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Water Dumpflood for reservoir pressure support is a non-conventional but simpler and cheaper alternative to Surface Water Injection. With dumpflood technology, a single well serves as the water producer and injector hence; the complexities of water treatment on surface can be avoided. A pilot Water Dumpflood scheme was executed 1997 in the Egbema West field and post performance analyses showed it has been successful in maintaining good pressure support since its inception 12 years ago. Opportunity exists to increase oil recovery significantly from this same reservoir by drilling additional water dumpflood wells for increased oil withdrawal given corresponding pressure support. With this, oil wells that were shut in many years ago, to minimise further pressure depletion, can be brought back to production and maintained with good well and reservoir management. There also exists an opportunity to supply the associated gas from these wells to a nearby power plant currently undergoing construction with a capacity to utilize as much as 100 MMscf per day. This paper explores the benefits of increased water dumpflooding in the depleted reservoir and describes the selection of number and position of dumpflood wells for optimal recovery using dynamic modelling. It also reviews the historical performance of the pilot scheme and applies learning to improve the well completion design, injection rates and effective sand control for the additional wells. The application of Smart Technology for improved well and reservoir management have also been explored. Water dumpflood can be very effective with good selection of well position, number, source aquifer, and target reservoir, completion design and sand control mechanism. Increasing the scope in this reservoir will not only increase oil recovery but also support energy demand through gas supply to the power plant.

Understanding the dynamics of a reservoir based on performance and acquired data is key to optimal field development. This is the case for a matured gas reservoir with more than 2Tscf of gas in-place in the Niger Delta. Based on initial data acquisition during the field development planning, the reservoir was interpreted to be compartmentalized by series of intra-reservoir shales. After four years production, acquired performance data analysis suggests increased communication between reservoir units and lower range of in-place volumes. This is believed to be driven by high mobility of gas and presence of intra reservoir faults that breached the intra-reservoir shales. This updated understanding forms the basis of the re-evaluation of the reservoir. The depth uncertainty used to generate the low and high case top reservoir structure was revised from 60ft to 33ft (based on residual analysis). The dynamic model was re-calibrated with the updated static model using the Experimental Design (ED) workflow. Performance data from the producing wells were used to calibrate the simulation model to ensure consistent ultimate recoveries estimation. The estimated developed ultimate recovery from the reservoir simulation is comparable with the results from a P/Z analysis and material balance model. The novelty of this approach is the ability to manage subsurface uncertainty through effective use of well and reservoir data to improve reservoir understanding. Overall, the subsurface uncertainty management strategy ensured collaboration within the sub-surface team, effective use of the installed permanent downhole gauges, and integration of surface and sub-surface data in the update of the simulation model.

Acquisition of bottom hole pressure is a statutory requirement in Nigeria. In addition, pressure data provide a better understanding of reservoir responses to production for effective wells, reservoirs and facilities management. The data is used to calibrate dynamic and well models in order to improve the quality and reliability of predictions that feed into Annual Review of Petroleum Resources (ARPR) cycle. Despite its importance in the oil and gas industry, there are often delays in mobilizing for Bottom Hole Pressure Data acquisition due to deferment concerns, budget constraints and security challenges. This was the case with some gas wells in Aowa field in the Niger Delta region of Nigeria where the bottom hole data could not be acquired on scheduled to support the technical evaluation of resources within the given timeframe of the annual volumes reporting cycle. This paper is a case study on the determination of closed in bottom hole pressure (CIBHP) from Closed in Tubing Head pressure (CITHP) during well shut in periods using the Cullender & Smith methodology. The proposed approach involves derivation of bottom hole pressure data from measured closed in tubing head pressure and known gas gradient. The scope of implementation covered three gas wells in the Aowa field (AOWA 3, 4 & 5) that supply gas to NLNG and processed through a Central Processing Facility (CPF). The three gas wells are produced from three different reservoirs in the field with total expected gas rate of about 350 MMscf/d. These wells are significant to achieving the export nomination expected from the CPF. These wells came onstream in July 2013 and have produced as expected. The novelty of this approach is the elimination of HSSE risks associated with undue staff exposure in the field, obtaining fit for purpose quality data without production deferment and costing down OPEX as ca. US$22,500 per well can be saved due to non-contractor engagement. The work flow established by this method can be applied across other operating units for gas wells having similar operation challenges. The results obtained from this methodology compared favorably with actual measurement carried out later in the wells with the highest deviation of < 5%. The study revealed that the accuracy of the result using this approach is highly dependent on gas gradient.

Smart well technology allows production acceleration from multiple completions and value realization from otherwise marginal reservoirs. Critical to the success of a smart well completion targeting more than one reservoir is the proper design selection and reservoir isolation to prevent cross flow. This case study describes the selection of a suitable gas well design from different available options, the considerations made in the design selection which incorporated the different completion components, one of the components being the feed-through swell packers which is its first use in the company, to achieve reservoir isolation. The paper also describes the execution of the selected completion design in one of the cases, as well as the testing of the well to verify reservoir isolation, and confirm the effectiveness of the feed-through swell packer. The selected completion design was cost effective, reduced operational / deployment risks (compared to other isolation options) and had no adverse impact on well productivity of the wells. It also achieved the objective of accelerating the recovery of a combined volume of 221 Bscf of gas from marginal gas reservoirs in a field.