Surveillance mapping is a reservoir management process first developed by Shell and Exxon for the Brent field in the UK North Sea. It involves an integrated reservoir-wide management process with the objective of not only understanding subsurface dynamics during production but also delivering a future work programme that will maximize reservoir potential.1 Surveillance Mapping was recently deployed in candidate selection for Short Term Oil Generation and Work Over activities in the Zoom reservoir located in the Niger Delta area. The Zoom reservoir is an East West Trending anticlinal structure, predominantly shore face deposits with incised channels. The Zoom reservoir, which is a large structure, commenced production in August 1991 and 50MMstb of oil has been produced to date. Thirteen oil wells have produced from the Zoom reservoir. These wells were drilled in phases post updates of various development plans published in 2003 and 2010. Production performance across the reservoir started declining due to natural water encroachment, poor productivity issues, well and flow line sabotage etc. This triggered an aggressive strategy to identify suitable remedial action that would support the drive for resuscitating the wells in a cheap and safe manner. Five wells were identified as potential Short-Term Oil Generation candidates and have been executed successfully with good rewards. This paper will review the success story of candidate wells scoped from the surveillance map and its impact on the optimization of the reservoir potential.

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.