Horizontal wells increase the reservoir-wellbore contact area, allowing the wells to produce at higher flow rates with smaller drawdowns which is especially important in oil reservoirs with a large gas cap or aquifer. Long wellbore lengths can lead to production challenges such as water or gas coning and cusping, an unwanted fluid breakthrough from high-permeability zones, and uneven inflow along the wellbore and nonuniform reservoir sweep. Inflow control devices (ICDs), based on well-established technology, have been used in hundreds of wells worldwide. Different ICD types and design methods are available and can be applied to mitigate some of the production challenges. The ICDs are installed as an integral part of the sand screens in the well completion hardware. They can be passive, where the ICD size and configuration does not change after it is run in the hole, or autonomous, where the ICD adapts to changes in downhole fluid-flow properties. However, the decision regarding the use of ICDs as well as the design criteria and selection has to be made prior to the well completion operation. This paper presents a feasibility study on an ICD application in an offshore Nigeria delta oil field with multiple hydrocarbon-bearing reservoirs. Most of the development wells in the field have horizontal openhole 1,000 to 3,000 ft drain sections completed with standalone screens. Strong aquifer and reservoir heterogeneity create production challenges associated with early water breakthrough and suboptimal reservoir sweep. This paper presents a detailed approach to ICD design, sensitivity analysis, and completion optimization, which is based on the coupling of a 3D reservoir model, segmented wellbore model, and ICD models. The proposed ICD completion design is evaluated and sensitized to subsurface reservoir uncertainties using volumetrics. The final decision process is presented to guide the selection and feasibility of an ICD application for two reservoirs.

Interference testing is a common tool for addressing reservoir connectivity and compartmentalization risks. Due to the high costs of deep-water and ultra-deep-water extended well testing, this type of test is rarely performed during the appraisal phase and is usually postponed until the start of the field development. With the infrastructure in place, testing can be carried out with minimum planning and at a minimum cost. This is generally acceptable for fields with a lower subsurface complexity. However, for complex turbidite fields, this information becomes critical at the appraisal and early development planning stages to reduce the risks in depletion optimization and production infrastructure planning. To make testing practical, it has to be performed in a way that minimizes rig time and de-risks collection of required data. To optimize the interference test design for the West Africa deep-water field appraisal phase, a simulation study was carried out to assess the impact of major uncertainties. A fine-scale 3D simulation model was used due to high heterogeneity and complex connectivity between individual channels and channel complexes. Impact of the drawdown rate, flow duration, tidal effect amplitude, OWC, faults transmissibility, absolute permeability, reservoir pore volume, and zones connectivity on interference time for different selections of test and observation wells were assessed through the sensitivity runs. Results were analyzed to get a better understanding of reservoir dynamic response such as pressure travel time and potential interference between zones. Based on this study a flexible interference test plan was defined that ensures optimal rig use and minimal risk of sub-optimal dataset collection. This plan embeds both pre-test decisions and real-time decisions that depend on early time observations. An optimal test and observation wells setup that provides a balance between the rig time and value of information will depend on the planned appraisal well results and is one of the decisions to be finalized before the test. However, decisions on flow duration adjustment and consequent data monitoring in the observation wells will be made based on a set of early time events identified from the sensitivity of pressure interference response between different zones and wells. The proposed uncertainty driven approach provides an obvious advantage over the common test design based on the "best technical estimate" model. It also provides a better basis for test feasibility decision and cost-effective implementation.

Historically the pioneers in Permanent Downhole Gauge (PDG) deployment were large operators targeting real time reservoir surveillance on a few high profile wells or field development projects. With time, utilization of PDG became an industry standard, unit prices went down and reliability has significantly increased, making application of PDGs a wide spread phenomenon. The interest in PDG data goes beyond simply recording pressure and temperature at any given time for reservoir surveillance and monitoring. The combination of the well production and PDG acquired pressure data proves to be an ideal dataset for reservoir characterization and improved production optimization. This paper presents a dynamic real-time well testing workflow used in analyzing PDG data for Pressure Transient Analysis on a complex reservoir geometry offshore Nigeria. It discusses the extent and applicability of Pressure Transient Analysis (PTA) using Permanent Downhole Gauge data for complex reservoir and well performance characterization. In analyzing such PDG data, it was important to correctly identify anomalies which could hamper the interpretation of the complex dataset, such as tidal effects. The presence of these anomalies can significantly impact data analysis, resulting in wrong flow regimes identification and erroneous well and reservoir parameters estimation. Therefore, tidal signal and other noises had to be identified and removed from the pressure data before the interpretation. Commercially available software was used for de-noising and managing the real-time measurements, as well as modeling and analysis of the test data. Actual real-time pressure from PDG and production data from surface well test measurements were used in the analysis to determine reservoir parameters and evaluate well performance. This paper elaborates on the proper techniques for data handling of offshore acquired PDG measurements for Pressure Transient Analysis. The workflow resulted in significant cost savings due to a reduction in the number of shut-ins planned consequently.

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