Performance of TheTaber South Polymer Flood

Abstract

Abstract A polymer flood was initiated in the Taber South Mannville B Pool in February, 1967. The reservoir, which contains a viscous, highly undersaturated crude oil with no bottom water, was depleted to the bubble-point pressure of 400 psig prior to polymer flooding. A 20 per cent hydrocarbon pore volume slug of polyacrylamide (Pusher* 700) was injected at the center of this long, narrow Lower Cretaceous' sandstone reservoir. In early 1972, injection was converted to plain water by gradually reducing polymer concentration. The reservoir was studied with reservoir simulation models in an attempt to identify incremental polymer flood oil recovery (relative to waterflood). It was found, because of unknown polymer quality in the reservoir and uncertainties in transmissibilities, that incremental polymer flood oil recovery could not be quantified. Results of a wettability study using restored cores under reservoir conditions are presented. The potential effects of wettability on polymer flood performance are discussed. It is not possible, using existing techniques, to quantify quality of produced polymer solution from the field. Some indirect observations on polymer quality are presented to help shed some light on the performance of this major polymer flood. Introduction THE TABER SOUTH Mannville B Pool, located in southern Alberta, was discovered in 1963, The pool consisted of 23 completed producers drilled on 40-acre spacing when polymer flooding was implemented in early 1967, Polymer was added to the injected water until the middle of 1972, at which time a 20.% HOPV slug of polymer had been injected into the reservoir. The polymer slug is currently being displaced through the reservoir with plain water, which consists of produced water plus sufficient fresh water to replace reservoir voidage. Oil recovery to December 1974 was approximately 18 per cent of the original oil in place. Our objective in this study was to evaluate polymer effectiveness by comparing polymer and waterflood performance using numerical simulation" models. Intercomp's three-phase, compressible polymer model was used to study the Taber South Mannville B Pool performance. The results are presented below. Geology The Taber South Mannville B Pool is an offshore barrier bar sandstone reservoir of Lower Cretaceous age. The reservoir rock, a fine-grained sand containing significant amounts of glauconite and- pyrite, is vertically homogeneous, with only a few minor shale stringers. The areal permeability variation is low, with tighter areas near the edges of the sand body. The pool is approximately 5 miles long and 1/2 mile wide. No initial gas cap or water zone is associated with the reservoir. A maximum net pay of 73 ft occurs in two wells, 3A-16 and 11–16, as shown in Figure 1. The sand reaches a structural high of 97 ft subsea in section 16; the base dips northwest at about 30 feet per mile. The average reservoir depth is 3250 ft. Basic Reservoir Data Six of the 31 completed wells in the pool have been cored. The core analysis indicates a low permeability variation, with the highest measured permeability and porosity being 6656 millidarcics and 33.9 per cent, respectively.