This study reports the size-dependent interactions of silica nanoparticle (NP) dispersions with oil, which facilitate oil recovery from sandstone rock. Herein, we studied various 7–22 nm sized colloidal silica NPs (CSNPs; the colloidal state when dispersed in aqueous solutions) and fumed silica nanoparticles (FSNPs; the dry powder state). Interfacial tension at the oil-nanofluids interface declined with decreasing NP size in a range from 7 to 22 nm. This is because NP spatial density at the interface increased with smaller particle size, thereby, the interface area per NP decreased to approximately 1/30, and interfacial energy had reduced enough. In addition, smaller NPs more strongly were adsorbed to the rock because of improved diffusion in suspension and increased adsorption density. This caused creating a wedge film between oil and rock, which changed the oil contact angle. Due to this effect, core flooding experiments indicated that oil recovery increased with decreasing particle size. However, FSNP dispersions exhibited low recovery factor because of particle aggregation. This phenomenon may facilitate massive permeability reduction, thus causing oil trapping inside rock pore. We found that both the sizes and types of CSNPs and FSNP affected the Interfacial tension at oil-water interface and rock surface wettability, which influenced ultimate oil recovery.

The depressurization method is known as the most productive and effective method for successful methane recovery from hydrate deposits. However, this method can cause considerable subsidence because of the increased effective stress. Maintenance of geomechanical stability is necessary for sustainable production of gas from gas hydrate deposits. In this study, the cyclic depressurization method, which uses changing the bottomhole pressure and production time during primary and secondary depressurization stage, was utilized in order to increase stability in the Ulleung Basin of the Korea East Sea. Various case studies were conducted with alternating bottomhole pressure and production time of the primary and secondary depressurization stages over 400 days. Geomechanical stability was significantly enhanced, while cumulative gas production was relatively less reduced or nearly maintained. Specially, the cumulative gas production of the 6 MPa case was more than three times higher than that of the 9 MPa case, while vertical displacement was similar between them. Therefore, it was found that the cyclic depressurization method should be applied for the sake of geomechanical stability.

Although various simulation studies on gas hydrate production have been conducted, a single vertical well in the cylindrical system has been adopted in most research. However, this system has a limited ability to predict commercial production in gas hydrate reservoirs. In order to facilitate commercial production, a field-scale reservoir model with a multi-well system must be constructed using geological data, such as seismic data, well logging data, core data, etc. The depressurization method is regarded as a practical production strategy because it has high levels of production efficiency and economical effectiveness. However, this method can lead to subsidence due to the increased effective stress. In this work, we studied a production simulation strategy for commercial gas hydrate production. A three-dimensional geological model with a realistic field scale is constructed using seismic and well logging data from the Ulleung Basin of the Korean East Sea. All of the grids are refined in the I and J direction, and the grids near the production well are very small to consider realistic hydrate dissociation. The cyclic depressurization method is adopted for the increase in the geomechanical stability, rather than the non-cyclic depressurization method. Various case studies are conducted with alternating bottomhole pressures for the primary and secondary depressurization stages over 100 days. Geomechanical stability is significantly enhanced, while cumulative gas production is relatively less reduced or nearly maintained. In particular, all cases of the cumulative gas production at 6 MPa during the secondary depressurization stage are similar to the non-cyclic case, while the geomechanical stabilities of those cases are restored. This study is thought to have contributed to the development of technology for commercial gas hydrate production with a geomechanical stability study using a reservoir-scale model with a multi-well system.

Shallow biogenic gas fields are widely distributed in the world, but their development is limited due to their smaller scale and lower reservoir pressure compared to conventional gas fields. However, as the discovery of new reservoirs becomes increasingly challenging and the demand for gas as a clean energy source continues to rise, the development of shallow biogenic gas fields is necessary. Specially, the total biogenic gas reserves in Indonesia are around 152.9 TCF, and the contribution of biogenic gas to the total reserves is only around 7.2 TCF (4.7%). In this study, we conducted reservoir and geomechanical simulation studies for the enhancement of gas recovery and analysis of the geomechanical stability in Indonesian biogenic shallow gas field. Geomechanical analysis is essential because many shallow gas fields are consisted of unconsolidated sandstone.

Hydraulic fracturing and horizontal drilling technology had contributed to the commercial shale gas production. However, hydraulic fracturing requires a water for the drilling fluids. Many countries have shale gas fields and are water stress country such as China. CO2 fracturing have many advantages than water fracturing. One is that CO2 gas is a greenhouse gas. The other is that SRV of the CO2 fracturing is much larger than that of the water fracturing due to the low viscosity of CO2 gas. Devonian age Besa River shale gas play in the Liard Basin of northeastern BC with net estimated sales gas of 48 TCF over an area of 430,000 acres. We have conducted many case studies about CO2 fracturing simulation and reservoir simulation in the shale gas of Liard basin. In order to study, mechanical earth model was constructed. From this case study, we designed optimum fracturing pattern and development plan.