High water content (>50%) water-in-oil (W/O) emulsions have been suggested as a drive fluid for recovery of heavy oil in high permeability reservoirs. High emulsion viscosity can provide sufficient mobility control and its oil-external nature enables a semi-miscible process while displacing crude oil. Initially crude oil itself was suggested as base oil for generating this type of emulsion, and both laboratory experiments and field pilot have demonstrated its high efficiency in recovering heavy crude. Recently used engine oil was suggested as a candidate for generating W/O emulsions for the same purpose, because of its better stability and more favorable viscosity.
In this work a stable emulsion was generated by mixing used engine oil (40%) and brine (60%) under high shear. Then this emulsion was injected into sandstone cores (400 ~ 2400 md, 0.5 or 1 ft in length) at several different rates for periods of several days, to characterize its stability and flow properties while passing through porous media. Small amounts of water breakout were observed in the emulsion effluents. Higher values of water breakout were observed in lower permeability rock, at higher injection rate, and with longer core lengths. The the emulsion was also injected into sand-packed slimtubes (~8000 md) of 3-ft and 6-ft lengths, and less than 1% of free water was observed from the effluents at moderate injection rates, verifying good stability of this emulsion passing through high-permeability porous media. Pressure drops were found to be quite stable at any constant rate of injection for all corefloods, indicating no plug-off effect from the soot particles in the emulsion.
Numerical simulations on emulsion flooding a homogeneous heavy oil reservoir were also conducted by simulating the emulsion as single-phase oil, and the breakdown of emulsion as a co-injection of water together with this oil. Results indicated significant improvement of displacement pattern and oil recovery compared to water flooding.
Steam-Assisted Gravity Drainage (SAGD) is the main commercial technology used for in-situ recovery of Canadian heavy oil and Bitumen. It is commercially proven and delivers high oil rates and high ultimate recoveries. One of the long-term concerns with the SAGD process is high energy intensity and related environmental impacts. Hybrid processes have been developed to take partial advantage of steam and solvent processes while introducing a more efficient and more economically viable recovery methods. Several processes such as Propane-SAGD, Expanding Solvent- SAGD (ES-SAGD), Solvent-Aided Process (SAP), Liquid Addition to Steam to Enhance Recovery (LASER) and Steam- Alternating-Solvent (SAS) were proposed; some of them currently under pilot test. Hybrid steam-solvent processes aim to accelerate oil production rate with lower cost than SAGD and also increase the ultimate oil recovery. Despite remarkable amount of laboratory and computational studies on these processes, there was no extensive critical review of the knowledge obtained for more than a decade. The current level of understanding of the hybrid processes and knowledge around the fundamental physics and mechanisms involved are not fully satisfactory. We believe that a critical review of the status of the hybrid processes will fill the gap by shedding the light on the deficiencies and the limitations of the process, further development areas, and new research topics. Analytical, numerical simulations, laboratory modeling efforts along with pilot test results are summarized. In addition, the main technical challenges of different aspects of hybrid steam-solvent processes are analyzed at different levels. In this paper, special attention is given to a) The effect of reservoir and operational parameters, b) solvent injection strategies, c) The inconsistency between laboratory, simulation and field results and d) problems faced in numerical modeling (capturing the physics of heat and mass transfer). It is believed that a good compilation of the records produced over one decade will constitute a useful reference for the industry and academics. Analytical, simulation, laboratory studies and reported field data strongly support hybrid steamsolvent processes. However, the results are mixed at different level levels and there exists some inconsistencies. The cost of the solvent retained in the reservoir is the major concern and the economics of selected hybrid steam-solvent process for a specific reservoir has to be verified using available tools. The main challenges are verifying effective mixing of the solvent with the in-situ bitumen, managing the solvent placement and distribution in the reservoir, reliably determining the incremental benefit of solvent-addition and ensuring economic solvent recovery.
This research is a study of the in-situ upgrading of Jobo crude oil using steam, tetralin or decalin, and catalyst (Fe(acac)3) at temperatures of 250 °C, 275 °C and 300 °C for 24 hours, 48 hours and 72 hours using an autoclave. Viscosity and API gravity changes were investigated. We found that tetralin and decalin alone were good solvents for heavy oil recovery. Tetralin or decalin at concentrations of 9% (weight basis) could reduce the Jobo crude oil viscosity measured at 50 °C by 44% and 39%. Steam alone had some upgrading effects. It could reduce the oil viscosity by 10% after 48 hours of contact at 300°C. Tetralin, decalin or catalyst showed some upgrading effects when used together with steam and caused 5.4%, 4% and 19% viscosity reduction compared with corresponding pre-upgrading mixture after 48 hours of reaction at 300°C. The combination of hydrogen donor tetralin or decalin and catalyst reduced the viscosity of the mixture the most, by 56% and 72% compared with pre-upgrading mixture. It meant that hydrogen donors and catalyst had strong synergetic effects on heavy oil upgrading. We also found that 300 °C was an effective temperature for heavy oil upgrading with obvious viscosity reduction in the presence of steam, hydrogen donors and catalyst. Reaction can be considered to have reached almost equilibrium condition after 48 hours. The study has demonstrated that in-situ heavy oil upgrading has great potential applications in heavy and extra heavy oil recovery.
Steam Assisted Gravity Drainage (SAGD) is the preferred in-situ technology to recover heavy oil and bitumen from Canadian reservoirs. It is commercially proven, delivers high oil rates and high ultimate recoveries. Given the large energy requirement and the volume of emitted greenhouse gases from SAGD process, there is a strong motivation to develop enhanced oil recovery processes with lower energy and emission intensities. Addition of suitable alkane solvents to steam in processes such as ES-SAGD can reduce the use of energy and green-house emissions in SAGD. Potential hydrocarbon additives provide an additional means to raise oil phase mobility beyond that achieved by heat.
The Athabasca reservoir contains small amounts of initial solution gas which is negligible compared to conventional oil reservoirs, however, even small amounts of solution gas might play an important role in thermal processes driven by gravity drainage. In majority of experimental and simulation study of Solvent-Assisted SAGD processes carried out, initial solution gas is not included.
In this study, extensive simulation study is performed to understand the mechanism of solvent addition to SAGD process when initial solution gas is present. Simulation results show that initial solution gas reduces the oil recovery by SAGD process especially in Athabasca reservoir. A varying thickness non-condensable gas layer impedes heat transfer from the condensing steam to the bitumen zone. Hydrocarbon additives are not very effective in the presence of high initial solution gas ratio. Exsolved solution gas causes early condensation of steam and additives. As a result, hydrocarbon additives have diminished opportunities to contact bitumen and are unable to create a high oil phase mobility zone.
In addition, a number of simulations are conducted to understand the role of operating pressure and pressure imbalance between SAGD well pairs. The difference between the operating pressure of adjacent SAGD well-pairs can be used to remove accumulated solution gas from the steam chamber.
Steam Assisted gravity drainage (SAGD) is demonstrated as a proven technology to unlock heavy oil and bitumen in Canadian reservoirs. One of the long-term concerns with the SAGD process is high energy intensity and related environmental impacts. The addition of suitable hydrocarbon solvents to steam has long been regarded as the simplest and most effective method to increase SAGD performance. Higher oil recovery, accelerated oil production rate, reduced steam to oil ratio and generally more favorable economics is expected from the addition of potential hydrocarbon additives to steam.
This paper summarizes experimental results of addition of potential solvents to steam in SAGD process. N-Hexane and nheptane were co-injected with the steam and the experimental results were compared with pure steam injection. In addition,
pure heated n-hexane was injected in one experiment to assess the performance of solvent-based processes. Experiments were conducted using a scaled two-dimensional physical model. Peace River Bitumen samples were used to conduct the experiments at 80 psia.
Experimental results were analyzed to determine the key variables involved in Solvent Assisted SAGD (SA-SAGD) processes. Solvent choice is not solely dependent on mobility improvement capability but also reservoir properties and operational conditions. Co-injection of suitable solvents with the steam led to accelerated oil production rate, higher oil recovery and lower energy to oil ratio. Solvent requirement for pure heated n-hexane injection was considerably high. The vaporized solvent chamber expansion was slow due to low heat content of the solvent and heat losses.
Using horizontal wells for In-Situ combustion operation brings new advantages. Horizontal wells provide larger contact area between the formation and combustion front. Mobilized oil does not necessarily should pass through cold oil bank to be produced and this improve the overall performance of the process. Combustion Assisted Gravity Drainage (CAGD) is an integrated horizontal well air injection process for in situ recovery and upgrading of heavy oil and tar sands bitumen. Short distance air injection and direct mobilized oil production are main features of this process that lead to stable sweep and high oil recovery. These characteristics identify CAGD process as a highly potential oil recovery method.
This paper summarizes recent experimental and numerical studies of CAGD process. In-Situ combustion experiments have been carried out using a rectangular 3D combustion cell with dimensions of 0.62 m, 0.41 m and 0.15 m. Enriched air (50% O2) has been injected to create and sustain the combustion front in the model. Experimental results showed that oil displacement occurs mainly by gravity drainage. Vigorous combustion was observed at the early stages near the heel of injection well, where peak temperature of about 690 °C was recorded. Moreover, a thermal simulator was used for history matching the laboratory data, while capturing the main mechanisms. Simulation results showed very good agreement between numerical and experimental data in terms of fluid production rate, combustion temperature and produced gas composition.