PAT 104239-1 PROCESS FOR PRODUCING HYDROCARBONS FROM A SUBTERRANEAN HYDROCARBON-BEARING FORMATION TECHNICAL FIELD [0001] The present disclosure relates to the production of hydrocarbons from a subterranean formation bearing heavy oil or bitumen. BACKGROUND DISCUSSION [0002] Extensive deposits of viscous hydrocarbons exist around the world. Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbon, heavy oil, extra-heavy oil, bitumen, or oil sands, and include large subterranean deposits in Alberta, Canada that are not susceptible to standard oil well production technologies. The hydrocarbons in such deposits are typically highly viscous and do not flow at commercially relevant rates at the temperatures and pressures present in the reservoir. For such reservoirs, various recovery techniques may be utilized to mobilize the hydrocarbons and produce the mobilized hydrocarbons from wells drilled in the reservoirs. For example, thermal techniques may be used to heat the reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells. [0003] Hydrocarbon substances of high viscosity are generally categorized as "heavy oil" or as "bitumen". Although these terms are in common use, references to heavy oil and bitumen represent categories of convenience, and there is a continuum of properties between heavy oil and bitumen. Accordingly, references to such types of oil herein include the continuum of such substances, and do not imply the existence of some fixed and universally recognized boundary between the substances. [0004] One thermal method of recovering viscous hydrocarbons from a subterranean hydrocarbon-bearing formation using spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). Various embodiments of the SAGD process are described in Canadian Patent No. 1,304,287 and - 1 - CA 3022035 2018-10-24 PAT 104239-1 corresponding U.S. Patent No. 4,344,485. In the SAGD process, steam is injected through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well that is vertically spaced from and near the injection well. The injection and production wells are located close to the base of the hydrocarbon deposit to collect the hydrocarbons that flow toward the production well. [0005] Such thermal processes are extremely energy intensive, utilize significant volumes of water for the production of steam, and may require additional equipment to handle the steam or gasses produced. [0006] A solvent may be used to aid a steam-assisted recovery process, in a so-called solvent-aided process (SAP). Hydrocarbon solvent is generally used to improve mobility in the hydrocarbon reservoir, potentially improving production and/or reducing steam and/or heating requirements. However, the use of solvent can add significant expense due to solvent costs; and, if injected solvent is to be recovered and/or recycled, additional surface processing apparatus may be needed. [0007] Commercial applications of solvent-aided recovery processes have been limited to date. Challenges remain in providing solvent-aided recovery processes for efficient and effective commercial application. SUMMARY [0008] In an aspect of the present disclosure, there is provided a process for producing hydrocarbons from a subterranean hydrocarbon-bearing formation that includes, during a production phase after a start-up phase, injecting a first fluid into a reservoir of the formation through an injection well to form a chamber and producing at least a portion of the hydrocarbons to a surface through a production well; while producing the at least a portion of the hydrocarbons to the surface, iteratively, injecting a second fluid into the reservoir through the injection well at a first rate to adjust a pressure in the reservoir to a first pressure value, and after the first pressure value is reached, - 2 - CA 3022035 2018-10-24 PAT 104239-1 injecting a third fluid into the reservoir through the injection well at a second rate to adjust the pressure in the reservoir to a second pressure value, such that a difference between the first pressure value and the second pressure value is at least about 25% of the higher of the first and second pressure values. [0009] The first fluid may be injected into the reservoir through the injection well until the chamber contacts a formation ceiling of the reservoir, and the second fluid may be injected into the reservoir at the first rate to adjust the pressure in the reservoir after the chamber reaches the formation ceiling. [0010] The first fluid may be steam that does not contain a significant amount of solvent. [0011] The second fluid may include a first mixture of steam and a first viscosity reducing solvent and the third fluid may include a second mixture of steam and a second viscosity reducing solvent. [0012] The first viscosity reducing solvent of the first mixture may comprise one or more alkanes having 2 to 9 carbon atoms and the second viscosity reducing solvent of the second mixture may comprise one or more alkanes having 2 to 9 carbon atoms. [0013] The first viscosity reducing solvent may be one or more of natural gas condensate, liquefied petroleum, hexane, pentane, butane, propane, and ethane, and the second viscosity reducing solvent may be one or more of natural gas condensate, liquefied petroleum, hexane, pentane, butane, propane, and ethane. [0014] The first viscosity reducing solvent may be the same as the second viscosity reducing solvent. [0015] A first amount of the first solvent in the first mixture may be between about greater than 20 percent by weight (wt%) of the first mixture and about 80 wt% of the first mixture, and a second amount of the second solvent in the second mixture may be between greater than about 20 wt% and about 80 wt% of the second mixture. - 3 - CA 3022035 2018-10-24 PAT 104239-1 [0016] A first amount of the first solvent in the first mixture may be between about 40 percent by weight (wt%) of the first mixture and about 80 wt% of the first mixture, and a second amount of the second solvent in the second mixture may be between about 40 wt% and about 80 wt% of the second mixture. [0017] A first amount of the first solvent in the first mixture may be about 50 wt% of the first mixture, and a second amount of the second solvent in the second mixture may be about 50 wt% of the second mixture. [0018] The first amount may be the same as the second amount. [0019] The first viscosity reducing solvent may be the same as the second viscosity reducing solvent. [0020] The second fluid may include a third mixture of steam and a third viscosity reducing solvent, and a third amount of the third viscosity reducing solvent in the third mixture may be between about 5 percent by weight (wt%) and about 20 wt% of the third mixture. [0021] The first pressure value may be higher than the second pressure value, and the third fluid may be steam that does not contain a significant amount of a solvent. [0022] The third fluid may include a fourth mixture of steam and a fourth viscosity reducing solvent, and a fourth amount of the fourth viscosity reducing solvent in the fourth mixture may be between about 5 wt% and about 20 wt% of the fourth mixture. [0023] The third amount may be the same as the fourth amount. [0024] The third viscosity reducing solvent may be the same as the fourth viscosity reducing solvent. [0025] The third viscosity reducing solvent may comprise one or more alkanes having 2 to 9 carbon atoms and the fourth viscosity reducing solvent may comprise one or more alkanes having 2 to 9 carbon atoms. - 4 - CA 3022035 2018-10-24 PAT 104239-1 [0026] The difference between the first pressure value and the second pressure value may be less than or equal to about 75% of the higher of the first and second pressure values. [0027] The difference may be between about 50% and about 75% of the higher of the first and second pressure values. [0028] The first pressure value may be greater than the second pressure value by an amount in a range of about 1000 kPa to about 3000 kPa. [0029] The greater of the first pressure value and the second pressure value may be less than the maximum operating pressure of the reservoir. [0030] The first pressure value may be maintained for a time duration before injecting the third fluid at the second rate, and the second pressure value may be maintained in the reservoir for the time duration before injecting the second fluid at the first rate. [0031] The time duration may be at least about 5 days. [0032] The time duration may be about 15 days. [0033] The time duration may be about 30 days. [0034] The time duration may increase in length over time, such that the time duration during a subsequent iteration is longer than the time duration of a previous iteration. BRIEF DESCRIPTION OF THE DRAWINGS [0035] Embodiments of the present application will now be described, by way of example only, with reference to the attached Figures, wherein: [0036] FIG. 1 is a sectional view through a reservoir, illustrating a well pair; [0037] FIG. 2 is a series of cross sectional views illustrating a well pair including an injection well and a production well during various stages of a hydrocarbon recovery process; - 5 - CA 3022035 2018-10-24 PAT 104239-1 [0038] FIG. 3 is a graph illustrating data of the measured oil production rate at a production well and the measured pressure in the injection well as a function of time during a solvent-aided process; [0039] FIG. 4 is a graph illustrating data of the measured oil production rate at a production well and the measured pressure in the injection well as a function of time during another solvent-aided process; [0040] FIG. 5 is a graph showing cumulative steam oil ratios (CSOR) as a function of time for three simulations of hydrocarbon recovery processes; [0041] FIG. 6 is a graph showing oil production rates as a function of time for the three simulations of hydrocarbon recovery processes shown in FIG. 5; [0042] FIG. 7 is a graph showing cumulative oil production as a function of time for the three simulations of hydrocarbon recovery processes shown in FIG. 5 and FIG. 6; [0043] FIG. 8 is a graph showing cumulative solvent injected as a function of time for two of the three simulations shown in FIG. 5 though FIG. 7; [0044] FIG. 9 is a graph showing cumulative oil production rates as a function of time for five simulations of various hydrocarbon recovery processes utilizing solvents with and without pressure cycling; and [0045] FIG. 10 is a flow chart illustrating a process for recovering hydrocarbons from a subterranean formation according to an embodiment of the present disclosure. DETAILED DESCRIPTION [0046] For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements. Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not - 6 - CA 3022035 2018-10-24 PAT 104239-1 described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein. [0047] The present disclosure generally relates to a process for recovering hydrocarbons from a hydrocarbon-bearing formation. The process includes, during a production phase after a start-up phase, injecting a first fluid into a reservoir of the formation through an injection well to form a vapor chamber and producing at least a portion of the hydrocarbons to a surface through a production well; while producing the at least a portion of the hydrocarbons to the surface, iteratively, injecting a second fluid into the reservoir through the injection well at a first rate to adjust a pressure in the reservoir to a first pressure value, and after the first pressure value is reached, injecting a third fluid into the reservoir through the injection well at a second rate to adjust the pressure in the reservoir to a second pressure value, such that a difference between the first pressure value and the second pressure value is at least about 25% of the higher of the first and second pressure values. [0048] A steam-assisted gravity drainage (SAGD) process may be utilized for mobilizing viscous hydrocarbons. In the SAGD process, a well pair, including a hydrocarbon production well (producer) and a steam injection well (injector) are utilized. One example of a hydrocarbon production well 100 and injection well 108 is illustrated in FIG. 1. The hydrocarbon production well 100 includes a generally horizontal segment 102 that extends near the base or bottom 104 of the hydrocarbon reservoir 106. The injection well 108 also includes a generally horizontal segment 110 that is disposed generally parallel to and is spaced generally vertically above the horizontal segment 102 of the hydrocarbon production well 100. [0049] During SAGD, steam is injected into the injection well 108 to mobilize the hydrocarbons and create a chamber (called a steam chamber) (shown in FIG. 2) in the reservoir 106, around and above the generally horizontal segment 110. - 7 - CA 3022035 2018-10-24 PAT 104239-1 [0050] A chamber within a reservoir or formation is a region that is in fluid/pressure communication with a particular well or wells, such as an injection or production well. For example, in a SAGD process, the steam chamber is the region of the reservoir in fluid communication with the steam injection well, which is also the region that is subject to depletion, primarily by gravity drainage, into the production well. In a SAP, the chamber may be referred to as a vapor chamber. [0051] In general, a SAGD process may be described as including three stages: the start-up stage; the production stage; and the wind-down (or blowdown) stage. The production stage may be described as including further stages such as, for example, a ramp-up stage and a plateau stage. [0052] FIG. 2 shows examples of cross sectional views of the horizontal segments 102, 110 of the production well 100 and the injection well 108, respectively. In FIG. 2, (a) shows an example start-up stage, (b) shows an example ramp-up stage of a production stage, and (c) shows an example plateau stage of the production stage. [0053] Generally, during the start-up stage, heat is transferred to the hydrocarbons within the near-wellbore region 206 of the reservoir near the horizontal sections 110 and 102 of the injection well 108 and production well 100, respectively. The hydrocarbons are heated to increase mobility of the hydrocarbons in order to establish fluid communication between the injection well 108 and the production well 100. Once fluid communication is established, the start-up stage ends and the production stage begins. The start-up stage may be performed by any suitable method. [0054] FIG. 2 shows one example of a start-up stage at (a) in which heat from each of the production well horizontal segment 102 and the injection well horizontal segment 110 is transferred to the hydrocarbons in the near-wellbore region 206. The hydrocarbons within the regions 202 and 204 have been heated by heat from the production well horizontal segment 102 and the injection well horizontal segment 110, respectively. As further heat is transferred to the - 8 - CA 3022035 2018-10-24 PAT 104239-1 hydrocarbons in the near-wellbore region 206, the regions 202 and 204 grow until they eventually merge, establishing fluid communication between the horizontal sections 102, 110 of the production well 100 and the injection well 108, respectively. [0055] The horizontal section 110 of the injection well 108 and the horizontal segment 102 of the production well 100 may be heated to transfer heat to the reservoir in any suitable manner including, for example, circulating a heated fluid through the horizontal segments 102, 110 such that the fluid is not injected into the reservoir to any significant degree. In other examples, heaters may be placed in the injection well horizontal segment 110 and the production well horizontal segment 102, or a heated fluid may be injected into the reservoir through openings in the horizontal segments 102, 110. The heated fluid may be, for example, steam or a mixture of steam and one or more solvents. [0056] During the ramp-up stage, steam is injected into the reservoir through the horizontal segment 110 of the injection well 108. Heated fluid that is circulated through the producer well 100 or injected into the reservoir through the horizontal segment 102 of the producer well 100 during the start-up stage is discontinued. If needed after start-up, the producer well segment 102 may be re-completed to produce the mobile hydrocarbons to the surface. During the production stage in a conventional SAGD operation, steam is injected through the injector well horizontal segment 110 at a substantially constant pressure, i.e., fluctuations in the pressure in a conventional SAGD operation may be less than or equal to about 12.5% higher or lower than the operating pressure. As shown in (b) of FIG. 2, the injected steam forms a vapor chamber 208 having an edge 210, which is the boundary between the heated steam and the hydrocarbons which are at a lower temperature, such as an initial reservoir temperature. [0057] In some typical bitumen reservoirs found in Alberta, Canada, the natural or initial temperature in the reservoir prior to hydrocarbon recovery may be between about 7 C and about 12 C, and the natural or initial pressure in the - 9 - CA 3022035 2018-10-24 PAT 104239-1 reservoir may be between about 1 MPa and about 5 MPa. In different reservoirs, the initial temperature and pressure may be different. [0058] As steam is injected, a vapor chamber 208 expands upwardly, and laterally to some degree, until the edge 210 contacts the overlying formation ceiling 212, as shown in (c) of FIG. 2, after which the vapor chamber continues to expand laterally. Typically, the rate of production of hydrocarbons at the production well 100 does not increase after the edge 210 of the vapor chamber 208 contacts the formation ceiling 212, but will remain constant for the next two to three years, for example. Because the rate of production does not typically increase after the vapor chamber 208 reaches the formation ceiling 212 as shown in (c) of FIG. 2, this stage of production is referred as the plateau stage. [0059] Steam that is injected through the injection well 108 moves outwards, towards the edge 210 of the vapor chamber 208, where the steam comes into contact with the hydrocarbons which are at a lower temperature, such as an initial reservoir temperature, in what is referred to as the "mixing zone" 214. Energy is transferred from the steam to the hydrocarbons at the edge 210 of the vapor chamber 208, heating the hydrocarbons in the mixing zone 214, which reduces the viscosity and increases the mobility of the heated hydrocarbons. The mobile hydrocarbons heated at the edge 210 of the vapor chamber 208 flow due to gravity toward the producer well 100 in side drained flow, illustrated by the arrows shown in the mixing zone 214 of the vapor chamber 208 shown in (c) of FIG. 2. [0060] Depending on the spacing between a pair of production and injection wells (not shown) adjacent the well pair of the production well 100 and the injection well 108 shown in FIG. 2, the vapor chamber (not shown) of the adjacent well pair will eventually coalesce with the vapor chamber 208 such that further significant growth of the vapor chamber 208 is not feasible. The stage after this coalescence of adjacent vapor chambers occurs may be referred to as the wind-down (or blowdown) stage. At this stage, the production stage is ended. During the wind-down stage, further steam injection is generally terminated or curtailed and a non-condensable gas (NCG) gas may be injected - 10 - CA 3022035 2018-10-24 PAT 104239-1 into the reservoir through the injection well segment 108 to maintain the pressure in the reservoir. In the wind-down stage the oil production declines until the wells are eventually abandoned. [0061] Light hydrocarbons, such as butane and propane, may optionally be injected into the injection well 108 during the production stage, in addition to the steam. The injected light hydrocarbons function as solvents in aiding the mobilization of the hydrocarbons. The co-injection of light hydrocarbons with steam may be part of a process referred to as a solvent-aided process (SAP). SAPs include steam driven solvent processes in which the amount of steam added is greater than the amount of solvent added, and solvent driven processes in which the amount of steam added is less than the amount of solvent added. In the present disclosure, unless otherwise stated, the term steam driven solvent process refers to SAPs in which the amount of solvent injected with the steam is between about 1 wt% and about 20 wt% of the mixture of steam and solvent, and the term hybrid solvent process refers to SAPs in which the amount of solvent injected with the steam is between about >20 wt% and about 80 wt% of the mixture. [0062] Generally, a steam driven solvent process according to the present disclosure may be initiated at any point during the production stage, whereas a hybrid solvent process is generally performed only when the plateau stage of production is reached, i.e., when the edge 210 of the vapor chamber 208 contacts the ceiling formation of the reservoir. [0063] Further, a steam driven solvent process may be performed in reservoirs in which solvent is already present due to injection of solvents during the production stage prior to initiating the steam driven solvent process, or during the start-up stage, or both. By contrast, a hybrid solvent process is desirably performed only when no, or very little, solvent is present in the reservoir due to injection during the start-up stage, during the production stage, or both, prior to initiating the hybrid solvent process. - 11 - CA 3022035 2018-10-24 PAT 104239-1 [0064] The present disclosure describes a process that includes iteratively, or cyclically, increasing and decreasing (or decreasing and increasing) the pressure in the reservoir during a production stage of a SAP, such as a steam driven solvent process or a hybrid solvent process. Cyclically adjusting the pressure during production may be performed as part of a steam driven solvent process at any time during the production stage, or may be performed as part of a hybrid solvent process during the plateau stage. Cyclically increasing and decreasing (or decreasing and increasing) the pressure in the reservoir is performed by increasing and decreasing (or decreasing and increasing) a rate of injection of steam, or a mixture of steam and solvent through the injection well 108. It has been observed that increasing and decreasing the pressure within the reservoir correlates to an increased rate of production of hydrocarbons at the production well 100. [0065] Without wishing to be bound to a particular theory, the solubility of a solvent in hydrocarbons within the reservoir increases with increased reservoir pressure. [0066] Because the thermal diffusivity in oil sands reservoirs is about 3 to 4 orders of magnitude lower than the hydraulic diffusivity, the temperature at the edge 210 of the vapor chamber 208 changes at a significantly lower rate than the pressure diffusion, via Darcy flow, of the vaporized steam and solvents. This means that solvents within the vapor chamber 208 diffuse toward the edge 210 at a rate that is faster than the rate of heating of the hydrocarbons at the edge 210. [0067] The solvent-hydrocarbon mixture viscosity at the edge 210 is highly dependent on solvent solubility. At SAP operating conditions, the solubility of the solvent increases with increased pressure and increases with decreased temperature. Injecting steam or a mixture of steam and solvent at higher pressures on a consistent basis will eventually cause the temperature at the edge 210 of the vapor chamber 208 to increase, which negatively affects the solvent solubility. - 12 - CA 3022035 2018-10-24 PAT 104239-1 [0068] By cyclically increasing and decreasing the pressure in the reservoir, the pressure in the mixing zone 214 may be relatively high during the high pressure period to increase the solubility of the solvents, but is lowered to the low pressure value such that the high pressure condition is not continuously maintained for such a long period of time that the temperature in the mixing zone 214 is significantly increased compared to the case in which the reservoir is constantly at a high pressure. [0069] The combination of the lower temperature and higher pressure due to cyclically increasing and decreasing the pressure of the reservoir results in higher solubility, which in turn results in lower viscosity of the solvent- hydrocarbon mixture and higher fluid drainage rates in the mixing zone 214. [0070] Further, increased pressure in the reservoir may lead to increased shear dilation of the oil sands within the reservoir. Shear dilation lowers the tortuosity and raises the porosity of the oil sands which lead to enhancement of the permeability of fluids, including steam and solvents, through the reservoir. By intentionally increasing the pressure within the reservoir, shear dilation occurs earlier, and by a greater degree, than during conventional SAGD processes in which the reservoir pressure may increase more gradually due to normal changes in operating pressure. Shear dilation effects will be greater in reservoirs with a larger ratio of horizontal to vertical principal stresses. Pressure Cycling in a Steam Driven Solvent Process [0071] Pressure cycling may be utilized in a steam driven solvent process in which the amount of solvent injected with the steam may be less than 50 percent by weight (wt%) of the mixture. In an example, the amount of solvent injected with steam during pressure cycling in a pressure cycling steam driven solvent process may be between about 1 wt% of the mixture and about 20 wt% of the mixture, and desirably the amount of solvent is at least about 5 wt%. [0072] A pressure cycling steam driven solvent process may be performed at any time during the production stage of the SAP. In an example, a pressure cycling steam driven solvent process may be initiated during the plateau stage - 13 - CA 3022035 2018-10-24 PAT 104239-1 described above, after the vapor chamber has reached the formation ceiling of the reservoir. A pressure cycling steam driven solvent process may be performed irrespective of whether solvents are present in the reservoir due to injection of solvent during the production stage prior to initiating a pressure cycling steam driven solvent process, during the start-up stage, or both. [0073] In a pressure cycling steam driven solvent process a heated fluid is injected into the reservoir through a horizontal segment of an injection well while hydrocarbons are produced through a horizontal segment of the producer well. The injection well and the production well may be similar to the injection well 108 and the production well 100, respectively, described previously with reference to FIG. 1. [0074] The rate of injection of the heated fluid may be increased to cause the pressure in the reservoir to increase to a desired high pressure value. Once a desired high pressure value is reached, the rate of injection of the heated fluid may be reduced to lower the reservoir pressure to desired low pressure value. Once a desired low pressure is reached, the rate of injection may be increased again in order to iteratively cycle between high and low pressures. [0075] Alternatively, during the initial cycle, the rate of injection of the heated fluid may be reduced to cause the pressure in the reservoir to first be lowered to a desired low pressure value, then the rate may be increased to increase the reservoir pressure to a desired high pressure value. [0076] The heated fluid injected during a pressure cycling steam driven solvent process may be a mixture of steam and one or more solvents. The solvents utilized for a pressure cycling steam driven solvent process may be selected from alkanes having 2 to 9 carbon atoms. The solvent utilized may be one alkane or a combination of alkanes. A mixture of different solvents may be utilized in a pressure cycling steam driven solvent process when, for example, utilizing a single solvent may not be feasible depending on solvent supply. Examples of solvents that may be utilized in pressure cycling steam driven solvent processes include natural gas condensate, liquefied petroleum (also - 14 - CA 3022035 2018-10-24 PAT 104239-1 known as liquefied petroleum gas), hexane, pentane, propane, butane, and ethane. [0077] In addition, non-condensing gases such as, for example, methane, carbon dioxide, nitrogen, or air, or a combination thereof, may be included in the heated fluid injected into the reservoir through the injection well. [0078] In general, the same fluid composition is injected for both increasing and decreasing the reservoir pressure to the high and low pressure values. [0079] However, a different fluid may be injected for increasing the reservoir pressure to the high pressure value than the fluid injected when decreasing the reservoir pressure to the low pressure value. In an example, the heated fluid injected through the injection well when increasing the reservoir pressure to the desired high pressure value may be a mixture of steam and one or more solvents, whereas the heated fluid injected through the injection well when lowering the reservoir to the desired low pressure value may be steam only. In this example, once the desired high pressure value is reached, solvent injection ceases. [0080] In another example, the heated fluid injected through the injection well during pressure cycling may be steam only. In this example, solvent must be present in reservoir in order for the pressure cycling to increase production rates due to increased solvent solubility. The solvent within the reservoir may be present due to solvent injected during the production stage prior to pressure cycling, or during the start-up stage, or both. [0081] The high pressure value and the low pressure value are chosen such that a difference between the high and low pressure values is at least about 25% of the high pressure value. In an example, the difference between the high and low pressure values is between about 25% and about 75%. [0082] In some examples, the values of the high and low pressure values may be varied between iterations such that the difference between the high and low pressure values may be different during different iterations of pressure - 15 - CA 3022035 2018-10-24 PAT 104239-1 cycling. Alternatively, in another example, the values of the high and low pressure values may be varied between cycles such that the difference between the high and low pressure values remains constant. [0083] The maximum pressure that may be utilized for the high pressure value is the maximum operating pressure (MOP) of the reservoir. The MOP may be, for example, set by the relevant regulatory authority such as, for example, the Alberta Energy Regulator (AER) for reservoirs located in Alberta, Canada. The MOP is a function of reservoir depth, reservoir geological characteristics, the selected recovery process and the strength of the cap rock that is used for containment. Typically, the MOP may be approximately 7000 kPa. [0084] The minimum pressure that may be utilized for the low pressure value generally is the lowest pressure that facilitates producing fluids through the production well up to the surface. [0085] In addition, the high pressure value and low pressure value may be limited by reservoir conditions. For example, the high and low pressure values may be limited by so called "thief zones", in the vicinity of the injection and production well pair. Thief zones may include bottom water, top water, a depleted gas cap, an intact gas cap, or any combination thereof. In cases in which such thief zones exist, the high pressure value should not be so high that injected solvent or steam enters into the thief zones in a significant amount, whereas the low pressure value should not be so low that fluids from the thief zone enter into the vapor chamber in a significant amount. [0086] In practice, the minimum low pressure value utilized in pressure cycling may be at least about 25% of the high pressure value. In an example, the low pressure value may be not greater than about 75% of the high pressure value. Desirably, the low pressure value may be between about 50% and about 75% of the high pressure value. [0087] In general, the time taken to adjust the reservoir pressure between the high and low pressure values is desirably as short as is feasible. For example, the time to reduce the reservoir pressure from the high pressure value - 16 - CA 3022035 2018-10-24 PAT 104239-1 to the low pressure value may be less than 2 days, and desirably less than 1 day. [0088] In some examples, the rate of injection of heated fluids may be adjusted as soon as the desired high or low pressure value is reached. [0089] Alternatively, once reached, the high pressure value, or the low pressure value, or both may be maintained for a particular time period. For example, the high pressure value may be maintained for a first length of time, and the low pressure value may be maintained for a second length of time. The time periods for maintaining the high pressure value and the low pressure value may be the same for a particular cycle, or may different. In addition, the time periods may vary from cycle to cycle. For example, later cycles may maintain the high and low pressures for time periods that are longer than in previous cycles. [0090] Because the relative amount of solvent utilized in a pressure cycling steam driven solvent process is low relative to the amount of steam, the impact of the time duration of the high or low pressure values on increased production rates may be less pronounced than in the case of pressure cycling during a hybrid solvent process, which utilizes relatively higher concentrations of solvents, as discussed in more detail below. [0091] Referring to FIG. 3, a graph shows the measured pressure within an injection well 300, which corresponds to the reservoir pressure, and the measured rate of oil production from a production well 301 as a function of time in a SAP utilizing an injection well and production well configuration similar to FIG. 1. The vertical dotted line indicates the point in time at which solvent (10 wt% butane) injection begins. FIG. 3 shows a time period 302 of approximately one year during which the injection pressure was increased from 2500 kPa to 3000 kPa, after which the injection pressure was reduced and maintained between 2000 kPa to 2300 kPa. Arrow 304 in FIG. 3 shows that the oil production rate increased significantly approximately six months after the time period 302. - 17 - CA 3022035 2018-10-24 PAT 104239-1 [0092] Referring to FIG. 4, a graph shows the measured pressure within an injection well 400, which corresponds to the reservoir pressure, and the measured rate of oil production 401 from a production well as a function of time in another SAP utilizing an injection well and production well configuration similar to FIG. 1. The vertical dotted line indicates the point in time at which solvent (10 wt% butane) injection begins. [0093] A spike 402 in the measured injection pressure corresponds to a time period of about 4 weeks during which the operating pressure of an injection well was increased from 2400kPa to 2900kPa by increasing a rate of injection of a mixture of steam and solvent through the injection well. The operating pressure was then decreased to 2500kPa about 2 weeks later by decreasing the rate of injection of the mixture of steam and solvent through the injection well. A spike 408 in the measured rate of oil production, corresponding to an oil rate increase from about 100 tons/day to about 200 tons/day was then observed. This oil rate spike 408 was believed to be correlated with injection pressure spike 402. The operating pressure of the injection well was increased again, corresponding to a second spike 404 in the measured injection pressure several weeks after the first pressure spike 402. The second pressure spike 404 was followed by a second spike 410 in the measured oil production. [0094] FIG. 5 through FIG. 8 show the results of simulations performed for various hydrocarbon recovery processes: SAGD without solvent injection or pressure cycling, a steam driven solvent process without pressure cycling, and a steam driven solvent process with pressure cycling. The simulations performed utilized a half-element of symmetry, dead oil, 2D reservoir simulation. A summary of the reservoir model input parameters are shown in the following table: - 18 - CA 3022035 2018-10-24 PAT 104239-1 Item Input Units/Comments Fluid Inputs Phases Aqueous, Oleic,Vapor Three phases Components Water, Bitumen, Methane, Four components Butane Reservoir Inputs Grid number 50,1,30 2D Cartesian grid Grid Size 50*1,1*2,30*0.8 Meter Permeability 5, 5, 4 Darcy Porosity 0.33 Initial Pressure 2200 kPa Initial Temperature 11 Degree C Soi, Swi 0.8, 0.2 No initial mobility to Water [0095] For the SAGD without solvent injection or pressure cycling simulation and the steam driven solvent process without pressure cycling simulation, the injection pressure was maintained at constant 2600 kPa. In the steam driven solvent process with and without pressure cycling simulations, solvent injection was commenced at 90 days utilizing a mixture of steam with butane at 10 wt% of the mixture. [0096] In the pressure cycling steam driven solvent process simulation, the injection pressure was cycled between a low pressure value of 2600 kPa and a high pressure value of 3000 kPa. The pressure cycling steam driven solvent process simulation data presented in FIG. 5 through FIG. 8 shows three pressure cycles in which the pressure was increased to the high pressure value over a period of 1 day, then maintained at the high pressure value for 1 day, then dropped immediately, i.e., in less than 1 day, to the low pressure value and was maintained at the low pressure value for approximately 100 days before the next - 19 - CA 3022035 2018-10-24 PAT 104239-1 cycle began by increasing the pressure to the high pressure value. In addition, during the pressure cycles, solvent injection was stopped when the high pressure value was reached, i.e., during pressure ramp-down, and was resumed when the low pressure value was reached, i.e., during ramp-up. [0097] FIG. 5 is a graph showing the simulated data of the cumulative steam to oil ratio (CSOR) for SAGD without pressure cycling and solvent injection 500, a steam driven solvent process without pressure cycling 502, and a pressure cycling steam driven solvent process 504 as a function of time. FIG. 5 shows that the CSOR for the steam driven solvent process without pressure cycling 502 is 30% lower than the CSOR for SAGD without pressure cycling and solvent injection 500. The CSOR for the pressure cycling steam driven solvent process 504 is 13% lower than the CSOR for SAGD without pressure cycling and solvent injection 500. [0098] FIG. 6 shows the rates of hydrocarbon production for the three simulated hydrocarbon recovery processes shown in FIG. 5. In FIG. 6, these are shown as: SAGD without pressure cycling or solvent injection 600, a steam driven solvent process without pressure cycling 602, and a pressure cycling steam driven solvent process 604 as a function of time. FIG. 6 shows that both the steam driven solvent process without pressure cycling 602 and the pressure cycling steam driven solvent process 604 have higher rates of hydrocarbon production than SAGD without pressure cycling or solvent injection 600. However, when the solvent injection is stopped in the pressure cycling steam driven solvent process simulation 604, i.e., when pressure is ramped down, the oil rate during the pressure cycling steam driven solvent process becomes lower than during the steam driven solvent process without pressure cycling 602. [0099] FIG. 7 shows cumulative hydrocarbon production for the three simulated hydrocarbon recovery processes shown in FIG. 5 and FIG. 6. In FIG. 7, these are shown as: SAGD without pressure cycling or solvent injection 700, a steam driven solvent process without pressure cycling 702, and a pressure cycling steam driven solvent process 704 as a function of time. FIG. 7 shows that the simulated cumulative hydrocarbons produced after 3 cycles of the - 20 - CA 3022035 2018-10-24 PAT 104239-1 pressure cycling steam driven solvent process 704 is nearly the same as the cumulative hydrocarbons produced in the steam driven solvent process without pressure cycling 702. [00100] FIG. 8 is a graph showing the cumulative amount of solvent injected for the two simulated SAPs shown in FIG. 5 through FIG. 7. In FIG. 8, these are shown as: the steam driven solvent process without pressure cycling 802 and the pressure cycling steam driven solvent process 804. FIG. 8 shows that the amount of solvent injected after 3 cycles in the pressure cycling steam driven solvent process 804 simulation is about 25% of the solvent used in the steam driven solvent process without pressure cycling 802. Thus the pressure cycling steam driven solvent process may have improved economics compared to the steam driven solvent process without pressure cycling, as much less solvent may be injected and may remain in the reservoir in the pressure cycling process. [00101] From the simulation results, the pressure cycling steam driven solvent process is able to produce approximately the same amount of oil as the steam driven solvent process without pressure cycling while injecting much less solvent, resulting in lower cost. Though the simulated CSOR in the pressure cycling steam driven solvent process is higher than that in the steam driven solvent process without pressure cycling, it is 13% lower than the simulated CSOR in SAGD without pressure cycling and solvent injection. Pressure Cycling in a Hybrid Solvent Process [00102] Pressure cycling may be utilized in a hybrid solvent process in which the amount of solvent injected with the steam may be greater than in a steam driven solvent process as described above. In an example, the amount of solvent injected in the pressure cycling in a hybrid solvent process may be between about >20 wt% of the mixture of solvent and steam and about 80 wt% of the mixture, and desirably the amount of solvent is about 50 wt%. In another example, the amount of solvent injected may be between about 40 wt% and about 80 wt% of the mixture of solvent and steam. - 21 - CA 3022035 2018-10-24 PAT 104239-1 [00103] A pressure cycling hybrid solvent process is performed after the vapor chamber has made contact with a ceiling formation of the reservoir, as shown in (c) of FIG. 2. In addition, prior to initiating a pressure cycling hybrid solvent process, it may be desirable that no solvent, or very small amounts of solvent, is present in the reservoir. For the purpose of this disclosure, a significant amount of solvent injected into the reservoir is greater than about 20% solvent saturation, such that a pressure cycling hybrid solvent process may be performed if the solvent saturation in the reservoir is less than or equal to about 20%. Solvent saturation is the volume of solvent in the reservoir at reservoir conditions divided by the total volume of solvent, gas, steam, oil and water at reservoir conditions. Without wishing to be bound by any particular theory, injecting at higher concentrations of solvents means less heat via steam is injected into the reservoir prior to initiating a pressure cycling hybrid solvent process. Having less heat in the reservoir will result in the solvent being less soluble in the hydrocarbons, which will reduce the benefits of any hybrid solvent process in which a relatively high amount, e.g., greater than 20 wt%, of solvent is already injected into the reservoir. [00104] Thus, for example, in pressure cycling in a hybrid solvent process, after the plateau stage is reached by injecting steam only, a heated fluid is injected into the reservoir through the injection well. [00105] The rate of injection of the heated fluid may be increased to cause the pressure in the reservoir to increase to a desired high pressure value. Once a sufficiently high pressure is reached, the rate of injection of the heated fluid may be reduced to cause the reservoir pressure to be decreased to a desired low pressure value. Once a sufficiently low pressure is reached, the rate of injection may be increased again, and so forth, in order to cycle between high and low pressure values. [00106] Alternatively, during the initial cycle, the rate of injection of the heated fluid may be reduced to cause the pressure in the reservoir to first be lowered to a desired low pressure value, then the rate may be increased to increase the reservoir pressure to a desired high pressure value. - 22 - CA 3022035 2018-10-24 PAT 104239-1 [00107] The heated fluid injected during a pressure cycling hybrid solvent process may be a mixture of steam and one or more solvents. The solvents utilized for a pressure cycling hybrid solvent process may be selected from alkanes having 2 to 9 carbon atoms. The solvent utilized may be one alkane or a combination of alkanes. A mixture of different solvents may be utilized in a pressure cycling hybrid solvent process when, for example, utilizing a single solvent may not be feasible depending on solvent supply. Examples of solvents that may be utilized in a pressure cycling hybrid solvent process include natural gas condensate, liquefied petroleum (also known as liquefied petroleum gas), hexane, pentane, propane, butane, and ethane. [00108] In addition, non-condensing gases, such as, for example, methane, air, carbon dioxide, or nitrogen, or any combination thereof, may be included in the heated fluid injected into the reservoir through the injection well. [00109] The high pressure value and the low pressure value are chosen such that a difference between the high and low pressure values is at least about 25% of the high pressure value. In an example, the difference between the high and low pressure values is between about 25% and about 75%. In some examples, the values of the high and low pressure values may be varied between iterations such that the difference between the high and low pressure values may be different during different iterations of pressure cycling. Alternatively, in another example, the values of the high and low pressure values may be varied between cycles such that the difference between the high and low pressure values remains constant. [00110] As with the above description with respect to pressure cycling steam driven solvent processes, the maximum pressure that may be utilized for the high pressure value in a pressure cycling hybrid solvent process is the MOP of the reservoir. In addition, the maximum pressure may be determined based on the presence of certain reservoir conditions, such as thief zones in the vicinity of the injection and production well pair, such that the high pressure value is not so high that injected steam and solvent may enter the thief zones in a significant amount. - 23 - CA 3022035 2018-10-24 PAT 104239-1 [00111] Similar to pressure cycling steam driven solvent processes, the minimum low pressure value utilized in a pressure cycling hybrid solvent process is a pressure value that is above the lowest pressure that facilitates producing fluid to the surface. In addition, the low pressure value may be determined based on the presence of reservoir conditions, such as thief zones in the vicinity of the injection and production well pair, such that the low pressure value is not so low that fluids from any thief zones enter the vapor chamber in a significant amount. [00112] In practice, the minimum low pressure value utilized in pressure cycling is at least about 25% of the high pressure value. In an example, the low pressure value may be not greater than about 75% of the high pressure value. Desirably, the low pressure value is between about 50% and about 75% of the high pressure value. [00113] In general, the time taken to adjust the reservoir pressure between the high and low pressure values is desirably as short as is feasible. For example, the time to reduce the reservoir pressure from the high pressure value to the low pressure value may be less than 2 days, and desirably less than 1 day. [00114] The rate of injection of heated fluids may be adjusted as soon as the desired high or low pressure value is reached. Alternatively, one or both of the high and low pressure values may be maintained for a time period after the respective high or low pressure value is reached. Because the solvent concentrations utilized in a pressure cycling hybrid solvent process are higher than utilized in a pressure cycling steam driven solvent process, maintaining the high and low pressure values for a time duration in each pressure cycle will have a greater effect in a pressure cycling hybrid solvent process compared to a pressure cycling steam driven solvent process. In addition, heat propagates to the edge 210 of the vapor chamber 208 more quickly in a pressure cycling steam driven solvent process than in a pressure cycling hybrid solvent process due to the higher concentration of steam that is injected in a pressure cycling steam driven solvent process. Because heat propagates to the edge 210 more quickly - 24 - CA 3022035 2018-10-24 PAT 104239-1 in a pressure cycling steam driven solvent process, the time period for maintaining a high pressure value in pressure cycling steam driven solvent process may desirably be set shorter than the time period that the high pressure value is maintained for in a pressure cycling hybrid solvent process. [00115] Therefore, in an example, the high pressure value, or the low pressure value, or both may be maintained for a particular time duration. For example, once the pressure in the reservoir is increased to the high pressure value, the high pressure value may be maintained for a particular time period, rather than immediately decreasing the rate of injection of the heated fluid to lower the pressure to the low pressure value again. Similarly, once the pressure is decreased to the low pressure value, the low pressure value may be maintained for a particular time period, rather than immediately increasing the rate of injection of the heated fluid to increase the pressure to the high pressure value again. [00116] Desirably, the high pressure value and the low pressure value may both be maintained for the same period of time during a particular cycle. In other examples the time period for maintaining the high pressure value may be different from the time period for maintaining the low pressure value. [00117] FIG. 9 shows a graph showing simulation data of cumulative oil production as a function of time for a pressure cycling hybrid solvent process performed with the high and low pressure values maintained for various time durations. The simulation was performed utilizing a steam and solvent mixture containing 50 wt% propane, a high pressure value of 5000 kPa and a low pressure value of 3250 kPa. [00118] Plot 902 shows the cumulative oil production for a duration of 5 days for the high and low pressure values. Plot 904 shows the cumulative oil production for a duration of 15 days for the high and low pressure values. Plot 906 shows the cumulative oil production for a duration of 30 days for the high and low pressure values. Plots 908 and 910 show the cumulative oil production - 25 - CA 3022035 2018-10-24 PAT 104239-1 for constant pressure at the high pressure value and the low pressure value, respectively. [00119] The simulation results in FIG. 9 show that utilizing a time duration of 15 days (plot 904) for maintaining the high and low pressure values resulted in the highest overall cumulative oil production. However, the time duration of 30 days (plot 906) resulted in the lowest solvent to oil ratio (SolOR). [00120] In an example, the time period for maintaining the reservoir pressure at the high and low pressure values in a pressure cycling hybrid solvent process may be between about 5 days and about 90 days, and desirably the time period may be about 30 days. Based on the simulation results, a 30 day time period for maintaining the high and low pressure values may be desirable because this results in a lower SolOR, and the spikes in cumulative oil rate are more pronounced than time periods of 5 and 15 days. [00121] As noted above, the time periods for maintaining the pressure at high and low pressure values in a pressure cycling steam driven solvent process are desirably shorter than for a pressure cycling hybrid solvent process due to the quicker propagation of temperature in the vapor chamber in a pressure cycling steam driven solvent process compared to a pressure cycling hybrid solvent process. [00122] In addition, the time periods for maintaining the high and low pressure values may vary from cycle to cycle. In an example, later cycles may maintain the high and low pressures for time periods that are longer than in previous cycles. As time passes and the vapor chamber expands, the pressure of the reservoir may be maintained at the high pressure value for longer time periods without causing a significant temperature increase in the mixing zone at the edge of the vapor chamber compared to earlier cycles. Without being limited to theory, longer time periods for maintaining the high and low pressure values may have a greater effect on increasing solvent solubility in the hydrocarbons at higher concentrations of co-injected solvent, for example about greater than 20 - 26 - CA 3022035 2018-10-24 PAT 104239-1 wt%, as compared to lower concentrations, for example less than or equal to about 20 wt%. Producing Hydrocarbons utilizing Pressure Cycling in a Solvent-Aided Process [00123] Referring now to FIG. 10, a process for producing hydrocarbons from a subterranean hydrocarbon-bearing formation utilizing solvents is shown in FIG. 10. The process illustrated in FIG. 10 may be performed as part of a SAP utilizing a production well and an injection well. The injection well includes a segment extending substantially horizontally into the reservoir and the production well includes a segment extending substantially horizontally into the reservoir. The horizontal segment of the production well is vertically offset from and extends substantially parallel to the horizontal segment of the injection well, similar to the production well 100 and the injection well 108 described above and illustrated in FIG. 1. [00124] At 1002, hydrocarbons in a near-wellbore region of the reservoir are heated during a start-up stage to establish fluid communication between the injection well and the production well. As described above, any suitable start- up process for heating the hydrocarbons in the near-wellbore region and establishing fluid communication between the injection well and the production well may be utilized including, for example, circulating heated fluids in one or both of the injection and production wells, injecting heated fluid into the reservoir through one or both injection and production wells, and heating by placing heaters into one or both of the injection and production wells. [00125] When the process of FIG. 10 is performed as part of a pressure cycling steam driven solvent process, any fluids injected during start-up may comprise injecting a solvent, or a mixture of steam and solvent, into the reservoir. When the process of FIG. 10 is performed as part of a pressure cycling hybrid solvent process, any fluid injected into the reservoir during start- up is desirably steam only such that the fluid does not contain a significant amount of solvent. As described above, a significant amount of solvent injected - 27 - CA 3022035 2018-10-24 PAT 104239-1 during the start-up stage and/or the production stage prior to initiating a pressure cycling hybrid solvent process is an amount that results in greater than about 20% solvent saturation in the reservoir. [00126] During the production stage, after fluid communication between the injection and production wells is established and the start-up stage is ended, hydrocarbons in the reservoir are produced to the surface through the production well at 1004. [00127] Optionally, at 1006, the production stage may include forming a chamber that results over time from injection of a first fluid into the reservoir. As noted above, if the process of FIG. 10 is performed as part of a pressure cycling steam driven solvent process, pressure cycling may be initiated at any point during the production stage and, desirably, when the vapor chamber has contacted a formation ceiling of the reservoir. In a pressure cycling steam driven solvent process, the first fluid that is injected during the production stage prior to pressure cycling may be steam, a mixture of steam and solvent, or solvent only. [00128] Alternatively, pressure cycling in a pressure cycling steam driven solvent process may begin immediately after start-up is completed, before significant, i.e., more than nominal, vapor chamber formation, and when fluid communication is established between the injection and production wells. In this case, optional step 1006 may be skipped. [00129] If the process of FIG. 10 is performed as part of a pressure cycling hybrid solvent process, pressure cycling begins after the plateau stage is reached, i.e., when the vapor chamber formed at 1006 reaches the formation ceiling of the reservoir. As described above, in this case the first fluid injected at 1006 is steam and does not contain a significant amount of solvent. [00130] At 1008, while producing hydrocarbons through the production well, a second fluid is injected into the reservoir through the injection well at a first rate to adjust a pressure in the reservoir to a first pressure value. After reaching the first pressure value, a third fluid is injected into the reservoir through the - 28 - CA 3022035 2018-10-24 PAT 104239-1 injection well at 1010. The third fluid is injected at 1010 at a second rate to adjust the pressure in the reservoir to a second pressure value. [00131] In an example, a difference between the first pressure value and the second pressure value is not less than about 25% of the higher of the first pressure value and the second pressure value. The difference may be not greater than about 75% of the higher of the first and second pressure values. Desirably, the difference between the first pressure and the second pressure may be between about 50% and 75% of the higher of the first and second pressure values. [00132] In general, the time taken to adjust the reservoir pressure to the first pressure value at 1008 and to the second pressure value at 1010 should be as short as feasible. For example, the time between the reservoir pressure changing from the first pressure value to the second pressure value may be less 2 days, and desirably less than 1 day. [00133] Generally, the second fluid and the third fluid may be the same. For example, in both a pressure cycling steam driven solvent process and a pressure cycling hybrid solvent process, generally the second fluid and the third fluid may each have the same composition of steam and solvent. Additionally, as described above, in some examples a pressure cycling steam driven solvent process may be performed in which the second fluid and third fluid are both steam only when, for example, solvent is injected into the reservoir during start- up, earlier during the production stage, or both. [00134] However, in some instances the second fluid may be different from the third fluid. For example in a pressure cycling steam driven solvent process, a mixture of steam and solvent may be injected when the pressure of the reservoir is being increased to a high pressure value, and steam only may be injected when the pressure in the reservoir is being decreased to a lower pressure value. [00135] In an example, the first pressure value may be a high pressure value, and the second pressure value may be a low pressure value that is lower than the high pressure value. In this example, the pressure in the reservoir is - 29 - CA 3022035 2018-10-24 PAT 104239-1 increased at 1008 and decreased at 1010. Alternatively, the first pressure value may be the low pressure value and the second pressure value may be the high pressure value. In this example, the pressure of the reservoir is decreased at 1008, then increased at 1010. [00136] As described above, the maximum pressure that may be utilized for the greater of the first and second pressure values is the MOP of the reservoir, for example, that is allowed by the relevant regulatory body. However, the maximum pressure may be limited by unique reservoir conditions such as, for example, thief zones in the reservoir in the vicinity of the injection and production well pair. The minimum pressure value that may be utilized for the lesser of the first and second pressure values is a pressure value that is above the lowest pressure that facilitates producing fluid to the surface, and may be limited by unique reservoir conditions such as, for example, thief zones in the reservoir in the vicinity of the injection and production wells. [00137] As described above, adjusting the pressure at 1008 may include maintaining the first pressure value for a time period, and adjusting the pressure at 1010 may include maintaining the second pressure value for a time period. As described above, maintaining the first and second pressure values will have a greater effect on the rate of production of hydrocarbons in a pressure cycling hybrid solvent process than in a pressure cycling steam driven solvent process. Therefore, when the process of FIG. 10 is performed as part of a pressure cycling hybrid solvent process, the first pressure value at 1008 and the second pressure value at 1010 are desirably maintained for a time period. The time period may be between 5 and 90 days. Further, as described above, the time period may vary over time such that subsequent iterations of steps 1008 and 1010 may have longer time periods than earlier iterations. For example, at the beginning of the pressure cycling process, the first and second pressures may be both maintained for about 30 days, while the first and second pressure values towards the end of the SAP production stage may be maintained for about 90 days. [00138] At 1012, a determination whether to continue pressure cycling is made. The determination at 1012 may be based on, for example, whether it is - 30 - CA 3022035 2018-10-24 PAT 104239-1 economical to continue cycling the pressure between the first and second pressure values. In an example, it may be determined that continuing to cycle the pressure is not economical when the operating costs of the pressure cycling steam driven solvent process or pressure cycling hybrid solvent process are greater than the value of the oil being produced. The operating costs include, for example, cost to produce steam, cost for the utilized solvents, costs with respect to recycling solvents produced through the production well. Alternatively, or additionally, the determination at 1012 may be based on a determination whether the well has reached the end of the production stage and a wind-down or blow-down stage should be initiated. [00139] If the determination at 1012 is yes, then the process continues to 1008 such that pressure cycling between the first and second pressure values is repeated at 1008 and 1010 respectively. [00140] If the determination at 1012 is no, then the process ends. Ending the process may include initiating a wind-down stage, as described above. Alternatively, ending the process may include resuming a SAP or a SAGD production process without pressure cycling. [00141] The present disclosure provides processes for producing hydrocarbons from a subterranean formation utilizing cycling of the pressure in the reservoir between a high pressure value and a low pressure value. Cycling between a high pressure value and a low pressure value is shown to increase the rate of oil production at the production well in a SAP compared to a SAP performed at substantially constant pressure or compared to SAGD, while reducing the solvent to oil ratio, and reducing cumulative solvent injected into the reservoir, compared to operating utilizing a constant pressure. Reducing the amount of solvent utilized while increasing the rate of hydrocarbon production results in a more cost effective process for producing hydrocarbons from a subterranean formation. [00142] The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the claims should not be limited - 31 - CA 3022035 2018-10-24 PAT 104239-1 by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole. All changes that come with meaning and range of equivalency of the claims are to be embraced within their scope. - 32 - CA 3022035 2018-10-24