Norman Wells PVT Properties After Reservoir Repressurization

Abstract

Abstract The Norman Wells reservoir was depleted primarily by solution gas drive until 1984 when a field-wide pattern water flood was implemented. The resultant reservoir repressurization has had an impact on the PVT properties. This paper presents the results of a 1988 study undertaken to determine the current reservoir fluid properties. The results indicate that:the current methodology for tuning the Peng-Robinson equation-of-state could not simultaneously match the bubble point pressure (Pb) and the corresponding solution gas-oil-ratio (Rsb) of these samples;neither the 1965 properties nor Standing's correlation could be used to match the PVT behavior of the new samples; andthe bubble point pressure varied widely while Rsb was nearly constant, It was found that preferential evolution and subsequent redissolution of light gases (CH4, N2 and CO2) caused major changes to the bubble point pressure but very little change to Rsb. The new PVT properties were used to:illustrate that reservoir fluid withdrawals are now balanced by injected volumes;improve the gas production proration factor by 15%; andprovide more accurate data for facility design and volume metering considerations. Introduction The Norman Wells Pool is located directly under the Mackenzie River, about 80 km south of the Arctic Circle in the Northwest Territories of Canada (Fig. 1). It is a layered Devonion limestone reef complex with natural fractures and matrix permeabilities of less than 10 mD(1). The pool was discovered in the 1920s and underwent its first major development during the 1940s when wells were drilled on the mainland and on two natural islands (Fig. 2). Production levels were determined by the demand for petroleum products in the North. In the early 1980s a waterflood operation was started with the mainland wells. Later, the pool was fully developed for a pattern waterflood using directional drilling and artificial islands. Waterflood operations began in 1985. It was recognized that the history of Norman Wells, which included intermittent injection of water and petroleum products, solution gas drive resulting in high producing gas-oil ratios (GOR), and a really inconsistent depletion of a tight reservoir, would cause changes in the reservoir fluid properties. Once the reservoir was repressurred from pool wide waterflood operations, reservoir fluid sampling and analysis could be carried out to quantify the changes. After first reviewing the relevant historical aspects. The sampling procedures and measured properties will be presented. Then the analysis and conclusions which enabled the practical application of the results will be discussed. Historical Operations Upon discovery in the 1920s, the reservoir pressure was 5500 kPa. In the 1940s some 60 wells were drilled under the terms of the Canol Agreement between the United States Army, Canada and Imperial Oil(2). A field-wide pressure survey done in 1945 showed a slight decline in pressure to 5200 kPa. As shown in Figure 3, from this time on through to the early 1980s the active well count ranged from 40 to 50 and the pool oil rate was 300 m3/d to 400 m3/d.