Foam Application in an Oil Sands Steamflood Process

Abstract

ABSTRACT: This paper outlines a foam field test presently being conducted in the McMurray formation of the Athabasca Oil Sands in Alberta. The test objective is to determine the viability of using foam as a mobility control and diverting agent for steam; which has a tendency to override the pay zone. Prior to initiating the test various surfactants were Prior to initiating the test various surfactants were tested in the laboratory by injecting with steam into a sand pack. The steam-surfactant mixture that resulted in the greatest pressure increase (ie. the greatest reduction in the gas mobility) was selected for the field test. Laboratory results also indicated that the simultaneous injection of surfactant, steam and a non-condensible gas provided a higher pressure increase compared to batching the pressure increase compared to batching the surfactant ahead of the steam and gas. The early results from the field qualitatively substantiate the laboratory pressure results. Numerical modelling using Computer Modelling Group's "Steam and Additive Reservoir Simulator" (STARS) was used as a pre-test directional tool, as well to analyze and predict long term steam-foam application performance. Reservoir geology which has been of major consequence in the subject reservoir recovery process was accounted for in the numerical model. Introduction The Athabasca tar sands of Northern Alberta are estimated to contain approximately 127 billion cubic metres of bitumen. Although the available technology and to a large extent the current world oil price cannot fully support the commercial development of this vast resource; it is envisaged that more efficient recovery methods presently being tested may allow its future development. The Athabasca tar sands deposit offers excellent reservoirs in terms of porosity, oil saturation, and pay thickness, however the lack of mobility within pay thickness, however the lack of mobility within the virgin sands does not allow for practical injection and production rates. The mobilize the highly viscous bitumen (10(6) mPas) the viscosity must be lowered significantly by using thermal recovery methods such as steam flooding and steam stimulation. Due to the negligible initial injectivity offered by the formation, the fluid has to be injected above fracture pressure. Hydraulic fracturing has been used in this region in an effort to try and develop interwell communication at the base of the reservoir. However due to the isotropric in-situ stress conditions existing at the depths of interest the directional control of these fractures is unpredictable. This is because, pore pressure increase due to fluid leak-off, thermal expansion and fracture loading may alter the stress fields inducing a change in the fracture orientation, or resulting in multi-directional fractures. P. 619