This paper presents the Mede & Mafe field Integrated Production System Modeling (IPSM) strategy, synopsis of work done and benefits derived from the model. The IPSM provided a simple fit-for-purpose tool for understanding, diagnosing and tracking the fields’ performance as well as optimizing well production and facility throughput. The main areas which the IPSM was used are: Opportunity identification and validation Optimization and Prediction of field performance. The IPSM enabled the integration of flow assurance with subsurface deliverability using well and reservoir operating conditions as boundary conditions & separators static pressures as topside constraints. The IPSM modeling strategy was aligned to meet the requirements of Well and Reservoir Management (WRM) minimum standard. Opportunity realization and optimization from the existing wells were achieved after calibrating the model to match actual field performance within ±5% error margin. Additionally, the opportunities generated from the Integrated Drainage Point Reviews (IDPR) were ranked and validated with the IPSM model to quantify Short Term Oil Gains (STOG) within calculated well and reservoir operating envelopes. The model is also used as a standard tool for quarterly Production System Optimization meeting with continual update made to enhance well and reservoir management of these fields. The IPSM has been used in four PSO reviews with seven (7) bean-up opportunities identified/validated delivering oil gain of 1500bopd. An opportunity to improve flow assurance and de-bottleneck the Mafe bulklines with a potential to deliver 1700bopd was also identified.

Accurate reservoir performance prediction m a structurally complex brown field is very important for generation of reliable production forecasts, location of possible by-passed oil estimation of reserves and optimal well/ reservoir management. Reserves estimation is one of tire key functions of Petroleum Engineers and it requires an integrated approach for tellable estimates to be made. The traditional techniques include Decline curve analysis, Material balance. Volumetric. Analogues and Numerical Reservoir simulation. Reservoir X is a structurally complex reservoir nr Field Y in the Niger Delta Basin. It came on stream in 1970 with 3 wells. Eight additional wells started production between 1972 and 1990. Five infill wells were drilled and completed between the years 2000-2005. However, due to operational and technical reasons (which are beyond the scope of this paper), 2 of these wells are yet to be put on production Over the years the reserves associated with these 2 wells have been estimated by analytical means (Volumetric and Material balance methods). However, there was the challenge of investigating the impact of fluid saturation changes around these wells, occasioned by the production fiom offset wells, on the reserves estimate obtained fiom material balance techniques These challenges necessitated the full field 3D integrated reservoir modeling The reservoir contains 9 blocks in which 8 are densely faulted. The material balance analysis, being, at most, a onedimensional model, was deficient in robustly assessing the subsurface uncertainties which includes fault sealing potential and fluid contacts movement. This paper discusses the techniques employed in building die static and dynamic models and shows a comparison of the reserves estimate results fiom analytical techniques versus 3D dynamic estimates.

The field presented in this paper is a structurally complex onshore oil field in the Niger Delta, with a densely faulted succession of stacked reservoirs. From previous field studies, three of the reservoir units have been interpreted as a single stacked reservoir complex beneath a top seal, and the vertical and lateral communication between these units is largely controlled by the inter-reservoir shales and intense fault configuration.Integrated 3D reservoir modeling has been used to investigate the production performance from this stacked reservoir complex, with a view to identifying the features that contribute to the observed communication across the reservoirs, quantifying the contribution of each reservoir unit to each well's production, estimating the ultimate recovery for the complex and evaluating the current redevelopment plan for the reservoir complex to identify opportunities for further oil development.The results from the study indicate that oil recovery is majorly influenced by communication across faults. A tracer model was used to demonstrate that some wells produce from adjacent blocks on the same reservoir unit as well as the other reservoir units across the fault, giving an indication of the presence of non-sealing faults across juxtaposed oil-bearing sands. Also the application of the 3D model in evaluating the current redevelopment plan for the reservoir complex resulted in the identification of 5 new opportunities in existing wells, to increase the ultimate recovery of the reservoir complex by 7.8MMstb. More so, there exists an opportunity to recover 7.5MMstb from a by-passed section of the complex with a new vertical well.

This paper presents the results of a 3D model constructed for a giant, densely faulted reservoir in one of the biggest fields in the Niger Delta. The study also showcases how simple analytical techniques applied in a technically thorough manner can achieve close or similar results to those from a calibrated 3D simulation model. In carrying out this work, a detailed 3D model was built and calibrated for a very mature reservoir; incorporating results of the recently drilled wells in the field, revalidated integrated data and latest historical performance data. The reservoir, which is densely faulted by a conjugate system of synthetic and antithetic faults, is the largest in the field accounting for almost half of the field's resource volumes. The large number of NW-SE faults, coupled with the relatively high offtake rates from the reservoir, have throttled the activity of the otherwise infinite aquifer and led to severe pressure depletion in the reservoir. Consequently, a lot of the producers quit at relatively low water cuts (~40 − 50%). One of the objectives of the detailed modelling study was to investigate the benefits and gains of gaslifting existing and future new wells. Prior to this study, simple decline curve analysis (DCA) had been carried out independently on a well-by-well basis using estimated abandonment conditions under gasliftassisted flow to predict the recoveries and gains from gaslifting. The prediction results from the full-field calibrated model compare very closely with the estimates from the individual wells DCA's and suggest that the DCA results can be used as 50/50 estimates for other reservoirs in the field where there are no full 3D models. This work therefore supports the fact that simple analytical methods, which are applied in a technically thorough manner, can still be used in the absence of full 3D models.

Well performance evaluation and prediction via decline curve analysis (DCA) requires defined abandonment conditions (Abandonment BSW and oil rate) to estimate the developed ultimate recovery (DUR) of a drainage point. Abandonment BSW and oil rate are derived from well models which require abandonment reservoir pressure and Gas-oil-ratio (GOR) among others as inputs. Good understanding of the performance of a reservoir is necessary for the prediction of abandonment GOR, and this prediction requires a systematic approach. The assumed value of producing GOR has a direct impact on the magnitude of the hydrostatic and dynamic pressure loss in a production tubular and hence it is a very important parameter in the vertical lift performance of a well. Similarly, the the reservoir pressure at abandonment is an indication of the energy available from the reservoir for lift hydrocarbon fluid s from the bottom of the producing wells. This paper illustrates the methodology employed for the estimation of abandonment reservoir pressure, GOR and BSW in support of well performance evaluation and reservoir management. Case studies for saturated and undersaturated reservoirs with weak-to moderate aquifers are considered.