Study of alternating anionic surfactant and gas injection in carbonate cores
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A major portion of the oil across the world is contained in carbonate reservoirs. Most of the carbonate reservoirs are typically oil-wet or mixed-wet, hence water-flooding processes have low oil recovery. Hence the most common mechanisms applied to increase the recovery are through wettability alteration and ultra-low interfacial tension (IFT) formulations with the addition of surfactants, or gas injection to have immiscible and miscible displacement processes, or combination of these processes. Secondary immiscible gas floods have been applied for several years in carbonate reservoirs and the typical recovery is found to be around 35-40% OOIP. The problems associated with many gas injection processes are the inefficient gas utilization, poor sweep efficiency, and low incremental oil recovery due to viscous instability (channeling or fingering) and gravity segregation. These are mainly caused by rock heterogeneity as well as the low density and viscosity of the injected gas. To address these drawbacks foam can be injected into the oil reservoir by co-injection of surfactant solution and gas, or by surfactant-alternating-gas (SAG) mode. The strategy implemented here is to inject a surfactant that causes wettability alteration or ultra-low IFT to recover additional oil followed by gas injection which helps in generation of foam and provides mobility control to achieve better sweep efficiency. The main objective of this research is to study the effect of slug size variation on oil recovery in surfactant-alternating-gas (SAG) processes for carbonate rocks using a wettability alteration anionic surfactant solution. The bulk foam stability in the presence and absence of the crude oil were studied for several surfactants. In addition, phase behavior studies and wettability alteration experiments were performed with the crude oil to screen the surfactant solutions. A propoxy sulfate surfactant, Alfoterra (0.5 wt%) was found to be optimal for these studies. Coreflood experiments in the absence of oil were performed in outcrop Texas Cream limestone rocks to measure the apparent foam viscosity and single phase pressure drop in presence of 80% quality foam, in comparison to 80% quality gas-brine co-injection as a base case. The resistance factor (measured as the ratio of pressure drop with foam and without foam) was found to be 3.5. Coreflood experiments with surfactant-alternating-gas (SAG) mode were performed in oil aged reservoir limestone rocks and outcrop carbonate rocks using Alfoterra (0.5 wt%). The coreflood experiments with a single slug of 0.5 PV surfactant solution showed additional oil recovery of about 25% OOIP in the outcrop rock. The average pressure drop during the experiment was in the range of 5-15 psi. The coreflood experiments with limestone rocks from a reservoir showed an additional oil recovery of about 25% OOIP for 0.1 PV slug size and smaller slug size injection of 0.05 PV showed an additional oil recovery of about 28% OOIP. The average pressure drop recorded was comparatively higher in the range of 40-60 psi for smaller slug sixe injection. Smaller slug size leads to higher oil recovery. The dynamic adsorption measured for Alf S23-7S-90 (S1) in Texas Cream limestone rock was found to be about 0.112 mg/gm of rock.