Integration of structural and horizon mapping of 3D seismic volume, petrophysical studies of over sixty (60) wireline logs, stratigraphic analyses, reservoir property modeling and production information have been adopted to study Eni field that has been experiencing production decline with increase in water output. Generated reservoir structural framework and spatial reservoir property distribution have proved useful to guide the optimal placement of proposed wells and also provide information needful for the development of best production plan that would guarantee effective oil drainage from the delineated reservoir compartments.

The XK field is a mature offshore asset with post peak production characterized by rapid oil decline rate and steep water cut. Many wells have ceased flow prematurely over time and non-rig interventions to reactivate and restore the wells to production had typically been ineffective owing to consistent low tubing head pressures and well construction/completions. Furthermore, the plan to initiate gaslift operations in the field was challenged by the lack of gaslift separator, compressor unit and gas line coupled with the fact that many of the wells were completed without gaslift mandrels. The deployment of innovative inter well gaslift, utilizing Gas Liquid Cylindrical Cyclone (GLCC) separator saved the situation and enabled achievement of the gaslift objective. The result was the successful restoration of three (3) long shut-in wells and associated increased oil production in the field. This paper discusses the opportunities and challenges from inter well gaslift initiation and operations in XK field and the enormous potential as a low cost and efficient system for rejuvenating Brown Fields.

Monitoring fluid movement in a heterogeneous water-flooded reservoir is key to optimizing water injection, detecting early water breakthrough, and locating bypassed oil. While well- and production-based reservoir monitoring techniques are commonly applied, they lack the inter-well spatial resolution required for an accurate assessment of the current water movement. As a key tool in spatial reservoir surveillance, 4D seismic surveys were acquired over a water-flooded field located offshore of the Niger Delta. The aim was to map fluid-flow paths and barriers, manage injection for breakthrough optimization, and optimize well placement. The application of 4D seismic techniques has tremendous potential to provide inter-well information on fluid dynamism over time, provided there is a clear link between the seismic observables and reservoir variables such as fluid, pressure, or temperature. Using physical properties of the rocks and fluids from input wells, a 2D seismic model was used to predict the amplitude response to changes in saturation. This involves estimation of the amplitude difference expected from incremental water saturation between pre-1987 and post-1996 wells. The study establishes a correlation between saturation and the two previously-acquired seismic (baseline and monitor) surveys, which were acquired over a nine-year interval. We interpreted the injected water flow path, the potential locations of bypassed oil, and compartmentalization. This was achieved by integrating the well production information, predicted seismic amplitudes at the wells, and the seismic attribute maps. The resulting analysis provided new insights into unexpected production behavior, such as the premature watering-out of updip wells relative to offset wells, and the anomalous pressure support across fault compartments. In accordance with the well performance, it was observed that the injected water follows preferential and heterogeneous flow directions, indicating a strong stratigraphic fluid-flow overprint on the reservoir not previously discernible from well data alone. Subsequently, early results from infill drilling and injection management show better well performance leading to improved oil recovery.

Asset development teams have the responsibility of identifying, evaluating and executing infill well opportunities. In maturing these projects, realistic forecasts are needed. An intrinsic part of these forecasts is the initial rate of production, which influences the economic viability of the opportunity and the producing life of subsequent facilities. It is every team's desire to come up with a range of producible rates given reservoir, wellbore and surface constraints. This would serve as the basis for the decisions regarding rates of production. Inflow-outflow modelling (nodal analysis) is generally the accepted method for rate prediction. However, data and time constraints such as unreliable well tests, BHP surveys and questionable PVT data can make rate determination very challenging. This paper details a methodology to overcome these obstacles through the application of a two-dimensional approach to deriving a range of production rates using both integrated modelling and analog comparisons. The 2-step approach involves building an integrated production model that includes wellbore models connected to a surface production network (could be built to varying levels of complexity). The results from the network model are tuned using an acceptable set of well test data from analog reservoirs. The end result is a more realistic range of IP rates that are representative of the opportunity under evaluation. The workflows detailed in this paper were used to derive forecasts for infill oil wells in the offshore Niger Delta. A few of these have been drilled and many are currently being evaluated, some of the challenges, lessons learned and results are also shared in this paper. Introduction Within every asset team lies the desire to derive the maximum possible production from infill oil wells in order to achieve superior returns on the capital utilized to drill them. The rising costs of drilling and maintaining wells in the Niger Delta has made this desire even greater. Good reservoir management dictates that rates of production should not compromise either the reservoir potential or the facilities being used to handle the production. Before a new well is put on stream, certain estimates can be made as to what the deliverability of the well could be given the constraints it may be facing and these estimates are vital before forecasts and economic results can be obtained. These forecasts and results drive the viability of the infill well on its own or when ranked side by side with other infill opportunities.

The design of a gravity dump flood well for a depleted QG reservoir located offshore in M Field was significantly enhanced by the inclusion of an Electric Submersible Pump (ESP). This resulted in 1,500 barrels of oil per day production gain from producer wells in Area 2 of the reservoir that had become inactive due to low tubing head pressures with reservoir pressure depletion. The identification of an optimal water injector location to improve the low reservoir energy and sweep oil towards the existing producers was grossly challenged due to remote nature of existing wells from water injection facility. Significant cost implications exist for the construction of new pipelines to the Water Injection facility. In addition, the existing infrastructure is aged and degraded, creating a need for a cost-saving solution. The challenges were tackled by implementing a pilot ESP powered dumpflood in an ideally situated injector "Xi". With this technique, a single well acts as both the producer and injector, utilizing an ESP generated pressure differential to pump water from a deep aquifer to a shallow reservoir or boost natural gravity forces to reverse pump water from a shallow aquifer to a deeper reservoir (R. Quttainah 2001). The latter option proved ideal for this application given the shallower location of the water source relative to the target oil zone. By innovatively using Y-tool technology, the ESP reverse pumped 7,000 BWIPD at a discharge pressure of 772 psig from the upper "A" aquifer zone into the target oil QG reservoir within the same well at startup. The ESP motor was powered by a 4km electrical subsea cable to draw power from the field's Quarter Production Platform. Significant cost savings were achieved by eliminating the need for pipeline construction since water source and injection were combined in one well. Within 3-months of ESP startup, the target reservoir pressure boost resulted in the restoration of inactive wells and 1,500 BOPD incremental production gain from producers in Area 2 of the reservoir. Following the success of the ESP powered dumpflood pilot project with initial oil production gain of 1,500 bopd and significant cost savings, a study is ongoing for a field-wide deployment of the technique in field M and 2 neighbouring fields.