Successful Laboratory Investigation of Low-Tension-Gas (LTG) Flooding for Tertiary Oil Recovery in Tight Formations (~10mD to Gas)

Abstract

Abstract This paper establishes Low-Tension-Gas (LTG) as a method for sub-miscible tertiary recovery in tight sandstone and carbonate reservoirs. The LTG process involves the use of a low foam quality surfactant-gas solution to mobilize and then displace residual crude after waterflood. It replicates the existing Alkali-Surfactant-Polymer (ASP) process in its creation of an ultra low oil-water interfacial tension (IFT) environment for oil mobilization, but instead supplements the use of foam over polymer for mobility control. By replacing polymer with foam, chemical Enhanced Oil Recovery (EOR) methods can be expanded into sub-30 mD formations where polymer is impractical due to plugging, shear, or the requirement to use a low molecular weight polymer. The proposed strategy is tested through low-quality, low rate co-injection 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% ROIP was achieved for cores with 2-15 mD permeability. Consistent with successful ASP floods typically observed in high permeability rocks, a large oil bank was observed at the effluent before the production of Windsor Type III and Type II(-) microemulsion. High LTG tertiary recovery is contrasted with results from reference surfactant (no gas) flooding (28% ROIP tertiary recovery) and immiscible gas co-injection (no surfactant) flooding (28% ROIP tertiary recovery). Additionally, high initial oil saturation was tested to determine process tolerance to oil and evaluate potential for application during secondary recovery. During flooding at initial oil saturation (1-Swi), LTG injection achieved recovery of 84% of OOIP with similar fractional flow, mobility, and other process attributes to those exhibited during LTG tertiary flooding. This reduces the risk that in-situ oil may cause unfavorable displacement due to destabilization of liquid lamellae which provide mobility control by creation of a dispersed gas phase (foam). Potential application at secondary recovery is suggested which would improve reserve capture and reduce high pressure gradients typically associated with flooding tight reservoirs. To better understand the physical mechanisms which impact mobilization and displacement, early production of an elongate oil bank at reduced fractional flow of oil was shown to be an attribute of high crude oil relative mobility and low pore volume available to mobile oil. This should favorably impact economics during chemical flooding by accelerating 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 18-22%. This is contrasted with gas saturation during co-injection of 5% and indicates that a large dispersed gas phase was present during LTG flooding and is consistent with stable lamellae production during flooding. Finally, by comparing effluent salinity profiles across floods, qualitative understanding of dispersion and macroscopic stability is developed. Plots show a reduction in dispersion for LTG flooding versus surfactant flooding, which indicates improvement in mobility ratios across the displacement fronts. Macroscopic stability of displacement fronts was studied via pressure derived mobility ratios. Approximate parity of relative mobility of injected fluids was observed with respect to relative mobility of displaced water at true residual oil saturation and interpreted relative mobility of a formed oil bank. These results indicate that in-situ foaming was present which enabled mobility control, and that stable displacement of in-situ fluids was achieved during flooding.