Experimental Study and Pilot Test of Combined Gel Treatment and Surfactant Imbibition Technology in High Temperature, High Salinity Reservoir

Abstract With the depletion of petroleum resources, EOR in marginal oilfields attracts more and more concern worldwide. For high temperature, high salinity (HTHS) reservoirs, CEOR shows promising potential while faces great challenge due to adverse effects on chemicals by severe reservoir conditions. Curling, thermal degradation, and breakdown of molecular segment caused by HTHS makes polymer an unsatisfactory candidate. How to effectively improve mobility control and achieve high recovery becomes one of the key issues in CEOR of HTHS reservoirs. Herein, a CEOR method combining gel treatment and surfactant imbibition was put forward and evaluated for a HTHS reservoir with reservoir temperature 126 °C, injection brine salinity 117,000 mg/L, and divalent ion content 3,340 mg/L. Gel formulation was optimized to suit application requirement. Tests on solubility, thermal stability at HTHS conditions, and spontaneous imbibition were performed for several surfactants to obtain suitable chemical agent for target reservoir. An organic crosslinker was added to the diluted solution of a heat tolerant, salt resistant Star-shape polymer to form flowing gel. Evaluation results showed the viscosity of gel reached 43,900 mPa·s at 5th day and standed at 43,500 mPa·s after 180 day aging, demonstrating good thermal stability. An anion-nonionic surfactant showed good compatibility with brine, acceptable thermal stability at HTHS, and sound spontaneous imbibition recovery. One injector three producer pilot test was conducted employing the gel plus surfactant formulation and an incremental oil production of 3660 MT was accomplished. In-lab evaluation and pilot test displayed inspiring result of gel with surfactant imbibition technology, which provides a good option for CEOR of HTHS reservoirs.