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.