IOSR Journal of Applied Geology and Geophysics (IOSR-JAGG) e-ISSN: 2321–0990, p-ISSN: 2321–0982.Volume 5, Issue 2 Ver. II (Mar. - Apr. 2017), PP 62-70 www.iosrjournals.org DOI: 10.9790/0990-0502026270 www.iosrjournals.org 62 | Page Porosity-Permeability Regimes in Reservoirs for Hydrocarbon Prospectivity in Nembe Creek Field, Niger Delta G. I. Alaminiokuma and W. N. Ofuyah Department of Earth Sciences, Federal University of Petroleum Resources Effurun, P.M.B. 1221, Effurun, Warri, Nigeria Abstract: Porosity and permeability regimes in hydrocarbon-bearing reservoirs of Nembe Creek Field, Niger Delta were delineated by digitizing and correlating gamma ray, resistivity, and density logs from three wells: Nembe 01, Nembe 02 and Nembe 03 respectively. Results obtained from the analyses of these composite logs reveal eight potential hydrocarbon-bearing reservoirs. These reservoir sands were observed to have very good to excellent average porosities ranging from 29 to 45%. Permeability values were excellent within these reservoirs and range from 2200 to 5789mD. Hydrocarbon saturation was observed to be high in all the reservoir sands, ranging from 64 to 81% with corresponding water saturation from 36 to19%. The regimes observed indicate that porosity and permeability increase with depth. Cross-plots indicate increase in porosity and permeability with depth and a linear increase of permeability with porosity. Petrophysicists and reservoir analysts will find these results very beneficial for better understanding of the reservoir properties, fluid distribution and in quantifying the hydrocarbon prospectivity of this Field which is observed to be very high. Keywords: Porosity, Permeability, Hydrocarbon, Reservoirs, Nembe Creek, Niger Delta I. Introduction Multinational hydrocarbon exploration companies may experience poor reservoir performance within few years of production due to inadequate reservoir properties description. The success of any hydrocarbon exploration program depends on the building of a reliable reservoir model. The delineation of petrophysical properties of hydrocarbon-bearing reservoirs in the Niger Delta has been conducted by several researchers (Egbai and Aigbogun (2012); Tamunosiki et al, 2014; Ekine and Ibe, 2013; Adewoye et. al (2013); Adaeze et al., (2012); Abraham-Adejumo (2013)). Several parameters describing the characteristics of these reservoirs have been investigated. Among these, lithology, depositional environment, shale volume, porosity, permeability, Formation resistivity, water and hydrocarbon saturations received the most attention. The evaluation of reservoir rocks in terms of porosity, water saturation and permeability is useful in defining abnormally pressured zones, hydrocarbon reserves estimates, and reservoir bed thickness and in distinguishing between gas, oil and water bearing strata by observing their electrical resistivity and relative permeability values (Hilchie, 1990; Schlumberger, 1996; Uguru et al., 2002). However, porosity and permeability are the main petrophysical properties of reservoir rocks that have vital impact on the evaluation processes at all stages. This research is geared towards maximizing hydrocarbon recovery from reservoirs, ensuring consistent reservoir description by accurate prediction of porosity and permeability regimes which helps in optimal well placement. Location and Geology of the Study Area The Nembe Creek Field is located in the Coastal Swamp depobelt (Oil Mining License 29) of the Cenozoic Tertiary Niger Delta Basin (Figure 1). Sediment deposition in this area started in early Miocene times and the sedimentary package is comprised of the basal holomarine shales (Akata Formation), the coastal plain sand-shale alternations (Agbada Formation), and coastal plain sands (Benin Formation) being the youngest stratigraphic unit at the shallower part of the basin. This succession is linked to the palaeo Niger and Benue system (Allen, 1965). The Nembe Creek Field reservoir is in the middle Miocene deltaic sandstone-shale sequence. The structure is dissected by numerous growth faults steeping upwards. The shallow sandstone reservoirs are faulted such that spill points are generated at remarkable uniform depths resulting in similarity of fluid contact depth. A transgressive shale formation overlay the reservoir, which makes up the caprock (Nelson, 1980).