Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. It is believed that the heavy oil resource volume is in the 50 to 70 billion bbl range which makes it a world class resource. This work briefly summarizes the reservoir properties of these formations and provides an overview of the primary CHOPS recovery mechanism which only recovers on average 8% of the original oil in place. Therefore, the target for Enhanced Oil Recovery (EOR) processes are substantial. For instance, if an additional 2% (25% of the primary) oil can be recovered, this means an additional 1 to 1.5 billion bbls of oil production which can sustain the oil industry for many years in this area providing jobs and contributing significantly to government royalties. A critical literature review of Cyclic Solvent Injection (CSI) as a post-CHOPS EOR technology is conducted. The key aspects of laboratory and theoretical studies of methane and propane mixtures, CO2 and propane mixtures and pure CO2 injection are summarized. A number of field pilots have been conducted using these solvents in post-CHOPS reservoirs in Lloydminster. Implementation of field pilots is presented and results are discussed using publicly available data. It is shown that while CSI technology is technically successful, economic feasibility is more elusive. However, it appears that CO2 injection is more likely to be economically successful. Furthermore, the economic attractiveness of Cyclic CO2 Injection increases in an environment where greenhouse gas emissions are taxed and credits for disposal are available.

Precipitation and deposition of asphaltene in reservoir rock can cause formation damage and reduce the fluid mobility, resulting in significant loss of the hydrocarbon production. A detailed study on asphaltene deposition behavior in porous media improves the understanding of asphaltene-induced formation damage and provides the possible solutions for preventing and/or controlling formation damage. Carbonate reservoirs in Western Canadian Sedimentary Basin (WCSB) have several challenges for enhanced oil recovery process (i.e. heterogeneity, the high viscosity of oil). Asphaltene-induced formation damage makes it more difficult for any process to recover heavy oil from such complex reservoirs. For advancements in understanding asphaltene deposition in fractured carbonate formations, asphaltene deposition behavior was analyzed with the help of pore scale observation during hydrocarbon solvent injection. Three types of solvent (nC5, nC7, and nC12) were used for solvent injection for extra-heavy oil recovery (30,000 cp at 22 °C). A uniquely designed heterogeneous-fractured micromodel imitating the fractured carbonate reservoirs was used for pore scale observation. A high-quality camera along with a microscope was utilized to capture images. SEM analysis was also performed on precipitated asphaltene to visualize the difference in the structure of the asphaltenes precipitated with different solvents. Observation through this study revealed that besides the amount of asphaltene deposition, the distribution pattern of asphaltene deposition could also be different when using various types of solvent. By increasing carbon number of solvent from C5 to C12, the amount of precipitation decreased while the wider distribution of deposited asphaltene was observed in a fractured-heterogeneous porous media. Moreover, it was noted that asphaltene could be deposited in different shapes that may or may not block the pore throat. The dominant flow mechanism (either diffusion dominant or viscous dominant) will affect the shape of deposited asphaltene. Asphaltene can deposit perpendicular or parallel to the flow direction which is in the form of parallel rope-shape deposits. The perpendicular deposits (usually in dominant diffusion flow), mainly observed in small pore throat, can block the diffusion path. However, the parallel shape deposits (typically in viscous dominant flow) will not significantly impede the flow path. The results of this study improve our understanding of different aspects of asphaltene-induced formation damage in the fractured carbonate reservoirs such as; susceptible locations of asphaltene deposition, different types/shapes of deposition which may or may not result in pore blocking, and effect of flow behavior and heterogeneity on asphaltene deposition and formation damage. The more we know about the asphaltene deposition in such heterogeneous reservoirs, the better we can control the formation damage and increase the effectiveness of heavy oil recovery processes.

Being the most popular technological framework for the heavy oil and bitumen production, the reservoir heating is mainly performed via steam injection. Progressively it becomes evident, however, that there exist other methods offering an efficient production for various initial reservoir conditions and oil properties. The electromagnetic (EM) heating assisted oil recovery is one of them capable to be an alternative to conventional approaches where they become inacceptable. Physically speaking the radio-frequency (RF) heat generation results from so-called microwave effect i.e. rotation with friction of polar molecules in the EM field. The intrinsic advantages of the RF-heating (RFH) based technology, which in particular avoids the problems associated to water supply and water treatment, can be strengthened by solvent injection. After certain period of preheating this may lead directly to improved oil recovery due to additional oil viscosity drop as a result of oil-solvent mixture process. Along with this the solvent injection may reduce the operational in-situ temperature and thus, to increase the energy efficiency (i.e. the amount of energy required per unit of oil production). This will open a way to the successful technology application in shallow and/or thin reservoir. Mention also that the combination of heat and solvent supply has recently been field-tested. Recently the large-scale EM heating models have been developed for numerical simulation of realistic RFH applications, which provided the technical basis for critical analysis of the oil recovery processes. The numerical methodology based on loose coupling between dedicated reservoir and electromagnetic simulators, has been applied to study the combination (and competition) of two principal physical mechanisms of oil viscosity reduction associated with heat and solvent mass transfer. Taking advantage of the field-scale modelling the evaluation of operational conditions providing the oil production efficiency has been done. It was shown that RFH and its modification can be efficient for the various reservoir conditions. Noticeably different solutions for well configurations can be envisaged in the technology under consideration. The simulations have included the pure RFH cases at variable total EM power and the RFH combination with solvent injection at different operational and well. The initial reservoir conditions and properties corresponded to typical Athabasca reservoir. Main results comprising the methodological aspects of the recent 3D code development, the conclusions on pure RFH advantages and drawbacks and the demonstration of enhanced oil recovery efficiency at solvent injection within the RFH framework, are presented in detail. The role of particular mass transfer mechanisms and their contribution to improved process efficiency in heterogeneous matrix are quantified and discussed. The solvent injection combination with electromagnetic (radio-freqency) heating may become a promising issue in many practical applications.

Electromagnetic (EM) heating holds a large potential in heavy oil recovery since it can reduce carbon emission and avoid excessive water usage, and is applicable for water hostile reservoirs such as shale oil reservoirs. Combining solvent injection and EM heating might further reduce the energy intensity of the process. The merits of using solvent in EM heating include diluting heavy oil and thereby increasing its mobility, serving as a heat carrier by reinforcing heat convection in porous media and facilitating gravity drainage by forming a vapor chamber. Detailed experimental investigations are needed to investigate the mechanism of such a complex process and to specify the most influential factors of this hybrid and expensive process to determine optimal operational conditions. In this study, we conduct a series of laboratory experiments to investigate the mechanisms of combined EM heating and solvent assisted gravity drainage for heavy oil recovery. During experiments, sand pack samples contained in Buchner filter funnel are placed in a microwave oven. Solvent injection can be initiated together with EM heating to simulate the hybrid process of combined EM heating and solvent assisted gravity drainage. We investigate the effects of influential factors on the process efficiency, including initial water saturation, solvent types ( n -hexane and n -octane), introduction methods of solvents (injection or premixed with oil), combination strategies of solvent injection and EM heating (simultaneous or alternate means), and EM heating power. Temperatures of the sand pack and oil recoveries are simultaneously recorded. Experimental results show that combined EM heating and solvent assisted gravity drainage could effectively enhance heavy oil recovery compared with EM heating or solvent use alone. A higher heating power provides a faster temperature rise and earlier oil production in the sand pack. Moderate initial water saturation could increase the heating speed, leading to a higher oil recovery. Solvent injection can further enhance the viscosity reduction and swelling effect of heavy oil due to EM heating. Compared with n -hexane, n -octane provides higher vertical displacement efficiency and oil recovery under the same experimental conditions. Alternate EMH and solvent injection is more cost effective due to the lower energy consumption compared to the simultaneous EM heating and solvent injection.

This paper summarizes a project that was part of the $40 million 2006-2010 Joint Implementation of Vapour Extraction (JIVE) pilot program managed by the Petroleum Technology Research Centre and including Husky Oil, CNRL, NEXEN, Alberta Innovates–Technology Futures, and the Saskatchewan Research Council. The project was in support of a cyclic solvent injection (CSI) field pilot in the Lloydminster region of Saskatchewan that was evaluating the potential of CSI to exploit reservoirs following cold heavy oil production with sand (CHOPS). History matches were performed for two Edam CHOPS wells in the Colony formation and they determined initial reservoir conditions (e.g. pressure, effective permeability, porosity, fluid saturations, and gas and oil phase mole fractions) for subsequent CSI simulations. Thin formation layers (~15 cm) were used in the CHOPS simulations to improve representation of wormhole generation and advance. One well had rapid sand production that quickly declined whereas the other well had continuous sand production due to wormhole propagation and scouring and resulted in sustained oil production. The reservoir model for the application of CSI contained a number of wells including the CSI well and two communicating offset wells ( Figure 1 ). Using an Alberta Innovates–Technology Futures (AITF) CSI model, a history match was obtained for CSI Cycle 1. Eleven different potential injection/production strategies were then evaluated for Cycle 2 and the simulation results were used in the design of this cycle. One conclusion was that expanding the solvent injection period from 1 to 2 months increased the combined oil production for the three wells by 29% but resulted in a 46% increase in net solvent to oil ratio. Figure 1 Conversion from post-CHOPS radial geometry to Cartesian geometry for CSI simulations

Effective communication between the injector and producer with a reasonable conformance during SAGD start-up phase is crucial for the success of SAGD conversion and the following ramp-up phase. The start-up operation normally relies on heat conduction mechanism to establish heat and fluid communication between the wells. For super heavy oil reservoirs in Fengcheng project in China, since the pay zone has low thermal conductivity and extremely high oil viscosity, establishing the temperature profile required for SAGD conversion using conduction as the only heating mechanism is not efficient and can take 150 to 180 days to achieve. In order to shorten the circulation time and accelerate the ramp-up phase after SAGD conversion, an approach using solvent injection with steam simultaneously to enhance injectivity was successfully designed and implemented. This paper reviews the design criteria, tests the thermal properties of cored samples, selects the typical wellpair based on geological modeling results, carries out the reservoir engineering design of solvent injection using CMG-STARS, and discusses the implementation performance of warm solvent injection in the start-up phase of a pilot wellpair in Fengcheng project. It also compares production responses of solvent-treated wellpair with other wellpairs with comparable reservoir properties in the same pad by conventional start-up to evaluate the performance of the designed pilot.

In a cyclic solvent injection (CSI) process, a solvent gas is cyclically injected, soaked, and released to produce heavy oil. Through this process the operating pressure is decreased and increased cyclically. This causes a dynamically changing pressure gradient across the solvent–oil mixing zone, leading to a convective mixing of solvent and oil in addition to molecular diffusion. This study aims at modeling the effect of pressure gradient-induced convection on the solvent–oil mixing process in the transition zone. A diffusion–convection model is developed to simulate the dynamic solvent–oil mass transfer in the transition zone during the CSI process. This model consists of two sub-models: a pressure model and a solvent concentration model. The pressure model considers the effect of a practical viscosity profile and the concentration model considers the effect of a dynamic convective mass transfer velocity. These two models are coupled through the convection velocity and oil viscosity across the transition zone. The entire model is semi-analytically solved, in which a piecewise linear approximation scheme is applied for the variable convection velocity and viscosity in the transition zone. Results show that during the solvent injection period, convection can significantly enhance the mixing of solvent and heavy oil. Larger solvent injection rates can be more efficient for heavy oil–solvent mass transfer. In addition, it is found that considerable solvent remains in the oil zone at the end of the production period, and this part of solvent is difficult to retrieve within a short time period.

Carbonate reservoirs, deposited in the Western Canadian Sedimentary Basin (WCSB), hold significant reserves of heavy crude oil that can be recovered by non-thermal processes. Solvent, gas, water, and water alternating gas injections are the main methods for carbonate heavy oil recovery in the WCSB. Due to the fractured nature of carbonate formations, many advantages of these production methods are usually contrasted by their low recovery factor. Alternative processes are therefore needed to increase oil sweep efficiency from carbonate reservoirs. Foam/polymer enhanced foam (PEF) injection has gained interest in conventional heavy oil recovery in recent times. However, the oil recovery process by foam, especially PEF, in conjunction with solvent injection is less understood in fracture heavy oil carbonate reservoirs. The challenge is to understand how the combination of surfactant, gas, and polymer allows us to better access the matrix and efficiently sweep the oil. This paper introduces a new approach to access the unrecovered heavy oil in fractured carbonate reservoirs. CO 2 foam and CO 2 PEF were used to decrease oil saturation after solvent injection, and their performance was compared with gas injection. A specially designed fractured micromodel was used to visualize the pore scale phenomena during CO 2 foam/PEF injection. In addition, the static bulk performances of CO 2 foam/PEF were analyzed in the presence of heavy crude oil. A high definition camera was utilized to capture high quality images. The results showed that in both static and dynamic studies the PEF had high stability. Unlike CO 2 PEF, CO 2 foam lamella broke much faster and resulted in the collapse of the foam during heavy oil recovery after solvent flooding. It appeared that foam played a greater role than just gas mobility control. Foam showed outstanding improvement in heavy oil recovery over gas injection. The presence of foam bubbles was the main reason to improve heavy oil sweep efficiency in heterogeneous porous media. When the foam bubbles advanced through pore throats, the local capillary number increased enough to displace the emulsified oil. PEF bubbles generated an additional force to divert surfactant/polymer into the matrix. Overall, CO 2 foam and PEF remarkably increased heavy oil recovery after solvent injection into the fractured reservoir. The results of these direct visualization experiments improve our understanding of the heavy oil recovery process by solvent alternating CO 2 foam/PEF flooding in fractured reservoirs. Besides enhancing oil production, application of CO 2 foam/PEF may require the injection of a lesser amount of solvent into the reservoir, providing economic and environmental advantages.

Thermal-based heavy oil recovery methods, which are exemplified by steam-assisted gravity drainage (SAGD), have been successfully used in a number of field applications to enhance heavy oil recovery over three decades. However, there are several major technical issues associated with the thermal-based methods, such as large energy and water consumptions, extensive heat losses and expensive water treatment, as well as considerable greenhouse gas emissions. Thus the thermal-based methods are not suitable for many heavy oil reservoirs with thin pay zones, bottom water, gas caps, and low rock thermal conductivities due to economic constraints and environmental concerns. Alternatively, the solvent-based heavy oil recovery methods are considered. This paper provides a critical review of several solvent-based methods by conducting a comprehensive literature search of over 100 most recent and significant technical publications. First, the basic idea and technical development of each solvent-based heavy oil recovery method are briefly introduced. The advantages of solvent-based methods are stressed. Second, solvent-based methods are classified and each method is described. Third, a large number of experimental, theoretical and numerical studies of solvent-based methods are reviewed, from physical and theoretical modeling to numerical simulations. In particular, the heavy oil recovery mechanisms, phase behaviour and mass transfer of the heavy oil–solvent systems are examined in detail. A few important factors or major phenomena as well as their effects on the solvent-based methods are analyzed, which include the operating conditions (i.e., pressure and temperature), well configuration, solvent-induced asphaltene precipitation, interfacial tension (IFT), and viscous fingering. Most importantly, a total of six pilot tests or field applications of solvent-based methods, such as vapour extraction (VAPEX), liquid addition to steam to enhance recovery (LASER), and other hybrid steam–solvent processes, are evaluated. Finally, several major technical recommendations are made accordingly for future studies and developments of solvent-based heavy oil recovery methods and their potential variations. This updated technical review will help to better understand the solvent-based heavy oil recovery processes and guide a heavy oil producer to better design a solvent-based heavy oil recovery project.

In oil sands in situ operations using steam-assisted gravity drainage (SAGD), achieving effective communication between the injector and producer with a reasonable conformance is crucial for the success of SAGD conversion and the following ramp-up phase. The start-up operation normally relies on heat conduction phenomena for establishing communication between the wells. For oil sands reservoirs containing extremely high viscosity bitumen, establishing the temperature profile required for SAGD conversion using conduction as the only heating mechanism is not efficient and can take 90 to 120 days to achieve. Start-up operation can be accelerated by enhancing the rate of convective heat transfer to the formation by techniques such as bullheading and cold/hot dilation. At Nexen's Long Lake in-situ SAGD project, the use of higher injection pressures to enhance start-up is limited by the presence of high water saturation zones within the bitumen pay zone ("lean zones"), an adjacent Quaternary-age fresh water-bearing channel, and shallow formation depth. In order to overcome these constraints, an approach using solvent injection in a warm system with enhanced injectivity was successfully designed and implemented. In this approach, the solvent was injected in a high bitumen saturation system after circulating the well for about 70 days. Then, the solvent was chased with hot water into the formation to deliver the solvent deeper into the formation and enhance the rate of solvent-bitumen mixing during the soaking time. This paper reviews the design criteria, well selection process, and implementation of warm solvent injection in the conducted pilot in the start-up phase of Pad 13 at Long Lake. It also compares production responses of solvent-treated and control wells with comparable reservoir properties within the same pad to evaluate the performance of the designed pilot. Review of the production data shows that the solvent-treated well pair has outperformed all the other well pairs of the pad with no apparent conformance issues. This well had a quick ramp-up which is considerably faster than the average ramp up time at the Long Lake project. The collected data suggests that applying solvent-assisted start-up in systems that have enhanced mobility by pre-circulation of steam can shorten the circulation time and accelerate the ramp-up phase after SAGD conversion.

In the $40 million Joint Implementation of Vapor Extraction Program (JIVE), an experiment was performed to investigate CSI behaviour in the Lloydminster region under pressure support from CH 4 injection at an offset well. The oil sand pack had high permeability (500 Darcy) and low permeability (3 Darcy) zones that represented regions with and without wormholes. Primary production was followed by two CSI cycles in which the solvent (60% CH 4 –40% C 3 H 8 ) was injected at the high permeability end. CH 4 offset gas was injected at the low permeability end during CSI production periods. Solvent recovery strategies were evaluated. The primary production drawdown strategy (designed using numerical simulation) resulted in 10.0% oil recovery. Production was only obtained after 6 hours due to a delay in gas exsolution and foamy oil drive. During CSI, a delay in oil recovery also occurred as the pressure-supporting offset gas required time to drive foamy oil generated in that region into the high permeability region. Cycle 1 oil recovery was 6.2%. Cycle 2 had low oil recovery. Post-run gas saturations indicated gravity override occurred. Asphaltene precipitation/deposition occurred as seen from microscopic observation. The asphaltene content was reduced in the produced oil and increased in the post-run oil sand. A rapid pressure drawdown after a third solvent injection period caused 1.7% oil recovery and foamy oil in the production line ( Figure 1 c). Additional oil recovery (4.5%) was obtained from offset CH 4 injection, heating of the sand pack to ~60 °C, and 22 °C nitrogen offset gas injection. Numerical simulations of primary production and CSI cycles showed: the best strategy is rapid well depressurization during production high offset gas rate enhances gravity override and reduces oil production

Cyclic solvent injection (CSI) process takes advantage of solution-gas drive and foamy oil flow for the oil production. However, it suffers from the solvent liberation during the production period. This results in an increased viscosity of the oil and its mobility loss. 0How to recover the partially diluted heavy oil becomes a key challenge for a CSI process. This paper first experimentally studies the conventional CSI processes with a one-well configuration, in which the solvent injector is alternately used the oil producer, and a two-well configuration, in which the solvent injector and oil producer are placed horizontally apart. It is found that during the one-well CSI test, some foamy oil that remains in the solvent chamber at the end of the production period of a previous cycle is pushed back by the injected solvent during the injection period of the next cycle. Such a back-and-forth movement of oil is not observed in the two-well CSI test. In addition, it is found that the oil saturation and oil relative permeability inside the solvent chamber are increased due to the foamy oil flow during the production period. Based on this fact, a new process, namely gasflooding-assisted cyclic solvent injection (GA-CSI), is proposed to enhance the performance of the CSI process. In this new process, a gasflooding slug is applied after the pressure depletion process to produce the partially diluted foamy oil in the solvent chamber. Results show that the GA-CSI process can increase the oil production rate by over 3 times, in comparison with the conventional CSI process.

This paper summarizes a study that was part of the $40 million Joint Implementation Vapor Extraction Program and was in support of a planned solvent (60% CH 4 – 40% C 3 H 8 ) injection field pilot at Fort Kent, Alberta where CHOPS wells are prolific oil producers. The pilot design was for a horizontal well between and below four vertical wells. The vertical wells were to be on CHOPS before becoming solvent injectors with the horizontal well as a producer. CHOPS simulations were based on matching specified oil production. The simulations utilized an AITF CHOPS model (with CMG STARS™ as a platform) to design CHOPS operating strategies. The CHOPS simulations determined: (a) wormhole penetration length required to maintain the specified oil rate, (b) when to stop CHOPS and start solvent injection, and (c) the initial conditions (wormhole occupied region, fluid saturations, etc.) for solvent injection simulations. The predicted post-CHOPS reservoir properties were transferred to a reservoir model that represented part of the proposed well arrangement and was used in the solvent injection simulations. Conclusions from the post-CHOPS solvent injection simulations included: During the post-CHOPS re-pressurization period, solvent should be injected in the horizontal well as well as the vertical wells. This strategy reduces subsequent channeling between the vertical and horizontal wells. Solvent injection performance depends on: (a) lateral offset between vertical injectors and horizontal producer, (b) layers in which vertical wells are perforated, (c) maintained pressure difference between injectors and producer, (d) operating pressure, and (e) gas production rate. Oil rates were significantly reduced by spreading of injected solvent in the high permeability region created by wormholes and by displacement of oil in this region away from the wells.

In situ bitumen recovery directly depends on the reduction of bitumen viscosity. Solvent injection is an alternative to thermal bitumen recovery by steam injection. Injection of solvents containing n-alkanes like butane, propane and naphtha may lead to asphaltene precipitation and deposition in the porous media and a possible negative effect on the ultimate oil recovery. Addition of an asphaltene inhibitor (stabilizer) to solvents is a way to prevent asphaltene precipitation and deposition in a reservoir. Efficiency of an asphaltene inhibitor depends on the characteristics of the inhibitor and bitumen properties.In addition to aromatic hydrocarbons, various natural and synthetic polar heteroatom species can be used as asphaltene inhibitors. Results of the study show that deasphalted bitumen is an effective asphaltene inhibitor and it is of the same strength as environmentally hazardous aromatic hydrocarbons. Resins prevent asphaltene precipitation and are similar to expensive synthetic inhibitors. Addition of less than 8 vol. % of resins to low boiling point n-alkanes provides total asphaltene stabilizationin the process of bitumen recovery. When n-alkanes are used as solvents, it is important to know the amount of precipitated asphaltenes in the reservoir. To obtain such data, an experimental study has been conducted to simulate bitumen recovery. A specially designed experimental set-up was used in the study. The experiments allowed a set of chemical additives to be selected to improve colloidal stability of asphaltenes in bitumen.

ExxonMobil and Imperial Oil Resources (Imperial) are conducting a Solvent Assisted - Steam Assisted Gravity Drainage (SA-SAGD) experimental pilot at Cold Lake in the Clearwater formation where up to 20% by volume of hydrocarbon solvent (diluent) has been injected along with dry steam in a dual horizontal well SAGD configuration. Experimental work performed by the Alberta Research Council (ARC) ( Nasr, 2003) and Imperial indicated that addition of solvent to steam increases bitumen rates and decreases steam-oil ratios relative to the conventional SAGD process. The main objective of this pilot has been to produce high quality field data to definitively support these experimental conclusions. The pilot scope includes two horizontal well pairs (four wells), six observation wells, associated steam and diluent injection facilities, artificial lift, as well as, dedicated production measurement and testing facilities. The SA-SAGD pilot uses existing steam generation, water treatment, bitumen separation and processing facilities at Imperial's Mahkeses plant and existing steam distribution and production gathering systems. The main focus of this paper is to document the integrated approach taken to ensure that this multi-year pilot is successful and to provide information resulting from this multi-year pilot. Key surveillance products, such as, production/injection measurements, horizontal-well temperature logs, observation-well temperature and saturation logs, time-lapse 3D seismic, and the impact of a mid-pilot solvent switch will be discussed. In addition, this paper will review how these surveillance products are integrated with laboratory data and simulation efforts to improve our understanding of this process and increase confidence in go-forward predictions. Given the emerging importance of solvent-assisted thermal heavy-oil processes and the accelerated conversion of this technology from laboratory-scale to field-scale, data from a field pilot provides invaluable information in the quest to deploy this emerging in-situ recovery technology.

Solvent-based in-situ enhance oil recovery (EOR) techniques are extensively studied to improve oil recovery factors (RFs) for heavy oil reservoirs. Continuous injection, such as vapour extraction (VAPEX), and cyclic injection, such as cyclic solvent injection (CSI) are two main categories of solvent EOR techniques. The production rates of VAPEX are low in field tests. CSI does not show exciting results due to the quick reservoir pressure depletion and the sudden reservoir energy loss, which causes the oil to regain its viscosity. A new enhanced heavy oil recovery technique, cyclic production with continuous solvent injection (CPCSI), is proposed in this paper. In this process, a vapour solvent is continuously injected into the reservoir to maintain reservoir pressure and also supply extra gas drive to flood the diluted oil out through an injector that is located on the top of the reservoir, while a producer, which is located at the bottom of the reservoir, is operated in a shut-in/open cyclic way. A series of experiments have been conducted to validate the CPCSI performance by using different sand-pack models with 4¬-5 Darcy permeability, and saturated with Western Canada heavy oil sample. Gaseous propane is continuously injected through an injector at a constant pressure, which is below the dew point pressure, and producer was operated with a cycle of 50-minute-shut-in/10-minute-open period. Experimental results show that, the oil is diluted and drained down by gravity during shut-in period, then produced in producer opening period by solution gas drive and gas flush. In comparison with VAPEX and CSI, CPCSI offers free gas driving, and still keeps oil diluted in the well opening period and produced by the gas flush. The RFs are up to 85% of OOIP in 1-D tests. Also, shorter height model has highest average production rate in comparison with others. Test results are also validated by 2-D physical model, in which the RF is improved by 11% by using the lateral CPCSI compared with classic lateral VAPEX. Well configurations and the shut-in/open scenarios are key optimization factors that affect CPCSI performance. This work shows that CPCSI could be an alternative optimization production scenario for applying solvent based in-situ EOR techniques for Western Canada heavy oil reservoirs.

Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. Cold Heavy Oil Production with Sand (CHOPS) has been successfully implemented in these reservoirs. However, primary recovery is still low averaging below 10%. How to economically recover the large amount of remaining oil in place is a challenge. Therefore, an effective follow up recovery process is required. Steam injection technologies cannot be widely applied because most of the Lloydminster heavy oil reservoirs are thin and the heat losses to overburden and under burden make the process uneconomic. Alternative solvent methods are not commercial yet due to uncertain oil recovery rates and low solvent recovery. Hybrid application of the aforementioned two technologies using hot water together with solvents could be an economic post CHOPS recovery process. The wormholes created during the primary recovery can be used to contact large reservoir volumes with hot water and solvent. This paper contains the results of hot water and solvent oil recovery experiments conducted in preserved heavy oil cores. Experimental work consisted of three phases. Cores were immersed in hot water in the first phase to pre-heat the formation. Next, cores were exposed to heptane as hydrocarbon solvent. Finally, cores were immersed in hot water again to recover the oil as well as the solvent. The ultimate oil recoveries varied between 42% and 88% OOIP and, the asphaltene precipitation varied between 2.5 wt% and 11.7 wt%. Experiments were also carried out with a distillate from Husky's Lloydminster upgrader used for heavy oil transportation in the pipelines. Better results were obtained if the distillate was used instead of the pure hydrocarbon solvent. It was observed that oil recovery at the end of the initial hot water injection phase due to thermal expansion and viscosity reduction was negligible compared to the ultimate recovery. However, the first phase serves to condition the reservoir for better diffusion in the second phase when the solvent is injected. The final phase of hot water injection causes the water to strongly imbibe into the matrix enhancing the oil and the solvent recovery.

This work presents experimental results of four 3D physical model experiments that were performed to evaluate the dependence of solvent vapour extraction (SVX) recovery process performance on initial dead oil viscosity and injected solvent mixture composition. Model excavation studies were also performed to approximate the solvent movement in the physical model and to map out the residual oil saturation and precipitated asphaltenes. All of the four experiments — designated as SVX 14, 15, 16 and 17A — were performed on a 3D physical model (having permeability and porosity of ~4 darcy and ~33%, respectively) that was oriented vertically to provide model dimensions of 2.5 m thick by 0.2 m wide by 0.5 m long. The 0.5-m-long horizontal top injection and bottom production wells were separated laterally across the width and vertically across the thickness. Prior to solvent injection the model was resaturated with live oil containing methane at a gas/oil ratio ranging from 8.5 to 11 sm 3 /sm 3 . The initial dead oil viscosity at 21°C for SVX 14, 15, 16 and 17A were approximately 13,000, 33,000, 16,000, and 48,000 mPa•s, respectively. The composition of the injected solvent mixture for SVX 14 and 15 was ~57/43 mol% of methane (C 1 )/propane (C 3 ) and for SVX 16 and 17A was ~57/43 mol% of carbon dioxide (CO 2 )/propane (C 3 ). The analysis of the experimental results revealed that the initial dead oil viscosity had a significant effect on the SVX performance. Higher oil production rates were achieved with the lower viscosity oils for both injected solvent mixture types, with a more pronounced effect observed when using the CO 2 /C 3 solvent mixture. The results also showed that the CO 2 /C 3 mixture resulted in earlier solvent breakthrough and initial oil production, reduced solvent makeup requirements (i.e., better solvent recycle stream), and reduced solvent retention in the model/reservoir, as compared to the C 1 /C 3 solvent mixture. The residual oil saturation mapping showed that the CO 2 /C 3 mixture led to comparatively lower values in the drained regions and higher amount of precipitated asphaltenes remaining in the model, although there was evidence of some precipitated asphaltenes close to both the injection and production wells in all four experiments, regardless of the solvent mixture type. Finally, this mapping also indicated that the solvent/oil interfaces and solvent chambers were more uniform and predictable for the CO 2 /C 3 solvent mixture injection. The field scale application and optimization of SVX processes requires that relationships be established among oil production rates, solvent utilization, and important process parameters such as matrix permeability, initial oil viscosity, solvent mixture composition, solvent utilization, etc. This work has attempted to generate such relationships for the two most promising mixed solvent systems being considered for use in heavy oil reservoirs.

ExxonMobil and its Canadian affiliate, Imperial Oil Resources, are actively developing the next generation of solvent-aided and solvent-dominated heavy oil recovery processes. While these new recovery processes possess multiple environmental and technical advantages relative to traditional heavy oil recovery processes, there are a variety of challenges that must be addressed and overcome before commercial application. One especially promising technology is the Solvent Assisted – Steam Assisted Gravity Drainage (SA-SAGD) process. In the SA-SAGD process, a light hydrocarbon solvent (diluent) is injected along with dry steam in a dual horizontal well SAGD configuration. An integrated research program has been implemented in order to progress the SA-SAGD technology from the laboratory to the field and to better quantify the benefits of SA-SAGD over SAGD. This integrated research program includes fundamental laboratory work, advanced numerical simulation studies, scaled physical laboratory models, and a two well-pair field pilot. In this paper, we review the scope, technical challenges, and key learnings from the laboratory, numerical modeling efforts, and the field pilot. Each individual component of the research program is important and provides unique and useful information concerning the SA-SAGD process. Given the technical and economic challenges of solvent-assisted thermal heavy-oil processes, these types of fully integrated research programs are essential in order to successfully progress new technologies from the laboratory to the pilot scale and ultimately to the commercial scale. Ultimately, the program is targeted at developing reliable commercial predictive capabilities that have been validated against both laboratory and field data, for application to a wide range of heavy oil reservoirs, operating conditions, and development plans.

Solvent injection into heavy-oil reservoirs is quite complex on account of the asphaltene destabilization that occurs due to the changes in temperature, pressure, and solvent type dissolved in oil. As a result of this destabilization, the asphaltene precipitates, flocculates, and eventually plugs the pores in the reservoir due to the formation of asphaltene clusters. In solvent applications, light molecular weight hydrocarbon solvents are preferred because of their high diffusion coefficient; but, as the carbon number of n-alkane solvents decreases, asphaltene precipitation increases. Therefore, the selection of the solvent and application condition is highly critical in cold and thermally-aided solvent applications. In this research, low carbon number n-alkane (propane, n-hexane and n-decane) injection into sand pack systems saturated with heavy-oil (87651 cp) was evaluated at different pressure conditions that are applicable to typical Canadian oilsands reservoirs (100-300 psi) and temperatures (25-120 °C). First, the asphaltene behavior of different solvents at different pressures and temperatures were studied through deasphalting work in a pressure-volume-temperature (PVT) cell. Based on the quantitative (amount of asphaltene precipitated) and qualitative (microscopic images of asphaltene clusters) observations, the characteristics of asphaltene were classified in terms of their shape, size, and amount for different oil/solvent types, pressure, and temperature. Continually, the same n-alkane solvents and heavy-oil were used in gravity drainage recovery experiments on unconsolidated sands. 2-D visual (Hele-Shaw type) and 3-D (cylindrical) sand pack experiments were carried out at the same temperatures and pressure conditions used for the PVT experiments. The asphaltene precipitated in the sand pack and in the produced oil was collected, and the standard SARA analysis was applied to determine the optimal operating conditions yielding the highest recoveries with minimal pore plugging. Moreover, the pore plugging process was analyzed through the visual inspection of 3-D sand pack experiments and the 2-D visual model using microscopic visualization and cross-checked against oil recovery rate. The asphaltene characteristics and concentration were evaluated using the microscope visualization and refractive index values, respectively. Eventually, optimal application conditions for solvent and thermally-aided solvent injection were listed for a wide range of heavy-oil and solvent types.