A large majority of the wells in deep-water/subsea environments are being drilled as horizontal wells to gain cost-effective accessibility to multiple sand bodies and larger reserves. Most of these wells are being completed as open holes because of the higher productivities as well as lower costs associated with such completions. Furthermore, a substantial fraction of the fields in deep-water environments requires some sort of sand control. Although standalone screen completions have been used successfully in some of these deep-water fields (relatively large sand grains and uniform particle size distributions, with little to no fines), premature sanding problems have been reported, jeopardising project economics as a result of prohibitively high cost of remediation. In this paper, we present a significant case history on the application of the simultaneous gravel-packing and cake-cleanup technique in the Foinaven field, West of Shetland, UKCS. The well is the first gravel-pack completion in this deep-water, harsh environment, where various types of standalone screen completions have been utilised since the initial development of the field in 1994. The subject well is of 3,075-ft open hole, penetrating through two sand bodies separated by a 530-ft shale section. It is the first openhole gravel-pack completion in such an environment in the North Sea to result in 100% packing efficiency based on gauge hole calculations and a zero mechanical skin based on pressure build-up testing. In addition to being the first horizontal well West of Shetland to be drilled with water-based mud (WBM), this was the first production well to be drilled in a new reservoir horizon of the field, discovered and brought on line in less than 10 months. Initial production from the well far exceeded expectations and the completion was delivered safely and 3 days ahead of the target time. Introduction It is widely recognized in the industry that properly selected reservoir drilling fluids along with properly designed filter-cake removal treatments are essential to achieve high-productivity wells with low skin, particularly in gravel-packed completions where the filtercake is trapped between the gravel-pack and formation. Engineering the filtercake cleanup to be incorporated into the gravel-pack carrier fluid provides a cost-effective and uniform filtercake removal along long horizontal openholes, eliminating remedial treatments. However, this approach requires significant integration of different disciplines of well construction and completion. Previous publications have elaborated on reservoir drilling fluid selection for optimisation of the cleanup process, and the integration of custom engineered solutions.1,2 Based on friction pressures derived during yard testing, shunt tube technology for openhole gravel packs can successfully pack long openhole sections in excess of 5,000 ft pumping at low rates (e.g., 2.5 bbl/min). At these rates there is a requirement for the carrier fluid to exhibit superior rheological properties to avoid the gravel from settling out when pumping down a large-diameter workstring. In the severe conditions West of Shetland, this was a significant extension to the technology's proven limits in a harsh deep-water subsea environment. Critical to the success of any shunt-tube gravel-packing operation is the rheology of the carrier fluid; it must meet the minimum requirement for slurry transportation in the shunt tubes.

The Greater Plutonio development in deepwater offshore Angola is BP's largest and highest producing subsea development in a sand prone reservoir. The development depletion plan stipulates 100% voidage replacement in multi-layered reservoirs; however, in a subsea environment drilling individual injectors into every produced zone is prohibitively expensive, so water injectors in multiple zones are completed as Down Hole Flow Control (DHFC) designs using wire wrapped screens across the reservoir sections. In June of 2009, problems were encountered during completion installation of the sixth DHFC water injector. Although the assembly was eventually deployed to depth and installed as planned, the problems encountered resulted in no injection into either the upper or lower zones. Coiled tubing intervention work was attempted to initiate injection, but further problems and rig time constraints led to the temporary suspension of completion operations. During the following months, a right scoping exercise was carried out on well recovery options, including recovering the existing equipment and recompleting if possible. Three months later the rig re-entered the well, whereby the coiled tubing intervention successfully cleaned the lower completion screen section exposing the lower zone, allowing rig based water injection to be successfully conducted. The lessons learned were incorporated into subsequent DHFC injectors, the next of which was completed in a project Best in Class time. This paper discusses the general design of DHFC wells in Greater Plutonio, the difficulties encountered while deploying equipment into the sixth DHFC well of the project, the temporary suspension and recovery planning process, and the successful re-entry and coiled tubing intervention.