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Past laboratory experiments have shown Low Tension Gas (LTG) floods to be a promising tertiary oil recovery technology in low permeability and high salinity carbonate reservoirs. Gas availability and cost are the major challenges in applying this technology under field conditions. The cost of importing gas from an outside source or on-site generation of nitrogen can be eliminated if the produced gas from the oilfield can be re-injected for generating in-situ foam. Also, the cost of both purchasing freshwater and processing the produced water can be decreased dramatically by injecting both the ultra-low IFT inducing surfactant slug and the drive at the same (constant) salinity. LTG corefloods were conducted for a carbonate reservoir with low permeability (<100 mD), moderate temperature (69 °C) and high formation brine salinity (180,000 ppm). Microemulsion phase behavior experiments were conducted at reservoir conditions with different gases. Dynamic foam propagation experiments with methane and a mix of methane-ethane (80 mol. % methane) were performed. The effect of microemulsion (generated using the constant salinity approach) on foam stability was also studied. Optimal conditions for both foam propagations and IFT reduction based on these experiments were identified and used to further develop injection strategies for enhancing oil recovery in coreflood on the same rock type. High pressure microemulsion phase behavior experiments showed that produced gas increased the optimum solubilization ratio compared to methane or nitrogen. The solubilization ratio at fixed salinity was a strong function of the surfactant formulation, pressure and the composition of the produced gas. Foam strength experiments showed that produced gas could generate an in-situ foam strength similar to the nitrogen gas. Lower foam quality showed higher apparent viscosity at lower injected surfactant concentration. Preliminary results from core flood experiments indicated that using constant salinity for both slug and drive could result in a remarkable increase in the oil recovery, even though ultra-low IFT inducing surfactants were only injected for a small slug. It also helped improve surfactant transport, which is important for the application of LTG process in high salinity carbonate reservoirs without the use of alkali. The results have advanced our understanding of how field gas can be combined with a high performance surfactant formulation to (i) provide necessary conformance control for surfactant flooding, (ii) improve surfactant transport in a very high salinity environment without the need for alkali, and thus soft water, (iii) reduce the complexity of salinity reduction from slug to drive that is typically required in ASP flooding, and (iv) further improve surfactant efficiency due to the increase of oil solubilization and oil viscosity reduction with the injection gas enrichment.

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Controlling the reactivity of HCl is the most viable approach to successfully stimulate a high-temperature carbonate reservoir. It is essential to retard the HCl-carbonate rock reaction to achieve the optimum balance between total fluid used and enhancing well production. However, drawbacks intrinsic to the technology architectures have prevented the industry-wide adoption of these inventions. For instance, the conventional emulsified acid is well documented to exhibit high friction pressure, is cumbersome to prepare, and performance is sensitive to a multitude of parameters. The recently developed singleaqueous-phase retarded acid (SAPRA) represents one big step toward the right direction, but there is certainly ample room for improvement. This paper presents the next generation of SAPRA system and its laboratory findings. In this system, the HCl reactivity is regulated and retarded by a single, potent low-dosage additive, which is compatible with selected acid corrosion inhibitors, non-emulsifiers, H2S scavengers, and other commonly used additives, and if necessary, friction reducers as well.