Water-Alternating-Gas

Key Takeaways

• WAG process design parameters including the WAG ratio (water-to-gas volume ratio per cycle), cycle length, and the sequence of the first injection slug determine the displacement efficiency and the conformance control achieved in the specific reservoir and fluid system: a WAG ratio of 1:1 (equal volumes of water and gas alternated) is a common starting point in many projects, but the optimal ratio depends on the relative permeabilities of the three phases (oil, water, gas), the mobility ratio between the water bank and the gas bank, and the degree of gravity segregation in the reservoir; tapered WAG (starting with a low WAG ratio, such as 1:3 water-to-gas, and progressively increasing the water fraction as the flood matures) has been used in some Permian Basin CO2 WAG projects to provide maximum gas sweep in the early injection period when the oil saturation is highest, then transitioning to higher WAG ratios to provide conformance control as residual oil saturations decline and the risk of gas channeling increases; WAG cycle length (typically 3-12 months per half-cycle for field applications) affects how deeply each fluid slug penetrates into the reservoir before the injection fluid is switched, with shorter cycles creating a more finely interleaved pattern of water and gas near the injector and longer cycles allowing each fluid to establish its own displacement front farther from the injector before the switch; the first injection fluid is typically water in a waterflooded reservoir that is being converted to WAG (to reduce the residual water saturation and re-establish water mobility before gas is introduced) or gas in a primary-depleted reservoir where the oil saturation is still high and miscible gas displacement is the primary recovery mechanism.
• Miscible versus immiscible WAG determines whether the injected gas achieves multi-contact miscibility with the reservoir oil (dissolving into the oil and extracting light hydrocarbons to form a single phase with low or zero interfacial tension and very low residual oil saturation) or maintains a distinct gas phase with a higher residual oil saturation: miscible WAG requires that the injection pressure be above the minimum miscibility pressure (MMP) for the specific gas-oil system, with CO2 MMP typically in the range of 1,000-3,000 psi for most reservoir oils at temperatures of 100-200 degrees Fahrenheit; above the MMP, CO2 achieves miscibility with the reservoir oil through a multi-contact mechanism (forward contact and condensing/vaporizing drive) in which the CO2 and oil exchange intermediate molecular weight components over multiple contacts until a single miscible phase forms; below the MMP (immiscible WAG), CO2 dissolves partially into the oil (swelling the oil and reducing its viscosity) and provides an immiscible displacement that reduces residual oil saturation below the waterflood level but does not achieve the very low residual saturations of miscible displacement; the economics of WAG strongly favor miscible operation wherever the reservoir pressure is sufficient to maintain injection above the MMP, because the incremental oil recovery from miscible WAG over immiscible WAG justifies the higher compression energy costs and operational complexity required to maintain the higher injection pressures; for offshore reservoirs at water depths with high wellhead pressures, achieving the MMP is typically not a constraint because the injection well pressure naturally exceeds the MMP for most gas-oil systems at those depths.
• Three-phase relative permeability effects in WAG injection create the most significant uncertainty in reservoir simulation of WAG projects, because the simultaneous presence of oil, water, and gas in the pore space during WAG creates hysteresis effects and three-phase trapping mechanisms that are poorly characterized by standard two-phase relative permeability measurements: the Land trapping model (which predicts gas trapping as a function of the maximum gas saturation reached and the irreducible gas saturation) shows that gas trapped during alternating water injection creates a zone of low permeability to all phases that limits the penetration of subsequent gas slugs and reduces their ability to achieve miscible displacement in the contacted volume; the trapped gas saturation (determined by the Land coefficient C = 1/Sgr - 1/Sgt, where Sgr is the residual gas saturation and Sgt is the trapped gas saturation at the point where gas saturation starts to decrease) varies widely between reservoirs (from 0.1 to 0.4 pore volume fraction) and is a key uncertainty in WAG simulation; experimental measurement of three-phase relative permeability for the specific rock type and fluid system of a WAG project (using laboratory corefloods at reservoir conditions with CO2-crude-brine systems and the alternating injection sequence mimicking the field WAG cycle) provides the hysteresis parameters needed to constrain the simulation and reduce the uncertainty in predicted WAG oil recovery; the difference between optimistic and pessimistic WAG recovery predictions based on the range of three-phase relative permeability models can be 5-15% of original oil in place (OOIP), a range that significantly affects the project economics and the decision to proceed with full-field WAG deployment.
• CO2 WAG in the Permian Basin represents the largest scale application of the WAG concept, with over 15,000 producing wells in the Permian Basin receiving CO2 injection through more than 1,200 injectors that collectively inject approximately 2 billion cubic feet per day of CO2 to produce incremental oil recovery above the primary and secondary (waterflood) recovery baseline: the CO2 WAG projects in the Permian Basin Central Basin Platform, Northwest Shelf, and Delaware Basin use CO2 sourced from natural CO2 reservoirs in the McElmo Dome and Bravo Dome (Colorado and New Mexico) and from industrial capture at gas processing plants, transported through approximately 5,000 miles of CO2 pipeline infrastructure that represents the world's largest CO2 pipeline network; the economics of CO2 WAG in the Permian Basin depend on the CO2 price (a function of supply from natural and industrial sources versus operator demand), the oil price (the incremental oil recovery from CO2 WAG is typically 5-20% of original oil in place over the primary and waterflood recovery, representing potentially millions of barrels per project), and the capital efficiency of the CO2 recycling plant (which recovers CO2 from produced gas to reinject it rather than purchasing new CO2); the Permian Basin CO2 WAG industry also demonstrates the long-term CO2 storage potential of EOR projects, with approximately 30-50% of the injected CO2 estimated to remain permanently sequestered in the reservoir rather than being produced and recycled, making CO2 EOR WAG a potential bridge technology between current commercial EOR and future dedicated geological carbon sequestration.
• Simultaneous water and gas (SWAG) injection as a variant of WAG eliminates the alternating cycle by co-injecting water and gas simultaneously through the same injection well or through adjacent wells, creating a mixed water-gas injection stream that addresses some of the operational challenges of cyclic WAG while maintaining the conformance control benefit of water presence: SWAG can be implemented as co-injection through a single wellbore (mixing the water and gas at the wellhead before injection) or as simultaneous injection through adjacent water and gas injectors with interleaved well patterns that achieve the same spatial mixing effect without requiring the complex wellhead equipment for downhole co-injection; the advantage of SWAG over cyclic WAG is the elimination of the pressure transients and near-wellbore saturation cycling that occur during each WAG phase change, which can cause injectivity impairment from scale precipitation (in CO2 WAG, the alternating contact of water and CO2 with the formation can cause carbonate scale precipitation that reduces injectivity near the injector) and mechanical damage from the fatigue loading of downhole completion equipment during repeated pressure cycling; the disadvantage of SWAG is that the simultaneously injected gas and water mix immediately rather than establishing the distinct mobility control sequence that cyclic WAG provides, potentially reducing the conformance improvement relative to optimally designed cyclic WAG; the choice between cyclic WAG and SWAG depends on the specific reservoir heterogeneity, the relative magnitudes of gravity override and viscous fingering, and the operational constraints of the injection facilities.