Laboratory Investigation of Low-Tension-Gas Flooding for Improved Oil Recovery in Tight Formations

Abstract

Summary This paper establishes low-tension gas (LTG) as a method for submiscible tertiary recovery in tight sandstone and carbonate reservoirs. The LTG process involves the use of surfactant and gas to mobilize and then displace residual crude after waterflood at a greatly reduced oil/water interfacial tension (IFT). This method allows extending surfactant enhanced oil recovery (EOR) in sub-20-md formations in which polymer is impractical because of plugging, shear, or the requirement to use a low-molecular-weight polymer. The proposed strategy is tested through the coinjection of nitrogen and a slug/drive surfactant solution. Results indicate favorable mobilization and displacement of residual crude oil in both tight-carbonate and tight-sandstone reservoirs. Tertiary recovery of 75−90% of residual oil in place (ROIP) was achieved for cores with 2- to 15-md permeability. High LTG tertiary recovery is contrasted with results from reference surfactant (no gas) flooding (28% ROIP tertiary recovery) and immiscible gas coinjection (no surfactant) flooding (13% ROIP tertiary recovery). In addition, high initial oil saturation was tested to determine the process tolerance to oil and to evaluate the potential for application during secondary recovery. Under such conditions, this method achieved a recovery of 84% of oil originally in place (OOIP), suggesting the potential application of this process at secondary recovery. To better understand the physical mechanisms that affect mobilization and displacement, the early production of an elongated oil bank at reduced fractional flow of oil was shown to be an attribute of high crude-oil relative mobility and low pore volume (PV) available to mobile oil. This should favorably affect economics during chemical flooding by accelerating the production of an oil bank. Next, by application of salinity as a conservative tracer and oil material balance, gas saturation during LTG floods was calculated to be 18 to 22%. By comparing effluent salinity profiles across floods, a qualitative understanding of in-situ fluid dispersion associated with macroscopic displacement stability is developed. The results indicate that in-situ foaming was present, which enabled mobility control, and that stable displacement of in-situ fluids was achieved during flooding.