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The overall goal of the research is to investigate the roles of unexplored yet important factors that affect Water Alternating Gas (WAG) injection performance. Specifically, the effects of fluid properties (brine salinity and gas composition), CO₂ and water half-cycle slug size, and timing of cyclic injection will be experimentally studied in near-miscible and miscible flooding.

In the past 8 months, the effect of salinity of the injection brine on Water Alternating Gas (WAG) performance in tertiary miscible carbon dioxide (CO₂) flooding was investigated. Coreflood experiments were performed in Berea sandstone core, from which the WAG performance, such as percent oil recovery, tertiary recovery factor, and CO₂/Gas utilization factor were determined. The core flooding experiments were conducted at 60^oC and at miscible condition, i.e., 20% above the minimum miscible pressure (MMP) of the oil sample. Two sets of experiments were performed, one set used a model oil, which was a mixture of 50 wt% n-decane and 50 wt% n-hexadecane, and the other used a crude oil from the Cottonwood Creek field in Wyoming. For experiments with the model oil, the artificial injection brines were made by dissolving NaCl into distilled water with different salinities ranging from 1000 to 32000 ppm (mg/L). Artificial injection brines containing 4000 ppm NaCl and 4000 ppm CaCl₂ were also used to investigate the effect of divalent salt. For experiments with the crude oil, artificial brines containing 4000, 10000, and 16000 ppm of salt with NaCl-to-CaCl₂ ratio of 2:1 were used as the injection brines.

The cores used, 1-in diameter and 10.5-in long, were drilled from a homogeneous Berea sandstone block, the permeability of which was about 150 mD. It was water wet and had low clay content. For experiments with the model oil, the core was saturated with an artificial brine containing 1000 ppm NaCl and eventually flooded with the oil to obtain certain oil saturation. For experiments with the crude oil, to mimic the Cottonwood Creek connate brine, the core was initially saturated with an artificial brine containing 20000 ppm NaCl and 10000 ppm CaCl₂. After water flooding, six alternate cycles of brine and CO₂ with a half-cycle slug size of 0.25 pore volumes (PV) and a CO₂/water ratio (volume ratio) of 1:1 were injected in every core flood test. The injection rates for secondary water flooding and tertiary WAG flooding were 0.3 mL/min to minimize the viscous instabilities and discontinuities at the inlet and outlet of the core.

At the same miscible condition, the tertiary recovery factor of WAG was demonstrated to be higher than that of continuous CO₂ flooding, i.e., to recover the same amount of oil, WAG flooding required less volume of CO₂ than continuous CO₂ flooding. The tertiary oil recovery and recovery factor of both model and crude oils increased slightly with the salinity of the injection brine. For example, for model oil, as the salinity increased from 1000 to 32000 ppm, the tertiary oil recovery increased from 52.8% to 59.4% Original Oil In Place (OOIP). Thus, for model oil, the WAG process under experimental conditions investigated enhanced the oil recovery by more than 50% OOIP over water flooding; for the record, the oil recovery of secondary water flooding remained constant around 32% OOIP with increasing salinity of the injection brine. The increase in tertiary oil recovery (WAG oil recovery) with salinity was attributed to the decrease in the CO₂ solubility in brine, which made more CO₂ available for oil displacement. The increase was unlikely due to the improved mobility control ability of the injection brines because the brine viscosity in the salinity range studied was almost constant. The CaCl₂ in the injection brine was found to have similar effect as NaCl.