CA3185384A1 - In situ startup process with elastic deformation of the reservoir - Google Patents

Abstract

Startup of an in situ process using a well pair can include introducing a startup fluid at elastic deformation pressure to induce temporary deformation of the reservoir region between the well pair to enhance establishing fluid communication between the wells.
Elastic deformation of reservoir regions can provide enhanced injectivity for improved in situ recovery operations.

Description

IN SITU STARTUP PROCESS WITH ELASTIC DEFORMATION OF THE RESERVOIR
TECHNICAL FIELD
[001] The technical field generally relates to startup of in situ hydrocarbon recovery operations, such as the startup stage of a Steam-Assisted Gravity Drainage (SAGD) operation.
BACKGROUND

[002] SAGD operations use well pairs that extend into a hydrocarbon reservoir and each includes a production well underlying an injection well. The startup stage of the well pair involves establishing fluid communication between the injection well and the production well. A fluid, such as steam, can be circulated through one or both of the wells to heat the surrounding reservoir region until the hydrocarbons are mobilized and fluid communication is established between the wells. In reservoir regions of high initial water mobility, steam can be injected into the wells without having to circulate.
However, there are various challenges in terms of the long duration of the startup stage and the lack of uniformity of fluid communication along the length of the well pair.
SUMMARY

[003] Startup of a well pair used for SAGD or other gravity dominated in situ hydrocarbon recovery processes operated using a horizontal well pair can be enhanced by introducing fluid at sufficiently high pressure to induce elastic deformation of the reservoir within the near-wellbore region. Elastic deformation of the reservoir can significantly increase permeability and injectivity, which, in turn, can enhance fluid communication between the wells while mitigating drawbacks related to higher pressure injection. Higher pressure injection may result in permanent deformation or fracturing of the reservoir, which could occur as a result of plastic deformation and failure at higher pressures.

[004] In some implementations, there is provided a startup process to establish fluid communication between a well pair comprising an injection well overlying a production well located in a hydrocarbon-bearing reservoir, comprising: introducing a startup fluid into an interwell reservoir region defined between the injection well and the production well at Date Recue/Date Received 2022-09-28 an elastic deformation pressure of the reservoir to induce temporary elastic deformation in the interwell reservoir region; and establishing fluid communication between the injection well and the production well.

[005] In some implementations, the introducing of the startup fluid comprises injection.
In some implementations, the introducing of the startup fluid comprises circulation. In some implementations, the startup fluid comprises steam. In some implementations, the startup fluid comprises water. In some implementations, the startup fluid comprises a hydrocarbon solvent, such as diesel. In some implementations, the elastic deformation pressure at which the startup fluid is introduced is between 0% and 15% below a yield point of the interwell reservoir region. In some implementations, the elastic deformation pressure at which the startup fluid is introduced is between 1% and 10% below a yield point of the interwell reservoir region. In some implementations, the elastic deformation pressure at which the startup fluid is introduced is between 2% and 7% below a yield point of the interwell reservoir region. In some implementations, the elastic deformation pressure at which the startup fluid is introduced is between 3% and 6% below a yield point of the interwell reservoir region. In some implementations, the elastic deformation pressure at which the startup fluid is introduced is between 0% and 15% below a reservoir fracture pressure. In some implementations, the elastic deformation pressure at which the startup fluid is introduced is between 3% and 10% below a reservoir fracture pressure. In some implementations, the introducing of the startup fluid comprises a multistep procedure comprising circulation and/or bullheading. In some implementations, the multistep procedure comprises: a fluid circulation step at pressures in an elastic deformation pressure zone; and a bullheading step at injection pressures in the elastic deformation pressure zone to provide fluid penetration into the interwell reservoir region.
In some implementations, the fluid circulation step is performed at a pressure between 85% and 95% of reservoir fracture pressure. In some implementations, the fluid circulation step is performed at a pressure between 88% and 92% of reservoir fracture pressure. In some implementations, the bullheading step is performed between 85% and 95% of reservoir fracture pressure. In some implementations, the bullheading step is performed at a pressure between 88% and 92% of reservoir fracture pressure. In some implementations, the bullheading step comprises a first bullheading stage operated at a first pressure and a second bullheading stage operated at a second pressure that is lower than the first pressure. In some implementations, the first pressure is gradually reduced to Date Recue/Date Received 2022-09-28 the second pressure between the first and second bullheading stages. In some implementations, the first pressure is up to 95% or 90% of the reservoir fracture pressure and the second pressure is 5% to 10% lower than the first pressure. In some implementations, the bullheading step is performed until fluid communication is established between the injection well and the production well. In some implementations, the fluid circulation step is performed in only the injection well. In some implementations, the fluid circulation step is performed in only the production well. In some implementations, the fluid circulation step is performed in both the injection well and the production well. In some implementations, the bullheading step is performed via the injection well only, and the production well is operated in shut-in mode. In some implementations, the bullheading step is performed via both the injection well and the production well until fluid communication is established and then the production well is operated in production mode. In some implementations, the multistep procedure further comprises, prior to the fluid circulation step, a wellbore fluid unloading step wherein unloading fluid is introduced to remove completion fluid and/or drilling mud to surface. In some implementations, the unloading fluid comprises steam, and the reservoir has low injectivity below 1 m3 of steam/hour. In some implementations, the multistep procedure further comprises, prior to the fluid circulation step, a wellbore fluid unloading step wherein unloading fluid is introduced to drive completion fluid and/or drilling mud into the reservoir.
In some implementations, the unloading fluid comprises an unloading liquid. In some implementations, the unloading fluid comprises water, and the reservoir has a high injectivity above 1 m3 of steam/hour. In some implementations, the multistep procedure comprises wellbore depressurization between steps. In some implementations, the multistep procedure comprises no wellbore depressurization between steps. In some implementations, the hydrocarbon-bearing reservoir comprises an oil sands reservoir comprising heavy oil or bitumen. In some implementations, the startup process is performed in preparation for Steam-Assisted Gravity Drainage (SAGD). In some implementations, the startup process is performed in preparation for a solvent-assisted recovery process. In some implementations, the startup process is performed in preparation for a solvent-dominated recovery process. In some implementations, determining an elastic deformation pressure zone for the reservoir; and selecting operating pressures for the startup fluid based on the elastic deformation pressure zone.
In some implementations, the determining of the elastic deformation pressure zone utilizes Date Recue/Date Received 2022-09-28 data obtained from testing reservoir samples, measurements collected from downhole instrumentation, or a combination thereof. In some implementations, the determining of the elastic deformation pressure zone comprises: determining a fracture pressure of a near-wellbore region; and estimating the elastic deformation pressure zone based on the fracture pressure of the near-wellbore region. In some implementations, monitoring at least one operating parameter to detect indication of reservoir fracture or plastic deformation; and if reservoir fracture or plastic deformation is detected, modifying operating conditions of the startup process to cease the reservoir fracture or the plastic deformation. In some implementations, the monitoring comprises measuring pressure conditions and/or flow rate conditions of the startup fluid.

[006] In some implementations, there is provided a process for recovering hydrocarbons from a reservoir, comprising: a startup phase operated according to the startup process as defined above or herein; and a hydrocarbon recovery phase comprising introducing an injection fluid via the injection well into the reservoir and recovering production fluid via the production well. In some implementations, the process is a Steam-Assisted Gravity Drainage (SAGD) process wherein the injection fluid is steam.
In some implementations, the process is a solvent-assisted process wherein the injection fluid comprises steam and hydrocarbon solvent. In some implementations, the process is a solvent-dominated process wherein the injection fluid comprises a dominant proportion of hydrocarbon solvent. In some implementations, the injection fluid consists essentially of the hydrocarbon solvent. In some implementations, the injection fluid comprises a paraffinic solvent including C3 to C6; a solvent mixture comprising a diluent blend; one or more alcohols; one or more ethers; diesel; biodiesel; a mixture of alkanes and alcohols;
one or more aromatic solvents; or a combination thereof. In some implementations, the introducing of the startup fluid comprising injecting via both the injection well and the production well to form respective elastically deformed zones in the interwell reservoir region that merge to form a merged elastically deformed zone in the interwell reservoir region.

[007] In some implementations, there is provided a well pair startup system comprising: a well pair comprising an injection well overlying a production well located in a hydrocarbon-bearing reservoir; and a startup fluid delivery unit located at surface and being in fluid communication with one or both of the injection well and the production well, Date Recue/Date Received 2022-09-28 the startup fluid delivery unit being configured for introducing a startup fluid down at least one of the wells and into an interwell reservoir region defined between the injection well and the production well at an elastic deformation pressure of the reservoir to induce temporary elastic deformation in the interwell reservoir region, and for establishing fluid communication between the injection well and the production well.

[008] In some implementations, the startup fluid delivery unit comprises a pump for when the startup fluid is a startup liquid. In some implementations, the startup fluid delivery unit comprises a steam generator and a pressure let-down unit for when the startup fluid comprises steam, the steam generator producing high pressure steam and the pressure let-down unit receiving the high pressure steam and reducing the pressure to produce the startup steam for introduction into the interwell region. In some implementations, the system further includes a circulation unit for circulating the startup fluid through the injection well and the production well, and a bullheading unit for bullheading the startup fluid via at least the injection well after circulation. In some implementations, the system also includes a monitoring unit configured to detect reservoir fracture or plastic deformation. In some implementations, the startup fluid comprising water. In some implementations, the startup fluid comprising liquid solvent. In some implementations, the startup fluid comprises the steam and a solvent that are co-injected together.
In some implementations, the startup fluid consists of the steam.

[009] In some implementations, there is provided an in situ hydrocarbon recovery system comprising: a well pair comprising an injection well overlying a production well separated by an interwell reservoir region; and a well pair startup system comprising a fluid delivery unit provided at surface and in fluid communication with at least one well selected from the injection well and the production well, and configured to introduce a startup fluid into the interwell reservoir region via the at least one well at an elastic deformation pressure of the reservoir to induce temporary elastic deformation in the interwell reservoir region; wherein the injection well is configured to supply an injection fluid into the reservoir to facilitate mobilization of hydrocarbons, and the production well is configured to recover production fluid comprising mobilized hydrocarbons. In some implementations, the well pair startup system has one or more features as described above or herein.
Date Recue/Date Received 2022-09-28

[0010] In some implementations, there is provided a process for recovering hydrocarbons from a reservoir comprising: operating a gravity based in situ hydrocarbon recovery operation comprising injecting an injection fluid via an injection well to mobilise hydrocarbons in the reservoir and recovering production fluid via a production well underlying the injection well; detecting suspected plugging in the production well;
temporarily ceasing recovery of production fluid via the production well;
stimulating the production well, the stimulating comprising: introducing a stimulation fluid via the production well and into a near-wellbore reservoir region of the production well at an elastic deformation pressure to induce temporary elastic deformation in the near-wellbore reservoir region; and injecting or circulating the stimulation fluid in the elastically deformed near-wellbore reservoir region and unplugging the production well. The process then includes reinitiating the production well in production mode for recovering production fluid to surface.

[0011] In some implementations, the gravity based in situ hydrocarbon recovery operation is Steam-Assisted Gravity Drainage (SAGD) and the stimulation fluid is steam.
In some implementations, the elastic deformation pressure at which the stimulation fluid is introduced is between 0% and 15% below a yield point of the near-wellbore reservoir region. In some implementations, the elastic deformation pressure at which the stimulation fluid is introduced is between 1% and 10% below a yield point of the near-wellbore reservoir region. In some implementations, the elastic deformation pressure at which the stimulation fluid is introduced is between 2% and 7% below a yield point of the near-wellbore reservoir region. In some implementations, the elastic deformation pressure at which the stimulation fluid is introduced is between 3% and 6% below a yield point of the near-wellbore reservoir region.

[0012] In some implementations, there is provided a process for recovering hydrocarbons from a reservoir comprising: operating a gravity based in situ hydrocarbon recovery operation comprising injecting an injection fluid via an injection well at an operating pressure to mobilise hydrocarbons in the reservoir and recovering production fluid via a production well underlying the injection well; in a chamber growth promotion mode for promoting growth of a chamber extending upward from the injection well, introducing the injection fluid into the chamber at an elastic deformation pressure above the operating pressure to induce temporary elastic deformation in the reservoir and Date Recue/Date Received 2022-09-28 promote growth of the chamber; and returning the injection well to normal operating mode where the injection fluid is injected at the operating pressure.

[0013] In some implementations, the gravity based in situ hydrocarbon recovery operation is Steam-Assisted Gravity Drainage (SAGD) and the injection fluid is steam. In some implementations, the elastic deformation pressure at which the injection fluid is introduced is between 0% and 15% below a yield point of the near-wellbore reservoir region. In some implementations, the elastic deformation pressure at which the injection fluid is introduced is between 1% and 10% below a yield point of the near-wellbore reservoir region. In some implementations, the elastic deformation pressure at which the injection fluid is introduced is between 2% and 7% below a yield point of the near-wellbore reservoir region. In some implementations, the elastic deformation pressure at which the injection fluid is introduced is between 3% and 6% below a yield point of the near-wellbore reservoir region.

[0014] In some implementations, there is provided a process for treating a reservoir for recovery of hydrocarbons from the reservoir in which a horizontal well pair is provided, the well pair comprising an injection well overlying a production well, the process including, in an elastic deformation mode, introducing a fluid into the injection well or the production well or both at an elastic deformation pressure to elastically deform a reservoir region and increase injectivity of the reservoir region, wherein the elastic deformation pressure at which the fluid is introduced is between 0% and 15% below a yield point of the reservoir region; and injecting the fluid into the reservoir region while in elastic deformation state.
The process also includes, in a normal operating mode, returning to a normal operating pressure where an injection fluid is injected into the reservoir via the injection well, and wherein production fluid is recovered via the production well.

[0015] In some implementations, the fluid is a startup fluid and the reservoir region comprises an interwell reservoir region in between the injection well and the production well. In some implementations, the startup fluid comprises steam, water or hydrocarbon solvent. In some implementations, the elastic deformation pressure at which the fluid is introduced is between 1% and 10%, between 2% and 7%, or between 3% and 6%
below a yield point of reservoir region. between 2% and 7% the well pair is operated as part of a Steam-Assisted Gravity Drainage (SAGD) operation and the injection fluid is steam.

Date Recue/Date Received 2022-09-28 BRIEF DESCRIPTION OF THE DRAWINGS

[0016] The attached figures illustrate various features, aspects and implementations of the technology described herein.

[0017] Fig 1 is a side view schematic of an in situ recovery system including a well pair where a startup fluid is introduced at elastic deformation pressure.

[0018] Figs 2A-2D are side view schematics of an in situ recovery system showing steps of a startup process.

[0019] Fig 3 is a cross-sectional view schematic of a well pair around which elastic deformation zones have formed.

[0020] Fig 4 is a graph of injectivity versus startup fluid pressure.
DETAILED DESCRIPTION

[0021] The present description relates to a startup process for establishing fluid communication for a horizontal well pair used for in situ recovery of hydrocarbons. The startup process includes introducing a startup fluid at elevated pressure to induce elastic deformation of the reservoir proximate to one or more of the wells during initial stages of well pair start-up. The startup fluid¨which can be steam, hot water, and/or solvent¨can be injected or circulated at a pressure causing significant elastic deformation while remaining below shear and tensile failure conditions of the reservoir and caprock. The elevated pressure promotes elastic deformation of the reservoir sand and temporarily increases injectivity. High-pressure circulation and injection can help accelerate the startup and ramp-up performance of well pairs by promoting early fluid communication for the well pair as well as early steam or solvent chamber growth through improved injectivity.
In some implementations, high-pressure startup within the elastic deformation zone of the reservoir sand can shorten the duration of the startup stage. Even small improvements in early in situ performance can allow significant economical benefits for the in situ hydrocarbon recovery process.

[0022] In some implementations, the startup fluid is introduced down one or both of the wells in the well pair at pressures that are close to yet below shear and tensile failure Date Recue/Date Received 2022-09-28 conditions, thus enabling elastic deformation which can have a notable impact on injectivity. The startup fluid pressure can be selected based on both the caprock properties and the near-wellbore reservoir properties. For example, the startup fluid pressure can be provided such that it is below the plastic deformation pressure of the near-wellbore reservoir and also below the fracture pressure of the caprock. In certain instances, the relevant properties of the caprock and the near-wellbore region of the reservoir in which the wells are located can be relatively similar (e.g., similar fracture pressures) such that the startup fluid pressure can be provided based on one or the other.

[0023] Referring to Fig 1, a well pair 10 is shown including an injection well 12 and a production well 14 provided in a pay zone 16 of a reservoir. Caprock 18 is located above the pay zone 16 and underburden 20 is located below the pay zone 16. The wells both extend up to the surface 22 where surface facilities are located and each has a generally horizontal well section vertically spaced apart from each other. Surface facilities can be configured and operated depending on the design of the particular in situ recovery process. For example, SAGD operations would include steam generators while solvent-based processes would include equipment for processing and injecting solvent.

[0024] Still referring to Fig 1, the startup process includes introducing a startup fluid 24 from surface through one or both of the wells at high pressure to induce elastic deformation of a reservoir region 26 surrounding the corresponding well. The startup fluid 24 can be supplied by a fluid delivery unit 28 located at surface. The fluid delivery unit 28 can be provided depending on the type of startup fluid. For example, when the startup fluid is liquid, e.g., hot water or liquid phase solvent such as diesel, the fluid delivery unit 28 can include one or more pumps configured to supply the liquid at the elastic deformation pressure. The pump can be used for a particular well pad during startup and then moved to another location once startup is complete, for example. When the startup fluid is a vapour, e.g., steam or vapour-phase solvent, the fluid delivery unit 28 can include compressors and/or generators (e.g., steam generators such as Once-Through Steam Generators or OTSGs or solvent vaporizers) and associated equipment that can be controlled to provide the fluid at the elastic deformation pressure. For example, steam generators can produce steam at high pressure and the steam pressure can be reduced to the target pressure prior to introduction at the wellhead. The fluid delivery unit 28 can include a controller that facilitates fluid pressure control to achieve the target pressure of Date Recue/Date Received 2022-09-28 the startup fluid to enable elastic deformation of the reservoir, it is also noted that the process could use electrical or electromagnetic devices downhole that could heat and vaporize the injected fluid, such that the fluid is introduced at the wellhead as a liquid and is vaporized downhole.

[0025] The elastic deformation can impact the reservoir proximate to the wells and can form an elastic deformation zone that extends a few meters from each well.
When both the injection and the production well are used for startup fluid injection, the corresponding reservoir regions 26 that undergo elastic deformation can approach each other and even merge, as illustrated in Fig 3. Since well pairs in gravity dominated recovery processes, such as SAGD, are conventionally vertically spaced apart by approximately five meters, elastic deformation of only two or three meters can be sufficient to provide beneficial permeability enhancements in the interwell region for startup purposes. When an elastically deformed reservoir zone extends less than four or three meters away form the well, it can be advantageous to use both wells to facilitate permeability increase over the height of the interwell region. Furthermore, when both wells are used for injection of startup fluid, it can be of interest to manage injection pressures so that the wells are at equal pressure, i.e., no pressure differential, which can include accounting for elevation differences. Such an approach can mitigate issues related to short circuits between the wells via preferential flow paths, for example.

[0026] In addition, the process can include determining fluid parameters such as pressure and volume based on various factors (e.g., an average or estimate of the yield point or fracture pressure of the near-wellbore region taken along the length of the well;
an estimated volume of the near-wellbore where the elastic deformation is to occur and which can be based on a cylindrical volume around the length of the well and having a radius of between 1 and 3 meters or up to 2, 3 or 4 meters from the well;
initial injectivity of the near-wellbore region and target injectivity increase due to elastic deformation; and other factors). The process can generally include predetermining fluid parameters such as pressure, volume, rate, etc., based on properties of the reservoir and/or process design.

[0027] Introduction of the startup fluid 24 can be performed using various methods.
For example, the startup fluid 24 can be introduced by injection and/or circulation; at constant or cyclical pressures; using a single startup fluid for the entire startup process or Date Recue/Date Received 2022-09-28 using different fluids or compositions at different stages of the startup process; via only one of the injection well and production well; or via both injection and production wells either simultaneously or in alternating fashion. The properties of the startup fluid 24 (e.g., pressure, phase, temperature, flow rate, composition) can also be controlled and modified at different stages of the startup process. The startup fluid 24 can also be selected based on predetermined reservoir properties and process design.

[0028] The introduction of the startup fluid 24 can be based on predetermined measurements regarding properties of the formation. Measurements can be obtained from observation wells and/or operational wells using downhole instrumentation and/or calculated using existing geological data and methods. Properties regarding deformation can be obtained for underburden, caprock, pay zone and/or target regions such as near wellbore regions of the pay zone. For example, caprock fracture pressure can be determined and used as a factor to set the startup fluid pressure to ensure caprock integrity. Stress-strain curves can be used to estimate the startup fluid pressure that can be used to induce an optimum or maximum elastic deformation without entering zones of plastic deformation or fracture. In some implementations, the yield point of the reservoir can be determined and used as an upper limit for the target pressure to induce elastic deformation, where the operating startup fluid pressure is set at, for example, 2%, 5%, 10%, 15% or 20% below the yield point. The determination of the startup fluid pressure can include determining deformation properties of several zones of the formation and selecting the pressure below the caprock fracture pressure and below the yield point of the near-wellbore pay zone while providing the fluid pressure as high as possible, e.g., within 10% or 5% or 2% of the lower of the caprock fracture pressure and pay zone yield point pressure. In some implementations, the startup fluid pressure can be provided based solely on the near-wellbore reservoir properties to remain within the elastic deformation zone of that region, especially if the caprock is remote from the well pair since the elastic deformation zone extends only a few meters into the pay zone from the well.

[0029] The startup fluid 24 can include hot water, steam, hydrocarbon solvent or various mixtures thereof, and may also include additional species that may be desired to condition the reservoir. Such additional species could include surfactants, alcohols, ethers (e.g., DME), diluent, diesel, biodiesel, one or more aromatic solvents, and various combinations of such chemicals. Other species known in the field of in situ startup could Date Recue/Date Received 2022-09-28 also be used. The startup fluid 24 can be heated at surface to have a target temperature and/or can be provided in vapour phase or liquid phase. Different startup fluids can be used for different stages of the startup process. The startup fluid can include some native fluids and/or drilling fluids that are present in the wellbores after drilling, particularly if the injectivity of the reservoir is relatively high such that the introduction of liquid startup fluid from surface can push existing wellbore fluids into the reservoir.

[0030]
Turning now to Figs 2A to 2D, the startup process can include a multistep procedure where different fluids and operating conditions can be used. The multistep procedure can include one or more injection and/or circulation steps, for example. An example of a multistep procedure will be described in relation to Figs 2A to 2D, but it should be noted that various other combinations of steps can be used for the startup process.

[0031] Fig 2A shows an initial step of unloading of wellbore fluids, such as completions kill fluid or drilling mud. An unloading fluid 30 is introduced and wellbore fluids 32 can be removed. The unloading step can be accomplished by injecting steam up to 95%
of reservoir fracture pressure and within the elastic deformation zone for 48 hours, for example, or until steam to toe is achieved with minimal water returns observed at surface.
As steam is introduced the wellbore liquids are recovered to surface. In this unloading context using steam, the unloading step would typically not include elastic deformation of the near-wellbore reservoir regions, but would be operated for wellbore fluid unloading prior to an elastic deformation step. This unloading step can be favoured when the injectivity of the reservoir is relatively low. Alternatively, when the injectivity of the reservoir is high, the unloading fluid 30 can be a liquid, such as water, and can be introduced via bullheading into the well to push the wellbore fluids into the reservoir rather than recovering the fluids to the surface. In this scenario, the bullheading can be performed to induce elastic deformation of the reservoir zones surrounding the wells.

[0032] Fig 2B shows a steam circulation step, which can be performed at pressure up to 90% of reservoir fracture pressure and within the elastic deformation zone, for a duration that can vary based on reservoir characteristics (e.g., days to weeks). This circulation step is performed to warm the near-wellbore area until reservoir fluid mobility is high enough to facilitate fluid (e.g., steam) injectivity into the reservoir. A circulation fluid 34 is introduced Date Recue/Date Received 2022-09-28 and flows through the tubing and annulus of the corresponding well and forms a warmed zone 35 surrounding each well. This circulation step enables warming of the wells and reservoir as well as elastic deformation of the near-wellbore region. The circulation pressure can be selected to be in the elastic deformation zone, as discussed above. The circulation can be performed in both wells or one of the wells. If the mobility in the near-wellbore region is high enough, the startup process can forgo circulation and pass directly to injection/bullheading.

[0033] Fig 2C shows a bullheading step, which can be performed at a pressure up to 90% of reservoir fracture pressure, which can be gradually reduced to 80%
reservoir fracture pressure, for a duration generally of one to four months, or two to four months, for example, depending upon reservoir response. The bullheading step can be performed using steam as a bullheading fluid 36, although other fluids can be used. The bullheading can be performed until fluid communication is established between the wells.
The bullheading step enables penetration of fluid into the reservoir, elastic deformation of the reservoir, and heating of the reservoir notably when a hot fluid such as steam is used as the startup fluid. It is also noted that the bullheading can be performed in both wells or one of the wells. In some implementations, the bullheading is first performed via both wells and then the production well is switched to production mode after a certain period of time while bullheading continues via the injection well until the production well begins to produce fluid to surface. This bullheading step can be performed with constant or cyclical injection at constant pressure or with a gradual decrease in pressure, for example.

[0034] Fig 2D shows a final step of the startup process which also leads into the ramp-up of the in situ hydrocarbon recovery process, where injection fluid 38 is injected via the injection well 12 and production fluid 40 is recovered via the production well 14. The injection fluid 38 forms a chamber 42 (e.g., a steam chamber when steam is used) extending upward from the injection well 12 while the hydrocarbons drain downward by gravity and are recovered via the production well 14. The transition from startup to production can be gradual where startup conditions are brought to production phase conditions. When the startup fluid is different from the injection fluid, there can also be a transition period to switch to the injection fluid for the production phase.
There can also be a shutdown period between startup and production phases if desired, and since the Date Recue/Date Received 2022-09-28 deformation during startup is substantially elastic the reservoir should generally return to its original state in terms of porosity and other petrophysical properties.

[0035] The elastic deformation region of the reservoir formed by the startup fluid pressure can have a shape and properties that depend on the well and near-wellbore reservoir characteristics. For example, the elastic deformation region can extend a couple or a few meters into the reservoir from the well, and can have a generally cylindrical shape that is generally symmetrical about the well. The deformation through the elastic deformation region may not be radially uniform though it may be generally uniform along the well particularly when the reservoir properties are not highly variable along the well. In addition, since the startup fluid is provided at low flow rate and higher-than-normal pressure, the pressure drop along the well is relatively low such that the fluid pressure is relatively consistent along the length of the well.

[0036] In addition, the startup fluid can be introduced so as to gradually increase the pressure that is exerted on the reservoir. For example, the startup fluid can be introduced to fill the wellbore and then the pressure can be gradually increased from hydrostatic up to the target pressure that may be 90% of reservoir fracture pressure or another pressure just below the plastic deformation zone. Gradually increasing the pressure can provide enhanced conformance along the well and can also reduce the risk of inadvertent fractures and breakthroughs.

[0037] It has been found that increasing startup fluid pressures compared to conventional pressures, which can be 50% or 60% of fracture pressure, resulted in notable improvements in terms of injectivity. For example, referring to Fig 4, the startup fluid injection pressure was increased up to 90% of fracture pressure (FP) (point 6) and a non-linear increase in injectivity was observed. The numbers on the points indicate successive injection cycles (injection, shut-in/fall-off, repeat) and demonstrate injectivity increasing with maximum pressure achieved in each cycle. It is clear that cycle 7 (going back to initial pressure) demonstrated the return to the low injectivity. In addition, the observed injectivity at 90% fracture pressure (FP) of cycle 6 was about 30% higher than a linear projection of points 1 and 2 to that high pressure. In addition, Fig 4 indicates that the reservoir returned to its original injectivity at the lower pressure (cycle 7) which indicates an elastic response.
Fig 4 illustrates that higher pressure startup operations can yield significant increases in Date Recue/Date Received 2022-09-28 injectivity with an exponential-like relationship within those pressure ranges. This testing also demonstrated a 4-times increase in injectivity at pressures that were approximately 12% higher than lower pressures and 90% of the expected failure pressure. The testing also indicated no adverse impacts to the caprock or to the adjacent well pairs. Laterally, pressure transient was limited; vertically, pressure response in the reservoir monitoring zone was barely measurable, supporting caprock integrity is maintained with the process.

[0038] Testing can be conducted prior to the startup process to determine operating parameters and, in particular, the elastic deformation pressure. Various data can be collected and analysed to determine mechanical properties of the reservoir, including the pressures required to be in the elastic zone, the plastic zone, and the fracture zone. Data collection can include microfrac/minifrac testing, triaxial core testing, and so on, to determine the stress regime. From this data, the target startup fluid pressure can be determined and may be a pressure in the elastic zone and just below the plastic zone.
Furthermore, the startup process can be monitored to assess whether the reservoir is in the elastic zone, e.g., by monitoring fluid flow parameters. For example, if the startup fluid is seen to be gradually entering the reservoir, this can indicate that the reservoir is in the elastic deformation zone, whereas a sudden increase in the fluid flow rate can indicate a fracture has occurred. It is noted that for a pumping operation, the pump could be set at a flow rate and pressure would be monitored real-time while performing pressure transient analysis (PTA) during shut-ins. Various other monitoring techniques could be used to assess the progress of the startup process. Fluid flow parameters can also be compared to prior tests where dilation or plastic deformation of the reservoir was performed, so as to avoid similar conditions and stay within the elastic deformation zone. It has been found that dilation can have adverse effects on the reservoir and there is a risk it could compromise operations safety; thus remaining in the elastic deformation zone can be advantageous. It is also noted that detailed reservoir geomechanical modeling can be performed to optimize the startup process for pressure, flow rate, fluid volume, efficiency, well conformance, and safety.

[0039] The startup process can be applied in advance of various in situ recovery operations, including SAGD, Expanding Solvent SAGD (ES-SAGD), solvent-assisted gravity drainage processes, solvent-dominated gravity drainage processes, and/or Enhanced Bitumen Recovery Technology (EBRT) that can involve azeotropic heated Date Recue/Date Received 2022-09-28 vapour extraction (AH-VAPEX) processes with co-injection of solvent and steam, to increase injectivity.

[0040] This high-pressure startup fluid approach can help accelerate the start-up and ramp-up performance of the well pair and it may have a duration of a week or several weeks. The elevated pressure used by this start-up process promotes elastic deformation of the reservoir sand and temporarily increases injectivity without long-term negative impacts to coalescence, premature breakthrough of steam, or risk to caprock integrity which is posed by other technologies which operate above shear failure stress conditions.
Startup fluid pressure may be constant or vary cyclically in one or both wells. Startup fluid injection may occur simultaneously into the injection and the production wells of a well pair or in a staggered/alternating fashion. For longer-term SAGD operations, it can be desirable to gradually lower the operating pressure for improved thermal efficiency.

[0041] One advantage of this high-pressure startup fluid injection is enhanced permeability and injectivity and, therefore, faster start-up and steam chamber growth.
High-pressure injection can promote much faster heating due at least in part to convective heat transfer achieved through higher rate and volume of energy input into the reservoir.
For low-mobility areas in particular, the startup process may result in significant savings in time, equipment and workforce requirements by eliminating circulation start-up through a start-up skid. In some implementations, the startup process can include multiple bullheading stages using the same or different fluids. For example, the process could first include a water bullheading stage followed by a steam bullheading stage.
Alternatively, steam is bullheaded from the beginning. Steam bullheading may occur for several weeks, and then the startup process could be assessed (e.g., with temperature fall-off tests) and then convert to SAGD mode with continuous injection and production from the respective wells once there is a solid indication of sufficiently high temperature between the wells.

[0042] While well pair startup has been discussed in detail above, it is noted that high-pressure fluid injection in the elastic deformation zone can have other applications for in situ recovery operations. For example, the high-pressure process could be implemented to stimulate production wells with suspected liner and/or near-wellbore plugging. In such cases, the production well would be shut down and a stimulation fluid would be introduced at elastic deformation pressure to stimulate the reservoir surrounding the production well.

Date Recue/Date Received 2022-09-28 In another example, the high-pressure process could be to stimulate the growth of steam chambers or extraction chambers impeded by poor reservoir quality. In such a case, the injection well would receive the fluid which would be injected at elastic deformation pressure into the reservoir to stimulate chamber growth for a stimulation period and then the injection would be brought back down to normal operating pressures.

[0043] Several alternative implementations and examples have been described and illustrated herein. The implementations of the technology described above are intended to be exemplary only. A person of ordinary skill in the art would appreciate the features of the individual implementations, and the possible combinations and variations of the components. A person of ordinary skill in the art would further appreciate that any of the implementations could be provided in any combination with the other implementations disclosed herein. It is understood that the technology may be embodied in other specific forms without departing from the central characteristics thereof. The present implementations and examples, therefore, are to be considered in all respects as illustrative and not restrictive, and the technology is not to be limited to the details given herein. Accordingly, while the specific implementations have been illustrated and described, numerous modifications come to mind.

Date Recue/Date Received 2022-09-28

Claims (85)

1. A startup process to establish fluid communication between a well pair comprising an injection well overlying a production well located in a hydrocarbon-bearing reservoir, comprising:
introducing a startup fluid into an interwell reservoir region defined between the injection well and the production well at an elastic deformation pressure of the reservoir to induce temporary elastic deformation in the interwell reservoir region;
and establishing fluid communication between the injection well and the production well.

2. The startup process of claim 1, wherein the introducing of the startup fluid comprises injection.

3. The startup process of claim 1 or 2, wherein the introducing of the startup fluid comprises circulation.

4. The startup process of any one of claims 1 to 3, wherein the startup fluid comprises steam.

5. The startup process of any one of claims 1 to 3, wherein the startup fluid comprises water.

6. The startup process of any one of claims 1 to 3, wherein the startup fluid comprises a hydrocarbon solvent.

7. The startup process of claim 6, wherein the hydrocarbon solvent comprises diesel.

8. The startup process of any one of claims 1 to 7, wherein the elastic deformation pressure at which the startup fluid is introduced is between 0% and 15% below a yield point of the interwell reservoir region.

9. The startup process of any one of claims 1 to 7, wherein the elastic deformation pressure at which the startup fluid is introduced is between 1% and 10% below a yield point of the interwell reservoir region.

10. The startup process of any one of claims 1 to 7, wherein the elastic deformation pressure at which the startup fluid is introduced is between 2% and 7% below a yield point of the interwell reservoir region.

11. The startup process of any one of claims 1 to 7, wherein the elastic deformation pressure at which the startup fluid is introduced is between 3% and 6% below a yield point of the interwell reservoir region.

12. The startup process of any one of claims 1 to 11, wherein the elastic deformation pressure at which the startup fluid is introduced is between 0% and 15% below a reservoir fracture pressure.

13. The startup process of any one of claims 1 to 11, wherein the elastic deformation pressure at which the startup fluid is introduced is between 3% and 10% below a reservoir fracture pressure.

14. The startup process of any one of claims 1 to 13, wherein the introducing of the startup fluid comprises a multistep procedure comprising circulation and/or bullheading.

15. The startup process of claim 14, wherein the multistep procedure comprises:
a fluid circulation step at pressures in an elastic deformation pressure zone;
and a bullheading step at injection pressures in the elastic deformation pressure zone to provide fluid penetration into the interwell reservoir region.

16. The startup process of claim 15, wherein the fluid circulation step is performed at a pressure between 85% and 95% of reservoir fracture pressure.

17. The startup process of claim 15, wherein the fluid circulation step is performed at a pressure between 88% and 92% of reservoir fracture pressure.

Date Recue/Date Received 2022-09-28

18. The startup process of any one of claims 15 to 17, wherein the bullheading step is performed between 85% and 95% of reservoir fracture pressure.

19. The startup process of claim 18, wherein the bullheading step is performed at a pressure between 88% and 92% of reservoir fracture pressure.

20. The startup process of any one of claims 15 to 19, wherein the bullheading step comprises a first bullheading stage operated at a first pressure and a second bullheading stage operated at a second pressure that is lower than the first pressure.

21. The startup process of claim 20, wherein the first pressure is gradually reduced to the second pressure between the first and second bullheading stages.

22. The startup process of claim 20 or 21, wherein the first pressure is up to 95% or 90%
of the reservoir fracture pressure and the second pressure is 5% to 10% lower than the first pressure.

23. The startup process of any one of claims 15 to 22, wherein the bullheading step is performed until fluid communication is established between the injection well and the production well.

24. The startup process of any one of claims 15 to 23, wherein the fluid circulation step is performed in only the injection well.

25. The startup process of any one of claims 15 to 23, wherein the fluid circulation step is performed in only the production well.

26. The startup process of any one of claims 15 to 23, wherein the fluid circulation step is performed in both the injection well and the production well.

27. The startup process of any one of claims 15 to 26, wherein the bullheading step is performed via the injection well only, and the production well is operated in shut-in mode.

28. The startup process of any one of claims 15 to 26, wherein the bullheading step is performed via both the injection well and the production well until fluid communication is established and then the production well is operated in production mode.
Date Recue/Date Received 2022-09-28

29. The startup process of any one of claims 15 to 28, wherein the multistep procedure further comprises, prior to the fluid circulation step, a wellbore fluid unloading step wherein unloading fluid is introduced to remove completion fluid and/or drilling mud to surface.

30. The startup process of claim 29, wherein the unloading fluid comprises steam.

31. The startup process of claim 29 or 30, wherein the reservoir has low injectivity below 1 m3 of steam/hour.

32. The startup process of any one of claims 15 to 28, wherein the multistep procedure further comprises, prior to the fluid circulation step, a wellbore fluid unloading step wherein unloading fluid is introduced to drive completion fluid and/or drilling mud into the reservoir.

33. The startup process of claim 32, wherein the unloading fluid comprises an unloading liquid.

34. The startup process of claim 32, wherein the unloading fluid comprises water.

35. The startup process of any one of claims 32 to 34, wherein the reservoir has a high injectivity above 1 m3 of steam/hour.

36. The startup process of any one of claims 15 to 35, wherein the multistep procedure comprises wellbore depressurization between steps.

37. The startup process of any one of claims 15 to 35, wherein the multistep procedure comprises no wellbore depressurization between steps.

38. The startup process of any one of claims 1 to 37, wherein the hydrocarbon-bearing reservoir comprises an oil sands reservoir comprising heavy oil or bitumen.

39. The startup process of any one of claims 1 to 38, wherein the startup process is performed in preparation for Steam-Assisted Gravity Drainage (SAGD).

40. The startup process of any one of claims 1 to 38, wherein the startup process is performed in preparation for a solvent-assisted recovery process.

Date Recue/Date Received 2022-09-28

41. The startup process of any one of claims 1 to 38, wherein the startup process is performed in preparation for a solvent-dominated recovery process.

42. The startup process of any one of claims 1 to 41, further comprising:
determining an elastic deformation pressure zone for the reservoir; and selecting operating pressures for the startup fluid based on the elastic deformation pressure zone.

43. The startup process of claim 42, wherein the determining of the elastic deformation pressure zone utilizes data obtained from testing reservoir samples, measurements collected from downhole instrumentation, or a combination thereof.

44. The startup process of claim 42, wherein the determining of the elastic deformation pressure zone comprises:
determining a fracture pressure of a near-wellbore region; and estimating the elastic deformation pressure zone based on the fracture pressure of the near-wellbore region.

45. The startup process of any one of claims 1 to 44, further comprising:
monitoring at least one operating parameter to detect indication of reservoir fracture or plastic deformation; and if reservoir fracture or plastic deformation is detected, modifying operating conditions of the startup process to cease the reservoir fracture or the plastic deformation.

46. The startup process of claim 45, wherein the monitoring comprises measuring pressure conditions and/or flow rate conditions of the startup fluid.

47. A process for recovering hydrocarbons from a reservoir, comprising:
a startup phase operated according to the startup process as defined in any one of claims 1 to 46; and Date Recue/Date Received 2022-09-28 a hydrocarbon recovery phase comprising introducing an injection fluid via the injection well into the reservoir and recovering production fluid via the production well.

48. The process of claim 47, wherein the process is a Steam-Assisted Gravity Drainage (SAGD) process wherein the injection fluid is steam.

49. The process of claim 47, wherein the process is a solvent-assisted process wherein the injection fluid comprises steam and hydrocarbon solvent.

50. The process of claim 47, wherein the process is a solvent-dominated process wherein the injection fluid comprises a dominant proportion of hydrocarbon solvent.

51. The process of claim 50, wherein the injection fluid consists essentially of the hydrocarbon solvent.

52. The process of claim 47, wherein the injection fluid comprises a paraffinic solvent including C3 tO C6; a solvent mixture comprising a diluent blend; one or more alcohols;
one or more ethers; diesel; biodiesel; a mixture of alkanes and alcohols; one or more aromatic solvents; or a combination thereof.

53. The process of claim 1, wherein the introducing of the startup fluid comprising injecting via both the injection well and the production well to form respective elastically deformed zones in the interwell reservoir region that merge to form a merged elastically deformed zone in the interwell reservoir region.

54. A well pair startup system comprising:
a well pair comprising an injection well overlying a production well located in a hydrocarbon-bearing reservoir; and a startup fluid delivery unit located at surface and being in fluid communication with one or both of the injection well and the production well, the startup fluid delivery unit being configured for introducing a startup fluid down at least one of the wells and into an interwell reservoir region defined between the injection well and the production well at an elastic deformation pressure of the reservoir to induce Date Recue/Date Received 2022-09-28 temporary elastic deformation in the interwell reservoir region, and for establishing fluid communication between the injection well and the production well.

55. The well pair startup system of claim 54, wherein the startup fluid delivery unit comprises a pump for when the startup fluid is a startup liquid.

56. The well pair startup system of claim 54, wherein the startup fluid delivery unit comprises a steam generator and a pressure let-down unit for when the startup fluid comprises steam, the steam generator producing high pressure steam and the pressure let-down unit receiving the high pressure steam and reducing the pressure to produce the startup steam for introduction into the interwell region.

57. The well pair startup system of any one of claims 54 to 56, further comprising a circulation unit for circulating the startup fluid through the injection well and the production well, and a bullheading unit for bullheading the startup fluid via at least the injection well after circulation.

58. The well pair startup system of any one of claims 54 to 57, further comprising a monitoring unit configured to detect reservoir fracture or plastic deformation.

59. The well pair startup system of claim 55, wherein the startup fluid comprising water.

60. The well pair startup system of claim 55, wherein the startup fluid comprising liquid solvent.

61. The well pair startup system of claim 56, wherein the startup fluid comprises the steam and a solvent that are co-injected together.

62. The well pair startup system of claim 56, wherein the startup fluid consists of the steam.

63. An in situ hydrocarbon recovery system comprising:
a well pair comprising an injection well overlying a production well separated by an interwell reservoir region; and Date Recue/Date Received 2022-09-28 a well pair startup system comprising a fluid delivery unit provided at surface and in fluid communication with at least one well selected from the injection well and the production well, and configured to introduce a startup fluid into the interwell reservoir region via the at least one well at an elastic deformation pressure of the reservoir to induce temporary elastic deformation in the interwell reservoir region;
wherein the injection well is configured to supply an injection fluid into the reservoir to facilitate mobilization of hydrocarbons, and the production well is configured to recover production fluid comprising mobilized hydrocarbons.

64. The in situ hydrocarbon recovery system of claim 63, wherein the well pair startup system is as defined in any one of claims 54 to 62.

65. A process for recovering hydrocarbons from a reservoir comprising:
operating a gravity based in situ hydrocarbon recovery operation comprising injecting an injection fluid via an injection well to mobilise hydrocarbons in the reservoir and recovering production fluid via a production well underlying the injection well;
detecting suspected plugging in the production well;
temporarily ceasing recovery of production fluid via the production well;
stimulating the production well, the stimulating comprising:
introducing a stimulation fluid via the production well and into a near-wellbore reservoir region of the production well at an elastic deformation pressure to induce temporary elastic deformation in the near-wellbore reservoir region; and injecting or circulating the stimulation fluid in the elastically deformed near-wellbore reservoir region and unplugging the production well; and reinitiating the production well in production mode for recovering production fluid to surface.
Date Recue/Date Received 2022-09-28

66. The process of claim 65, wherein the gravity based in situ hydrocarbon recovery operation is Steam-Assisted Gravity Drainage (SAGD) and the stimulation fluid is steam.

67. The process of claim 65 or 66, wherein the elastic deformation pressure at which the stimulation fluid is introduced is between 0% and 15% below a yield point of the near-wellbore reservoir region.

68. The process of claim 65 or 66, wherein the elastic deformation pressure at which the stimulation fluid is introduced is between 1% and 10% below a yield point of the near-wellbore reservoir region.

69. The process of claim 65 or 66, wherein the elastic deformation pressure at which the stimulation fluid is introduced is between 2% and 7% below a yield point of the near-wellbore reservoir region.

70. The process of claim 65 or 66, wherein the elastic deformation pressure at which the stimulation fluid is introduced is between 3% and 6% below a yield point of the near-wellbore reservoir region.

71. A process for recovering hydrocarbons from a reservoir comprising:
operating a gravity based in situ hydrocarbon recovery operation comprising injecting an injection fluid via an injection well at an operating pressure to mobilise hydrocarbons in the reservoir and recovering production fluid via a production well underlying the injection well;
in a chamber growth promotion mode for promoting growth of a chamber extending upward from the injection well, introducing the injection fluid into the chamber at an elastic deformation pressure above the operating pressure to induce temporary elastic deformation in the reservoir and promote growth of the chamber; and returning the injection well to normal operating mode where the injection fluid is injected at the operating pressure.

72. The process of claim 71, wherein the gravity based in situ hydrocarbon recovery operation is Steam-Assisted Gravity Drainage (SAGD) and the injection fluid is steam.

Date Recue/Date Received 2022-09-28

73. The process of claim 71 or 72, wherein the elastic deformation pressure at which the injection fluid is introduced is between 0% and 15% below a yield point of the near-wellbore reservoir region.

74. The process of claim 71 or 72, wherein the elastic deformation pressure at which the injection fluid is introduced is between 1% and 10% below a yield point of the near-wellbore reservoir region.

75. The process of claim 71 or 72, wherein the elastic deformation pressure at which the injection fluid is introduced is between 2% and 7% below a yield point of the near-wellbore reservoir region.

76. The process of claim 71 or 72, wherein the elastic deformation pressure at which the injection fluid is introduced is between 3% and 6% below a yield point of the near-wellbore reservoir region.

77. A process for treating a reservoir for recovery of hydrocarbons from the reservoir in which a horizontal well pair is provided, the well pair comprising an injection well overlying a production well, the process comprising:
in an elastic deformation mode:
introducing a fluid into the injection well or the production well or both at an elastic deformation pressure to elastically deform a reservoir region and increase injectivity of the reservoir region, wherein the elastic deformation pressure at which the fluid is introduced is between 0% and 15% below a yield point of the reservoir region; and injecting the fluid into the reservoir region while in elastic deformation state;
in a normal operating mode:
returning to a normal operating pressure where an injection fluid is injected into the reservoir via the injection well, and wherein production fluid is recovered via the production well.

Date Recue/Date Received 2022-09-28

78. The process of claim 77, wherein the fluid is a startup fluid and the reservoir region comprises an interwell reservoir region in between the injection well and the production well.

79. The process of claim 78, wherein the startup fluid comprises steam.

80. The process of claim 78, wherein the startup fluid comprises water.

81. The process of claim 78, wherein the startup fluid comprises a hydrocarbon solvent.

82. The process of any one of claims 77 to 81, wherein the elastic deformation pressure at which the fluid is introduced is between 1% and 10% below a yield point of reservoir region.

83. The process of any one of claims 77 to 81, wherein the elastic deformation pressure at which the fluid is introduced is between 2% and 7% below a yield point of the reservoir region.

84. The process of any one of claims 77 to 81, wherein the elastic deformation pressure at which the fluid is introduced is between 3% and 6% below a yield point of the reservoir region.

85. The process of any one of claims 77 to 84, wherein the well pair is operated as part of a Steam-Assisted Gravity Drainage (SAGD) operation and the injection fluid is steam.

Date Recue/Date Received 2022-09-28