The North Slope of Alaska has significant accumulations of low API-gravity oil in unconsolidated formations. The combination of low-productivity wells in relatively unconsolidated formations in the arctic environment presents many challenges. Consequently, both formation stimulation (for economic production rates), and sand control (for acceptable operating costs) are required. A fracturing technique for sand control (FSC) with a resin-coated proppant (RCP) for proppant-flowback control proved feasible in laboratory testing. The initial attempts at field implementation were an investment in learning that resulted in a large number of first-order failures resulting from proppant and formation flowback. With these early failures, these attempts were not commercially viable. Laboratory investigations and field tests revealed the source of the problems, and led to design changes and improvements in implementation procedures. Field results have demonstrated that the FSC completion is a viable technique within certain formations on the North Slope that can achieve the stated goals of effective stimulation, proppant-flowback control, and sand control.

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.