Permanent Downhole Gauges Used in Reservoir Management of Complex North Sea Oil Fields

Abstract

Original SPE manuscript received for review Sept. 7, 1993. Revised manuscript received May 10, 1994. Paper accepted for publication May 23, 1994. Paper first presented at the 1993 SPE Offshore Europe Conference held in Aberdeen, Sept. 7–10. SPE Production & Facilities, August 1994. Summary This paper presents experience with and applications of permanent downhole pressure and temperature gauges in the reservoir management of two complex North Sea oil fields, Gullfaks and Veslefrikk (both operated by Statoil A/S). In total, 40 quartz and quartz capacitance gauges from three different suppliers have been installed in platform wells over 6 years. The gauges have given invaluable real-time data for reservoir management of these two fields and contribute directly to increased daily oil production. The installations have proved to be safe and reliable, as well as good investments. Introduction The Gullfaks field is in the central part of the Eastern Shetland basin in the North Sea, 175 km [109 miles] northwest of Bergen, Norway (Fig. 1). The field has been developed with three concrete gravity-based platforms-Gullfaks A, B, and C-and started production in Dec. 1986. The oil is located in three major sandstone units: the Brent group, the Cook formation, and the Statfjord formation. These shallow, highly porous sandstones are generally poorly consolidated, and sand control is necessary in a number of high-permeability producers. The reservoirs are overpressured, and water injection is the main drive mechanism. As of June 1993, 80 of 107 planned wells had been drilled. Of these wells, 29 have a permanent downhole gauge installed. The daily oil production is 85 000 std m3/d [530,000 std B/D]. The Veslefrikk field consists of an upthrown horst block on the northwestern flank of the Horda platform, approximately 145 km [90 miles] northwest of Bergen (Fig. 1). The field has been developed with a lightweight drilling and wellhead platform and a floating production platform. Production started in 1989 from six predrilled wells. The oil is produced from two separate sandstone reservoirs: the deltaic Brent group and the deeper, shallow marine Intra Dunlin sand (IDS). The reservoirs are slightly overpressured. The production strategy is to commingle production and injection with peripheral water injection to maintain the average reservoir pressure above the saturation pressure. As of June 1993, 17 of 20 planned wells had been drilled. Permanent downhole gauges are installed in eight wells. The daily oil production is 12 000 std m3/d [75,000 std B/D]. Table 1 lists general field and reservoir data for the two fields. Differences between the two fields lead to various applications for permanent gauges. The Gullfaks field is heavily faulted with a number of sealing or partially sealing faults. One important reservoir monitoring objective is to identify the degree of communication between the fault blocks. The Veslefrikk field is partially developed with commingled wells. Permanent gauges are installed in dedicated wells to monitor the two reservoirs independently. Data from the permanent gauges are used for both fields to ensure single-phase oil flow in each fault block. That information also is used to monitor and optimize well performance with time, for transient well-test analysis, and for matching numerical models. Permanent downhole gauges are installed in key wells where the need for enhanced data acquisition is defined. The first permanent downhole pressure gauge was installed in July 1987 in a Gullfaks well. As of June 1993, 40 gauges had been installed in Gullfaks and Veslefrikk wells in 35 producers and 5 injectors. Locations of the wells with permanent gauges are given in Fig. 2 for Gullfaks and Fig. 3 for Veslefrikk. Three different gauge systems delivered by three different suppliers have been used. Fig. 4 shows the gauge installation history for each platform during 1987-93, and Fig. 5 shows the number of gauges installed for each system. Cost/Benefit Analysis The decision to install permanent gauges was based on three primary factors.The need for enhanced reservoir description, especially during the initial production phase.Increased production resulting from a combination of less downtime for data acquisition and optimization of reservoir and well management.Safety and operational considerations. Large investments before production startup are typical for most North Sea developments, requiring a high early production to ensure project profitability. At the same time, reservoir complexity and relatively short field lifetimes necessitate extensive data acquisition during the initial production phase. Permanent gauges support both these requirements by supplying continuous downhole data with a minimum of well downtime. Production from the Gullfaks field has mainly been limited by well capacity, whereas Veslefrikk production has been partly limited by well capacity and partly by injection system capacity and availability. Consequently, well downtime owing to data acquisition results in deferred production. Running a wireline gauge typically requires 28 hours of shut-in, including shut-in of neighboring wells for safety reasons. Because individual well rates vary between 500 and 5000 std m3/d [3,145 and 31,450 std B/D], this represents a significant production deferment. The cost of the deferred production depends on several parameters: the platform in question, plateau length, planned well lifetime, oil price, dollar exchange rate, and taxation. A common factor among the most important parameters is that the cost is highest early in the life of the well when the information is most important. On average, a cost of 270 NOK/stock-tank m3 [$US 7/STB] for deferred production is estimated. In addition, the cost for a well test with wireline gauges is approximately 600 000 NOK [$US 100,000]. The extra rig time required to install a permanent gauge is about 8 hours, and the investment costs average 1 100 000 NOK [$US 180,000] per installation. Comparison of direct costs shows that the average payback period for permanent gauge installations is less than 1 year. This cost/benefit analysis is based on a comparison of permanent and wireline gauges. However, a number of Gullfaks wells are highly deviated and require coiled tubing or snubbing equipment for downhole data acquisition. This increases the cost dramatically. In these wells, the cost of installing a permanent gauge is less than the cost of a single data-acquisition operation. Furthermore, considerable potential for increased production through improved reservoir and well management exists. The possibility of using pressure data from drawdowns and operationally derived shut-ins also results in increased production by avoiding extra shut-ins for data acquisition. The use of wireline gauges for data acquisition in a North Sea well is a complex operation that may involve 10 or more people, including service company personnel and company representatives. P. 195^

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