydrocarbon stream that comprises the second diluted viscous hydrocarbon fraction.

4. The method of claim 1 or claim 2, wherein the method further includes repeating the injecting, the producing, the monitoring, and the adjusting a plurality of times as part of a plurality of stimulation-production cycles.

5. The method of any one of claims 1-4, wherein the product hydrocarbon stream includes a heavy liquid hydrocarbon fraction, a light liquid hydrocarbon fraction, and the diluted viscous hydrocarbon fraction.

6. The method of any one of claims 1-5, wherein the product hydrocarbon stream includes at least a portion of the diluent.

7. The method of any one of claims 1-6, wherein, prior to the injecting the diluent, the method further includes characterizing the viscous hydrocarbons.

8. The method of claim 7, wherein the characterizing the viscous hydrocarbons includes obtaining a sample of the viscous hydrocarbons from the subterranean formation and characterizing the sample of the viscous hydrocarbons.

9. The method of claim 7 or claim 8, wherein the characterizing the viscous hydrocarbons includes determining a critical diluent-to-viscous-hydrocarbon ratio for dilution of the viscous hydrocarbons by a given diluent at a given temperature and a given pressure.

10. The method of claim 9, wherein, when the given diluent and the viscous hydrocarbons are mixed at a ratio that is less than the critical diluent-to-viscous-hydrocarbon ratio, the given diluent and the viscous hydrocarbons combine to generate a single liquid phase that includes the diluted viscous hydrocarbon fraction, and further wherein, when the given diluent and the viscous hydrocarbons are mixed at a ratio that is greater than the critical diluent-to-viscous-hydrocarbon ratio, the given diluent and the viscous hydrocarbons combine to generate two phase-separated liquid phases that include a heavy liquid hydrocarbon fraction and a separate light liquid hydrocarbon fraction.

11. The method of claim 9 or claim 10, wherein the method further includes selecting at least one of a chemical composition of the diluent, a temperature of the diluent, and a pressure of the diluent based, at least in part, on the critical diluent-to-viscous-hydrocarbon ratio.

12. The method of any one of claims 7-11, wherein the method further includes selecting at least one of a chemical composition of the diluent, a temperature of the diluent, and a pressure of the diluent based, at least in part, on the characterizing the viscous hydrocarbons.

13. The method of any one of claims 7-12, wherein the method further includes heating at least a portion of the subterranean formation, and further wherein the method includes selecting a target temperature range for the subterranean formation based, at least in part, on the characterizing the viscous hydrocarbons.

14. The method of any one of claims 7-13, wherein the characterizing includes determining at least a portion of an equation of state for a diluent-viscous hydrocarbon mixture.

15. The method of any one of claims 1-14, wherein the method further includes calculating a quantity of heat required to heat the portion of the subterranean formation to at least a threshold upper temperature and providing the quantity of heat to the subterranean formation.

16. The method of claim 15, wherein the quantity of heat is provided by at least one of injecting steam into the subterranean formation, heating the diluent prior to injecting the diluent, electrical heating, and electromagnetic heating.

17. The method of claim 15, wherein the quantity of heat is provided by injecting steam into the subterranean formation, and further wherein the steam is injected at least one of prior to the diluent, prior to injection of the modified diluent, with the diluent, and with the modified diluent.

18. The method of any one of claims 15-17, wherein the method further includes monitoring a temperature and repeating the heating responsive to the temperature being less than a threshold lower temperature, wherein the temperature includes at least one of a temperature of the product hydrocarbon stream and a temperature of the portion of the subterranean formation.

19. The method of any one of claims 1-18, wherein, subsequent to the injecting the diluent and prior to the producing the product hydrocarbon stream, the method further includes waiting at least a threshold soak time.

20. The method of claim 19, wherein the method further includes regulating a pressure within the subterranean formation during at least one of the waiting and the producing.

21. The method of any one of claims 1-20, wherein the method further includes selecting at least one of a volume of the diluent, a chemical composition of the diluent, and a temperature of the diluent based, at least in part, on a composition of the viscous hydrocarbons within the subterranean formation.

22. The method of claim 21, wherein the selecting includes selecting such that a portion of the product hydrocarbon stream that comprises the diluted viscous hydrocarbon fraction is expected to be greater than a threshold portion of the product hydrocarbon stream and any produced water.

23. The method of any one of claims 1-22, wherein the monitoring the variable includes monitoring a chemical composition of the diluted viscous hydrocarbon fraction.

24. The method of any one of claims 1-23, wherein the monitoring the variable includes monitoring a chemical composition of a light liquid hydrocarbon fraction of the product hydrocarbon stream.

25. The method of any one of claims 1-24, wherein the monitoring the variable includes monitoring a chemical composition of a heavy liquid hydrocarbon fraction of the product hydrocarbon stream.

26. The method of any one of claims 1-25, wherein the monitoring the variable includes monitoring at least one of a viscosity of the diluted viscous hydrocarbon fraction and a density of the diluted viscous hydrocarbon fraction.

27. The method of any one of claims 1-26, wherein the monitoring the variable includes monitoring at least one of a viscosity of a heavy liquid hydrocarbon fraction of the product hydrocarbon stream and a density of a heavy liquid hydrocarbon fraction of the product hydrocarbon stream.

28. The method of any one of claims 1-27, wherein the monitoring the variable includes monitoring at least one of a viscosity of a light liquid hydrocarbon fraction of the product hydrocarbon stream and a density of a light liquid hydrocarbon fraction of the product hydrocarbon stream.

29. The method of any one of claims 1-28, wherein the monitoring the variable includes monitoring a ratio of the light liquid hydrocarbon to the heavy liquid hydrocarbon volume ratio in the product hydrocarbon stream.

30. The method of any one of claims 1-29, wherein the monitoring the variable includes determining a portion of the product hydrocarbon stream that comprises the diluted viscous hydrocarbon fraction.

31. The method of any one of claims 1-30, wherein the monitoring the variable includes monitoring the amount and/or composition of non-condensable gas in the product hydrocarbon product stream.

32. The method of any one of claims 1-31, wherein the monitoring the variable includes at least one of:
(i) monitoring a temperature of the product hydrocarbon stream;
(ii) monitoring a viscosity of the product hydrocarbon stream;
(iii) monitoring a density of the product hydrocarbon stream;
(iv) monitoring a color of the product hydrocarbon stream; and (v) monitoring a diluent-to-viscous-hydrocarbon ratio in the product hydrocarbon stream.

33. The method of any one of claims 1-32, wherein the monitoring the variable includes at least one of:
(i) monitoring an instantaneous value of the variable; and (ii) monitoring a cumulative value of the variable.

34. The method of any one of claims 1-33, wherein the at least one property includes at least one of a volume of the modified diluent relative to a volume of the diluent, a chemical composition of the modified diluent relative to a chemical composition of the diluent, and a temperature of the modified diluent relative to a temperature of the diluent.

35. The method of any one of claims 1-34, wherein the product hydrocarbon stream is a first product hydrocarbon stream, and further wherein the method further includes injecting the modified diluent to the subterranean formation and, subsequent to the injecting the modified diluent, producing a second product hydrocarbon stream from the subterranean formation.

36. The method of claim 35, wherein the adjusting includes adjusting to increase the portion of the second product hydrocarbon stream that comprises the diluted viscous hydrocarbon fraction relative to the portion of the first hydrocarbon stream that comprises the diluted viscous hydrocarbon fraction.

37. The method of claim 36, wherein the adjusting includes adjusting to maintain the portion of the second product hydrocarbon stream that comprises the diluted viscous hydrocarbon fraction above a threshold portion of the second product hydrocarbon stream.

38. The method of claim 36, wherein the adjusting includes adjusting to decrease a viscosity of the second product hydrocarbon stream relative to the first product hydrocarbon stream.

39. The method of claim 36, wherein the adjusting includes adjusting to decrease a proportion of the second product hydrocarbon stream that comprises a heavy liquid hydrocarbon fraction relative to a proportion of the first product hydrocarbon stream that comprises the heavy liquid hydrocarbon fraction.

40. The method of claim 36, wherein the adjusting includes adjusting to maintain a diluent-to-viscous-hydrocarbon ratio in the second product hydrocarbon stream below a threshold diluent-to-viscous-hydrocarbon ratio.

41. The method of claim 36, wherein the adjusting includes adjusting a quantity of non-condensable gas within the subterranean formation to maintain a diluent-to-viscous-hydrocarbon ratio in the second product hydrocarbon stream below a threshold diluent-to-viscous-hydrocarbon ratio.

42. The method of any one of claims 36-41, wherein, responsive to a portion of the product hydrocarbon stream that comprises the diluted viscous hydrocarbon fraction being less than a threshold portion of the product hydrocarbon stream, the method includes at least one of:
(i) increasing a temperature of the subterranean formation;
(ii) increasing a concentration of a non-condensable gas within the modified diluent relative to a concentration of the non-condensable gas in the diluent;
(iii) increasing a concentration of dimethyl ether in the modified diluent relative to a concentration of dimethyl ether in the diluent; and (iv) decreasing a diluent-to-viscous-hydrocarbon ratio of the modified diluent relative to the diluent.

43. The method of any one of claims 36-42, wherein, responsive to a portion of the product hydrocarbon stream that comprises the diluted viscous hydrocarbon fraction being greater than a threshold portion of the product hydrocarbon stream, the method includes at least one of:
(i) decreasing a concentration of a non-condensable gas within the modified diluent relative to a concentration of the non-condensable gas in the diluent;
(ii) decreasing a concentration of dimethyl ether in the modified diluent relative to a concentration of dimethyl ether in the diluent; and (iii) increasing a diluent-to-viscous-hydrocarbon ratio of the modified diluent relative to the diluent.

44. The method of any one of claims 1-43, wherein the viscous hydrocarbons include at least one of bitumen, asphaltenes, tar, and an unconventional hydrocarbon reserve.

45. The method of any one of claims 1-44, wherein at least one of the diluent and the modified diluent includes at least one of methane, ethane, propane, butane, pentane, hexane, heptane, octane, nonane, decane, dimethyl ether, an alkane, cyclopentane, cyclohexane, naphtha, natural gas condensate, and gas plant condensate.

46. The method of any one of claims 1-45, wherein the subterranean formation includes at least one of an oil sands formation, a tar sands formation, a bituminous sands formation, and an oil shale formation.

47. A method of performing a cyclic hydrocarbon production process to stimulate production of viscous hydrocarbons from a subterranean formation, the method comprising:
determining a critical diluent-to-viscous-hydrocarbon ratio for dilution of the viscous hydrocarbons by a diluent at a given temperature and pressure;
calculating a quantity of heat required to heat a portion of the subterranean formation to the given temperature;
providing the quantity of heat to the subterranean formation to heat the subterranean formation to the given temperature;
injecting a predetermined volume of the diluent into the subterranean formation to dilute the viscous hydrocarbons and generate reduced-viscosity hydrocarbons within the subterranean formation;
ceasing the injecting the diluent;
subsequent to the ceasing the injecting, producing a product hydrocarbon stream from the subterranean formation, wherein the product hydrocarbon stream includes at least a portion of the reduced-viscosity hydrocarbons;
concurrently with the producing, regulating a production pressure of the product hydrocarbon stream to maintain the production pressure above a threshold production pressure;
concurrently with the producing, monitoring a variable of the product hydrocarbon stream that is indicative of a diluted viscous hydrocarbon fraction of the product hydrocarbon stream;

ceasing the producing responsive to a temperature of the product hydrocarbon stream being at least one of less than a lower stream temperature threshold and lower than a hydrocarbon stream production rate threshold;
adjusting at least one property of the diluent to define a modified diluent and to mitigate formation of a heavy liquid hydrocarbon fraction within the subterranean formation, wherein the adjusting is based, at least in part, on the variable of the product hydrocarbon stream; and repeating at least the calculating, the providing, the injecting, the ceasing the injecting, the producing, the regulating, the monitoring, the ceasing the producing, and the adjusting a plurality of times as part of a plurality of stimulation-production cycles.

48. The method of claim 47, wherein the method further includes repeating the calculating a quantity of heat required to heat a portion of the subterranean formation to the given temperature, the providing a quantity of heat required to heat a portion of the subterranean formation to the given temperature, and, the injecting, the ceasing, the producing, the regulating, the monitoring, and the ceasing prior to performing the adjusting.

49. The method of any one of claims 47-48, wherein prior to the injecting, the method further includes selecting at least one of a volume of the diluent, a chemical composition of the diluent, and a temperature of the diluent based, at least in part, on a composition of the viscous hydrocarbons within the subterranean formation.

50. The method of any one of claims 47-49, wherein the at least one property includes at least one of a volume of the modified diluent relative to a volume of the diluent, a chemical composition of the modified diluent relative to a chemical composition of the diluent, and a temperature of the modified diluent relative to a temperature of the diluent.

51. The method of any one of claims 47-50, wherein, responsive to the diluted viscous hydrocarbon fraction being less than a lower threshold portion of the product hydrocarbon stream, the method includes at least one of:
(i) increasing a temperature of the subterranean formation;
(ii) increasing a concentration of a non-condensable gas within the modified diluent relative to a concentration of the non-condensable gas in the diluent;
(iii) increasing a concentration of dimethyl ether in the modified diluent relative to a concentration of dimethyl ether in the diluent; and (iv) decreasing a diluent-to-viscous-hydrocarbon ratio for the modified diluent relative to the diluent.

52. The method of any one of claims 47-51, wherein, responsive to the diluted viscous hydrocarbon fraction being greater than an upper threshold portion of the product hydrocarbon stream, the method includes at least one of:
(i) decreasing a concentration of a non-condensable gas within the modified diluent relative to a concentration of the non-condensable gas in the diluent;
(ii) decreasing a concentration of dimethyl ether in the modified diluent relative to a concentration of dimethyl ether in the diluent; and (iii) increasing a diluent-to-viscous-hydrocarbon ratio for the modified diluent relative to the diluent.

53. The method of any one of claims 47-52, wherein the method further includes selecting the predetermined volume of the diluent to maintain a diluent-to-viscous-hydrocarbon ratio within the subterranean formation below the critical diluent-to-viscous-hydrocarbon ratio.

54. The method of any one of claims 47-53, wherein the quantity of heat is provided by at least one of injecting steam into the subterranean formation, heating the diluent prior to injecting the diluent, electrical heating, and electromagnetic heating.

55. The method of claim 54, wherein the quantity of heat is provided by injecting steam into the subterranean formation, and further wherein the steam is injected at least one of prior to the diluent, prior to injection of the modified diluent, with the diluent, and with the modified diluent.