Oil and gas industry is increasingly approaching more challenging situations where it is of primarily importance to carefully assess the technical solutions to maximize productivity, to evaluate the economic worth of investment and identify all the risks and opportunities involved in the project.A challenging subsea well is planned to be drilled and completed in a deep offshore field in the Adriatic Sea (Italy). This project includes all the challenges and criticalities related to: deepwater wells, sour environment, gas lift wells, multilateral and intelligent wells.The objective of the study was to provide decision support for the selection of the most suitable multilateral and completion design addressing, through a probabilistic approach, all the uncertainties regarding reservoir characteristics, well design and productivity in terms of duration and cost.A multidisciplinary working team, including drilling and completion engineers, geologists and reservoir engineers, has been created in order to assess all the aspects of the project with its opportunities and criticalities.Different scenarios have been compared with regards to the available technologies for multilateral and intelligent completions.The first step of the analysis was the identification of the uncertainties (opportunities and risks) related to technical, organizational or environmental issues, successively reported in a probabilistic time and cost model.A dedicated fault tree approach was deemed useful to focus on the combination of events leading to a potential branch loss and to calculate the associated probability.All uncertainties were then combined with production profiles into a technical unit cost ($/bbl). This paper describes workflow and results. The results provide the managers with a comprehensive picture of a complex issue to make the investment right decision at a given confidence level.This should provide a guideline to engineers, geologists and managers on the risked approach for the development of complex projects.

Usually, the preferred way to restore production in wells with accessibility heavily compromised is by rig workover activity. However, a preliminary approach in rigless mode followed by rig activity can be even more effective in the presence of several critical issues. Here we illustrate the methodology and technical solutions adopted to perform a challenging rigless fishing job to make the subsequent rig workover operation quicker, cheaper, and safer. A workflow was developed for a course of actions to perform a complex fishing intervention while fully respecting the well control requirements. Considering the well status—1½-in. coiled tubing (CT) stuck in 4½-in. tubing at 7582 ft due to scale buildup, parted in two segments side by side, top of fish at 1345 ft and with no injectivity in the well—it was decided to adopt a fit-for-purpose rigless strategy by combining conventional fishing tools (flow release overshot, continuous cutting overshot) with a CT anchor, which guided the electrical line (EL) cutting tools inside the pipe while keeping it in tension. To accomplish the target, a robust design, with multiple contingency plans was properly defined and successfully implemented. In addition to the main constraint of having a CT pipe parted and stuck in the tubing, the scale deposit prohibited killing the well by bullheading. Consequently, the overall fishing operations were planned and managed as if the well was alive. The alternate use of CT fishing tools, CT anchor, and EL cutting operations allowed recovering approximately 6958 ft over a total length of 7398 ft, leaving just 440 ft of CT pipe stuck in hole inside the scale deposit (with the new top of fish at 7142 ft). As a result, a complex well situation, which could have led to a long and expensive rig operation, was successfully approached in rigless mode, leaving the well ready for a simpler workover activity. The use of Continuous Cutting Overshot (CCO), through a standard "cut & drop" approach, was limited by the CT lubricator height. An innovative fishing approach was then deployed: a proper CT anchor BHA, to latch and hang the CT pipe in the tubing wall, was run. The beveled shape of the CT anchor allowed EL tools to enter inside the CT pipe and cut the same above the free point, so recovering longer sections of pipe.

Nowadays WAG (water alternate gas) injector is considered a new frontier for subsea field with injectors or disposal wells in order to minimize CAPEX and obtain same benefits on field substain. Looking forwards to forthcoming subsea development, to implement this technology has been considered a must in order to reduce the number of wells dedicated to injection and reduce subsea facilities layed for injection both gas and water. Company is going to develop field in Angola and Nigeria, where oil has different characteristics but with the same constrains related to reservoir pressure maintenance. This abstract shall consider a study performed by headquarter related to the possible scenario accepting WAG injection using intelligent completion technology and the relative risk analysis. This technology for the company is considered a key choice in order to complete, partialize and control flowing in different layers, with different pressures and different characteristics. Conscious of this ability engineering center decided to move in this direction (more or less one years ago in 2010) and started a dedicated detailed study to consider Angolan field. The field have a water depth and environment with 1,500 - 2,000 m of water depth. The goal of the project will be achieved a cut off 50% of the CAPEX related to injectors in both fields, at the same time considering also interface with subsea facilities and surface facilitites. Abstract aims to show what is the impact in terms of economic, evaluated on this project, beginning by base case of injectors dedicated for each level, to final project approved and actually in execution. Terms of comparison will be the delta CAPEX, NPV and IRR of both projects.

This paper describes the experience and advantages of both the operator and service company in using Intelligent Completion (IC) technology in deepwater challenging environment. Following a feasibility and risk analysis study performed by the operator, a single well with a triple zone the IC was selected as the best completion solution compared to a dual zone or single wells cluster solutions. The increased cost of this technology was justified by the overall CAPEX project reduction, increment of expected cumulative production and anticipated reservoir's lower layers production. While two zones IC can be completed with the flow control valves run above the gravel packed zones, the same cannot be done in triple zone IC; in this case, to allow fully independent zonal monitoring and control, two out of three of flow control valves and gauges needs to be run inside the lower zone gravel pack assemblies, bringing a complete new set of interface challenges between the upper and lower completion equipment. Equipment and procedure's risks were addressed and mitigated through Failure Mode and Effects Criticality Analysis (FMECA) reviews and completion System Integration Test (SIT). Flow control valve's choke design were also checked, based on the expected production profiles and downhole PVT, to cover the entire production rate and achieve the best draw down applicable. The well was completed across November and December 2008 with no incident and lost time and the completion solution adopted proved not only to solve all the initial reservoir challenges but also to reduce the number of well interventions, workover costs and risk. The well was successfully started up in February 2009 with a NPV increment of 15% and a reservoir recovery factor increase of 6%.