Phase Behaviour And Scaled Model Studies of Prototype Saskatchewan Heavy Oils With Carbon Dioxide

Abstract

Abstract Non-thermal enhanced oil recovery (EOR) techniques show good potential for recovering oils from the thin and shaly heavy oil reservoirs of Saskatchewan. Among the non-thermal processes, immiscible carbon dioxide injection holds the most promise of accessing these reservoirs. This technique, however, is much less developed than thermal methods. The process, if proven applicable to Saskatchewan reservoirs between three and seven metres thick, will access approximately 90% of the total oil-in-place. Considering the above, a multi-client experimental research program was initiated at the Saskatchewan Research Council. The objective of this research program is to evaluate various solvents in the context of the heavy oil resource and to investigate displacement mechanisms associated with immiscible gas injection processes. This paper is divided into two sections. The first deals with the characterization of a Kindersley area heavy oil The characterization includes analysis of stock-tank oil with and without additives, recombined reservoir fluid, and reservoir fluid plus carbon dioxide. The second section describes a scaled physical model and two displacement experiments conducted using a Lloydminster area heavy oil. The laboratory phase behavior data were generated to show the effect of pressure and temperature on carbon dioxide solubility, oil density and viscosity, compressibility, and swelling factors. The addition of 73.1 sm3/m3 of carbon dioxide at 7 MPa reduced the viscosity of the reservoir fluid at 25.5 °C from 819 mPa •s to 45 mPa •s, an eighteen-fold reduction. The same reduction in viscosity by thermal methods would require healing the sample to approximately 80 °C. The above oil under similar conditions, increased in density from 963.0 kg/m3 to 974.3 kg/m3 and swelled approximately 15%. Two scaled model experiments (secondary displacements) were conducted using a 10-cycle water-alternating-gas (WAG) process with a WAG ratio of 4: 1. In each run, the total mass of carbon dioxide injected was1.41 g •mole (0.53 PV at 2.5 MPa, 0.30 PV at 4. 1 MPa). These displacements indicated the immiscible carbon dioxide WAG process to be partially sensitive to the operating pressure in the range of study. More important is the relative volume of carbon dioxide, at experimental conditions, which dictates overall performance. Introduction Carbon dioxide flooding to be the primary non-thermal recovery process that hold promise of allowing access to the typically thin reservoirs in which most of Saskatchewan's heavy oil is found. Thermal methods are often inefficient and uneconomical because of excessive vertical heat losses, due to thin pay zones, and steam-scavenging by bottom water zones. Carbon dioxide may behave as a miscible or immiscible fluid when contacted with oil at reservoir conditions. For petroleum reservoirs, Holm(1) defines miscibility as that physical condition between two or more fluids that will permit them to mix in all proportions without the existence of an interface. If two or more fluid phases form after some amount of one fluid is added to others, the fluids are considered immiscible and an interfacial tension exists between the phases. Therefore, miscible displacement may not be applicable to all reservoir fluids.