CA3079710A1 - Solvent enhanced sagd with reduced steam and variable solvent­to-steam ratio - Google Patents

Abstract

Described herein is a method for producing heavy hydrocarbon from a reservoir via a solvent enhanced SAGD process. The method comprises injecting steam into an upper wellbore of a wellbore pair in the reservoir at a constant rate of steam injection that is below, in embodiments 40 to 60% below, the actual or estimated peak SAGD steam injection rate, and co-injecting a solvent with the steam, wherein the rate of solvent injection is gradually increased over time to maintain a target reservoir operating pressure. The method produces hydrocarbons at oil production rates that are at least equivalent to those for conventional SAGD.

Description

SOLVENT ENHANCED SAGD WITH REDUCED STEAM AND VARIABLE SOLVENT-TO-STEAM RATIO
FIELD
[0001] Embodiments taught herein relate to in situ production of heavy hydrocarbons, such as bitumen, using hybrid solvent/steam co-injection and, more particularly, wherein an amount of steam is reduced compared to conventional steam assisted gravity drainage (SAGD) processes when solvent is co-injected, thereby maintaining reservoir pressures.
BACKGROUND

[0002] It is well known to mobilize and recover heavy hydrocarbons, such as bitumen, from subterranean deposits using a variety of in situ processes. In many of these processes, heat is applied to the reservoir to mobilize the heavy hydrocarbons. Heat can be applied, for example, using downhole combustion, indwelling heaters, or can be provided by injection of a heated fluid, such as steam.

[0003] One known process is SAGD, as taught in Canadian Patent 1130201 to Butler.
In conventional SAGD, one or more pairs of vertically spaced, substantially horizontal wellbores are drilled through the formation of interest. An upper wellbore is used as an injection wellbore and a lower wellbore, typically located near a bottom of a pay zone in the reservoir, is used as a production wellbore. Steam injected through the upper injection wellbore heats the heavy hydrocarbons thereabout, reducing the viscosity of the heavy hydrocarbons. The now reduced-viscosity heavy hydrocarbons drain by gravity to the lower production wellbore and are produced therein to surface.
The pore spaces, from which the heavy hydrocarbons have drained, are depleted and filled with injected steam, forming a steam chamber. The steam chamber generally grows vertically and laterally as more heavy hydrocarbons are heated, generally at the outer margins of the steam chamber where the steam condenses, and drain to the production well.

Date Recue/Date Received 2020-04-27

[0004] Further, it is also known to modify conventional SAGD to utilize solvent to mobilize heavy hydrocarbons. The solvent, alone or with steam, is injected into the injection wellbore. The solvent, typically in a vapor state when injected, acts to dissolve the heavy hydrocarbons therein, reducing the viscosity of the heavy hydrocarbons and allowing the solvent/heavy hydrocarbon to drain by gravity to the production wellbore.

[0005] Solvent can be used alone in vapor-extraction processes, such as VAPEXTM, wherein solvent vapor, such as propane, is injected into the reservoir in the vapor phase to form a vapor chamber therein. Heavy hydrocarbons, mobilized with dissolved solvent, drain to the production wellbore as in SAGD.

[0006] Further still, steam and solvent co-injection processes are known, wherein both steam, or hot water, and solvent are co-injected into the reservoir. Generally the ratio of solvent to steam is maintained at a constant ratio throughout the entire co-injection process. Overall, the prior art processes taught to date each teach relatively fixed solvent-to-steam ratios.

[0007] As taught in Canadian Patent 2323029 to Nasr et al., a relatively small amount of solvent, such as up to about 5% liquid volume solvent, is co-injected with steam.
While Nasr reports a decrease in the steam/oil ratio (SOR) and an increase in production compared to conventional SAGD, field trials appear to show little benefit as the solvent dilution effect is limited at such low concentration and high steam volume.

[0008] Canadian Patent 2391721 to Nasr et al. teaches a complicated regime of stepwise reductions in the amount of steam with increases in the amount of solvent co-injected. The solvent-to-steam ratio is limited to less than 1:1.5 liquid volume ratio.

[0009] Canadian Patent 2915571 to Boone et al. teaches solvent/steam co-injection at or near the azeotropic solvent molar fraction of the steam and solvent, as measured at the reservoir operating temperature. Applicant believes, based on the teachings therein, that at a reservoir pressure of about 2700 kPa, about 91% to 99% volume fraction of butane would be required in the steam/solvent mixture. Such a process is clearly solvent dominant and requires significant heating of the solvent/steam mixture at Date Recue/Date Received 2020-04-27 surface to vaporize the solvent and heat to a desired temperature, given that the amount of steam in the injected fluids is very limited and steam can deliver much more latent heat than light hydrocarbon (solvent).

[0010] There is great interest in the industry for in situ heavy hydrocarbon recovery processes that are efficient and effective, that improve the economics of recovery, that are more responsible environmentally and that provide oil production rates equivalent to those for conventional SAGD.
SUMMARY

[0011] Embodiments taught herein balance the dilution effect of solvent and the heating effect of steam, and operate at a fixed rate of steam injection that is significantly lower than the rate used in conventional SAGD ("conventional" meaning SAGD
performed with steam injection only). The amount of solvent added is varied over time to maintain a desired target operating pressure in the reservoir. Generally the amount of solvent injected is increased over time to maintain the desired target operating pressure. The target operating pressure is determined by cap rock integrity, presence and pressure of thief zones such as gas cap or lean zone or bottom water, and SAGD
performance optimization. The target operating pressure may be maintained constant over time, or it may change over time

[0012] Embodiments taught herein enable a significant reduction in steam injection volumes as compared to conventional SAGD steam injection volumes, while maintaining oil production rates similar to that of conventional SAGD. A
reduction in the steam-to-oil ratio (SOR) of about 40% to about 60% can be achieved.

[0013] As the amount of steam injected is significantly lower than that injected in conventional SAGD, and because solvent vapor is present, the steam chamber temperature of the operation is much lower than that of a conventional SAGD
operation.
Operation at this lower temperature results in lower heat losses, as about one third of injected energy is lost to overburden in a conventional SAGD operation. At this lower temperature, the process benefits more effectively from solvent dissolved into the heavy Date Recue/Date Received 2020-04-27 hydrocarbons. Further, this lower temperature is lower than aquathermolysis reaction threshold temperature (-200 C), therefore the amount of hydrogen sulfide (H2S) generated is significantly reduced compared to that generated by higher temperature conventional SAGD processes. Greenhouse gas (GHG) emission intensity, such as CO2 produced during steam generation, and the volume of water required are reduced as the need to generate steam is reduced.

[0014] In embodiments, as seen in Fig. 1, a process of in situ production of heavy hydrocarbons comprises: injecting steam into an upper horizontal injection wellbore and into a lower horizontal production wellbore in a reservoir for heating the reservoir thereabout and, when fluid communication between the injection and production wellbores is established; ceasing injection of steam into the production wellbore;
injecting steam into the injection wellbore and producing fluids from production wellbore until the steam injection rate is about 40-60% of a predicted peak steam rate for conventional SAGD, after which solvent co-injection starts; and co-injecting a solvent with the steam into the injection wellbore and gradually increasing the rate of co-injection of the solvent with the steam to maintain a target operating pressure in the reservoir, wherein the solvent is selected to have a boiling temperature in the range of about 80 C to about 170 C, preferably about 100 C to about 150 C, at the target operating pressure, for heavy hydrocarbon recovery. The rate of co-injection of the .. solvent is continually adjusted thereafter to maintain the target operating pressure in the reservoir.

[0015] In one aspect, described herein is a method for producing heavy hydrocarbon in situ from a reservoir comprising:
a) injecting steam into an upper and a lower horizontal production wellbore in the reservoir at a pressure that is greater than or equal to reservoir pressure, until fluid communication between the injection wellbore and production wellbore is established;

Date Recue/Date Received 2020-04-27 b) after fluid communication is established, ceasing injection of steam into the production wellbore, and injecting steam only into the injection wellbore, c) increasing the rate of steam injection into the injection wellbore until:
i) peak oil production is reached and an actual peak SAGD steam injection rate is determined, and thereafter reducing the steam injection rate to a selected reduced rate that is below the actual peak SAGD steam injection rate, or ii) the steam injection rate reaches a selected reduced rate that is below an estimated peak SAGD steam injection rate;
d) thereafter, injecting steam at the selected reduced rate, and co-injecting a solvent with the steam, wherein the rate of solvent injection is gradually increased over time to maintain a target reservoir operating pressure, and e) recovering heavy hydrocarbons and solvent from the production well.

[0016] In another aspect, descried herein is a method for producing heavy hydrocarbon in situ from a reservoir comprising:
a) injecting steam into an upper and a lower horizontal production wellbore in the reservoir at a pressure that is greater than or equal to reservoir pressure, until fluid communication between the injection wellbore and production wellbore is established;
b) after fluid communication is established, ceasing the injection of steam into the production wellbore, and injecting steam only into the injection wellbore, c) increasing the rate of steam injection into the injection wellbore until the steam injection rate reaches a selected reduced rate that is below an estimated peak SAGD steam injection rate;

Date Recue/Date Received 2020-04-27 d) thereafter, continuing to inject steam at the selected reduced rate of steam injection, and co-injecting a solvent with the steam, wherein the rate of solvent injection is selected to maintain a target reservoir operating pressure;
e) gradually increasing the rate of solvent injection over time, to maintain the target reservoir operating pressure at the selected reduced rate of steam injection; and f) recovering heavy hydrocarbons and solvent from the production well.

[0017] In another aspect, described herein is a method for producing heavy hydrocarbon in situ from a reservoir comprising:
a) injecting steam into an upper and a lower horizontal production wellbore in the reservoir at a pressure that is greater than or equal to reservoir pressure, until fluid communication between the injection wellbore and production wellbore is established;
b) after fluid communication is established, ceasing the injection of steam into the production wellbore and injecting steam only into the injection wellbore;
c) increasing the rate of steam injection into the injection wellbore until peak oil production is reached and an actual peak SAGD steam injection rate is determined, d) thereafter reducing the steam injection rate to a selected reduced rate that is below the actual peak SAGD steam injection rate at peak oil production, and co-injecting a solvent with the steam, wherein the rate of solvent injection is selected to maintain the target reservoir operating pressure;
e) gradually increasing the rate of solvent injection over time, to maintain the target reservoir operating pressure at the selected reduced rate of steam injection; and Date Recue/Date Received 2020-04-27 f) recovering heavy hydrocarbons and solvent from the production well.

[0018] In embodiments of the methods the selected reduced rate of steam injection is a rate between about 40% and about 60% of the actual or estimated peak SAGD steam injection rate for a conventional SAGD process.

[0019] In embodiments of the methods, the reservoir is a bitumen reservoir or heavy oil reservoir, and the temperature of the fluids produced at the production well is significantly lower than steam saturation temperature at the target reservoir operating pressure. In embodiments the temperature of the fluids is about 50 C to about lower than steam saturation temperature at the target reservoir operating pressure .

[0020] In embodiments of the methods the solvent has a boiling temperature in the range of about 80 C to about 170 C at the target reservoir operating pressure. In embodiments the solvent has a boiling temperature in the range of between about 100 C to about 150 C at the target reservoir operating pressure.

[0021] In embodiments of the methods, the solvent is a C3, C4 or C5 hydrocarbon or mixtures thereof, or a solvent mixture comprising more than 70%
liquid volume C3 - C5 hydrocarbon.

[0022] In embodiments of the methods the target reservoir operating pressure is between about 500 kPa and about 1,000 kPa, and the solvent is pentane or butane or mixtures thereof.

[0023] In embodiments of the methods the target reservoir operating pressure is between about 1,000 kPa and about 4,000 kPa, and the solvent is butane.

[0024] In embodiments of the methods the target reservoir operating pressure is greater than about 4,000 kPa and the solvent is butane or propane or mixtures thereof.

[0025] In embodiments of the methods, the liquid volume ratio of solvent:steam is between about 1:1.5 and about 1.5:1.

Date Recue/Date Received 2020-04-27 BRIEF DESCRIPTION OF THE DRAWINGS

[0026] Figure 1 is a graphical representation of a steam-solvent process according to an embodiment taught herein at a pressure of 2500 kPa and a reduced steam rate of 190 m3/d.

[0027] Figure 2 is a graph illustrating the correlation between typical bitumen viscosities and temperature at 2700 kPa pressure; as temperature increases, bitumen viscosity decreases. When bitumen is saturated with lighter hydrocarbon (C3-05), solvent dilution effects further reduce viscosity, but the effect is more profound at lower temperature. For example, a typical bitumen saturated with butane at 2700 KPa has a viscosity of less than 1 cP at a temperature of about 130 C.

[0028] Figure 3 is a graph illustrating the relationship between pressure and boiling point temperature of water and a variety of solvents ranging from propane (C3) to heptane (C7). Solvent is selected according to embodiments taught herein such that the boiling temperature of the solvent falls between about 80 C to about 170 C, preferably between about 100 C to about 150 C, at target operating pressure.
Butane is a preferred solvent as it has the desired boiling temperature at most typical SAGD
target operating pressures (about 1500 ¨ about 3500 kPa). Solvent selection may also consider other factors such as asphaltene deposition, solvent price, and market supply.

[0029] Figure 4 is a graph illustrating the relationship between temperature, pressure and the solubility of butane in Athabasca Bitumen. At any one pressure, butane solubility in heavy hydrocarbons increases as temperature is lowered.

[0030] Figure 5 is a graph illustrating the relationship between selected reduced steam rates of the steam-solvent process taught herein and the cumulative steam to oil ratio achieved at these rates. These are simulation results and include results for conventional SAGD for comparison.

[0031] Figure 6 is a graph of simulation results illustrating the relationship between selected reduced steam rates of the steam-solvent process taught herein and cumulative oil production. According to an embodiment taught herein, the optimum Date Recue/Date Received 2020-04-27 reduced steam rate is about 55% of the predicted conventional SAGD peak steam rate at this operating pressure (2,500 kPa) and simulated reservoir conditions.

[0032] Figure 7 is a graph illustrating simulation results of the relationship between selected reduced steam rates and the solvent co-injection rate (butane in this case) that is required to maintain target operating pressure over time.
DETAILED DESCRIPTION

[0033] In conventional solvent-aided SAGD processes, such as that taught in Canadian Patent 2323029, a relatively small volume of solvent (usually less than 20%
of steam volume) is co-injected with steam and the ratio of solvent to steam is maintained at a constant ratio throughout the process.

[0034] Heavy hydrocarbon reservoirs contain highly-viscous "heavy hydrocarbons" which as used herein means heavy oil (API density less than 20 degree API but greater than 10 API) and bitumen (also called extra heavy oil, API
density less than 10 degree API) having a viscosity higher than 30,000 cP, optionally higher than 80,000 cP, and optionally higher than 100,000 cP, under initial reservoir conditions. The heavy hydrocarbons are unable to flow to production wells under initial reservoir conditions (typically a virgin reservoir temperature at about 5-20 C).

[0035] In embodiments taught herein, a conventional SAGD well pair arrangement may be utilized, that is, an injection wellbore and a production wellbore are drilled into and extend substantially horizontally in a reservoir. The well pair is typically positioned near the bottom of the pay zone. The injection (or "injector") wellbore may be vertically spaced from the production (or "producer") wellbore, such as for example by a distance of 5 m. This distance may vary and may be selected to optimize the performance of the operation. The wellbores may be configured and completed in any suitable manner know to those skilled in the art, provided that they are compatible with the method described herein.

[0036] The method begins with a conventional "warm-up" (or "start-up") phase, in which steam is injected into both the injection wellbore and the production wellbore of a Date Recue/Date Received 2020-04-27 SAGD wellbore pair, at a pressure normally equal to or greater than formation pressure, in order to establish fluid communication between the wellbores. "Steam" as used herein means water vapour or a combination of liquid water and water vapour.
"Injection" as used herein when referring to the start-up phase includes direct injection, circulation start up, and any other means of delivering steam to the formation in order to establish fluid communication between an injection and production wellbore.

[0037] The warm-up phase is considered to be complete when fluid communication is established between the injection wellbore and the production wellbore. "Fluid communication" as used herein means that the mobility of heavy hydrocarbon between injection wellbore and production wellbore is sufficiently high such that this fluid and the majority of fluid injected into the injection wellbore can be produced at the production wellbore under a predetermined operating pressure.

[0038] A "ramp-up" phase may follow the warm-up phase. During the ramp-up phase the steam chamber grows laterally and vertically. During the ramp-up phase, steam is injected only into the injection wellbore and the steam injection rate is increased gradually or step-wise over time, to maintain a desired target operating pressure. A "gradual" increase, as used herein, means that the steam (or solvent) injection rate is increased at a substantially constant rate, or is adjusted in a series of discrete amounts over sufficiently small time intervals relative to the total injection time, so as to avoid appearance of any specifically identifiable step-wise like change.

[0039] "Peak oil production rate", as used herein, means that the rate of oil production using a "conventional" SAGD process (that is, steam only) has reached its maximum rate. In embodiments, this means that steam chamber vertical growth has reached its limit. The ramp-up phase is then complete and SAGD process enters into a "plateau" phase. At plateau phase, the steam chamber has reached its pay top and grows more laterally. At this stage, the oil production rate is relatively flat or slightly decreases over time and the steam injection rate is also plateaued or slightly increases over time, as shown in Figure 1 (SAGD Bitumen and Conventional SAGD Peak Steam curves). "Peak SAGD steam injection rate" as used herein, means the maximum steam Date Recue/Date Received 2020-04-27 injection rate used in a conventional SAGD operation, and may or may not coincide with peak oil production rate.

[0040] In an embodiment, during the ramp-up phase the steam injection rate is increased gradually or in a step-wise manner until peak oil production is reached. After peak oil production is achieved, and the peak SAGD steam injection rate is determined, the rate of steam injection into the injection wellbore is lowered to a selected "reduced"
rate. The steam injection rate is thereafter maintained at the selected reduced rate until wind down of production.

[0041] In another embodiment, during the ramp-up phase, the steam injection rate is increased gradually or in a step-wise manner, however it is not increased to peak SAGD rate. In this embodiment, during the ramp-up phase the steam injection rate is gradually increased until it reaches the selected "reduced" rate based on an estimated peak SAGD injection rate. The steam injection rate is thereafter maintained at the selected reduced rate until wind down of production.

[0042] Estimation of peak oil production rate and peak SAGD steam injection rate may be accomplished, for example, by Computer Modelling Group (CMG) STARS
Software, which simulates production by numerical modelling, or by using an analytical ,6sKga model such as Butler and Stephens (1981) LINDRAIN equation (q=,\11.300 (H-Z) mv Alternatively, peak oil production rate and peak SAGD steam injection rate may be estimated by comparison to an analogous well pair in the same or similar reservoir that is produced using conventional SAGD process.

[0043] The selected reduced steam injection rate may be between about 20%
and about 80%, between about 30% and about 70%, or may be about 20%, 30%, 40%, 50%, 60%, 70% or 80% of the peak SAGD steam injection rate as determined or estimated. In preferred embodiments the selected reduced steam injection rate is between about 40% and about 60%, of the peak SAGD steam injection rate, as determined or estimated. The reduced steam injection rate maintains the temperature of the reservoir within the desired range, as described below.

Date Recue/Date Received 2020-04-27

[0044] As used herein, "about" means +1- 10% of the value referenced.

[0045] Fig. 1, shows an embodiment wherein, following a conventional initial warm-up phase, steam is injected into the injection wellbore during the ramp-up phase, until it reaches a selected reduced injection rate that is between about 40%
to about 60% of an expected peak SAGD steam injection rate for the reservoir. The steam injection rate is maintained at this selected reduced rate until wind-down of the operation. Heavy hydrocarbons may begin to mobilize and be produced during growth of a steam chamber prior to the introduction of the solvent thereto.

[0046] Co-injection of solvent begins when the steam injection rate is at the selected reduced rate. As the steam injection rate is lower than it would be in a conventional SAGD operation while oil production rate is the same or better, pressure in the reservoir is maintained by solvent addition. When solvent is mixed with steam, solvent is vaporized by the steam, and as steam and solvent vapor encounter colder heavy hydrocarbons, steam starts to condense and heat the heavy hydrocarbons to a higher temperature and reduce their viscosity, and solvent also starts to condense and mix with heavy hydrocarbons to further reduce their viscosity. By selecting the solvent, the desired operating temperature and the designed selected reduced steam rate, one can keep oil production at a rate that would be higher or at least similar to a conventional SAGD operation.

[0047] "Solvent" as used herein includes C3 to C5 hydrocarbons, and mixtures thereof. For example, solvent means propane, butane and pentane and mixtures thereof. In embodiments the solvent is a mixture of C3 to C5 hydrocarbons and other hydrocarbons, in which the majority (>70% by liquid volume) is C3 to C5 hydrocarbon.

[0048] In embodiments, during the ramp-up phase, when the steam injection rate reaches the selected reduced injection rate, based on an estimated peak SAGD
steam injection rate, co-injection of solvent begins. The steam chamber, now known as a vapor chamber, comprises both steam and solvent vapour. The solvent injection rate increases gradually or stepwise over time to maintain a target operating pressure in the reservoir. The target operating pressure during solvent co-injection is substantially the Date Recue/Date Received 2020-04-27 same as the operating pressure that would be used in conventional SAGD
operations for the same reservoir. As the vapor chamber continues to grow and oil production proceeds, the solvent injection rate is increased or otherwise adjusted as necessary to maintain the target operating pressure and peak oil production rate.
Eventually, a plateau stage of solvent injection rate is reached, after which solvent injection rates may require only minor adjustments so as to maintain the target operating pressure.
Sustained maximum production occurs during this period and can last up to several years depending upon the reservoir quality, thickness and spacing between adjacent well pairs, if any.

[0049] In the embodiment shown in Fig. 1, when the steam injection rate reaches a selected rate that is between about 40% to about 60% of the estimated peak steam injection rate, co-injection of solvent begins and gradually increases thereafter. The solvent injection rate increases over time to maintain a target operating pressure in the reservoir and the desired oil production rate. After a plateau stage of solvent injection rate is reached, solvent injection rates may require only minor adjustments so as to maintain the target operating pressure and oil production rates.

[0050] In other embodiments, the ramp-up phase continues until peak oil production is achieved. The steam injection rate is then reduced either gradually or step wise, to the selected reduced injection rate. Co-injection of solvent begins and the solvent injection rate increases gradually or stepwise over time to maintain a target operating pressure in the reservoir.

[0051] Without being bound by theory, Applicant believes, in embodiments taught herein, that the injected solvent plays a significant if not equivalent role to steam in reducing heavy hydrocarbon viscosity. The operational strategy, utilizing the constant, reduced steam injection rate, compared to prior art methods including conventional SAGD, and an increasing amount of solvent injected over time to maintain a target operating pressure, achieves reduction in heavy hydrocarbon viscosity by both steam heating and solvent dilution, each providing a substantially equal contribution. As will be appreciated, increasing the solvent-to-steam ratio generally lowers the temperature in Date Recue/Date Received 2020-04-27 the vapor chamber to a range where solvent dilution is more effective in reducing the viscosity of the heavy hydrocarbons, compared to steam dominant, or solvent-aided SAGD processes.

[0052] As can be seen in Figure 2, the ability of a solvent to lower the viscosity of bitumen can be greater at a lower temperature than at a higher temperature. As this Figure shows, the effect of butane dilution on bitumen viscosity is much greater when the temperature is 130 C than when it is 230 C. At a temperature of 130 C, butane dilution can lower the viscosity of bitumen from about 60 cP to below 1 cP, whereas at a temperature of 230 C the butane dilution lowers the viscosity of bitumen only from about 6 cP to about 3 cP. It is believed that this results from solubility of solvent as shown in Figure 4. At the same pressure, the solubility of solvent in bitumen is higher at lower temperature as compared to a higher temperature.

[0053] Having reference to Figs. 2 and 3, the relationships between pressure, temperature and viscosity are used to assist in selecting a suitable solvent for use in embodiments taught herein. Fig 2, which illustrates the correlation between typical viscosities of bitumen, or bitumen saturated with solvent, and temperature, is used to help in solvent selection. By way of example, at 2700 kPa pressure, C3 reduces heavy hydrocarbons viscosity from about 500 cP to about 10 cP at a temperature of 90 C, C4 reduces heavy hydrocarbons viscosity from about 60 cP to about 1 cP at a temperature of 130 C, and C5 reduces heavy hydrocarbons viscosity from about 10 cP to about 1 cP
at a temperature of 190 C. Butane is a preferred solvent as it is more effective at reducing viscosity compared to C3 at this operating pressure. Even though C5 reduces viscosity to similar level compared to C4, this occurs at a much higher temperature and the solvent dilution effect is not as profound, since the heat alone already reduced heavy hydrocarbon viscosity to about 10 cP. Other reasons not to prefer C5 include that it is a more expensive solvent and heat loss is higher due to higher operating temperature ranges.

[0054] Alternatively, Fig 3 can be used for quick solvent selection.
A solvent with a boiling point temperature range of between about 80 C to about 170 C, preferably Date Recue/Date Received 2020-04-27 between about 100 C and about 150 C, is generally suitable for solvent enhanced SAGD process described herein. For a typical operating pressure range from 1500 KPa to 3500 KPa, once again, butane is preferred solvent. At a lower operating pressure, such as 1000 kPa, pentane may be used to drive the temperature of the vapor chamber higher. At a higher operating pressure, such as above 4000 KPa, propane may be used to lower the vapor chamber temperature.

[0055] The flow rate of the co-injected solvent is selected to maintain the reservoir pressure at the target operating pressure, and as a result, the rate of solvent co-injection may increase over time (could be a period of a few months) and eventually plateaus. During this period, as the steam injection rate is fixed, the temperature of the injected mixture of steam and solvent would slightly decrease, as solvent injection rate increases. That temperature can be calculated based on steam rate, pressure, and solvent rate. The production well gross liquid rate may be controlled to avoid excessive live steam production. During this period, the temperature of production well should continuously decrease as solvent starts to produce back from production wellbore.
Once the rate of produced solvent from the production wellbore plateaus, the production wellbore temperature may be relatively stable, and that temperature may be in a range that allows production of a small amount of live steam (such as about 1 to 5 m3/d of cold water equivalent steam). The production fluid temperature is measured by downhole instrumentation.

[0056] In the methods described herein, about 40-60% less steam is used as compared to the amount of steam that would be used in a conventional SAGD
operation, to produce at peak oil production rate. Thus the steam-to-oil ratio (SOR) and cumulative steam-to-oil ratio (CSOR) are reduced by about 40-60% and yet peak oil production rate (as compared to conventional SAGD) is maintained.

[0057] In embodiments, the temperature of the fluids produced at the production well is significantly less (about 50 to 120 C lower) than steam saturation temperature at the reservoir operating pressure.
Date Recue/Date Received 2020-04-27

[0058] In preferred embodiments, liquid solvent may be injected into the steam line close to the wellhead, within the said range of solvent steam ratio, and the solvent will be vaporized after mixing with the steam at the cost of a small amount of steam being condensed into water. Alternately, solvent may be vapourized through heating before it is mixed with the steam and co-injected either before the wellhead or downhole.

[0059] Further, in embodiments, a non-condensable gas (NCG), such as natural gas, is injected into the injection wellbore to drive residual solvent remaining in the reservoir to the production wellbore, where it can be recovered at surface.
EXAMPLES
The following are representative examples of embodiments of the method, using butane as the solvent.
Example 1 Operating Pressure 2500 KPa

[0060] Having reference again to Fig. 1, and by way of example, a simulation according to an embodiment taught herein was performed for a bitumen reservoir having a target operating pressure of about 2500 kPa. According to Figs. 2 and 3, butane (C4) was selected as the solvent to be used at the target operating pressure. A
conventional SAGD wellbore pair as described herein was used for the simulation.

[0061] In the initial warm-up phase, steam was circulated in both the injection and production wellbores for about 2 to 4 months to substantially heat the reservoir between horizontal sections of the injection and production wellbores. Alternatively, in cases of high injectivity, direct injection of steam to the reservoir without return may be considered for heating the reservoir. In this case, steam is bullheaded into either the injector or producer wellbore, or both.

[0062] At such time as bitumen was mobilized and fluid communication was established between the injection and production wellbores, as described above, the process was converted from the warm-up phase to a ramp-up phase according to an Date Recue/Date Received 2020-04-27 embodiment taught herein. In the ramp-up phase, steam alone was injected solely to the injection wellbore, as in conventional SAGD.

[0063] The ramp-up phase ranged from a few months to more than one year for conventional SAGD to reach peak oil production, and its length depends on reservoir quality and thickness. As in this example, reservoir simulator CMG STARS was used to predict conventional SAGD steam injection rate and oil production rate under a constant operating pressure of 2500 kPa. The predicted conventional SAGD steam injection rate at peak oil production is about 300 m3/d, and increases slightly over time during the plateau phase to maximum of about 350 m3/d. Butane was selected as the solvent according to embodiments taught herein. Again the reservoir simulator CMG
STARS
was used to simulate the solvent co-injection process that significantly reduces the SAGD process steam to oil ratio. As shown in this example, the reduced steam injection rate was set to 190 m3/d and butane co-injection was started essentially at the beginning of the ramp up phase to maintain a target 2500 kPa operating pressure. This steam injection rate is about 54% of conventional SAGD peak steam injection rate (350 m3/d). This reduced steam injection rate (190 m3/d) is maintained until wind down. The ramp-up phase resulted in growth of the steam chamber and increasing production of bitumen at the production well. The butane co-injection rate increases over time to maintain the operating pressure according to an embodiment taught herein.

[0064] At this time, butane co-injection with the steam was begun to maintain the operating pressure of about 2500 kPa. The steam/vapor chamber continued to grow.
The butane injection rate reached a peak injection rate in the range from about 1:1.5 to about 1.5:1 liquid volume ratio (butane:water). This is equivalent to about 40% (liquid volume) to about 60% (liquid volume) butane in injected fluids mixture. At this ratio and at a pressure of 2500 kPa, no additional heat is required, as the steam is sufficient to vaporize the butane. In other embodiments, the solvent can be preheated to reduce steam condensation, thereby improving steam quality to further optimize the process.

[0065] At any time after the conversion from the warm-up phase to SAGD, butane co-injection may be initiated. In the example shown in Fig. 1, butane injection Date Recue/Date Received 2020-04-27 was initiated after about 1 month of steam injection and was gradually increased thereafter. The gradual increase in the rate of butane injection caused the temperature to gradually decrease from that of steam alone to reach a target temperature of about 80 C to about 170 C, preferably about 100 C to about 150 C at the vapor chamber front (drainage front). The butane injection rate was continually increased to maintain the reservoir pressure at the target pressure, being about 2500 kPa, and was adjusted thereafter as necessary to continue to maintain the target pressure.

[0066] At the end of the operation, injection of steam and butane is stopped and natural gas may be injected into the injection wellbore to continue production to maximize bitumen and solvent recovery.
Example2 Select Reduced Steam Rate

[0067] To determine the reduced steam injection rate for solvent enhanced SAGD process, a reservoir simulator such as CMG STARS can be used. Fig 5 shows that the lower the reduced steam injection rate, the lower the cumulative steam oil ratio.
However, as can be seen in this figure, the effect that a reduction in steam rate has on cumulative steam oil ratio decreases as the steam rate is lowered. Thus, the magnitude of the reduction in steam oil ratio is lower at the lower reduced steam rates.
.

[0068] To evaluate the optimum reduced steam rate, oil production rate or cumulative oil production rate are examined. Fig 6 shows that at a reduced steam rate of 55% of conventional SAGD peak steam rate, 5 year cumulative oil production increases as compared to conventional SAGD, likely due to an enhanced solvent dilution effect combined with sufficient heat energy from the steam that is used. Further, a lower reduced steam rate results in less cumulative oil production, likely due to the fact that insufficient heat energy is provided for oil viscosity reduction.
For this example, the optimum reduced steam rate is about 55% of conventional SAGD peak steam rate, which balances the effects of heat (steam) and solvent dilution on heavy hydrocarbon viscosity reduction.

Date Recue/Date Received 2020-04-27

[0069] Fig 7 shows that at lower steam injection rates, higher solvent co-injection rates are needed to maintain target operating pressure. Economic evaluation maybe used to determine the optimum reduced steam rate and solvent rate, to achieve the best economic benefit for a given situation and environment.

[0070] This reduced steam rate that is selected may vary slightly according to reservoir operating pressure. At a lower operating pressure such as 1500 kPa, the selected reduced steam rate for solvent enhanced SAGD process taught herein may be about 40% of conventional SAGD peak steam rate. At a higher operating pressure such as 3500 kPa, the selected reduced steam rate may be about 60% of conventional SAGD peak steam rate.

[0071] 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 disclosure 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.

Date Recue/Date Received 2020-04-27

Claims (15)

1. A method for producing heavy hydrocarbon in situ from a reservoir comprising:
a) injecting steam into an upper and a lower horizontal production wellbore in the reservoir at a pressure that is greater than or equal to reservoir pressure, until fluid communication between the injection wellbore and production wellbore is established;
b) after fluid communication is established, ceasing injection of steam into the production wellbore, and injecting steam only into the injection wellbore, c) increasing the rate of steam injection into the injection wellbore until:
iii) peak oil production is reached and an actual peak SAGD steam injection rate is determined, and thereafter reducing the steam injection rate to a selected reduced rate that is below the actual peak SAGD steam injection rate, or iv) the steam injection rate reaches a selected reduced rate that is below an estimated peak SAGD steam injection rate;
d) thereafter, injecting steam at the selected reduced rate, and co-injecting a solvent with the steam, wherein the rate of solvent injection is gradually increased over time to maintain a target reservoir operating pressure, and e) recovering heavy hydrocarbons and solvent from the production well.

2. A method for producing heavy hydrocarbon in situ from a reservoir comprising:
a) injecting steam into an upper and a lower horizontal production wellbore in the reservoir at a pressure that is greater than or equal to reservoir pressure, until fluid communication between the injection wellbore and production wellbore is established;

b) after fluid communication is established, ceasing the injection of steam into the production wellbore, and injecting steam only into the injection wellbore, c) increasing the rate of steam injection into the injection wellbore until the steam injection rate reaches a selected reduced rate that is below an estimated peak SAGD steam injection rate;
d) thereafter, continuing to inject steam at the selected reduced rate of steam injection, and co-injecting a solvent with the steam, wherein the rate of solvent injection is selected to maintain a target reservoir operating pressure;
e) gradually increasing the rate of solvent injection over time, to maintain the target reservoir operating pressure at the selected reduced rate of steam injection; and f) recovering heavy hydrocarbons and solvent from the production well.

3. A method for producing heavy hydrocarbon in situ from a reservoir comprising:
a) injecting steam into an upper and a lower horizontal production wellbore in the reservoir at a pressure that is greater than or equal to reservoir pressure, until fluid communication between the injection wellbore and production wellbore is established;
b) after fluid communication is established, ceasing the injection of steam into the production wellbore and injecting steam only into the injection wellbore;
c) increasing the rate of steam injection into the injection wellbore until peak oil production is reached and an actual peak SAGD steam injection rate is determined, d) thereafter reducing the steam injection rate to a selected reduced rate that is below the actual peak SAGD steam injection rate at peak oil production, and co-injecting a solvent with the steam, wherein the rate of solvent injection is selected to maintain the target reservoir operating pressure;
e) gradually increasing the rate of solvent injection over time, to maintain the target reservoir operating pressure at the selected reduced rate of steam injection; and f) recovering heavy hydrocarbons and solvent from the production well.

4. The method of Claim 1, 2 or 3, wherein the selected reduced rate of steam injection is a rate between about 40% and about 60% of the actual or estimated peak SAGD steam injection rate for a conventional SAGD process.

5. The method of any one of Claims 1 to 4, wherein the reservoir is a bitumen reservoir or heavy oil reservoir, and the temperature of the fluids produced at the production well is significantly lower than steam saturation temperature at the target reservoir operating pressure.

6. The method of claim 5 wherein the temperature of the fluids is about 50°C to about 120°C lower than steam saturation temperature at the target reservoir operating pressure .

7. The method of Claim 5 or 6, wherein the solvent has a boiling temperature in the range of about 80°C to about 170°C at the target reservoir operating pressure.

8. The method of Claim 7 wherein the solvent has a boiling temperature in the range of between about 100°C to about 150°C at the target reservoir operating pressure.

9. The method of any one of Claims 1 to 8, wherein the solvent is a C3, C4 or C5 hydrocarbon or mixtures thereof, or a mixture comprising more than 70% liquid volume C3 - C5 hydrocarbon .

10. The method of any one of Claims 1 to 9, wherein the target reservoir operating pressure is between about 1,000 kPa and about 4,000 kPa,

11. The method of any one of Claim s 1 to 10, wherein the liquid volume ratio of solvent:steam is between about 1:1.5 and about 1.5:1.

12. The method of any one of Claims 1 to 11, wherein the target reservoir operating pressure is between about 500 kPa and about 1,000 kPa, and the solvent is pentane or butane or mixtures thereof.

13. The method of any one of Claims 1 to 11, wherein the target reservoir operating pressure is between about 1,000 kPa and about 4,000 kPa, and the solvent is butane.

14. The method of any one of Claims 1 to 11, wherein the target reservoir operating pressure is greater than about 4,000 kPa and the solvent is butane or propane or mixtures thereof.

15. The method of Claim 12, 13 or 14, wherein the liquid volume ratio of solvent:steam is between about 1:1.5 and about 1.5:1.