The need of cutting the costs of new oil wells in the San Jorge Basin led YPF S.A. to study the option of reducing well diameters. For an effective cost reduction, it was necessary to be able to case the hole with diameters smaller than 4.5 inches. The problem of a completion in 3.5 inches or less was the inability to efficiently lift the production with traditional methods. Initially a monobore type completion was tested, in detriment of pump setting depth and pump efficiency due to the presence of gas. The introduction of a mechanical pumping system lifting fluids through coiled tubing made possible the solution of the problems of the pump depth and efficiency. The paper describes the type of installation and procedure followed to run the system. The success of this type of installation will allow the operator to produce in wells cased with 3.5 inches or less, matching the efficiency of conventional wells cased with 5.5 inches, in a range of production volumes compatible with most of the wells in the basin. At the same time, the system offers the advantage of using conventional technology such as beam pump on the surface and mechanical pump at the bottom of the well.

An innovative surfactant chemistry in a nonaqueous system with an oil-to-water ratio (OWR) of 20/80 was effectively utilized for the first time to provide wellbore stability and run a sand-control screen in an openhole gravelpack completion. This novel type of invert emulsion system uses relatively higher aqueous internal phase, i.e., less than 50/50 OWR, which subsequently allows for a relatively higher density than the drilling fluid. More importantly this system is maintained as solids free and oil continuous.The increasing application of Inflow Control Devices/Intelligent Wellbore Systems and swellable elastomers as well as drilling longer intervals and their exposure to shale/sand dictates the use of compatible and solids-reduced invert systems to reduce the risk of an unsuccessful gravel placement treatment caused by shale swelling or plugging of sand control screens. This novel high-internal phase system provides flexibility for these types of completions. The use of the higher internal phase allows the formulation of oil-continuous solids-free systems while still achieving the required density necessary in solidsladen aqueous systems. This paper will focus on the selection of the 20/80 high-internal-phase system for this openhole completion, the upfront testing and planning for deployment. Discussion will also be provided with respect to the mixing of the system at the wellsite as well as the lessons learned.

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.