Offshore platforms and subsea wells often are designed to enable interventions to be performed during the completion phase of the well construction. An example of the above is the deployment of a deep-set plug (as a temporary barrier) to set the production packer and test integrity of the production tubing.Each intervention has a direct cost due to rig time and the risks mitigation associated with the manual rig-up and testing of the pressure-control equipment addressing health, safety, and environmental challenges becomes a high priority that will consume time during the planning of operations. Operational risk is present due to the mechanical methods used for deployment and retrieval of the plug, and in deviated well designs, this risk will be even more severe due to the implied impact.Using a case study in Equatorial Guinea, West Africa, this paper demonstrates how barrier provisions with remote open/close technology capabilities enables interventions to be removed from a completion design. The technology described was used in a horizontal subsea producer well drilled to 3,460m, and will illustrate how combining downhole electronic control with a full-bore hydraulically operated barrier valve removes any need for running control lines to surface. Surface applied pressure and time combinations were used to command remote actuation of the valve. The factors that must be considered when determining these commands are also discussed.The successful field deployment discussed in this case history illustrates how applying remote open/close technology provided the opportunity to challenge conventional completion methodology and was capable of providing significant cost savings as well as simplifying operational strategies. IntroductionThe Ceiba field is located 22 miles (35 kilometers) offshore Equatorial Guinea, West Africa, and is 150 miles (241 kilometers) south of Malabo (Figure 1). (Weaver, R.A. et al, 2002) Located in approximately 700 m of water and in one of six subsea clusters in the development, this well was identified as a suitable candidate for the inclusion of the technology outlined in this paper.

Achieving flow performance in openhole sand control completions often requires removal of the annular gap between the screen section and wellbore. For the first time in the industry, patented hydraulic screen technology has been used to provide wellbore support and overcome the challenges associated with gravel packing in depleted reservoirs with low operational margins. This paper demonstrates how new technology has been adopted by an operator in Norway to provide effective downhole sand control in an offshore environment faced with continuous reservoir pressure depletion. Detailed job planning and evaluation of risks when adopting new technology is described.The case study describes a producer well drilled to 2580 m, at a maximum deviation of 30º, and temperature approximately 90ºC. With the sand control equipment run to depth closed ended, the liner hanger and hydraulic screens are set by surface applied pressure. When set, the screens extend radially to close the annular gap and provide wellbore support; production ports in each screen provide the flow path from the reservoir to production tubing. The liner hanger packer was set and reservoir isolation barrier valve closed in the same trip providing testable barriers, prior to displacing the well for upper completion operations.The paper outlines how adopting new technology challenges openhole gravel packing and delivers effective downhole sand control in a depleted reservoir. The operator has demonstrated savings associated to operational planning, logistics, HSE risks and rig time. Production rates meet expectations with all screens contributing to flow.