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The Anglia gas field was originally developed in the late 1980s with the first wells being drilled with mineral oil-based mud in the reservoir sections. In most cases, production from the original wells was below expectation and only five years later, plans were being made to re-develop the field in order to maintain its economic viability as a gas producer, and meet gas delivery commitments. Well-bore placement and drilling fluid selection were determined to be critical factors in ensuring the success of planned in-fill wells. This paper reports on the planning and testing which was conducted during the selection of the drilling fluid for the reservoir phase of the new wells, changes in drilling practice and the subsequent production obtained from utilising this new approach, in comparison to the production from the original wells. Reasons for the poor production from the first phase of the development are discussed. Due to the more complex trajectories and longer well-paths required by the well design team, additional difficulties were created for the drilling fluid, notably that of lubricity. Further testing is described in the paper, where the best combination of good lubricity and minimal formation damage was sought. Final production data on three wells drilled during 1997–9 are reported. The overall experience confirms that a detailed drilling fluid selection process which takes into account key reservoir-specific factors, combined with a holistic approach to the drilling and completion of the reservoir section of a well can significantly enhance its resultant productivity. Introduction The advent of sand-face completions during the late 1980s and early 1990s drove the development of specialised drilling fluids (now usually referred to as "drill-in" fluids) for use in the reservoir section of a well1. Cased and perforated completions had been run in wells typically drilled with little or no consideration for the mud type and its potential for formation damage on the assumption that the perforation tunnels would extend beyond any near well-bore damage. In the North Sea during the 1980s, special consideration from an invasion perspective was only given to drilling fluid design for coring applications. In such cases, high oil content or "all oil" muds were frequently used, although here, the emphasis was on the use of "native state" fluids, which would not alter the innate wett ability of the core or otherwise prevent meaningful analysis of the target formation. The development of the Anglia field covers a period spanning the above transition. The early production wells were drilled with conventional invert oil emulsion muds in the 12¼" and 8½" (reservoir) sections with little if any difference in terms of fluid composition between the two sections. The later wells (A6 to A8, drilled during 1997–99) continued to use oil-based mud in the 12¼" sections but utilised a specifically designed, water-based drill-in fluid for the reservoir sections in all cases. The considerations involved in making this alteration to the mud system selection, together with the subsequent effects on the performance of the Anglia field are the subject of this paper. Jones et al2 have previously reported on the benefits of a specific design process for the selection of a drill-in fluid as a necessary step in optimising the productivity of wells; here we report on the application of this process to a multi-well project. Historical Background The Anglia Field is located in blocks 48/18b and 48/19b in the U.K. sector of the Southern North Sea, approximately 55 kilometres north-north east of Bacton in Norfolk and 90 km east of The ddlethorpe in Lincolnshire (Figure 1). The field is located in the area of the inverted Sole Pit basin close to the Dowsing Fault zone. The reservoir interval comprises the Permian Rotliegendes Sandstone formation. The Anglia Field has eight producing wells. Six wells, in the Eastern half of the field, are tied back directly to the Anglia ‘A’ platform, a small, normally unattended, tripod.

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