Low Tension Gas Flooding as a Novel EOR Method: An Experimental and Theoretical Investigation

Abstract

Low Tension Gas (LTG) flooding is a novel EOR process which can address challenging reservoir conditions such as high salinity, high temperature, and tight rock. Current process understanding is limited, and a joint experimental and modeling approach allows for both interpretation and insight into the complex interactions between the key process parameters of salinity gradient, foam strength, microemulsion phase behavior, and phase desaturation in order to achieve a physically correct and predictive process model. We performed a series of corefloods in high permeability Berea sandstones (~500 mD) to demonstrate the impact of salinity gradient on the LTG process and interactions between key mechanisms such as microemulsion phase behavior and foam stability. In order to provide additional insight into the experimental study and improve understanding of the LTG process, we used our newly developed LTG simulator which we built within CMG GEM. The results demonstrate that decreasing slug injection salinity can lead to a 15% increase in residual oil in place (ROIP) recovery over a slug injected at optimum salinity, with earlier breakthrough and steeper recovery slope. In addition, there is evidence of a late time pressure buildup as salinity is decreased through mixing with drive salinity which is indicative of increasing foam stability. This may be due to an inverse relationship between oil-water IFT and foam stability and thus designing an optimal salinity gradient for an LTG process requires balancing oil mobilization due to ultralow IFT and effectively displacing mobilized oil with adequate foam mobility control. We introduce and show the strength our compositional LTG simulator in a pioneering laboratory and simulation study that sheds light on the interaction between salinity, microemulsion phase behavior, and foam strength. Our conclusions indicate a significant departure from traditional ASP understanding and methodology when designing an LTG salinity gradient and serve as a foundation for future investigation.

A Comparative Study of Gas Flooding and Foam-Assisted Chemical Flooding in Bentheimer Sandstones

“…low permeability regions (Shupe 1981). Variants of the ASF process were investigated by others in literature (Srivastava et al 2009;Szlendak et al 2013;Tang et al 2014;Jong et al 2016) but they did not provide clues about oil mobilisation and displacement mechanisms.…”

Low-tension gas process in high-salinity and low-permeability reservoirs

“…The only difference between Corefloods 2 and 1 was that the slug injection salinity in Coreflood 2 was at the boundary between Type I and Type III (130,000 ppm), unlike the optimum Type III salinity (148,000 ppm) in Coreflood 1. Jong et al (2016) experimentally observed that injection at sub-optimum salinity is better for oil recovery in higher-permeability rocks. These experiments were done in sandstone rocks at low formation and injection salinity.…”

Low Tension Gas Process in High Salinity and Low Permeability Reservoirs

“…Compared to coreflood 1 (Figure 2), the pressure drop curves show sharp increases and decreases in successive sections, indicating better propagation of the oil bank. It has been experimentally observed that injection at sub-optimum salinity is better for oil recovery in higher permeability rocks, while injection at optimum salinity is beneficial for oil recovery in tight rocks (Jong and Nguyen, 2016). Even though the oil breaks through earlier, it is observed that the oil cut curve is elongated and does not show a sharp increase.…”