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Development and management of deepwater oil fields requires material investment and must be supported by application of quality technological solutions and tools. To maximize the advantages that can derive from these, it is essential to integrate technologies and disciplines throughout the field cycle. This integration makes it possible to identify and fix issues early and seize business opportunities quickly. We describe the activity carried out on a field characterized by a high-quality oil-bearing clastic reservoir located in a deepwater belt along a West African continental passive margin. We highlight how geoscience specialists from both geologic and geophysical branches have contributed to construction of the static and dynamic reservoir model, field monitoring, model updating, and operations optimization. The wide geologic and geophysical experience in the area made it possible to build a petroelastic model and a sedimentological model that were integrated in the population of a geocellular model. Seismic data also were used to support reservoir monitoring of the producing field. A dedicated 4D seismic project helped our understanding of fluid movement and fault behaviors in the field. The 4D information was interpreted and shared within the integrated team with the goal of identifying further business opportunities and driving decision making over our area of interest.

2018 will be the brightest year for upstream investment since 2014. Costs reduction and the oil price stabilization gives operators confidence in launching new challenging projects. However, launching new projects is still particularly challenging for deep-water assets. Even if project costs are 20% lower than mid-2014, deep-water projects are not yet competitive with tight oil, considering also the higher associated uncertainty. The direction to improve is clear: further cost cuts, through leaner development principles and improved well designs. Moreover, operators have to take advantage from lesson learned of projects already in production. Eni has consolidated on its West Africa deep-water assets a workflow that can support challenging projects FID through: Reduction of time to market parallelizing project phasesManagement of project uncertainty through flexibilityWork in integrated teams taking advantage from digital transformation More in details, the first target is to reduce time to market anticipating free cash flow generation. This is achieved through an appraisal while developing phase: drilling appraisal as first wells of development campaign, derisking the following well locations. Time-to-market reduction is achieved by parallelizing development phases, starting development plan definition during exploration phases and anticipating procurement of long lead items. This is possible if subsurface uncertainty has been properly defined through robust 3D models and if projects can guarantee the flexibility to capture new opportunities: fine tune well locations during drilling campaign, keep spare slots availability and sidetrack opportunities, substitute water and gas injectors with water alternate gas wells (WAG). In addition, Digital Transformation offers more and more the possibility to continuously update 3D models thanks to the availability of real time data, run thousands of simulations on super computers and monitor in real time field performance, taking advantage from simple daily operations. This work is aimed to describe the steps that were the key successful factors of Eni operated deep water projects in West Africa. The presented workflow can now be considered a standard approach for the most challenging Eni's projects and supported the company to reach record time-to-market for the execution of challenging deep-water projects in the range of 2,5 to 4 years from authorization to first oil.

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