Exceeding the estimated technical UR of mature fields is a valid positive risk to be considered in field development. Extending the field life of prolific fields in the Niger Delta using integrated subsurface analysis of available data is an imperative in the current "lower price for longer" oil economy. For matured reservoirs producing beyond their estimated ultimate recovery, it is necessary to demonstrate the basis on which a revision of recovery factors can be made (SPE et al., 2007). This paper examines how the seismic, geological, production data and pressure data were integrated to arrive at the most plausible reservoir understanding for the re-allocation of In-place volumes for the Tanure field in the Western Niger Delta. An integrated review of the field history was done on a well- by- well basis, taking into account the cross -sections and relative positions of both flowing and closed -in wells. The CO log data analysis showed the relative movement of the water influx in the field, helping to identify wells that had been shielded by sealing faults, explaining observed production performance. The pressure equivalence of the hitherto separate sub-blocks in the field proved that 75 of the sub-blocks on the various reservoir sand levels could be technically merged into 24 larger blocks. The average contacts for the new sub-blocks were estimated by petrophysical analysis of original contacts observed from open hole log data. The re-interpretation of 3D seismic and the fault model of the geological structure, led to the revision of Stock Tank Oil Initially In Place (STOIIP) estimates to support the production figures from the maturing field (SPE/WPC, 2001). Fluid contact analysis estimated OWCs for the resulting new blocks, confirmed by pressure data history from the field. The technical recovery limits for the affected blocks were revised based on the calculated STOIIP volumes of the new blocks.

The impact of intra-reservoir faults on fluid connectivity and recoverable volumes in any reservoir depends principally on structural uncertainties (fault extent, fault throws, fault zone, fault heave, fault sealing capacities etc.) associated with the reservoir. This paper focuses on the integrated approaches used to determine block by block fluid connectivity, re-assignment of estimated hydrocarbon initially in-place volume and its associated recoverable volumes in different reservoir blocks in view of production performance and complex fault architecture in the field. In this study, we have explored the feasibility of determining fluid connectivity across reservoir blocks and their associated recoverable volumes by integrating reservoir performance (post-production data) with the reservoir structural uncertainties. Over 50 wells have been drilled in the field and their penetrations spread across the reservoirs. Pressure data were acquired across most of the blocks in the reservoir. The reservoir is sub-divided into separate blocks and it has over 25 years of production with evidence of over-production (Np > Ultimate Recoveries) experienced in some of these blocks. This over-production triggered the need to integrate available data (Performance, Pressure data, Fluid Contacts, structural morphology etc.) to re-evaluate the impact of the intra reservoir faults on the estimation of the hydrocarbon in-place volume and recovery in the field. The integrated approach has aided the re-estimation and re-assignment of the associated volumes on a block by block basis thereby promoting the opportunity for a robust infill well planning and further development of the field.

The productivity of oil wells depends on a lot factors such as and not limited to environment of deposition, reservoir thickness, permeability, reservoir drive mechanism, drain hole length and formation damage at the near well bore region. The productivity of oil wells can also be linked to the effectiveness of the sand control method deployed in the well. Sand control methods play very important roles in safeguarding our assets, maximizing production from assets and reducing life-cycle OPEX for the well. This paper presents a comparative approach towards understanding the effect of different sand control methods on productivity of wells completed in a mature reservoir in the Niger Delta. The methodology involves the use of statistical comparison of the production performance of 4 sand control methods installed in the XYZ reservoir in the YED field. The approach considers the productivity performance, the average sand reliability index, and the intervention frequency ratio. The productivity performance of the completed conduits on XYZ reservoir shows that conduits completed with Slotted Liners showed impressive production performance as well as low sand production, while the wells completed with IGP had better production performance when compared to other sand exclusion methods. The drainage points completed with SCON showed average production performance, with high sand production averaging around 25-30 pptb for the completed conduits. The conduits that were completed with MCUGP showed below average production performance as well as high sand production. The results in this work will help provide an easy guide to sand control selection as it concerns productivity in the Niger-Delta region. It will also deepen the understanding of the performance of different sand control methods in the Niger-Delta Region.

The importance of Wells, Reservoir, and Facility Management in the life of producing Oil and Gas assets cannot be overemphasized. Several authors in the past have highlighted the significant contributions WRFM practice and process have to the ultimate recovery of matured assets. WRFM serves as a stop-gap to redevelopment in areas of cash crunch, whereby active WRFM practice arrests severe natural decline in production. Onshore assets comprising of fields Alpha and Beta are operated by Shell Petroleum Development Company (SPDC). These assets have been operated for over 30 years, rising water cut & high gas-oil ratio production and facility downtime risks have impacted oil recovery. This work showcases the application of WRFM at the re-startup of production in these fields post shut-in for almost 5 years. Effective and deliberate application WRFM processes and practices woven together in the WRFM Plan not only ensure an efficient restart of the facility but the ability to ramp production while maintaining the intricate balance of good reservoir management. The paper will highlight the best WRFM practices which enabled the resumption of production at a lower water rate compared to when the field was shut and maintain this higher net oil for a prolonged time. Also highlighted are opportunity identification and implementation in-closed wells and effective collaboration across disciplines to ensure a safe and efficient restart of production facilities.

MERO-006T is an oil development well that was drilled and completed in the Q2100X reservoir. The well came into production in March 1988 and has been plagued with incessant wax build up leading to loss of oil production several times over a period of 17years. Several wax cutting activities have been carried out to restore production in the well, however due to the frequency of wax build up leading to loss of revenue and the difficulty of the swamp terrain where the well is located, it became pertinent to adopt a more optimal, cost effective and long-term approach to address the frequent deferment caused by wax build up. Research indicates that a wax inhibition tool (Silver HAWG) can be deployed in the well to address wax build up issue though historical deployment in some wells have not been very effective due to suboptimal installation depths in these wells. Hence, it became pertinent to determine the optimal depth for installation of the wax inhibition tool in MERO-006T. This paper highlights the thermodynamic modelling approach adopted to determine the Wax Appearance Temperature in MERO-006T, the well modelling approach to estimate the depth which wax formation would occur and the optimal depth to place the wax inhibition tool based on lifecycle production expectations from the well. Installation of the Silver HAWG is expected to restore ca. 500 bopd, improve well availability by 30% and avoid biannual costs of ca. $2mln associated with repeated wax treatment in the well.