Article pubs.acs.org/EF
Propane-Enriched CO2 Immiscible Flooding For Improved Heavy Oil Recovery Peng Luo,* Yiping Zhang,† Xiaoqi Wang, and Sam Huang Saskatchewan Research Council Regina, Saskatchewan, Canada S4S 7J7 ABSTRACT: The majority of heavy oil reservoirs in west-central Saskatchewan, Canada, are thin and marginal, such that they are economically unsuitable for thermal recovery methods. Immiscible gas flooding appears to be highly promising for these underexploited reservoirs. The goal of the research described here is to advance development of cost-effective immiscible gas flooding processes applicable to moderately viscous heavy oils in this region, by improving recovery factors through designing an injection solvent mixture with optimized properties. In this study, two solvents were studied and compared: pure CO2 and 81 mol % CO2 + 19 mol % C3H8. The phase behavior (pressure−volume−temperature (PVT)) and physical properties of a reconstituted live heavy oil with these solvents were measured, respectively. In terms of oil viscosity reduction and swelling, the CO2−C3H8 mixture was found to be substantially more effective than CO2 alone. At about 4 MPa and 21 °C, CO2−C3H8 addition reduced the live oil viscosity by 96.5%, compared with 92.6% for CO2. As well, the live oil swelled by 10.6% when saturated with the CO2−C3H8 mixture, much higher than the 6.8% with CO2. Furthermore, a comparative coreflood study of the oil recovery performance using CO2 alone and the CO2−C3H8 mixture at different operating pressures was carried out to assess their respective effectiveness. The obtained oil recovery factor confirmed that the solvent mixture was much more effective than CO2 alone. At the operating pressure of 4 MPa, the CO2−C3H8 mixture recovered 34.2% original oil in place (OOIP) during the water-alternating-gas (WAG) cycles, compared to 22.5% OOIP using CO2 alone at 4 MPa. The gas utilization factor for CO2− C3H8 flooding, however, was only 72% of that for CO2-alone flooding. The comparative advantage of the solvent mixture was also apparent in two specially designed radial corefloods, which were conducted to better represent fluids radial flow in heavy oil reservoirs.
1. INTRODUCTION Saskatchewan’s heavy oil reservoirs are distributed in a series of thinner blanket and channel sands that extends into the province from the Alberta border. The majority of them are characterized by thin payzone, shaly sand, heterogeneity, and bottomwater. About 97% of their proven original oil in place (OOIP) is contained in payzones of less than 10 m, with 55% OOIP less than 5 m thick,1 with the in situ oil viscosity ranging from 150 to 4000 mPa·s.2 In general, primary recovery (i.e., solution−gas drive) followed by secondary recovery (i.e., waterflooding) can recover only a maximum 10% OOIP because of low natural energy and adversely high mobility ratio. If suitable enhanced oil recovery (EOR) technologies can be developed to provide additional recovery of 10% to 15% of the in-place heavy oil resources for these reservoirs, it will add between 339 × 106 m3 and 508 × 106 m3 of oil reserves to Saskatchewan.3 The nature of the heavy oil reservoirs in Saskatchewan dictates that the commonly used EOR methods are very limited to efficiently recover the remaining trapped heavy oils. For example, thermal recovery techniques are generally not applicable, mainly because the oil payzones are relatively thin (
