Multicomponent Solvent Co-injection with Steam in Heavy and Extra

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Multicomponent Solvent Co-injection with Steam in Heavy and Extra-Heavy Oil Reservoirs Mohammed Taha Al-Murayri, Brij B. Maini, Thomas Grant Harding, and Javad Paytakhti Oskouei Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.5b02774 • Publication Date (Web): 03 Mar 2016 Downloaded from http://pubs.acs.org on March 4, 2016

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Multicomponent Solvent Co-Injection with Steam in Heavy and Extra-Heavy Oil Reservoirs MOHAMMED T. AL-MURAYRI, BRIJ B. MAINI, THOMAS G. HARDING AND JAVAD OSKOUEI will be mainly in the liquid phase and will not be able to travel effectively to the vapor chamber boundary but rather will have a tendency to drain downward and be directly produced. The solvent vapor does not condense into a separate liquid until the partial pressure of solvent in the vapor becomes higher than the dew-point pressure but it dissolves and diffuses into the oil. As the diluted oil drains, a new interface with relatively lower solvent concentration emerges. The recurring drainage of the emerging bitumen interfaces can be visualized as the peeling of onion layers. This interface renewal is accelerated by reduction of both interfacial tension and oil viscosity due to solvent dissolution into the oil phase. Zhao et al (2005) propose a steam alternating solvent injection process designed to increase interfacial area for heat and mass transfer at the boundary between the steam chamber and the high bitumen saturated, undepleted reservoir. Yang and Gu (2005) studied the interfacial tension between a Lloydminster heavy oil sample and methane, ethane, propane and carbon dioxide. They found that “interfacial tension between the heavy oil and a solvent is reduced almost linearly with pressure for the four oil-solvent systems tested” at reservoir temperature. They also state that “reduced interfacial tension alters the gravity-capillary force balance and thus reduces the residual oil saturation”. Sharma and Gates (2011) have demonstrated mathematically that steam/solvent co-injection increases instability at the interface between the vapor chamber and the bitumen at the edge of the chamber compared to steam-only injection. This greater instability has the effect of promoting mixing at the edge of the chamber which results in the observed higher rates of oil mobilization and production from solvent co-injection with steam. The mathematical model of Sharma and Gates (2011) includes the effect of solvent on the interfacial tension of the solvent-oil mixture. Moreover, the solvent dissolution can potentially reduce the residual oil saturation (Jha et al., 2013; Hosseininejad et al. 2012; Yazdani et al., 2011; Nasr & Ayodele 2006).

Summary Expanding Solvent Steam Assisted Gravity Drainage (ES-SAGD) is a hybrid steam-solvent oil recovery process that can be used to extract oil from heavy oil and bitumen reservoirs. It is a variation of the SAGD process in which only steam is used. In ES-SAGD, the mobilization of highly viscous oil is enhanced through a combination of heat and mass transfer processes, which results in significantly reduced volumes of water and natural gas needed to generate the injected steam, making ES-SAGD more energy efficient and environmentally sustainable relative to SAGD. Both SAGD and ES-SAGD use the same well configuration and solvent coinjection in existing SAGD projects often requires limited facility modifications. This study investigates different aspects of ES-SAGD experimentally, based on typical Long Lake reservoir properties and operating conditions, using different concentrations of gas condensate. Furthermore, this study provides phase behaviour insights to govern the selection of appropriate solvents for use in ES-SAGD. The performance of the gas condensate ES-SAGD cases in this study exceeded that of the baseline SAGD case in terms of oil production rates, energy efficiency and post-production water handling. These findings were instrumental in the design and implementation of a field pilot project by Nexen Energy ULC in the Athabasca Oil Sands that began in September 2014s.

Introduction With careful consideration of solvent type and concentration, the co-injection of solvent and steam in ESSAGD increases the mobility of highly viscous oil or bitumen relative to conventional SAGD wherein only steam is injected. This consequently results in higher oil production rates and lower energy consumption relative to SAGD due to the combined benefits of heating and dilution. The solvent-steam mixture should ideally stay vaporized before condensing at or near the boundary of the vapour chamber. Upon condensation, steam releases its latent heat of vaporization and the steam condensate drains downward. Similarly, the solvent vapour condenses near the vapour chamber boundary which facilitates the dilution of the oil surrounding the vapour chamber with the co-injected solvent. The solvent should be one that will travel with steam in the vapor phase to the vapor chamber boundary where both steam condensation and solvent dissolution in bitumen can be effective for mobilizing bitumen. If the solvent is too heavy and/or is in too high a concentration, the solvent

This study experimentally compares the performance of ES-SAGD relative to SAGD, based on typical Long Lake reservoir properties and operating conditions, at different concentrations of gas condensate ranging from 5 to 15 percent by volume of the total steam and solvent volume on a cold liquid equivalent basis. A series of high pressure/temperature experiments were conducted using a partially-scaled and highly instrumented sand-pack model to accurately measure pressure, temperature and fluid flow rates. Upon completion of each experiment, extensive produced fluid and porous media analyses were carried out to evaluate different aspects of SAGD performance with and without solvent co-injection including chamber growth, oil and water production, steam-to-oil ratio,

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residual oil and water saturations, asphaltene precipitation, produced oil viscosity and density as well as solvent recovery.

cut-off techniques. Also, mixtures such as gas condensate are generally more readily available and tend to be less expensive than pure solvents that are suitable for use under certain operating conditions.

Solvent Selection

Experimental Model and Analysis

Ideally, the co-injected solvent in ES-SAGD should remain in the vapour phase before condensing at or near the boundary of the vapour chamber. If solvent condensation takes place earlier, the co-injected solvent will be short-circuited without establishing the sought after contact with highly viscous bitumen in the vicinity of the bitumen-vapour chamber interface. On the other hand, if the solvent does not condense, it will restrict heat transfer from steam to the highly viscous bitumen zone surrounding the vapour chamber. Relatively heavy solvents such as cracked naphtha, which was investigated in a previous study as a potential ES-SAGD solvent (AlMurayri, 2012), tend to be more soluble in bitumen and can potentially result in enhanced dilution if they can remain vaporized within the vapour chamber. To ensure that this is achievable, the inter-relation between pressure, temperature and solvent concentration has to be taken into consideration. The phase envelope of cracked naphtha is plotted along with a saturated steam curve in Figure 1. If steam and cracked naphtha are analyzed separately and in isolation of partial pressure effects, one may mistakenly conclude that, for example, at a pressure of 2300 kPa and a temperature of 219.59oC, cracked naphtha is expected to be in the liquid phase. However, the dew point pressure of cracked naphtha at a temperature of 219.59oC is 281.59 kPa. This means that the partial pressure of vaporized cracked naphtha needs to be higher than 281.59 kPa before it can condense. Therefore, assuming ideal behavior, the maximum amount of cracked naphtha that can be co-injected at the above-mentioned operating conditions before the two-phase region is reached can be estimated by dividing 281.59 by 2300. As a result, in this particular case, the concentration of cracked naphtha must exceed 12.2 mol% for it to condense.

A partially scaled two-dimensional sand-pack model was used to evaluate the performance of ES-SAGD relative to SAGD using typical Long Lake oil, reservoir properties and operation conditions at different concentrations of gas condensate ranging from 5 to 15 percent by volume of the total steam and solvent volume on a cold liquid equivalent basis. Fresh field-produced samples of Long Lake bitumen were acquired for the experiments by collecting produced emulsion from a point upstream of where demulsifiers and diluent were added to the production stream. Water was removed from the emulsions by rotary evaporation. A detailed description of the experimental model, procedure, scaling methodology and analysis techniques that were used in this study have been previously published (Al-Murayri 2012). This sand-pack model is made of type 316 stainless steel as shown in Figure 3 and has the following dimensions:  Width: 71 cm  Height: 22.5 cm  Depth: 15 cm The temperature propagation profiles inside the sandpack model were monitored using 240 thermocouples that were implanted during the preparation of the sand-pack model prior to the addition of sand, water and oil. After the installation of the thermocouples, the sand-pack model was filled with Ottawa sand, which was then saturated using de-ionized water and Long Lake oil until initial water and oil saturations were achieved. The experimental runs were conducted by placing the sand-pack model in the confining pressure jacket that is shown in Figure 4. This confining pressure jacket can withstand pressures up to 550 psi. To reduce heat loss from the physical model, the annulus between the confining vessel and the physical model was filled with insulating ceramic wool. Furthermore, the top and bottom sides of the model were internally insulated with ¼ inch PTFE sheet. To have uniform steam outflow into the sand-pack model, a special well design was used wherein the slot size in the injection well increased towards the toe. However, for the production well, the same slot size was used throughout the well length. Mesh screens were used on the injection and production wells to prevent sand migration into the wells.

The ES-SAGD experiments in this study were carried out using gas condensate which is more volatile than cracked naphtha. A typical composition of gas condensate is shown in Table 1. In addition, a phase envelope of gas condensate is presented in Figure 2 that was generated using the commercial fluid property software WinProp (Computer Modeling Group). The multicomponent nature of gas condensate provides enhanced operational flexibility relative to single component solvents and makes it more resilient to variations in subsurface operating conditions, particularly pressure. Furthermore, some of the limited light ends in gas condensate tend to be noncondensable under typical SAGD operating conditions and can potentially accumulated near the top and reduce heat loss to the overburden of the reservoir and zones of high water saturation without causing a significant reduction in temperature within the vapour chamber. From a logistical point of view, gas condensate is normally used to blend produced bitumen to make it suitable for pipeline transportation and the properties of gas condensate tend to be relatively consistent with that of the diluents that are used on-site for oil-water separation in SAGD operations. Another advantage that can be associated with the use of gas condensate in ES-SAGD relative to heavier multicomponent solvents, particularly in relation to Athabasca reservoirs, is the fact that gas condensate has limited compositional overlap with produced bitumen and can potentially allow for easier measurement of solvent concentration in diluted produced bitumen using proper carbon

Experimental Procedure The baseline SAGD and gas condensate ES-SAGD experiments were all conducted using high permeability (555 D) Ottawa sand, de-ionized water and Long Lake oil. The porosity, initial oil saturation and initial water saturation of the sand matrix for all the experiments were reasonably consistent as shown in Table 2. Experiment 1 was the baseline SAGD experiment and Experiments 2, 3 and 4 were the ES-SAGD experiments with a gas condensate concentration of 5, 10 and 15 volume percent in the injected steam-solvent mixture, respectively, on a cold liquid equivalent basis. De-ionized water and gas condensate were pumped using two constant-flow ISCO pumps at varying flow rates to maintain the desired solvent concentration in the injected fluid. Thereafter, deionized water and gas condensate were mixed before passing 2


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through the pre-heater and steam generator toward the heel of the SAGD injection well. Low injection rates were used initially due to limited fluid injectivity into the sand-pack model at the early stages of the experiments. As time passed, fluid injectivity improved, particularly in the 15 vol% gas condensate ES-SAGD experiment, and the sand-pack model was able to handle higher fluid injection rates without developing a high pressure difference between the injection and production wells. The coinjection of gas condensate with steam enhanced the mobilization of bitumen in the inter-well region and resulted in a better production ramp-up profile relative to the baseline SAGD experiment. Fluid injection rates were increased gradually to compensate for heat loss to the annulus and to continue supporting the growth of the steam/vapour chamber. The power settings of the pre-heater and steam generator were adjusted accordingly throughout all the experiments to ensure that steam was being injected into the sand-pack model at superheated conditions. The injection and production well pressures were recorded using pressure transducers. The pressure in the back pressure regulators for the baseline SAGD and gas condensate ES-SAGD experiments was fixed at 2100 kPa. The injection rates were maintained such that the pressure difference between the injection and production wells remained below 20 kpa. The annulus pressure was maintained above the injection pressure throughout the experiments and the difference between the two pressures was not allowed to exceed 40 psi (276 kPa) to avoid any damage to the sand-pack model.

cumulative injected steam in Figure 6 are clearly steeper for the ES-SAGD experiments relative to the baseline SAGD experiment at the initial stages of the experiments. This implies that early gas condensate co-injection with steam is extremely beneficial to accelerate the establishment of inter-well communication between the SAGD injection and production wells, thereby causing a significantly improved production ramp-up profile. The temperature profiles within the model for the baseline SAGD and gas condensate ES-SAGD experiments were compared at same volumes of cumulative produced oil to account for variations in the injectant flow rates as illustrated in Figure 7. It is evident from Figure 7 that the amount of steam required to produce the same amount of oil was much lower in all the gas condensate ES-SAGD experiments relative to the baseline SAGD experiment, even when only 5 vol% of gas condensate was used. The temperature profiles in Figure 7 show that the same amount of oil can be produced using ESSAGD with gas condensate while having lower temperatures within the sand matrix due to the combined benefits of heat and mass transfer processes. Of particular importance is the temperature at the top of the steam/vapour chamber which was much lower in all the gas condensate ES-SAGD experiments relative to the baseline SAGD experiment, thereby resulting in less heat loss from top of the sand-pack model. This implies that gas condensate co-injection with steam can extend the economic window of SAGD by allowing oil production to continue at lower steam-oil ratios, particularly when dealing with thin reservoirs and in the presence of reservoir impairments such as top water above the exploitable bitumen zone.

Results and Discussion Temperature variation along the length of the injection and production wells was closely monitored throughout the life of all the experiments using three thermocouples mounted on the heel, mid-region and toe of each well. The temperature profiles for the injection and production wells throughout the baseline SAGD and gas condensate ESSAGD experiments are presented in Figure 5. It is evident from Figure 5 that, in all the experiments, the temperature along the injection well was always higher than that along the production well due to the drainage of fluids at lower temperatures toward the production well. Having evenly distributed temperature along the SAGD injection and production wells within the reservoir results in more uniform steam/vapour chamber growth, enhanced production ramp-up and reduced operational challenges. Figure 5 also shows that temperature conformance along the production and injection wells was improved in the gas condensate ES-SAGD experiments relative to the baseline SAGD experiment.

Regarding the size of the high temperature zone within the sand matrix, as illustrated in Figure 7, it is shown that the baseline SAGD case had the largest heated volume compared to the ES-SAGD cases. Experiment 2 with 5 vol% gas condensate had the smallest high temperature zone relative to Experiments 3 and 4 wherein higher concentrations of gas condensate were used. Figure 8 shows that, for Experiment 2, the production well temperature was generally higher by 30 to 50 °C compared to those for Experiments 3 and 4 and this suggests that the smaller heated volume in experiment 2 resulted from greater heat withdrawal in the produced fluid. The steam zone shape is less uniform in the ES-SAGD cases compared to steam-only injection. The profiles of cumulative steam-to-oil ratio (cSOR) for all the gas condensate ES-SAGD experiments relative to the baseline SAGD experiment are presented in Figure 9 as a function of time and cumulative injected steam to normalize operational variations in the injection rates. It can be noticed from Figure 9 that the cSOR values for the gas condensate ESSAGD experiments were lower than those for the baseline SAGD experiment. The energy efficiency of the baseline SAGD and gas condensate ES-SAGD experiments deteriorated with time as the contact area between the steam/vapour chamber and the annulus continued to increase. Heat loss to the annulus of the physical model is analogous to heat loss to the reservoir overburden during actual SAGD operations, although it is not possible to properly scale the heat transfer aspects of the process in the laboratory.

The produced fluids and the model porous media from the SAGD and ES-SAGD experiments were analysed extensively to evaluate the impact of injecting different amounts of gas condensate on SAGD performance. Gas condensate concentration in the injected steam-solvent mixture was 5, 10 and 15 volume percent on a cold liquid equivalent basis for Experiments 2, 3 and 4, respectively. The injection rates of steam and gas condensate varied throughout the SAGD and ESSAD experiments to maintain a consistent operation pressure of 2100 kPa. To normalize this variation in injection rates, cumulative solvent-free produced oil was plotted versus cumulative injected steam as shown in Figure 6. It is evident from Figure 6 that co-injection of gas condensate with steam causes more oil to be drained and produced using much lower amounts of steam relative to the baseline SAGD experiment. The slopes of cumulative produced oil as a function of

Al-Murayri (2012) provided a detailed description of the procedure that was followed to analyze solvent recovery in 3


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the gas condensate ES-SAGD experiments. The solvent produced in the liquid phase was analyzed by means of Simulated Distillation and the solvent produced in the vapour phase was analyzed using data from the gasometer and gas chromatography system. It was found that solvent recovery in the vapour phase increases during the blowdown period of the experiments wherein pressure reduction induces solvent flashing. The increase in solvent recovery by blowdown during Experiments 2, 3 and 4 was 5.07%, 1.78% and 1.39% respectively. Total solvent recovery for Experiments 2, 3 and 4 was 80.5%, 89.98% and 99.54%, respectively. For Experiment 4, solvent co-injection was stopped after 634.1 minutes and only steam was injected for around 143.2 minutes, thereby allowing more solvent in the sand matrix to be flashed and recovered. As a result, total solvent recovery for Experiment 4 was significantly higher than that for Experiments 2 and 3 wherein solvent injection was terminated and only steam was injected for 8.9 and 70.1 minutes, respectively, prior to the termination of the experiments. This suggests that solvent recovery in ES-SAGD can be substantially improved if solvent co-injection is stopped prior to the end of the production life of a SAGD well pair. However, it is not expected that solvent recovery will be as high in the field as it is in the closed, homogeneous laboratory system. The variation in solvent recovery with respect to time for all the gas condensate ESSAGD experiments is presented in Figure 10.

much higher at the lower corners of the sand matrix relative to the other regions in Figure 13. It should be mentioned that the residual oil saturation can be even lower in the field. It is hypothesized that solvent coinjection with steam reduces residual oil saturation in the swept zone within the steam/vapour chamber. In SAGD, the drainage of oil continues for long periods of time in the swept zone after the steam front has passed through it, thus leaving high vapour saturation and some residual saturation. Initially, this residual oil saturation would be similar to what can be measured by conducting a steam flood on a core plug and in numerical simulations it would be the residual oil saturation in the relative permeability curves. However, the drainage of oil under gravity does not stop at this point if the oil spreads on the gas-water interface. If the formation is water-wet, which is normally the case in Athabasca-type reservoirs, there will be a wetting layer of water on the sand grains and high gas phase saturation in the swept zone. The residual oil is expected to spread on the gaswater interface when the spreading coefficient is positive. An increase in the spreading coefficient can be achieved through solvent co-injection with steam in SAGD due to solvent dissolution in the oil phase, which reduces the interfacial tension forces between the oil and water phases, thus promoting film drainage and residual oil saturation reduction. This is a slow process that is likely to continue for many months after the steam front has passed by and theoretically it can drive residual oil saturation to nearly zero. While it is likely that oil will spread even in the absence of solvent, it is believed that solvent addition can increase the rate of such spreading, thus accelerating film drainage. This hypothesis as illustrated in Figure 15 needs to be confirmed by running long duration drainage experiments in sand-pack columns with and without solvent added to steam.

Cumulative injected steam and cumulative produced water remained reasonably at balance throughout the life of the baseline SAGD and gas condensate ES-SAGD experiments, as shown in Figure 11. The minor differences between cumulative injected steam and cumulative produced water can be attributed to the amount of water retained within the sand matrix as well as the amount of water that was injected to pressurize the sand-pack model which was around 290g for all the experiments.

The amount of asphaltene (toluene soluble and pentane insoluble) in the oil that was extracted from the depleted sand matrix was measured experimentally for the baseline SAGD and gas condensate ES-SAGD experiments. Asphaltene content analysis was carried out by placing a beaker and a filter paper in an oven for 1 hour and a desiccator for 2 hours to minimize moisture effects. A dehydrated oil sample of around 5 grams was then placed inside the beaker and mixed with approximately 200ml of pentane using a stirring rod. This mixture was left for 2 hours to induce the precipitation of asphaltenes due to the dissolution of maltenes in pentane. Asphaltenes were then separated by filtering the maltenes containing pentane through the moisture-free filter paper into another beaker. Pentane was used to remove the remaining traces of maltenes on the filter paper and the weight of the accumulated asphaltenes above the filter paper was then recorded after allowing the pentane evaporate. Figure 16 presents contour maps for asphaltene content within the sand matrix for the baseline SAGD experiment and the gas condensate ES-SAGD experiments. The numerical values that were used to generate these contour maps were published by Al-Murayri (2012). Asphaltene content in the original oil that was used to saturate the sand-pack model for Experiments 2, 3 and 4 was 22.5%, 22.3% and 22.3%, respectively. It can be noticed from Figure 13 that asphaltene content was higher near the injection well, possibly due to the relatively higher temperatures in this region, which could have resulted in the evaporation of light ends from the residual oil. Laboratory analysis of the extracted oil from different regions within the depleted sand matrix did not show a significant difference in

As shown in Figure 12, the depleted sand matrix was divided into three horizontal and five vertical segments, after depressurizing the sand-pack model, thus resulting in 15 distinct samples. Oil was extracted from each sample in order to measure asphaltene content, water saturation and residual oil saturation. Each sand-matrix sample was weighed and separated into bitumen, water and sand by refluxing toluene using a Soxhlet extraction apparatus. The initial oil and water saturations for Experiments 1, 2, 3 and 4 were reasonably consistent as shown in Table 2. Contour maps for the residual oil and water saturations for the baseline SAGD and gas condensate ES-SAGD experiments are presented in Figures 13 and 14, respectively. The numerical values that were used to generate these contour maps were reported by Al-Murayri (2012). It is worth mentioning that some redistribution of water saturation may have occurred during the period between end of the test and the opening of the model to extract the sand samples. The oil saturation distribution is more reliable due to low mobility of the oil that would limit its redistribution. It is challenging to conclusively correlate the concentration of the co-injected solvent with residual oil and water saturations within the depleted sand-pack model because the duration of Experiments 2, 3 and 4 was not the same. Analyzing the depleted sand matrix for the baseline SAGD and gas condensate ES-SAGD experiments revealed that residual oil saturation varies from one region to another based on the extent of the steam chamber growth. Residual oil saturation was found to be

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asphaltene content as a result of gas condensate co-injection with steam. The maximum fraction of asphaltene with the depleted sand matrix for Experiments 2, 3 and 4 was 27.1% 27.3% and 29.4%, respectively.

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Gas condensate co-injection with steam reduced the density and viscosity of produced oil. As a result, the dehydration of the produced emulsion samples from the gas condensate ES-SAGD experiments was significantly easier relative to those from the baseline SAGD experiment. Asphaltene content in the dehydrated produced oil was measured using pentane as described earlier. The maximum difference in asphaltene fraction between the original and produced oil for Experiments 1, 2, 3 and 4 was found to be 0.9%, 3.3%, 2.9% and 3.6%, respectively. A plot of asphaltene content versus time is presented in Figure 17 for Experiments 1, 2, 3 and 4. Some of the shown reduction in asphaltene content can be attributed to solvent presence in produced oil. These results indicate that the co-injection of gas condensate with steam does not result in high levels of asphaltene precipitation. This is mainly because the gas condensate that was used has a relatively heavy molecular weight as opposed to lighter solvents such as propane or butane where asphaltene precipitation is expected to be more pronounced.

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The density and viscosity of the dehydrated produced oil from the baseline SAGD and gas condensate ES-SAGD experiments were also measured and the results are presented in Figures 18 and 19. It is evident from Figure 18 that the density of produced oil remained more or less constant throughout the baseline SAGD experiment. However, for the gas condensate ES-SAGD experiments, the density of produced oil fluctuated to some extent but was generally reduced with time until solvent injection was stopped and only steam was being injected, beyond which the density of produced oil started to increase. As stated above, gas condensate co-injection was discontinued and only steam was injected for 8.9, 70.1 and 143.2 minutes prior to the termination of Experiments 2, 3 and 4, respectively. The viscosity of produced oil followed a similar trend of fluctuation to that of density throughout Experiments 1, 2, 3 and 4 as shown in Figure 19. It can be noticed from Figures 18 and 19 that both density and viscosity of produced oil from Experiment 4 were lower than that from Experiments 1, 2 and 3 until gas condensate co-injection was discontinued. This is mainly because the concentration of the co-injected gas condensate was considerably higher in Experiment 4.

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consideration to ensure that the solvent used remains vaporized within the vapour chamber. ES-SAGD using gas condensate results in higher oil production rates and energy efficiency relative to SAGD. Gas condensate co-injection with steam enhances temperature conformance along the SAGD production and injection wells. Early gas condensate co-injection with steam accelerates the establishment of inter-well communication between the SAGD injection and production wells, thereby causing a significantly improved production ramp-up profile. The incremental benefits of gas condensate coinjection with steam diminish towards the end of the SAGD process. Gas condensate co-injection with steam improves the dehydration of produced emulsions and post-production water handling and causes insignificant levels of asphaltene precipitation. Gas condensate co-injection with steam in SAGD reduces heat loss from the top of the steam chamber to areas above the exploitable bitumen zone. This can be particularly useful when dealing with thin reservoirs or in the presence of steam thief zones such as top water. Solvent recovery can be increased significantly if solvent injection is stopped some time prior to the end of the production life of a SAGD well pair. SAGD performance can be enhanced by increasing the concentration of the co-injected solvent without significantly reducing effective temperature within the steam/vapour chamber, particularly when relatively lighter solvents are used.

Acknowledgements The authors are grateful to Nexen Energy ULC for their support of this work.

References 1.

Conclusions

2.

For the field pilot testing at Long Lake, 10 volume % gas condensate was chosen as the solvent additive. Gas condensate was chosen because cracked naphtha from the integrated upgrader has been replaced by gas condensate as the diluent in the field operation. The solvent concentration of 10 volume % was selected because this was deemed to be high enough to be able to assess the effects of the solvent addition in the field and represents about half the gas condensate normally added on surface as diluent.

3.

4.

The key observations that can be concluded from this study can be summarized as follows:  The inter-relation between pressure, temperature and solvent concentration has to be taken into

5.

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Zhao, L., et al (2005), “Steam Alternating Solvent Process: Lab Test and Simulation, Journal of Canadian Petroleum Technology, vol. 44, no. 9, pp. 37-43. Yang, C. and Gu, Y. (2005). “Effects of Heavy-Oil/Solvent Interfacial Tension on Gravity Drainage in the Vapor Extraction (VAPEX) Process”, International Thermal Operations and Heavy Oil Symposium, Calgary, Alberta, Canada, 1-3 November, SPE/PS-CIM/CHOA 97906. Sharma, J. and Gates, I.D. (2011), “Interfacial Stability of In-Situ Bitumen Thermal Solvent Recovery Processes”, SPE Journal, March, pp. 55-64. Jha, R.K., Kumar, M., Benson, I., & Hanzlik, E. (2013). “New Insights into Steam/Solvent-Coinjection-Process Mechanism”. SPE Journal, vol. 18, no. 5, pp. 867-877. Nasr, T.N. & Ayodele, O.R. (2006). “New Hybrid SteamSolvent Processes for the Recovery of Heavy Oil and Bitumen”. SPE International Petroleum Exhibition and Conference, Abu Dhabi, U.A.E, November 5-8. SPE 101717.


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6.

Yazdani, A., Alvestad, J., Kjonsvik, D., Gilje, E. & Kowalewski, E. (2011). “A Parametric Simulation Study for Solvent Co-Injection Process in Bitumen Deposits”. Canadian Unconventional Resources Conference, Calgary, Alberta, Canada, November 15-17. 7. Hosseininejad Mohebati, M., Maini, B.B., & Harding, T.G. (2012). “Experimental Investigation of the Effect of Hexane on SAGD Performance at Different Operating Pressures”. SPE Heavy Oil Conference, Calgary, Alberta, Canada, June 12-14. SPE 158498. 8. Al-Murayri, M.T. (2012), “Experimental Investigation of ES-SAGD Using Multicomponent Solvents”, Ph.D. Dissertation, University of Calgary, December 2012. 9. Butler, R.M., McNab, G.S. & Lo, H.Y. (1981), "Theoretical Studies on the Gravity Drainage of Heavy Oil During In-Situ Steam Heating", Canadian Journal of Chemical Engineering, vol. 59, no. 4. 10. Butler, R.M. & Mokrys, I.J. (1991), "A New Process (VAPEX) for Recovering Heavy Oils Using Hot Water and Hydrocarbon Vapour", Journal of Canadian Petroleum Technology, vol. 30, no. 1, pp. 97-106. 11. Nasr, T.N., & Isaacs, E.E. (2001), "Process for Enhancing Hydrocarbon Mobility Using a Steam Additive”, US Patent No. 6,230,814.

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Tables Table 1: Typical composition of gas condensate Component Mole Fraction CO2 0.0002 C1 0.0012 C2 0.0020 C3 0.0038 iC4 0.0024 nC4 0.0731 iC5 0.2349 nC5 0.2149 C6 0.1819 C7+ 0.2856 Total 1.0000

Table 2: Properties of the Sand-Pack Matrix

Experiment Number

Experiment Type

Solvent Vol. %

Porosity (%)

Water

Oil

1 2 3 4

SAGD ES-SAGD ES-SAGD ES-SAGD

0 5 10 15

32.5

9.116

90.884

32.7

9.243

90.757

33.0

8.844

91.156

32.9

7.854

92.146

7

Initial Saturations (%)


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Figures

Figure 1: Phase envelope of cracked naphtha and saturated steam curve

Figure 2: Phase envelope of gas condensate and saturated steam curve

Figure 3: Sand-pack model

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Figure 4: Confining pressure jacket

Figure 5: Temperature profiles along the injection and production wells

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Figure 6: Cumulative produced oil versus cumulative injected steam for the baseline SAGD and gas condensate ES-SAGD experiments

Figure 7: Temperature profiles of baseline SAGD and gas condensate ES-SAGD experiments at cumulative produced oil of 1500g, 2000g and 2500g, respectively

Figure 8: Production well temperature for the gas condensate ES-SAGD experiments

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Energy & Fuels

Figure 9: Cumulative steam-oil ratio as function of time and cumulative injected steam for the baseline SAGD and gas condensate ES-SAGD experiments

Figure 10: Solvent recovery versus time for the gas condensate ES-SAGD experiments

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Energy & Fuels

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Figure 11: Cumulative injected steam and cumulative produced water for the baseline SAGD and gas condensate ES-SAGD experiments

Figure 12: Sand-matrix sample locations

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Energy & Fuels

Figure 13: Residual oil saturation within the depleted sand matrix for the baseline SAGD and gas condensate ES-SAGD experiments

Figure 14: Water saturation within the depleted sand matrix for the baseline SAGD and gas condensate ESSAGD experiments

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Figure 15: Residual oil saturation reduction due to solvent co-injection with steam

Figure 16: Asphaltene content with the depleted sand matrix for the baseline SAGD and gas condensate ESSAGD experiments

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Energy & Fuels

Figure 17: Asphaltene content in produced oil versus time for Experiments 2, 3, 4 and 5

Figure 18: Density of produced oil from the baseline SAGD and gas condensate ES-SAGD experiments

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Energy & Fuels

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Figure 19: Viscosity of produced oil from the baseline SAGD and gas condensate ES-SAGD experiments

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Multicomponent Solvent Co-injection with Steam in Heavy and Extra

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