This paper presents the numerical modeling study to investigate the leakage possibility of CO 2 in a deep saline aquifer where caprock is discontinuous or does not exist. As a result of simulations for 30 years of injection and 5000 years of monitoring, injected CO 2 rises by buoyancy. However, it does not reach the surface, and the height of CO 2 moving upward is not high from the effect of residual and solubility trap mechanisms. Meanwhile, when the vertical permeability is higher than the actual, CO 2 moves highly upward and the phase of CO 2 changes into a gas phase. However, it is shown that CO 2 does not affect the surface during the monitoring period. When CO 2 is injected into a deeper aquifer, it is more effective and stable for CO 2 sequestration. Finally, CO 2 may leak faster when there are flow networks composed of faults and porous mediums. For this reason, we should pay attention to the formation lies on the target aquifer to prevent the possible leakage of injected CO 2 .

The rotary steerable system(RSS) is technically capable of controlling a direction during drilling by changing angle of bits or applying lateral force. The RSS has an advantage which is reducing the drilling time due to its high rate of penetration(ROP). RSS has been widely applied to develop oil and gas reservoir, as well as unconventional resources such as shale gas. This study presents technical characteristics about mechanism of the RSS operating and introduces laboratory experimental cases and field projects. Laboratory tests show that it is possible to predict directional behavior of RSS. Furhemore, field projects show that the drilling time is reduced by the increasing ROP since slide was not required. The results in the directional behavior by various concrete strength and bit characteristics can be used to build and apply to a directional drilling plan for oil and gas field development.

This study presents the Bottom-hole pressure (BHP) behavior with different wettabilities and the optimal design scheme to effectively inject CO 2 into the Gorae-V aquifer. As a result, the injection rate and injectivity were increased as the wettability condition became more waterwet. However, the more wettability condition becomes water-wet, the more the ultimate CO 2 injection volume decreases. When the injectivity was 346 ton/day/Mpa at the Gorae-V aquifer, the aquifer can sustain CO 2 injection at a rate of 2,425 tons per day over this time period. A design for a complete CCS system was developed based on the existing off-shore pipeline in combination with new on-shore CO 2 transport infrastructure, and a pressure of 12.8 MPa is required at the CO 2 source to maintain this injection rate.

This paper presents a simulation study of fluid flow in the tubing on a reservoir system formed in a severe cold region. The thickness of the permafrost and specific gravity of the oil were applied by field survey. Then, flowing improvement techniques for oil production such as progressive cavity pump (PCP), insulated casing, electric trace heater and gas lifting were applied. For the reservoir located at 1,000 m depth in the Arctic region, the thicker the permafrost layer was, the more the mobility of oil in the tubing declined. By applying the flowing improvement techniques to this reservoir, the effect of the heater increased with the oil containing heavier components, and it was found that the production rate was improved as the heater installation interval became deeper. Despite the gas lifting method showing better productivity compared to other methods, there was an optimal injection rate at which the production rate became maximum. Moreover, it was shown that increasing the temperature of injection gas had little effect on enhancing the oil flow in tubing. Based on these results, flowing improvement techniques were applied to the oil wells in the Ada field. The productivity by PCP of Bashenkol_1X well, which contained comparatively light oil, increased 3.75 times more than natural state. Also, additional installation of insulated casing could yield better production. In the case of Bashenkol_3X in which 19.2 o API of heavy oil was reserved, oil production was impossible without flowing improvement methods. This well was able to produce 158 BOPD of oil by installing PCP with insulated casing and additional installation of heater increased production rate to 267 BOPD. Meanwhile, although the gas lifting method can greatly improve productivity, the applicability and cost should be considered prior to its being applied.