Enhanced oil recovery has been gaining relevance over the years following success stories from already executed projects from various parts of the globe. The recoveries from such successful projects have tremendously increased the terminal life cycle recoveries from the subject reservoirs and subsequently the project Net Present Value and Value to Investment Ratio. More than 90% of Field Development Plans in the Niger Delta have not considered Enhanced Recovery Mechanism as part of the field development options and as such Top Quartile Recovery Factors are never achieved. In this study, the effectiveness of Enhanced Oil Recovery within the Niger-Delta reservoir sands via 3-Dimentional Dynamic Simulation, Economic models and Experimental investigations (temperature and pressure effects on polymer effectiveness) was done. The GN7000 reservoir was used as a case study for this work. This reservoir is the largest gas cap reservoir in the N-Onshore field within the Niger Delta area and it is at the mid-life stage. This study tested the effectiveness of three Recovery mechanisms (Water Flood, Polymer Flood and Polymer Alternating Gas). Simulated and Experimental result suggests that Polymer flooding and Polymer Alternating Gas (PAG) yields greater Technical Ultimate Recovery, better economic indices but greater complexity in polymer selection due to inherent high reservoir temperature and low salinity that make the use of synthetic polymers inadequate. Experimental investigation showed that biopolymers are most suitable for this sand. The suitability of some biopolymers (Xanthan and copolymers containing high level of 2-acrylamido2-methyl propane sulfonate (AMPS) showed good results. Study results shows that with the deployment of biopolymers with high viscosifying power and high resistance to thermal degradation an incremental recovery of 8% from the natural flow could be achieved. Research findings indicate that biopolymers could yield good results for Niger Delta sands within the pressure and temperature ranges of 93°C and 290 Bar.

Faults are subsurface entities in clastic fields that can influence the economic viability of a field at various stages. In Exploration, fault-seal behavior impacts prospect analyses, whilst in the Development stage, compartmentalization and fault transmissibility analyses impact Well placement, recovery and reserves estimation (Brem Et al; 2019). Accurate representation of structures -major and Intra-reservoir faults is a key requirement in any fault analysis and resulting impact. Hence, fault modeling-a key part of the structural modeling workflow in field development work cannot be over emphasized. The Eureka field is a high-pressure gas discovery asset in Shell 's operated acreage in onshore Niger delta. The field, which is currently in the mid development stage, comprises of stacked reservoirs with series of anticlinal dip assisted/fault bounded structure with minor faults. The potential compartmentalization of target reservoirs for development by intra-reservoir faults is the major uncertainty in the development of the Eureka field. This work aims to define the fault sealing properties of the intra reservoir faults and their impact on Eureka green field gas development. The current development plan requires two or more Wells to be drilled to optimally develop the resource volumes in one reservoir (X2000) in the field. Mapping of each of the intra-reservoir faults from seismic and available log data were used to determine how well connected the segments separated by the faults are. Fault zone properties studied include fault throw/thickness, shale gauge ratio (SGR), fault zone permeability and transmissibility multiplier. The intra reservoir fault uncertainties were mitigated by building different realisations during the modeling process. The intra-reservoir faults which are normal faults on the crest of the anticline in the study area have low SGRs and high permeabilities which indicates partial sealing capabilities. Also, the majority of the intra-reservoir faults have transmissibilities <1 which indicates partial fluid flow to partial seal. Partially sealed faults give rise to hydrocarbon movement through and along fault planes (Fagelnour Et al; 2018). Results of the fault zone properties were incorporated with fault transmissibility multiplier in a dynamic simulator and showed that one development Well can drain the gas bearing reservoir.

Well integrity is a key focus area in any oil and gas development. There have been several cases of well integrity issues which have resulted in scenarios of blowout, loss of lives, assets, and reputation, including costs spent for clean-up and environmental remediation, amongst others. These and more have made the energy industry put a keen focus to making sure all hydrocarbon production and processing facilities are integral, with newer technologies still being developed to aid the diagnosis of well integrity problems. Well integrity considerations cut across the entire life cycle of the well, from well conceptualization/planning through to drilling, completion, production and abandonment. This case study presents a high-pressure, high temperature gas well with sustained annulus pressure in the early production phase of the well. Well X is a gas well completed in an elevated pressure and temperature reservoir on a land terrain. The reservoir is about 13000ftss deep, with a temperature of 219°F and a reservoir pressure of 9300psi. The well was completed, cleaned up and brought to production about a year ago and annular pressures were observed. This paper details the different approaches used in diagnosing the sustained annular pressures – separating thermal effect from sustained pressure due to leak. It shows the different scenarios of leak paths identified and how these were streamlined. The paper also highlights the integration of data acquired during the investigation. Some of the data acquired include well annuli pressures, high precision temperature logs, spectral noise logs and electromagnetic corrosion logs.

Reservoir models are calibrated with production and pressure data to provide some confidence in the prediction of future reservoir production using the models. The last two decades have witnessed the proposal of numerous computer-assisted history matching techniques to ease the laborious task of reservoir model history matching and the related task of uncertainty analysis. Although many of these proposals have proved not to be viable when tried on real (i.e field) cases, some, such as experimental design, are now routinely used in the petroleum industry for history matching and uncertainty analysis. One notable, but largely under-utilised, technique that has generated a lot of interest for application to history matching is adjoint-based optimization. This paper discusses a field example of the application of the adjoint technique with experimental design to match the historical production and pressure data of a Niger Delta oil rim reservoir with a huge gas cap – the "SWX" reservoir in the "Beska" Field. The "SWX" reservoir, which is one of the few oil reservoirs in the gas-dominated "Beska" field, has been on production since 1992. A decision was to be made on the best time to commence gas cap blow down without jeopardising the life cycle hydrocarbon recovery from the reservoir. A properly history matched model of the reservoir was required for this decision. Adjoint technique was deployed to assist with the history matching of the "SWX" reservoir which had previously proved difficult to history match. The technique was applied both in the model-maturation stage for improved understanding of the reservoir and the final stages of the history matching exercise to fine tune the history matches of some difficult-to-match wells. The exercise provided an opportunity to test the merits and limitations of the adjoint technique. The result of these tests will be discussed in this paper.

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.