This paper reviews the experience with the original completion of the Statfjord wells. A brief description of the reservoirs and geology is given and the drainage strategy for each reservoir is reviewed.The workovers' performed due to reservoir requirements, corrosion, sand production and mechanical failures are summarized.The design basis for an optimized completion is given and the benefdts of the monobore completion are reviewed. A typical Statfjord well life sequence is described and finally some production~esults are given.-

The Kvitebjørn medium rich gas condensate field in the Norwegian North Sea is characterized as a high pressure high temperature (HPHT) reservoir with 770.5 bar pressure and 150°C temperature at about 4000 m TVD MSL. Despite high temperature and depth, the average reservoir properties are reasonably good. The main reservoir is Brent Group of Middle Jurassic age which is extensively faulted. One of the main challenges is the drilling in depleted reservoir. The strategy to mitigate the problem has been to put the field on reduced production and/or to actively manage reservoir pressure by producing more from areas far away from the drilling locations. Advanced drilling technologies have also been developed to improve drillability. Several improved oil/gas recovery methods are currently under consideration, which include infill drilling, process capacity upgrading, low pressure-production and gas recycling. Infill drilling is challenging due to reservoir depletion. Capacity upgrading is to be implemented to expedite hydrocarbon recovery. Gas recycling has some potential for improved condensate recovery, but the project economy is poor. Low pressure production appears to be a very attractive option. A compressor concept has been selected based on thorough evaluation of space and weight limitations on the platform, possibility for future drilling and intervention operations, explosion hazard, tie-in of other prospects and future export facilities etc. Subsurface challenges include uncertainties related to well integrity and productivity, reservoir communication, reservoir volumes, etc. The purpose of this paper is to present the challenges related to development and management of this HPHT gas condensate reservoir, the strategies to overcome the challenges and the methods to improve gas and condensate recoveries from this field with special focus on the low pressure production and gas recycling. Introduction The HPHT Kvitebjørn Field is located in block 34/11 in the southeastern part of the Tampen Spur area of the Norwegian North Sea (Fig. 1). The field is currently owned 58.55% by StatoilHydro, 30% by Petoro, 6.45% by Enterprise Oil and 5% by Total. StatoilHydro is the operator. Block 34/11 was awarded in the 14th concession round in 1993. The field was discovered in 1994 by the exploration well 34/11–1 (Fig. 2), which encountered a gas condensate column of 175 m in the Brent Group. A gas-water-contact (GWC) at 4139 m TVD MSL was observed in this well. Another appraisal well (34/11–3T2) was drilled in 1996–97, which confirmed a gas condensate column of 160 m in the same formation. A plan for development and operation (PDO) of the field was approved by the authority in 2000. The main drilling program started in October 2003 and the production commenced on 26th of September 2004. The development plan consisted of a platform having a 20.7 MSm3/d production/processing capacity with three stage separation, one drilling rig and living quarters. The water depth at the Kvitebjørn platform is 190 m TVD MSL. The drainage strategy was chosen to be pressure depletion by 11 production wells.