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_x000D_ 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 ° 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.

Permafrost Heavy Oil Pumping Heater Gas Lifting

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