An Improved Vapour Solvent Injection Technique for Enhanced Heavy Oil Recovery
There are tremendous heavy oil and bitumen resources in Canada, and most of them are located in the Western Canadian Sedimentary Basin. Thermal-based recovery techniques, such as steam flooding, cyclic steam stimulation (CSS), and steam-assisted gravity drainage (SAGD), are effective and have been widely applied in the field to reduce heavy oil viscosity. However, thermal-based methods are costly and uneconomic, particularly for reservoirs with a thin net-pay. In Saskatchewan, half of the heavy oil resources are contained in reservoirs with a pay zone thickness of less than 10 metres. Non-thermal methods, such as cold production, and solvent-based methods, are the alternative approaches. Cold production, such as cold heavy oil production (CHOP) and cold heavy oil production with sands (CHOPS), suffers low recovery factor, which is approximate 5–10% of original oil in place (OOIP). Solvent-based heavy oil recovery methods represent a promising technique that has been extensively studied by many researchers. It has the potential to recover heavy oil resources more economically and in a more environmentally friendly fashion in cases in which the thermal-based method is not applicable or after CHOP/CHOPS processes. Currently, traditional solvent injection methods include continuous injection processes, such as vapour extraction (VAPEX), and cyclic injection processes, such as cyclic solvent injection (CSI). The low production rates of VAPEX are observed in field tests. CSI does not show exciting results due to the quick pressure depletion and the sudden reservoir energy loss, which causes the oil to regain its viscosity. Thus, a more effective solvent injection technique is urgently required to overcome the disadvantages in traditional solvent injection processes. In this study, a new cyclic solvent production (CSP) technique, cyclic production with continuous solvent injection (CPCSI), was proposed and evaluated through experiments and numerical simulations. Low permeability physical models were packed with Potter glass beads and then saturated with Western Canadian heavy oil samples at connate water saturation. Pure propane was used as gaseous solvent that was injected into the physical models continuously to extract the heavy oil while the producer was operated with a cycle of long shut-in time and short open periods. Solvent breakthrough time, heavy oil production rate, pressure profile, and asphaltene content were measured. The effects of drainage height, gravity, and production configurations were evaluated. Numerical simulations were performed using CMG STARS to history match the experimental results. It is found that the simulation can match the experimental results but it has the limit to predict the performance for different models. It was found that the heavy oil was diluted and drained down by gravity during the shut-in periods and then produced in the open periods via solution gas drive and gas flush. In comparison with VAPEX and CSI, CPCSI offers a free gas drive to flush the diluted oil out while the reservoir pressure is maintained so that the diluted heavy oil viscosity will not be re-increased. The CPCSI process can be an alternative optimization production scenario for applying solvent-based in-situ EOR techniques in Western Canadian heavy oil reservoirs.
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Faculty of Graduate Studies and Research, University of Regina