Millions of dollars are spent across the oil and gas industry on data gathering activities with a view to reducing subsurface uncertainties towards optimizing reservoir development and management. However, suboptimal attention is often paid to assessing the value of the information (VoI) during data acquisition requirement planning and before requesting for such information. The capital intensiveness of the industry and emerging low oil price regime has necessitated scrutiny on every dollar spent on data gathering in the current business terrain. The application of the VoI concept in the oil & gas industry provides a predictive, analytic and quantitative framework for decisions and justifications for data gathering activities including but not limited to log data acquisition; downhole fluid sampling; subsurface diagnostic tests; core data acquisition; appraisal drilling and seismic acquisitions. Value of Information in simple terms is described as the amount a decision maker should be willing to pay for a piece of information. It is evaluated as the difference between the future value of a project given the availability of particular information versus its value without it. This paper demonstrates the methodology and application of VoI analysis to support a key decision on whether or not to drill an appraisal leg of a well to test for fluid contact and possible presence of an oil rim in a reservoir prior to initial gas development. The major uncertainty in this study is the evaluation of the hydrocarbon extent in a gas reservoir with a gas-down-to (GDT). To evaluate the options, a VoI analysis was carried out by integrating results of different data sources; well log data; formation pressures; seismic data and analogue information. Integration of the different data was used to arrive at different subsurface realizations which fed into 3D static and dynamic simulation models. The modeling result for the different scenarios was used as input for economics in the VoI analysis. Using the multiscenario analysis, the range of oil rim thickness proved to be non-commercial and the VoI analysis showed that drilling an appraisal will result in a negative value of appraisal giving the estimated VoI and cost of drilling an appraisal well. The analysis has led to significant cost saving of about $8million which is the appraisal cost of an earlier planned appraisal/development well. The analysis also helped to challenge the pre-existing appraisal paradigm and provided a robust basis for a commercial decision without compromising on regulator standards and industry best practices.

Nearby field production effects in field development is a key consideration in well design for safe well delivery and HSE considerations. Formation Pore Pressure Prediction (PPP) aims to identify and manage formation pressures with associated subsurface uncertainties/risks, and serves as input into well design and delivery. Reservoir injectivity, depletion from hydraulic communication with other reservoirs, and fault seal reactivation, amongst others are some of the common processes that could alter the in-situ pore pressures of virgin reservoirs. Thus planning a well where these subsurface uncertainties and more exist, would pose the challenge of quantifying the uncertainties and incorporating them into the well's PPP/design to allow for safe well operations, protecting lives, properties, and the environment.This was the case of a development oil well (Oganza-015), planned to be drilled into the virgin and appraised block-B of the Oganza Field in the Niger Delta. Regional (map and correlation) and Production data from the field suggest that some of the reservoirs are in hydraulic communication with two producing nearby fields (Okpokiri and Ekunam) via a common aquifer, and as such would have seen some level of depletion due to production from these nearby fields. Other identified subsurface uncertainties in this block include, the reservoir structural tops and bases, fluid contacts (original vs. present), fluid type and density/gradient, connectivity between blocks (by aquifer or hydrocarbon zones), fault extension and transmissibility, strength of aquifer/gas cap, etc. Related risks with drilling through these depleted reservoirs include; mud losses that could lead to a well control situation, differential sticking and loss of drill string with BHA, casing burst, and other reservoir management issues.An integrated approach via quantitative seismic interpretation, appraisal, development, and production data analyses in PPP for the planned Oganza-015 well was adopted to manage the aforementioned uncertainties and associated risks. This incorporated all available seismic (seismic velocity), geological (maps and sand correlation), petrophysical (porosity sensing well logs, fluid type and gradients), reservoir engineering (RFT, PVT), drilling (mud weights, drillability exponent), and production (BHP) data.This work further demonstrated that the Oganza field is hydrostatic in-situ with average pressure gradient of 0.433psi/ft, and that slight depletion (ca. 0.425psi/ft.) at some deeper reservoir levels has occurred. These and other subsurface uncertainties were taken into consideration in the PPP that has been put forward for a safe well design and delivery.In this paper, a PPP workflow for design and safe delivery of development wells targeting and/or traversing virgin reservoirs under depletion using seismic velocity and appraisal well data is presented.