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Abstract Thermal fracturing in water injectors plays a large role in controlling and determining injectivity. Vertical wells cannot always deliver the required rates to support offtake and achieve voidage replacement. Thus, horizontal wells are often selected to provide better sweep efficiency, and achieve higher injection rates than conventional vertical injectors. However, studies from Prudhoe Bay mature waterflood field indicate that these additional benefits can decline with time. A clearer understanding of the injection mechanism and an integrated solution was required to improve field injection performance. This paper presents field data on an injectivity study of several Prudhoe Bay injectors. Step rate tests results indicated no significant difference in injectivity between horizontal and conventional vertical injectors with time. It was concluded that the key to operating horizontal wells is achieving and maintaining fractures in multiple locations, and limiting fracture growth in the better quality rocks. In addition, water quality is crucial in attaining desired injection rate, fracture injectivity, and fracture growth. A recommended approach is presented in this paper which emphasises the need for a concise understanding of fracture characteristics in the reservoir for optimal injection performance. With the increasing need for water-flooding to access today's reserves and the rising costs in drilling horizontal injectors, this paper showcases the benefits of mitigating the decline in horizontal well injection performance with time. This is crucial for the proper distribution of water across the entire net interval reducing the risk of injectivity loss, and optimizing injection performance throughout the life of the field to achieving ultimate recovery. Introduction The Prudhoe Bay field, Alaska, is the largest oilfield in North America and has been in production since 1977. The Northwest Fault Block, originally containing 1.0 Billion STB of oil, is a structurally complex area bounded by faults on three sides and reservoir heterogeneity of fractures, high permeability streaks, layered reservoir and gravitational segregation. This area has lower pay Zones 2 and 3 (high quality) which are almost flooded out, and an upper Zone 4 (low quality) which contains the majority of the un-swept oil. Seawater injection ceased in 1996 and waterflooding was conducted solely with produced water thereafter. Due to vertical conformance issues, horizontal injectors were drilled and several of the existing vertical injectors were sidetracked as high angle or near horizontal wells to place injection into the un-swept upper Zone 4 Ivishak1. By accessing the remaining reserves in the lower permeability spots and careful well design and management, significant benefits have been delivered and field decline rate has been nearly halved from 19% to 10% per year. Waterflooding Challenges As the waterflood matured, waterflooding challenges became evident. From field data in Zone 4, it was observed that a conventional vertical injector could inject about 2000 to 3000 bwpd of produced water by injecting above fracture pressure. Above this rate, fracture growth becomes excessive and the well eventually loses rates to the more permeable Zone 3 connecting it to Zone 4. This has a negative impact on flood efficiency creating water cycling. Conversely, when produced water was injected into an unfractured cased and perforated well, the perforations plugged up with time, and injectivity declined unless the well was thermally fractured. This was evident in both vertical and horizontal wells. Moreover, step rate tests (SRT) on seven periphery injectors comparing horizontal and vertical completions indicated that there was no significant difference in their injectivities with time. Three of these wells were vertical injectors, Well A, Well B and Well D; the other four were horizontal injectors Well C, Well D-ST, Well E, and Well F. Vertical Injector Step Rate Test: Well A, a vertical injector which was drilled in April 1994, was perforated in Zone 4. Testing indicated out-of-zone injection in July 1999. It was squeezed in May 2000, however the well lost conformance again in May 2002. A temperature profile on Well B, a vertical injector, which was drilled in May 1994, also indicated out-of-zone injection in May 1998. SRT results for Wells A and B are shown in Figure 1. Following this the injection rate was set at 3000 bwpd for the wells. |
