A Technical Evaluation of a CO2 Flood for EOR Benefits in the Cooper Basin, South Australia

Abstract

Abstract This study evaluates reservoir and reservoir fluid parameters relevant to CO2 flooding to enhance hydrocarbon recovery from a Cooper Basin oilfield (Field A), located in South Australia. Field A is a tight (k<1mD) sandstone reservoir containing volatile and low viscosity oil. CO2 could be separated from raw gas produced from a nearby gas field (Field B) or made available from a gas processing facility located some 60km from Field A. The costs of preconditioning the CO2 to suitable composition and pressures are known to be high, but have not been considered in this study. Laboratory experiments were conducted using both pure carbon dioxide and a synthesized gas derived from Field B gas, consisting mainly of CO2 and methane. The increase in oil recovery as a function of pressure was determined, which would be a basis for selection of injection pressure. In addition, minimum miscibility pressures using both CO2 and the synthetic gas mixture and the utilization factor of CO2 injected to oil produced were also determined. Introduction The oil field in question (Field A) is a very tight sandstone reservoir (permeability in range 0.1–1mD) located in the Cooper Basin, South Australia (see Fig. 1). A summary of the reservoir properties is provided in Table 1. Average porosity throughout the oil bearing formations of Field A is low at ~7–11%. The initial reservoir pressure of Field A was approximately 4200 psig. The reservoir pressure in the northeastern part of the reservoir is currently approximately 3150 psig while in the southwestern part of the reservoir it has been depleted to approximately 2700–2800 psig. The oil is volatile (50°API) with a low viscosity (0.14cP) at reservoir conditions. Reservoir temperature is quite high at 279°F. The reservoir is essentially produced by depletion drive. Although there is indication of some aquifer support, little data are available to analyze its impact. To date the recovery has been only 3–4% of the original-oil-in-place, and simulation studies indicate a recovery at abandonment of some 5–10%. Hence, it is envisaged that a suitable EOR scheme may help improve recovery. With a suitable gas injection process, it is estimated that the ultimate recovery would increase to 20–30% implying that some extra 2.5 MMstb of oil could be recovered. Due to the tight nature of the reservoir, the required water flooding injectivity pressures would be impractically high. However fluids with much lower viscosities than water, such as carbon dioxide or hydrocarbon gases, would have a higher injectivity. Therefore, the viability of flooding the reservoir with a gas would be much greater. In the past ethane has been injected in a neighboring oilfield with success. Both the neighbouring oilfield and Field A produce mainly from the same rock formation and have similar reservoir rock and fluid properties. Although the primary motivation for ethane injection at the neighbouring field was to store it, it also contributed to improved oil recovery. An important conclusion derived from the ethane injection experience is that injectivity of ethane was not a major concern. Because ethane and CO2 are similar in many of their physical and thermodynamic characteristics and the reservoir properties of the two fields are very similar, it is envisaged that CO2 injectivity will also not be a major concern in the neighboring Field A. One possible source of CO2 would be to extract it from a nearby gas field (Field B). Field B produces a wet gas with ~45mol% CO2 and ~45mol% methane. Wellhead pressures are high with a shut-in wellhead pressure above 2500 psig. The high wellhead pressures imply that lesser compression would be required for the transportation and injection process. A possible scenario would be that as much as practical, "saleable" components in the gas from Field B would be extracted for sale, and the remaining gas (that is, a CO2-rich waste gas) would be used as the injection gas for Field A.