Low-tension gas process in high-salinity and low-permeability reservoirs
- PDF / 1,170,661 Bytes
- 16 Pages / 595.276 x 790.866 pts Page_size
- 25 Downloads / 188 Views
ORIGINAL PAPER
Low‑tension gas process in high‑salinity and low‑permeability reservoirs Alolika Das1 · Nhut Nguyen1 · Quoc P. Nguyen1 Received: 28 November 2019 © The Author(s) 2020
Abstract Polymer-based EOR methods in low-permeability reservoirs face injectivity issues and increased fracturing due to near wellbore plugging, as well as high-pressure gradients in these reservoirs. Polymer may cause pore blockage and undergo shear degradation and even oxidative degradation at high temperatures in the presence of very hard brine. Low-tension gas (LTG) flooding has the potential to be applied successfully for low-permeability carbonate reservoirs even in the presence of high formation brine salinity. In LTG flooding, the interfacial tension between oil and water is reduced to ultra-low values (10−3 dyne/cm) by injecting an optimized surfactant formulation to maximize mobilization of residual oil post-waterflood. Gas (nitrogen, hydrocarbon gases or CO2) is co-injected along with the surfactant slug to generate in situ foam which reduces the mobility ratio between the displaced (oil) and displacing phases, thus improving the displacement efficiency of the oil. In this work, the mechanism governing LTG flooding in low-permeability, high-salinity reservoirs was studied at a microscopic level using microemulsion properties and on a macroscopic scale by laboratory-scale coreflooding experiments. The main injection parameters studied were injected slug salinity and the interrelation between surfactant concentration and injected foam quality, and how they influence oil mobilization and displacement efficiency. Qualitative assessment of the results was performed by studying oil recovery, oil fractional flow, oil bank breakthrough and effluent salinity and pressure drop characteristics. Keywords Enhanced oil recovery · Foam · Microemulsion · Carbonate · High salinity · Low permeability
1 Introduction Conventional alkali–polymer (AP), surfactant–polymer (SP) and alkali–surfactant–polymer (ASP) flooding methods have limited success in carbonate formations because of typical high reservoir salinity, low permeability and complex rock–fluid interactions. The use of polymer is restricted due to plugging and shear degradation, particularly for very tight carbonate reservoirs (Farajzadeh et al. 2015). Lower molecular weight polymer might be a solution, but higher concentration would be required to achieve an equivalent viscosity, which might impact the economic feasibility of Edited by Yan-Hua Sun * Quoc P. Nguyen [email protected] 1
Hildebrand Department of Petroleum and Geosystems Engineering, University of Texas at Austin, 200 E. Dean Keeton, Austin, TX 78712, USA
the process. Although finding a suitable surfactant at high salinities is possible, relatively high viscosity of oleic phase and oil–water emulsions compared to the displacing aqueous phase prompt the use of a mobility control agent. Low-tension gas (LTG) flooding process replaces polymers with foam, typically generated with an injected gas such as n
Data Loading...
