Expandable Sand Screens (ESS®) were deployed successfully in two gas-condensate subsea production wells on the Scoter field, in the UK sector of the North Sea in May 2003. The Shell UK operated 22/30a-S1 (Scoter P1) and 22/30a-S2 (Scoter P2) wells are near-vertical, drilled from the semi-submersible rig, Ocean Guardian, and penetrate the Forties sandstone. Well clean-up performance to the rig (June 2003) and first production to the Shearwater processing platform (December 2003) exceeded original expectations. The success of the Scoter 4" ESS installation has been due, in part, to the multi-disciplinary approach taken by both Shell and Weatherford, from concept selection to after-action review. This paper details learnings on the extensive ESS design and execution including:Torque and drag analysis for screen running in and expansion to minimize damage.Determination of rig-heave effects on screen expansion from an Axial Compliant Expansion (ACE) tool.Use of long-term, synthetic core baking-tests (at temperature) to estimate the effect of completion-to-clean-up time on reservoir return permeability: initial production data showed no evidence of skin (no wellbore damage or screen plugging for both wells).Erosion and collapse modeling of the screens.Well clean-up and bean-up, including offshore petroleum engineering support.Sand control contingency planning (e.g. external gravel pack sand control design, including mud selection testing).Simplified completion including use of a Formation Isolation Valve (FIV) This technical knowledge can be adopted elsewhere for future sand control applications, including:Any design and installation of ESS, especially from a semi-submersible rig.Any return permeability testing, especially to assess the effect of delayed clean-up on reservoir return permeability.Any clean-up of a gas-condensate ESS well. Introduction Scoter is a lean gas-condensate field, penetrated by two vertical wells (Forties sandstone; Figure 1), and tied back to the Shearwater process facilities. It is located in the UK Central North Sea, some 160 miles east of Aberdeen, 7.5 miles north of Shearwater field. Scoter's lower completion consists of approximately 400ft of 4" ESS (230-(m weave; 316L metallurgy) expanded inside open-hole of 57/8" diameter, a Formation Isolation Valve (FIV), and a hydraulically-set packer from which the lower completion is hung. Note that the lower completion does not include expandable isolation sleeves (EIS), for potential future water shut-off, due to the risk of setting the EIS across reservoir sands (in case the completion string was not run to total depth as planned), and subsequent loss of reserves. The upper well completion consists of 5.5" 13Cr tubing with a permanent downhole pressure and temperature gauge (PDG), and a hydrostatically-set packer. See Figure 2 for a generic completion schematic of the Scoter wells.

Early production history of the U2 sand, Mapiri field, indicated that solution gas drive was the predominant producing mechanism, and by mid–1954 the reservoir pressure had dropped from the original 4,100 psi to below 3,000 psi for a production of approximately 3.25 million bbl, or 11 per cent of the oil initially in place. At this time it was predicted that the ultimate recovery by primary depletion would be only 5.9 million bbl or 19.6 per cent. Repressuring by gas injection was then initiated, and the reservoir pressure was raised to the original value of 4,100 psi by the end of 1957. It is planned to maintain the reservoir pressure at this level until depletion, at which time it is estimated that the recovery will be 32.4 per cent or 9,725,000 bbl, an increase of 3,825,000 bbl over recovery by primary depletion. The performance to date has followed closely that predicted in 1954, and has indicated that gas has reentered solution in the oil leg, and that a sharp flood front has been formed. GOR's are consequently close to the solution ratio, and no serious channelling or gas breakthrough has occurred. Introduction Among the few major reservoirs in the Mapiri field, the U2 sand (Fig. 1), which lies at an average depth of 10,200 ft, was recognized at an early date as having good possibilities for a future gas injection project. This formation is a channel-type sand of Miocene-Oligocene age, in which the channel runs roughly north-south with the net sand thickness exceeding 60 feet in the center. The average thickness is 23.5 ft. Near the edges the thickness drops rapidly, being virtually unproducible in areas with less than 10 ft of net sand. The oil leg has a closure of about 600 ft and the water-oil contact is shown at an average depth of 9,450 ft below MSL. Sand Characteristics The sand is a fine to coarse-grained sandstone, hard, quartzitic and massive with some secondary cementation. It is heterogeneous with variations in vertical and horizontal permeability, and individual lenses vary widely in thickness. The porosity varies considerably both vertically and horizontally and the weighted average for the reservoir is approximately 12 per cent.