Methane foam flow behaviour at varied rock permeabilities under high pressure and high temperature conditions / Ridhwan Zhafri Kamarul Bahrim

• Main Author: Kamarul Bahrim, Ridhwan Zhafri
• Format: Thesis
• Language: English
• Published: 2022
• Subjects: Nonmetallic minerals
• Online Access: https://ir.uitm.edu.my/id/eprint/76824/1/76824.pdf; https://ir.uitm.edu.my/id/eprint/76824/

Gas is injected into the reservoir as an oil displacing agent, to provide energy for fluid mobilization or mix with the oil to decrease its viscosity and ease extraction towards the oil producer wells. However, due to the lower viscosity of gas compared to oil, this method is negatively affected by viscous fingering and gravity segregation, which reduces the oil displacement efficiency of gas. To mitigate this, foam was introduced to complement the secondary recovery and Enhanced Oil Recovery (EOR) methods such as the immiscible gas and water-alternate-gas (WAG) injection. However, the availability of the foam EOR studies under actual Malaysian high pressure and temperature field conditions, using representative fluid and rock samples, are limited to non-existent. Permeability has shown in past studies to affect the main foam behaviour particularly on the maximum gas mobility reduction factor of foam, fmmob, and the limiting water saturation, at which foam starts to de-stabilize, Sw*. The study comprised of three laboratory experiments, modelling and simulation using lab derived foam parameters. The first two experiments were done to select the most stable surfactant under reservoir temperature of 94°C and to qualitatively observe foam bubble movement in micromodel chip. Then, coreflood experiments were conducted to study the effect of permeability on foam, using three reservoir core plugs obtained from Reservoir R of Field B, with the Darcy permeability of 57.5 mD, 191 mD, and 493 mD. Methane was used as the injection gas, which is the field’s main gas component. Results showed that the maximum gas mobility reduction factor of foam increases with permeability with values of 2.90 x 104 , 6.10 x 104 , and 3.10 x 105 , respectively. Whereas, the limiting water saturation, Sw*, shows decreasing trend of 0.56, 0.45, and 0.39 with increasing permeability respectively. Lastly, the lab derived foam model parameters were applied in commercial reservoir simulator STARSTM and several cases were simulated. Simulation shows that foam, when applied in WAG process, provides up to 51% oil recovery as compared to 35% without foam. It is concluded that foam can effectively improve the conformance of the oil displacement in presence of reservoir heterogeneity. Additionally, trends of foam model parameters differ by a certain magnitude when compared with the values in selected literatures. This strongly necessitates the requirement to conduct experiments under representative conditions as to reduce the uncertainties during EOR field implementation studies