Alwyn North IOR Gas Injection Potential - A Case Study

Abstract With 220 million stb IOIP, Brent East is the largest oil accumulation in Alwyn North. The current drive mechanism, waterflood at 350 bar with eight producers and four peripheral injectors, yields a recovery factor of 54% but leaves 60 million stb by-passed oil and 40 million stb capillary-trapped oil. Injecting gas into the panel appears technically attractive: laboratory experiments show that miscibility is achieved at 375 bar and residual oil can be reduced to 7%. Based on these experiments, EOS parameters and 3-phase relative permeabilities were derived for full field simulation. Preliminary studies indicate that the optimum scheme consists of injecting gas using the existing injectors, followed by a resumption of water injection and terminating field life with a blowdown The project could bring 20 million stb additional oil over 15 years. Introduction 1.1 The Alwyn North field The Alwyn North field was discovered in 1974 in the UKCS, 150 km east of the Shetlands. Oil and gas were encountered in two sandstone formations of Jurassic age, the Brent and the Statfjord. The reservoirs are contained in fault blocks tilting towards the West. The exposed eastern edges of these blocks are severely eroded and gravitational collapse has caused the formation of slumps on the eastern flank. Because of faulting, the Brent formation is divided into several panels: Brent East, Brent North and the West flank. The oil composition varies from one panel to the other and even within one panel, it may vary with depth. The hydrocarbons initially in place add up to about 600 million stb of oil and 50 billion sm3 of gas. 1.2 The Brent East panel With 220 million stb IOIP, the Brent East panel is the largest oil accumulation in Alwyn North. The reservoir is around 150 m thick. Permeability is generally good but the displacement of fluids is impaired by various barriers (horizontal and vertical). The 39 API oil is highly undersaturated : bubble point of 255 bar and initial pressure of 453 bar at -3231 mss. 1.3 Primary and secondary recoveries The development began with a natural depletion phase bringing the average reservoir pressure down to 350 bar. Then followed a waterflood at this pressure which allows the production up to 100% water cut. The conditions are favourable to waterflood : mobility ratio (0.5), displacement efficiency (around 70%), shape of the structure. The scheme includes 8 producers and 4 injectors located near the water-oil contact on the west side of the panel. Production started end 87, injection in 88 and early water breakthrough (in 90) pointed out the significance of the permeability barriers. The problem was alleviated by modifications to the completions on both producers and injectors, based on close monitoring of water saturation development. This policy appears to be successful since a production of 120 million stb is expected for an ultimate water cut of 97%, yielding a recovery factor of 54%. Cumulative production will add up to around 100 million stb at year end 95, so 48% of IOIP or 89% of the initial reserves. 1.4 Tertiary recovery However efficient it may be, the waterflood will nevertheless leave 100 million stb in the ground : 60 million stb in the areas by-passed by water and 40 million stb capillary-trapped in the flooded areas (based on the displacement efficiency). The characteristics of the fluids encountered in Alwyn North (composition variable with depth, initial pressure and temperature close to critical conditions) suggested a possible miscibility between the produced gas and the oil in place. Moreover depending on possible future production schemes, gas may be available for injection during the summer quarters. Therefore it was justified to investigate the interest of injecting gas in Brent East. P. 13^