Scaled Model Studies Of Carbon Dioxide/Brine Injection Strategies For Heavy Oil Recovery From Thin Formations
Authors: Rojas G. , Ali S.M. Farouq 
Published: March 2010

Abstract
In Alberta and Saskatchewan, there are many thin, heavy oil reservoirs that are unsuitable for thermal recovery techniques. This paper shows that immiscible carbon dioxide/waterflooding methods are an important alternative to thermal processes. Experiments were conducted in a scaled model, with Aberfeldy-Lloydminster heavy oils (1000 ∼ 500 mPa.s), using a small slug (20% hydrocarbon pore volume) of sub-critical carbon dioxide in a rectangular scaled model, designed to simulate a thin formation.
Among the different strategies tested, the injection of alternate slugs of carbon dioxide (at 5.5 MPa and 21–23 °C) and brine (the WAG – Water Alternating Gas – Process) yielded the best results; highest incremental recovery and lowest carbon dioxide requirement. The volumetric ratio of the brine/carbon dioxide slugs (WAG ratio) was varied from 1:1 to 6:1, in order to determine optimal conditions. It was found that for immiscible displacement of a heavy oil, a high rather than a low WAG ratio should be employed in the field. The oil recovery varied from a low of 5% to as much as 48% of theoil-in-place.
While most of the experiments were conducted under secondary conditions, i.e. after primary recovery, several runs simulated tertiary recovery, where carbon dioxide was injected after a waterflood. In such tertiary recover experiments there was a clear indication that carbon dioxide/brine injection mobilized residual heavy oil, which was banked up and produced al a moderate water-oil ratio. On the whole, displacement was more efficient when initial oil saturation was high.
An increase in oil viscosity caused a reduction in oil recovery. In Ihe case of the more viscous oil, the incremental recovery over a waterflood was realized mainly in the blowdown phase of the process.

Introduction
The Aberfeldy field operated by Husky Oil Operations Ltd. is one of the largest oil reservoirs in the Lloydminster area. High crude oil viscosity, low solution GOR, and low initial reservoir pressures have resulted in low primary recovery efficiencies(1), less than 10% HCPV (Hydrocarbon Pore Volume). Given the large volume of oil in place in the Aberfeldy reservoirs and the low primary recovery, there is a considerable incentive to apply an enhanced oil recovery method. In these thin (6.1 m thickness) reservoirs, the thermal methods could yield good results, but due to the high heat loss their economics may be tenuous, An alternative process for thin, heavy oil sands is the immiscible CO2 injection as has been recently demonstrated by the encouraging results of several projects in the United States(2,3) and Hungary(4). The field projects have yielded moderate secondary (10% HCPV) and tertiary (5% RCPV) heavy oil (14–17 ° API, 160–280 mPa.s at res, cond.) recoveries at very low CO2 requirement, 1000 sm3 CO2/m3 oil. While the pattern displacement projects have been economical basically due to low requirements of CO2, the CO2 cyclic stimulation projects have been unsuccessful(4) as the production state of each cycle is very short.
Immiscible CO2 flooding is essentially a technique for improving the flow of a heavy oil in the reservoir.