Investigation of effects of thermal shock technique on shale oil rock properties and its application to increase oil recovery from unconventional reservoirs in conjunction with cyclic gas injection
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Previous studies have demonstrated that injection of cold fluids into hot formations could create new fractures. This experimental study extends the previous researches by demonstrating that implementing Thermal Shock (TS) technique in conjunction with Cyclic Gas Injection (CGI) increase oil recovery from shale oil reservoirs. It is believed that injecting cold fluid into a hot reservoir results in Thermal Shock (TS) that alters reservoir rock properties and creates new cracks and/or extends existing ones in the rock, which consequently enhances the reservoir conductivity (and thus oil recovery) by connecting to natural fractures. To provide a complete overview of the process; first, using low-temperature nitrogen gas, this study examines effects of implementing the thermal shock technique on porosities, permeabilities, and rock mechanical properties of unconventional reservoirs core samples. Three cycles of thermal shock were applied on two core samples from unconventional reservoirs: one actual core sample and one outcrop. After heating each sample up to 180 °F for one hour, nitrogen at 0 °F and 1,000 psi was injected into the sample for 5 minutes. Porosity, permeability and ultrasonic velocities of each core sample were measured both prior to and after conducting the thermal shock technique. Also, Computed Tomography (CT) scanner was used to scan the core samples before and after performing the thermal shock test. Effectiveness of the thermal shock technique in conjunction with cyclic gas injection method on oil recovery factor was investigated by injecting two gases (nitrogen and carbon dioxide) into outcrop core samples from Eagle Ford at various combinations of temperature and pressure. After heating the samples to 180 °F, nitrogen was injected into them at various combinations of temperatures (-15 °F, 0 °F, 32 °F, and 72 °F) and pressures. Nitrogen was injected at 1,000 psi, 1,500 psi, 2,000 psi, and 3,000 psi, while carbon dioxide was injected at 1,000 psi, 2,000 psi, 3,000 psi and 4,000 psi. Porosity, permeability and ultrasonic velocity measurements were conducted on the samples, which carbon dioxide was injected into. In addition, dynamic Young’s moduli, Poisson’s Ratios, brittleness ratio, and fracability index of these core samples were calculated prior to and after performing the thermal shock technique to thoroughly evaluate efficacy of this technique. Moreover, thermal stress resulted from applying the thermal shock technique on the core samples were calculated. The results clearly demonstrate that applying thermal shock technique on the core samples created cracks on the surfaces of the samples, increased their porosities and permeabilities, and altered their Young’s moduli, Poisson’s ratios, brittleness ratios and fracability indices. Additionally, the results indicate that injecting nitrogen and carbon dioxide at low temperatures results in creating new fractures and/or extending the existing ones yielding to higher oil recovery factor than injecting them at ambient temperature. It was also observed that injecting cold CO2 enhanced both porosities and permeabilities of the core samples. Hence, implementing cyclic cold gas injection method improves the efficacy of the current industry practice of cyclic gas injection technique in shale oil reservoirs.