Abstract The reliable calculation of tubing pressure drops in oil and gas wells is important for the most cost effective design of well completions. None of the traditional multiphase flow correlations works well across the full range of conditions encountered in oil and gas fields. Consequently, two of the recently published "mechanistic" models, one by Ansari, the other by Hasan and Kabir, were evaluated. The performance of these methods was compared against traditional correlations in three ways: The predicted against measured pressure drops were compared for stable flow conditions using 246 data sets collected from 8 producing fields, including a gas and gas-condensate field. None of these datawere available to the developers of any of the multiphase flow model sevaluated. Suitable methods should reliably predict the "lift curve minima".This determines when a well may need to be "kicked off", artificially lifted or recompleted. The multiphase flow model must not contain discontinuities or be subject to convergence problems. No single traditional correlation method gives good results in both oil and gas wells. In fact, most of the traditional methods which work reasonably in oil wells give very poor predictions for gas wells. Hasan and Kabir's mechanistic method was generally found to be no better than the traditional correlation methods. However, the Ansari mechanistic model gave consistently reasonable performance. Although it did not give the most accurate results in every field, it gave reasonable results across the complete range of fields studied. The Ansari method also gives a reliable prediction of the lift curve minima. Areas in which it needs improvement were identified. By comparison the best of the traditional methods, the Hagedom and Brown correlation, gave good results forstable flow conditions in oil wells, but it does not correctly predict the lift curve minima. A field example shows how this can lead to erroneous conclusions. Background Flow up the tubing in oil and gas wells is usually multiphase. Calculation of pressure drops in upward multiphase flow is not simple, due to the slippage of gas past liquid, along with the changing temperature and pressure conditions. Nevertheless, Petroleum Engineers need to predict pressure drops in oil and gas wells for the following reasons: To construct "lift curves", which are tables or plots of flowrate versus bottom hole pressure, used to predict well flowrates. To select the appropriate tubing size. If the tubing diameter is too large, the well acts as a gas-liquid separator and a flow conduit, and the excessive slippage results in needlessly high bottom bole pressures. However, tubing which is too small will cause excessive frictional pressure drops. To design artificial lift completions such as electric submersible pumps, jet pumps or gas lift. Several multiphase flow correlations are available for predicting tubing pressure drops. P. 109^

SPE Member Abstract The Gannet cluster is an integrated oil and gas development encompassing the Gannet A, B, C and D fields which came on-stream in October 1992. This marginal field development marks an evolutionary phase for Shell U.K. Exploration and Production as future fixed installation green field developments are expected to consist of small sized hydrocarbon accumulations which will be uneconomic to develop on their own. The features which serve to make this otherwise marginal development economic pose considerable reservoir management challenges over the life of the project because of the differing reservoir conditions, expensive data acquisition in sub-sea wells, the integrated nature of the facilities and the need to meet stringent sales gas contractual requirements whilst maximising oil production. This paper describes the pre-drilling optimisation studies that were carried out, the success of which is partly attributable to the introduction of integrated field teams within Shell Expro's Central Fields Unit, and the preparation of a reservoir management plan which is now an integral part of the planning process for the Gannet Cluster. Introduction The Gannet project is an integrated oil and gas development of the Gannet group of fields that came on-stream in October, 1992. The fields are located in the Central North Sea some 180 km east of Aberdeen in water depths of 95 m and are operated by Shell U.K. Exploration and Production on behalf of Shell and its co-venturer Esso. The project consists of the development of the Gannet A, B, C and D fields through a single platform located at Gannet A and Subsea wells at Gannet B, C and D (Fig. 1). The reservoirs are good quality turbiditic sands of tertiary age (Tay, Rogaland, Forties, Lista and Andrew formations see Fig. 2) and reservoir depths vary between 5800 - 8900 ft ss. Produced fluids from each of the fields are piped to the Gannet A platform where they are processed. Oil is exported via the Fulmar Floating Storage Unit located 112 km south of the Gannet cluster while sales gas is routed via the 20" Fulmar to St. Fergus gas line. Gas compression is installed on Gannet A to compress gas up to sales/injection/gaslift specifications. The development potential of the cluster was recognised in 1984 leading to development plans and conceptual design in 1985. However the project fell victim to the oil price collapse of 1986. Significant cost reductions were identified during 1986 and 1987 and a new development plan was proposed in 1988 leading to final Annex B approval in 1989. The new plan was based on the concept of reducing lifetime costs and incorporated several design features that helped to reduce the capital and operating Costs of the facilities. These include single lift installation, minimum facilities, minimum manning and tender assisted drilling. Adequate aquifer Support is expected thus the onerous cost of installing water injection facilities was avoided. On the revenue side, oil income is Supplemented by gas sales. The Substantial gas reserves in Gannet have been packaged with a fixed Daily Contract Quantity and seasonal swing capability thus enhancing the value of the gas. Gannet B, which is developed as a non-associated gas field, will provide the swing capacity in the early years while in the later years of the project the gas contract will be met by the planned blowdown of the gascaps in Gannet A and C. Given that literary future North Sea projects will be of a similar nature i.e. the clustering of marginal fields to give a overall economic project, the successful performance of the Gannet project is of relevance to future marginal field developments in Shell and Esso's North Sea hydrocarbon resource portfolio. However, the engineering design features and stringent gas sales contract that help to make the Gannet development economic, also pose considerable reservoir management challenges over the life of the project. In order to realise the concept of low lifecycle costs, it is also necessary to adopt a comprehensive lifetime approach to reservoir management. RESERVOIR MANAGEMENT CHALLENGES As is common with some other North Sea operators, the exploration, appraisal and development planning sectors of Shell U.K. Exploration and Production are based in London. P. 183^