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.

Ormen Lange is the second-largest gas field in Norway, currently providing 20% of the domestic gas consumption for the UK. As one of the world's largest subsea big-bore gas wells -with production rates up to 350 MMscf/d per well, a 120-km tieback to shore, subzero seabed temperatures and a design life of more than 30 years -these wells provide unique technical challenges. Due to the low reservoir rock strength, high velocities and the life expectancy of these wells, sand control was identified as a prerequisite from day one. This paper clarifies the logic of the selected sand control method and describes the extensive testing required to qualify the sand control hardware and associated completion fluids for the expected operating conditions. The execution of thirteen successful sand control completion installations will be discussed, including both ends of the success spectrum, and well performance will be covered.Throughout the four-year installation campaign to date, a number of new technologies were qualified and successfully integrated into the lower completions. These included cableless gauges to provide data closer from the reservoir inflow area, tagged proppant for individual subsea well fingerprinting if proppant is found at the gas plant, and water-tracer technology to aid in identifying the subsea source of potential formation water breakthrough.This subject explains the extent of the effort to progress an ambitious field development based on big-bore gas wells only (to reduce well count) from the drawing board to flawless execution and world-class production. Relevance also relates to other major big-bore, high-rate gas subsea developments with sand control requirements that are currently being pursued in similar harsh environments (deep water, Arctic conditions, sub-zero seabed) that might have interest in the application of Ormen Lange's successfully implemented technology.

The challenges in developing the Ormen Lange field were the harsh weather conditions, deep-water depth, subsea topography and sub-zero seabed temperatures. Due to environmental constraints and the selected sand face completion type, a water-based fluid system was required. This paper discusses the design of the fluids to give full hydrate inhibition, maximize breaker effectiveness, provide low overbalance, and reduce corrosion risk. An extensive research and development program was initiated that spanned over two years. The study included bridging and chemical component selection, brine evaluation, hydrate suppression measurement, elastomers compatibility, extensive breaker treatment studies, formation damage measurements using actual reservoir core and long term corrosion testing. An in-situ generating acid/enzyme breaker treatment deployed in the gravel pack carrier fluid was developed to optimise filtercake cleanup whilst providing a non-corrosive environment for the selected gravel pack screens and lower completion metallurgy. The basis of design and knowledge gained in the laboratory testing phase was transferred to the field and the first three wells of the initial development phase have been drilled and completed trouble-free. The resulting production rates have met expected targets proving low formation damage and an efficient cleanup was achieved. Introduction When the Ormen Lange field comes into full production, it will make Norway the second largest exporter of natural gas in the world and will supply 20% of the UK's gas requirement. Maximum daily exports from the Ormen Lange field will amount to 80 MSm3/day of gas and 50,000 bbls of condensate. The gas will be piped to the UK through the Langeled Pipeline which is the world's longest underwater gas pipeline at 1200 km long. The field was discovered in 1997 and is the second largest gas field on the Norwegian continental shelf. It is situated 140 km west of Kristiansund in the Norwegian Sea in deepwater, with depths up to 1100 meters and seabed temperatures as low as minus 1°C. The field has proven gas reserves of 400 billion m3 (14 Tcf), with an expected field life of 25–30 years. The first phase of the field development consists of two subsea templates with eight subsea big bore wells requiring a total investment close to 10 billion USD. During the later phases of the project, a third and possible fourth template will be installed bringing the total number of wells up to 24. Each of the big bore wells is designed for production rates up to 10 MSm3/day (350 MMScf/day). Therefore optimum drilling and completion fluid selection was considered to be a key focus area to maximise the open area to flow and associated well productivity, in order to comply with the planned lifetime and production targets.

This paper describes the design and qualification testing of high density oil based screen running fluids for an HPHT subsea gas field development in the Norwegian Sea. The field of interest contains gas bearing sandstones with permeabilities up to 5-10 Darcy buried at greater than 5000 m at high temperature and pressure (185 °C, 830 bar). The wells are designed to be completed with standalone screens. However, running screens in high density OBM has been a challenge for the industry due to the high solids load of such fluids. To qualify an HPHT screen running fluid, crucial to the economical development of this field, a rigorous fluid testing program was designed and carried out. The main drivers for the fluid qualification are to ensure that: The fluid is stable at downhole temperature to allow the running of the screens to bottom without plugging The fluid should remain mobile to allow easy backflow after a 28-day static period to allow subsequent well completion operations and back flow of the wells The fluid should not plug the screens after the 28-day static period The fluids were first designed and tested in vendor laboratories to ensure good long term stability and mobility. This was followed by internal confirmation testing by the operator. Final qualification at a third party facility for stability and mobility was carried out at simulated downhole conditions using a purpose built HPHT cell incorporating a sand control screen. The results of the qualification program showed that a 1.90 sg oil-based fluid containing fine barite can deliver a feasible solution to the completion challenges for the HPHT field development. The designed fluids are stable, easy to backflow and will not plug the sand control screens. The learnings from this study will also be presented.

Summary The challenges in developing the Ormen Lange field were the harsh weather conditions, deepwater depth, subsea topography and subzero seabed temperatures. Due to environmental constraints and the selected sandface completion type, a water-based fluid system was required. This paper discusses the design of the fluids to give full hydrate inhibition, maximize breaker effectiveness, provide low overbalance, and reduce corrosion risk. An extensive research and development program was initiated that spanned over two years. The study included bridging and chemical component selection, brine evaluation, hydrate suppression measurement, elastomers compatibility, extensive breaker treatment studies, formation damage measurements using actual reservoir core and long term corrosion testing. An in-situ generating acid/enzyme breaker treatment deployed in the gravel-pack carrier fluid was developed to optimize filter-cake cleanup while providing a noncorrosive environment for the selected gravel-pack screens and lower completion metallurgy. The basis of design and knowledge gained in the laboratory testing phase was transferred to the field, and the first three wells of the initial development phase have been drilled and completed trouble free. The resulting production rates have met expected targets proving low formation damage and an efficient cleanup was achieved.