Taber South - Canada's First Polymer Flood

Abstract

Abstract Three years of actual performance of the Taber South Mannville "B" pool polymer flood has resulted in sufficient data to review the initial decision to implement this type of secondary recovery scheme. Comparison of performance to the original forecasts to a critical re-examination of those forecasts and to the performance of conventional waterfloods in pools with similar characteristics has been made. Operating costs and capital costs caused by polymer injection have been studied. Consideration of ultimate polymer slug size and operational procedures has been undertaken to provide a guide for optimum future performance. The conclusion has been reached that polymer flooding has been economically successful and appears to have been significantly more profitable than a conventional waterflood. INTRODUCTION CANADA'S FIRST POLYMER FLOOD was initiated in February 1967 in the Taber South Manriville "B" oil Pool, located approximatehr 35 miles southeast of Lethbridge, Alherta (Figure 1). The Taber South Mannville "B" pool was discovered in March 1963 with the drilling of the CPOG Taber S 2-29-7-16 well. A total of 23 oil wells and 1l dry holes drilled on a 40-acre spacing- pattern, to an average depth of 3,230 ft, defined a reservoir containing an estimated 40,010,000 st. barrels of oil. Reservoir Description ROCK PROPERTIES The producing horizon is a lenticular Lower Cretaceous Mannville sandstone extending approximately 4 miles in a north-south direction and having a maximum width of slightly more than half a mile, as shown in Figure 2. The reservoir is structurally located on a north-south plunging nose which dips 90 ft from the south to the north end of the pool. The Mannville "B" pool is separated from the adjacent Taber South Mannville "A" pool by a high in the underlying Rierdon unconformity. No gas cap or water zone is associated with this oil pool. The sandstone is generally homogeneous, with only a few minor shale stringers. The net pay ranges from 6 ft on the west edge to a maximum of 73 ft at the 11-16-7-16 well. The average porosity and permeability for the pool are 26.6 per cent and 2,100 md, respectively. The average water saturation, as determined from restored-state data and later-log calculations, is 9.5 per cent. The average sand properties and reservoir fluid data are shown in Table I. The cut-offs for determining the net oil pay were 78 microseconds for the sonic travel time and 50 md for the core data) as determined from well completion experience and log data. Less than 1 per cent of the cored sections had a permeability 100ver than 50 md. Fluid Properties The fluid properties indicated a highly undersaturated oil reservoir, as the discovery pressure was 1,472 psia and the saturation pressure was indicated to be 415 psia. The latter pressure appears to be low, as bottom-hole pressure surveys indicate the bubble-point pressure to be in the range of 500 psia. The oil contained 65 cu.ft of gas and had a viscosity of 58 centipoises at the saturation pressure.