CA3040263C - Solvent-enhanced steamflood process - Google Patents

Abstract

SE-SF is a recovery process for heavy oil reservoirs with no or minimal initial mobility, which is an improvement to known post-HPCSS steamflood processes. The SE-SF recovery process uses reservoir pre-conditioning followed by co- injection of solvent and steam, optionally at varying solvent:steam ratios, to maintain reservoir operating pressure and mobilize the oil phase using a combination of heat and dilution. Processes for reservoir pre-conditioning, solvent selection, co- injection timing, and optimum solvent-steam mixing ratios are described.

Description

SOLVENT-ENHANCED STEAMFLOOD PROCESS
= FIELD
[0001] Embodiments herein relate to a solvent-enhanced steamflood process for heavy oil recovery from widely-spaced wells, and more specifically to a process that comprises the pre-conditioning of the reservoir before solvent-steam co-injection, and the selection of steam and solvent injection rates.
BACKGROUND

[0002] In thick heavy oil-bearing reservoirs (greater than about 10m thick payzone) with high vertical permeability, steam-assisted gravity drainage process (hereafter "SAGD") has been used successfully. In SAGD, a closely-spaced pair of horizontal injector and producer wells (typically spaced 5m apart) is used.
Steam is injected into the top (injector) well over time to heat the reservoir, forming a steam chamber. Heavy oil in the chamber and at the edge of the steam chamber is mobilized by the heat, and drains downward, typically by gravity alone, and is produced by the bottom (producer) well.

[0003] In thinner reservoirs (less than about 10m thick payzone) or reservoirs with low vertical permeability, gravity-based recovery processes, such as SAGD
are not the recovery process of choice. In these reservoirs, high heat losses to the overburden and underburden formations, or low vertical permeability, negatively impact the oil rates and reduces the oil rate and thermal efficiency of the process.

[0004] Formation permeability controls steam injectivity and rate of steam chamber rise within a reservoir. Formation permeability is controlled by spatial distribution and lateral continuity of mud beds within the reservoir. Barriers and baffles can impose temporary or permanent impediments to steam flow and negatively impact oil rate and recovery factor.

[0005] In thin reservoirs or reservoirs with vertical impairments, a variety of thermal recovery techniques, such as high-pressure cyclic steam stimulation (hereafter "HPCSS") and steamflood (hereafter "SF") with different well configurations, spacing and patterns have been successfully implemented. In HPCSS, the distance between wells typically ranges from about 40m to about 180m.

[0006] HPCSS (also known as the "huff and puff' method) proceeds through three steps: injection, soaking and production, each of which can take a period of weeks to months. First, at each well accessing the reservoir, high pressure steam is injected to pressurize the reservoir and transfer heat into the reservoir.
Second, steam injection is stopped and the well is shut in, to allow heat to soak into the formation to mobilize the viscous oil. High pressure steam injection causes fracturing and dilation of reservoir, which drastically improves the vertical permeability of the formation and maximize the reservoir oil access to injected steam. Third, mobilized oil is produced at the same well. At the end of the third step, reservoir pressure drops to a very low level (<500kPa). This cycle of steps is then repeated. In earlier HPCSS cycles, reservoir compaction and solution gas drive are the main production mechanisms. As the HPCSS process matures, gravity drainage becomes the major recovery mechanism. Typical recovery factor (cumulative volume of oil produced/original volume of oil in place, hereafter "RF") in HPCSS is less than 25%.
(Batycky et. al., 1997).

[0007] In later HPCSS cycles, after a significant amount of solution gas is produced and after hydraulic communication between neighboring HPCSS wells is established; thermal efficiency of process drastically declines (i.e., there is an increase in steam-to-oil ratio (injected volume of steam/produced volume of oil, hereafter "SOR").

[0008] At this stage of depletion, HPCSS may be followed by a continuous recovery process, such as SF. In SF (also known as steam drive), a sub-set of HPCSS wells are converted to permanent steam injectors and the remaining HPCSS wells are converted to permanent producers. By conversion from a cyclic to a continuous process, oil production at economic SORs can be continued and a significantly higher RF can be achieved (70-85%) (Imperial Oil 2017).

[0009] The post-HPCSS SF process still relies on injection of high steam volumes into the reservoir to mobilize the oil phase between wells that are widely spaced from one another (e.g., about 40-180 m apart). Typical SOR in the SF
process is >4m3/m3. The disadvantages of the SF process include: need for a high steam injection volume and inherently higher SOR, which means the process is expensive; high greenhouse gas (hereafter "GHG") emissions because of the steam generation process; high emulsion and water processing costs; requirement for a bigger processing facility; and high heat losses to overburden and underburden by operating at steam saturation temperature (>200 C).

[0010] Solvent-aided steamflood processes have been proposed to overcome some of the limitations of SF by simultaneous application of heat and solvent, to mobilize heavy oil at temperatures that are lower than heat alone can. The main advantages of these processes include: reduction in steam injection rate and consequently SOR; reduction in amount of GHG emission; lower emulsion handling and processing costs; reduction in SO2 production by lowering the vapor chamber temperature (e.g., to about 70-150 C); and, lower heat loss to overburden and underburden. The concept of a solvent-aided steamflood process has been discussed in the past (see e.g., Liu et al., 2017, Hedden and Verlaan, 2014 and Zhao et al., 2013). These studies investigated the impact of solvent-steam co-injection on oil rate and SOR, as a primary process or immediately following HPCSS.

[0011] The addition of solvent to steam is also known in SAGD and HPCSS.
Imperial Oil has patented the LASER process (Canadian Patent No. 2,342,955) to improve cyclic steam-based recovery process by using co-injection of diluent and steam in late HPCSS cycles. In SAGD, where injector and producer wells are separated vertically by about 5m, various recovery techniques using steam and solvent co-injection to improve SAGD performance have also been developed and tried. A detailed review of these recovery processes and field trials is provided by Bayestehparvin et al. (2016).
SUMMARY

[0012] Generally, disclosed herein is a solvent-enhanced steamflood (hereafter "SE-SF") recovery process that can be applied to widely spaced vertical and/or slant and/or horizontal wells. In this process, after reservoir pre-conditioning by HPCSS
and SF, the SE-SF process is used to reduce SOR by at least about 50% and keep oil rate at the SF level. The SE-SF process is based on co-injection of a volatile solvent with steam and utilization of both heat and dilution to mobilize heavy oil. .

[0013] Described herein is a process for recovering heavy oil from a heavy oil reservoir penetrated by a multi-well array comprising a plurality of wells spaced between about 40m and about 180m apart from one another, the process comprising:
a) pre-conditioning the reservoir by:
i. producing heavy oil from the multi well array using an HPCSS
process;
ii. designating a sub-set of wells to be injector wells and the remaining wells as producer wells;
iii. producing heavy oil at the producer wells using an SF process;
iv. ensuring reservoir readiness for conversion to an SE-SF
process by improving the communication between an injector well and a producer well by increasing the temperature at the producer well, using the SF process; and v. checking reservoir readiness for the SE-SF process by monitoring the temperature of produced fluid at a producer well and comparing against steam saturation temperature at a desired SE-SF producer well pressure;
b) starting the transition from the SF process to the SE-SF process after hydraulic and thermal communication between an injector well and a producer well is confirmed (that is, the reservoir is ready), by co-injection of a solvent-steam mixture into the injector well;
wherein solvent type and mixing ratio is selected based on selected SE-SF
reservoir operating pressure; and c) producing a solvent and heavy oil mixture from the producer well.

[0014] In one aspect, disclosed herein is a process for recovering oil from a heavy oil reservoir penetrated by a plurality of wells spaced between about 40m and about 180m apart from one another, the process comprising:
a) pre-conditioning the reservoir by:
producing heavy oil from the plurality of wells by high pressure cyclic steam stimulation (HPCSS) to improve the vertical permeability of formation and develop steam chambers within the reservoir;
designating at least one of the plurality of wells to be an injector well, and at least one of the plurality of wells to be a producer well;
producing heavy oil at the at least one producer well by a steamflood (SF) process; and iv.
continuing the SF process until the temperature at the least one injector well increases the temperature of produced fluids at a neighboring at least one producer well to near steam saturation temperature at the producer well pressure;
b) selecting a solvent-enhanced SF (SE-SF) operating temperature range that reduces the viscosity of the heavy oil by orders of magnitude, as compared to the viscosity of the heavy oil at initial reservoir conditions;
c) selecting a solvent that vaporizes within the SE-SF operating temperature range, at the SE-SF reservoir operating pressure;
d) co-injecting a solvent-steam mixture having a selected solvent:steam ratio into the at least one injector well to maintain reservoir operating pressure at the SE-SF reservoir operating pressure by vaporization of co-injected solvent at a reduced steam rate;
e) producing heavy oil diluted with the solvent, at the neighboring producer well.

[0015] In embodiments, the process further comprises the step of optimizing the solvent:steam ratio based on an observed ISolOR and temperature of the heavy oil produced.

[0016] In embodiments, the SF process is performed at a first steam rate, and the co-injecting of the steam-solvent mixture is performed at a second steam rate that is no more than about 50% of the first steam rate.

[0017] In embodiments, the SF process is performed at a first steam rate, and the co-injecting of the steam-solvent mixture is performed at a second steam rate that is about 50% of the first steam rate.

[0018] In embodiments, the SF process is continued until the temperature of produced fluid at the neighbouring producer well is about 50 C lower than the temperature of steam injected at the injector wells.

[0019] In embodiments, the SF process is continued until the temperature of produced fluids at the neighboring producer well is above about 180 C.

[0020] In embodiments, the SE-SF operating temperature range is between about 80 C and about 200 C.

[0021] In embodiments the SE-SF operating temperature range is between about 80 C and about 150 C.

[0022] In embodiments, the SE-SF reservoir operating pressure is between about 1 MPa and about 6 MPa.

[0023] In embodiments, the SE-SF reservoir operating pressure is between about 2 MPa and about 4 MPa.

[0024] In embodiments, the solvent-steam mixture has a ratio of solvent:steam of between about 20 and about 50 v/v%.

[0025] In embodiments, the solvent-steam mixture has a ratio of solvent:steam between about 20 and about 30 v/v%.

[0026] In embodiments, the solvent-steam mixture has a ratio of solvent:steam that changes over time.

[0027] In embodiments, the solvent selected vaporizes in the range of about 80 C to about 150 C, at the SE-SF reservoir operating pressure.

[0028] In embodiments, the solvent is selected from the group consisting of:
propane and butane, and mixtures thereof.

[0029] In embodiments the solvent is propane or butane.

[0030] In embodiments, the viscosity of the heavy oil is below about 1000 cP at the SE-SF operating temperature range.

[0031] In embodiments, the wells are selected from the group consisting of:
vertical, slant and horizontal wells.

[0032] For a reservoir operating pressure during the SE-SF process of between about 2 MPa and about 4 MPa, the solvent is preferably selected from the group consisting of: propane and butane, and mixtures thereof.
BRIEF DESCRIPTION OF DRAWINGS

[0033] Figure 1 is a drawing depicting the pre-conditioned reservoir at the start of the SE-SF process described herein.

[0034] Figure 2 shows the impact of reservoir pre-conditioning on the net instantaneous solvent-oil-ratio (1SolOR), for propane-steam co-injection.

[0035] Figure 3 shows the viscosity of solvent (Cl, C3 and C4) saturated bitumen as a function of temperature.

[0036] Figure 4 shows the difference between the effect of SE-SF and SF
only, on oil rate.

[0037] Figure 5 shows the difference between SE-SF and SF only, on instantaneous steam-to-oil ratio (ISOR).

[0038] Figure 6 shows a schematic of rate profiles of the SF process as compared to the SE-SF process, at the point where pre-conditioning is completed an injection of a steam-solvent mixture is started at a reduced steam rate.

[0039] Figure 7 provides pressure-temperature diagram of C2-C7 solvents and water.

[0040] Figure 8 shows an example of pre-conditioning of a number of producer wells in a reservoir according to the method described herein.

DESCR IPTION

[0041] High SOR at the end of HPCSS process makes the process uneconomic.
SF has been used as follow up process to HPCSS to continue economic production.
SE-SF, as described herein, further improves the performance of SF process.
Inventors have found that pre-conditioning the reservoir by HPCSS and SF, before SE-SF is started, helps to ensure that communication between the injector well and producer well is fully established and interface temperatures are within the optimum range. This step is necessary to ensure that injected solvent will vaporize and that no excessive solvent accumulation occurs within the reservoir. In addition, injected solvent maintains reservoir operating pressure at SF levels at reduced steam rate of at least about 50%. Excessive solvent accumulation not only increases solvent to oil ratio (injected solvent volume/produced oil volume, hereafter "SolOR") of the SE-SF
process, but it can also cause asphaltene precipitation, which results in plugging of the formation and of the producer well, and/or reduction of RF.

[0042] In the literature, a number of solvent-assisted SF processes have been proposed and studied. However, these prior art methods are focused on the impact of steam-solvent co-injection on performance of SF and do not provide any details on reservoir pre-conditioning and the solvent selection process, as described herein.
Pre-conditioning, by combination of HPCSS and SF processes not only helps to improve the vertical permeability of formation, but also establishes hydraulic and thermal communication between an injector well and a producer well, to mitigate or eliminate excessive solvent accumulation within the reservoir. This disclosure also addresses solvent selection and tailoring the solvent to the reservoir operating pressure during the SE-SF process, to keep ISolOR within an acceptable range.

[0043] The innovations in the disclosed SE-SF recovery process compared to known solvent-based processes are: i) implementation of the SE-SF process to a high viscosity heavy oil reservoir, after reservoir pre-conditioning using HPCSS and post-HPCSS SF; ii) implementation of the SE-SF process when injector wells and producer wells are widely spaced from each other; iii) co-injection of steam and solvent at varying ratios and concentrations, based on reservoir parameters (composition, temperature, operating pressure, and injection timing); and iv) solvent selection method.

[0044] As used herein, "about" means +/- 10% of the value referenced.

[0045] The SE-SF process described herein begins with the step of pre-conditioning a low vertical permeability heavy oil reservoir having a plurality of widely-spaced wells, by using HPCSS and SF. "HPCSS" as used herein refers to a CSS process in which the steam injection pressure is greater than the fracture pressure of the formation. Typically, this pressure is in the range of 6 to 15 MPa.

[0046] Heavy crude oil reservoirs contain highly-viscous "heavy oil" which as used herein means an oil, including bitumen, having a viscosity higher than 30,000 cP, optionally higher than 80,000 cP, and most preferably higher than 100,000 cP, and which is unable to flow to production wells under initial reservoir conditions (that is, the reservoir conditions existing before HPCSS is started, typically a virgin reservoir).

[0047] As is known, in the HPCSS process a number of widely-spaced wells are drilled into a heavy oil reservoir, and each well is used both for steam injection and for oil production. When the HPCSS process is converted to an SF process, some of the wells become injection-only wells and some of the wells become production-only wells. A production well that is paired with an injector well, is referred to herein as a "neighboring" producer well. A similar configuration of wells is used in the SE-SF
process described herein.

[0048] As used herein, "widely-spaced wells" means vertical and/or slant and/or horizontal wells that are separated by a distance of about 40m to about 180m, preferably a distance of about 40m to about 80m. These wells may be in a thin reservoir, or in a thick reservoir.

[0049] Reservoir "pre-conditioning" refers to the steps of performing HPCSS on the reservoir, followed by SF until a high temperature hydraulic communication has been established between an injector well and a producer well. The efficiency of pre-conditioning phase can be evaluated by monitoring the pressure and temperature at injector wells and producer wells, by integration of other reservoir surveillance data, such as observation wells and by seismic data.

[0050] The HPCSS and SF processes pre-condition the reservoir for the SE-SF
process described herein, by improving vertical permeability of the formation, by developing hydraulic communication between drainage boxes of the wells, by increasing the temperature at the edge of steam chamber which minimizes excessive solvent loading within the reservoir and increases the mobility of injected solvent that is to be transported to the edge of steam chamber which mobilizes the oil phase.

[0051] Pre-conditioning is considered to be complete when high temperature hydraulic communication is established between an injector well and a producer well. As used herein, a "high temperature hydraulic communication" is achieved when steam injected at the injector well increases the temperature of the neighboring producer well to about steam saturation temperature, at the producer well downhole pressure. The temperature of the producer well is determined by measuring the temperature of produced fluid.

[0052] One injector well may have a high temperature hydraulic communication with more than one producer well, and also, one producer well may have a high temperature hydraulic communication with more than one injector well.

[0053] Figure 1 shows the schematic of an ideal communication between injector wells and producer wells, wherein the steam chambers are filled with steam to replenish the temperatures around the wells and at the edge of steam chamber.
The darker arrows represent steam injected at the injector well and the lighter arrows represent steam/water/oil produced at the producer well. When the temperature of the produced fluid in the producer well reaches approximately the steam saturation temperature at the producer well pressure, high temperature hydraulic communication has been established between the injector and producer well. In Figure 1, the solid black bars represent vertical flow barriers and baffles that impact the vertical steam chamber growth. In this figure, the bars with upward diagonal pattern are the baffles and barriers that were fractured and dilated during pre-conditioning phase by HPCSS. The increase in permeability of these features resulted in improvement of vertical permeability of reservoir and vertical growth of steam chamber.

[0054] If solvent co-injection is started before a high temperature hydraulic communication between an injector well and a producer well is established, the amount of solvent required to produce a unit volume of oil is significantly higher. This is because, in absence of a high temperature communication, solvent may condense within depleted steam chambers and/or excessive condensation will occur on the edge of steam chamber and accumulates within the reservoir.

[0055] Figure 2 is an example showing how reservoir pre-conditioning affects the instantaneous solvent-oil-ratio (1SolOR) in two scenarios: i) SE-SF is started right after the last HPCSS cycle (i.e., no high temperature hydraulic communication between injector well and producer well); and ii) SE-SF is started after post-HPCSS
SF and after a high temperature hydraulic communication between wells has been established (i.e., after pre-conditioning). As is evident the ISolOR is significantly higher when no pre-conditioning is performed.

[0056] As mentioned, high temperature hydraulic communication is established when the temperature of produced fluid (e.g., oil, water and/or steam) at the producer is near the steam saturation temperature at the operating pressure of the producer well, during the SF process. The meaning of "near", as contemplated herein and in this context, is a temperature at the producer well about 50 C
to about 70 C, preferably about 50 C, lower than the actual steam saturation temperature at the producer well pressure. The reservoir is then considered to be pre-conditioned.

[0057] Figure 3 shows how the viscosity of bitumen is affected by temperature and by the saturation with solvent (Cl, C3 or C4). The viscosity of a mixture of bitumen and solvent can be as low as that of bitumen at steam temperature, or even lower, as shown in Figure 3.

[0058] "Solvent" as used herein includes light and intermediate hydrocarbons, e.g., 02 to C8 hydrocarbons, and mixtures thereof. For example, solvent means ethane and propane and butanes, pentanes, hexanes, heptanes and octanes, and mixtures thereof. Preferred for use as solvents herein are propane and butane, and mixtures thereof.

[0059] Figure 7 charts the pressure of 02 to 07 solvents and water, against temperature, showing that saturation temperature is a function of operating pressure. Thus, as carbon number of an injected solvent increases, higher temperatures are required to vaporize and transport the solvent within the reservoir.

[0060] In SE-SF process described herein, Figure 3 and Figure 7 may be used together to select the suitable solvent. For the bitumen ("dead oil") depicted in Figure 3, viscosity can be reduced by several orders of magnitude just by increasing the reservoir temperature from 10 C to 80 C ¨ 150 C. In this temperature range, the butane and propane will vaporize at a pressure of between about 1.0 MPa and about 4.0 MPa. As solvent solubility increases with pressure and decreases with temperature, solvent selection should be done in a manner that maximizes solubility within the range of selected reservoir operating pressures and ensures that co-injected solvent remains in vapor phase from the site of injection to the edge of vapor chamber, where it is expected to condense and dilute the heavy oil phase. For instance, in a temperature range of about 80 C to about 150 C and at a reservoir operating pressure range of about 1.0 MPa to about 2.0 MPa, butane or pentane may be selected over propane to ensure maximum solubility and viscosity reduction by solvent dissolution. However, at higher operating pressures, such as about 3.5 to about 4.0 MPa, propane becomes a more attractive solvent for mobilizing the heavy oil phase.

[0061] After conversion from the SF process to SE-SF process, the producer well temperature will decline as the temperatures of the front will decline, because of the at least about 50% reduction in steam injection rate, thus reducing heat losses occurring to overburden and underburden formations.

[0062] In the SE-SF process which follows pre-conditioning, a mixture of solvent and steam is injected into the reservoir. The solvent-steam mixture may have a ratio of between about 20-50 v/v% (liquid equivalent) solvent:steam. In embodiments, the solvent:steam ratio is about 20-30 v/v%, about 20-40 v/v%, about 30-50 v/v% or about 30-40 v/v%. The type of solvent used and the steam-solvent ratio are determined based on the selected reservoir operating pressure for the SE-SF
process. The reservoir operating pressure for the SE-SF process is measured by measuring the bottomhole pressure of steam injection at an injector well.

[0063] The solvent:steam ratio can vary over time and may be optimized based on produced fluids temperature, observed ISolOR, and required vaporized solvent volume to maintain reservoir operating pressure. For example, a drop in the temperature of the produced fluid and an increase in ISolOR translates into suboptimal accumulation of solvent at the edge of vapor chamber that is caused by lower temperatures within the reservoir. Increasing the steam component of the solvent:steam mixture can deliver more heat into the reservoir, thereby increasing interface temperatures and reducing solvent accumulation at the interface.
ISolOR is measured by determining the ratio of injected volume of solvent to produced oil volume.

[0064] After the solvent and desired solvent:steam ratio is selected, a mixture of steam and solvent having this ratio can be co-injected into the injector well at steam rate that is 50% or less than the steam rate that was used during SF, in the pre-conditioning step. Figure 6 shows a schematic comparing the rate profiles of steam and oil, in the SF process during pre-conditioning, and in the SE-SF process after pre-conditioning. As can be seen, the steam rate used at the end of the SF pre-conditioning can be reduced by at least about 50% during the SE-SF process, and this does not reduce the oil production rate.

[0065] The objective of solvent/steam co-injection is to maintain the temperature in the vapor chamber within the range of about 70 C to about 150 C. The injected steam vaporizes the solvent, and the vaporized solvent and steam maintain reservoir pressure and heat the reservoir, using less steam that would be used without solvent addition. Solvent in the vapor phase and steam travel though the reservoir and reach the edges of the vapor chamber. At the edges, solvent and steam may condense releasing latent heat, and solvent may dissolve/diffuse into the heavy oil, mobilizing the heavy oil. The mobilized diluted oil flows to the producer well for production.

[0066] The SE-SF process can sustain oil production rates at a significantly lower steam rate (m3/day) as compared to SF alone, because both solvent dilution and heat are used to mobilize the oil phase. Figure 4 and Figure 5 compare simulated oil rate and instantaneous steam-to-oil ratio (ISOR), respectively, for the SE-SF
process disclosed herein and an SF process. In the SE-SF process, C3 (propane) is co-injected at a varying solvent to steam ratio initially and after a while stabilizing at about 20% vol solvent/vol steam and at 50% of the steam injection rate used in the SF process during pre-conditioning. As shown in these figures, comparable oil rates can be sustained during SE-SF, even when there is a significant reduction in ISOR.

[0067] An optimized combination of reservoir temperature, solvent type, solvent and steam rates, and operating pressure, ensures optimum solubility of solvent in oil phase to mobilize the oil phase and minimum solvent loading in cold regions of the reservoir or at the edges of the vapor chamber. With an increase in the solvent content of the oil phase, partial upgrading of oil phase by minimal asphaltene deposition within the reservoir may occur.

[0068] Figure 8 provides a field example of reservoir pre-conditioning by HPCSS
and SF as contemplated herein. The injector and producer wells are horizontal wells with variable well spacing between 60m and 80m apart, and are drilled in the Clearwater Formation with an average thickness of 18.5m. At the end of the HPCSS
process, the wellhead temperature of the 13 producer wells varies between about C and about 70 C. At this point, the SF process is started, and continues at average steam rate of 270 m3/day for 21 months until the temperature of produced fluid from producer wells is between about 180 C and about 200 C. Once produced fluid temperatures reach about 180 C, a high temperature hydraulic communication is considered to be established between an injector well and a producer well.
Now, the SE-SF process can begin.

[0069] While the method has been described in conjunction with the disclosed embodiments which are set forth in detail, it should be understood that this is by illustration only and the method is not intended to be limited to these embodiments.
On the contrary, this disclosure is intended to cover alternatives, modifications, and equivalents which will become apparent to those skilled in the art in view of this disclosure.
References:
Batycky, J.P., Leaute, R.P., Dawe, B.A. (1997), A mechanistic model of cyclic steam stimulation, SPE 37550-MS, Bakersfield-California, 10-12 February.
Imperial Oil Resources Ltd. (2017), Annual performance review: Cold Lake Approvals 8558 and 4510.

Canadian Patent No. 2,342,955, Imperial Oil Resources Ltd. (2001), Additive liquid addition to steam for enhancing recovery of cyclic steam stimulation or LASER.
Bayestehparvin, B., Farouq Ali, S.M., Abedi, J. (2016), Use of solvents with steam ¨
state-of-the-art and limitations, SPE 179829-MS, Muscat-Oman, 21-23 March.
Liu H. L., Cheng L., Xiong H., Huang S. (2017) in Effects of solvent properties and injection strategies on solvent-enhanced steam flooding for thin heavy oil reservoirs with semi-analytical approach, Oil & Gas Science and Technology 72, 20.
Hedden R. and Verlaan M. (2014) Solvent enhanced steam drive SPE-169070 Zhao D. W., Wang, J., Gates I. D., (2013), Solvent-aided steam-flooding strategy optimization in thin heavy oil reservoirs, IPTC 16793,

Claims (18)

1. A process for recovering oil from a heavy oil reservoir penetrated by a plurality of wells spaced between about 40m and about 180m apart from one another, the process comprising:
a) pre-conditioning the reservoir by:
i. producing heavy oil from the plurality of wells by high-pressure cyclic steam stimulation (HPCSS) to improve the vertical permeability of formation and develop steam chambers within the reservoir;
ii. designating at least one of the plurality of wells to be an injector well, and at least one of the plurality of wells to be a producer well;
iii. producing heavy oil at the at least one producer well by a steamflood (SF) process; and iv. continuing the SF process until the temperature at the least one injector well increases the temperature of produced fluids at a neighboring at least one producer well to near steam saturation temperature at the producer well pressure;
b) selecting a solvent-enhanced SF (SE-SF) operating temperature range that reduces the viscosity of the heavy oil by orders of magnitude, as compared to the viscosity of the heavy oil at initial reservoir conditions;
c) selecting a solvent that vaporizes within the SE-SF operating temperature range, at the SE-SF reservoir operating pressure;
d) co-injecting a solvent-steam mixture having a selected solvent:steam ratio into the at least one injector well to maintain reservoir operating pressure at the SE-SF reservoir operating pressure by vaporization of co-injected solvent at a reduced steam rate; and e) producing heavy oil diluted with the solvent, at the neighboring producer well.

2. The process of claim 1 further comprising the step of optimizing the solvent:steam ratio based on an observed lSolOR and temperature of the heavy oil produced.

3. The process of claim 1 or 2, wherein the SF process is performed at a first steam rate, and the co-injecting of the solvent-steam mixture is performed at a second steam rate that is no more than about 50% of the first steam rate.

4. The process of claim 1 or 2, wherein the SF process is performed at a first steam rate, and the co-injecting of the solvent-steam mixture is performed at a second steam rate that is about 50% of the first steam rate.

5. The process of any one of claims 1 to 4, wherein the SF process is continued until the temperature of produced fluid at the neighboring producer well is about 50°C lower than the temperature of steam injected at the at least one injector well.

6. The process of any one of claims 1 to 5, wherein the SF process is continued until the temperature of produced fluid at the neighboring producer well is above about 180°C.

7. The process of any one of claims 1 to 6, wherein the SE-SF operating temperature range is between about 80°C and about 200°C.

8. The process of any one of claims 1 to 7, wherein the SE-SF operating temperature range is between about 80°C and about 150°.

9. The process of any one of claims 1 to 8, wherein the SE-SF reservoir operating pressure is between about 1 MPa and about 6 MPa.

10. The process of any one of claims 1 to 8, wherein the SE-SF reservoir operating pressure is between about 2 MPa and about 4 MPa.

11. The process of any one of claims 1 to 10, wherein the solvent-steam mixture has a ratio of solvent:steam between about 20 and about 50 v/v%.

12. The process of any one of claims 1 to 10, wherein the solvent-steam mixture has a ratio of solvent:steam of between about 20 and about 30 v/v%.

13. The process of any one of claims 1 to 12, wherein solvent:steam ratio of the solvent-steam mixture varies over time.

14. The process of any one of claims 1 to 13 wherein the solvent vaporizes in the range of about 80°C to about 150°C, at the SE-SF reservoir operating pressure.

15. The process of any one of claims 1 to 14, wherein the solvent is selected from the group consisting of: propane and butane, and mixtures thereof.

16. The process of any one of claims 1 to 14, wherein the solvent is propane or butane.

17. The process of any one of claims 1 to 16, wherein the wells are selected from the group consisting of: vertical, slant and horizontal wells.

18. The process of any one of claims 1 to 17, wherein the viscosity of the heavy oil is below about 1000 cP at the SE-SF operating temperature range.