Sedimentology and depositional environment of E2000-Sand in the southern part of the Central Swamp depobelt have been studied using core and wireline log data. Nine wells were used for the study, one of which has some 200ft of core in the southern part of the field. Key wells were correlated based on normalized gamma-ray and other logs. Using two main panels, one along the depositional dip across syn-sedimentary intra-field faults and another along strike, lateral continuity, reservoir development, and shoreline proximity were evaluated. The cores were described to identify lithology, sedimentary structures, depositional processes, and genetic units. The results from the electro-facies analysis, wireline log correlation, core description, and core permeameter measurements were integrated to interpret depositional environments. The E2000-Sand normalized gamma-ray log profile showed three broad sections made up of (from bottom to top) a coarsening upward funnel-shaped basal section overlain by an overall cylindrical-shaped gamma-ray log signature capped by a short coarsening upward funnel-shaped interval. The overall gamma-ray log profile is consistent with a deltaic progradational setting typical of a shoreface sequence inundated by channel activities. Seven genetic units were identified in the cored interval comprising Marine Shale, Offshore Transition Heteroliths, Lower Shoreface, Upper Shoreface, Lagoonal Shale/ Heterolithics, Tidally Influenced Channel/Crevasse Splay, and Distributary Channel. Petrophysical analysis of these units showed a direct correlation between lithofacies type and grain size with flow properties deteriorating with decreasing grain size. Using such attributes as permeability, porosity, and grain size, four genetic units in the sand namely Lower Shoreface, Upper Shoreface, Tidal Channel, and Distributary Channel were interpreted as reservoir units. The best reservoir flow properties were preserved in the Distributary Channels with a porosity range of 20-29%, permeability in the range of 3,300-9,900mD and average grain size ranging from 177-500μ, while the Lower Shoreface corresponded to the worst quality reservoir units with porosity ranging from 17-26%, permeability varying from 0.01-180mD, and average grain size varying from 62-125μ. Three of the genetic units including Offshore Transition Heteroliths, Lagoonal Shales/Heterolithics, and Marine Shale were interpreted as non-reservoir units with porosity and permeability ranging from 4-17%, and 0.03-36mD respectively, while average grain size was below resolution. The E2000-Sand is interpreted as deposited in a coastal shoreface/delta mouth shallow marine setting. Reservoir quality in the sand is strongly faciesdependent with sedimentology and depositional environments controlling the reservoir properties of the sand bodies.

No abstract

TRACT: The Cretaceous sediments in the Anambra Basin (SE Nigeria) consist of a cyclic succession of coals, carbonaceous shales, silty shales and siltstones  interpreted as deltaic deposits. The objective of this study is to compare the hydrocarbon generation potential of organic matter from shale sediments along Isugwuato-Okigwe axis in the Anambra Basin, Nigeria. Data obtained indicates the presence of Type III kerogen with Tmax values are between 424 and 441ºC indicating that the shales are thermally immature to marginally mature with respect to petroleum generation. Hydrogen Index (HI) values range from 14 to 388.9mgHC/gTOC while S1 + S2 yields values ranging from 0.2 to 1.0mgHC/g rock, suggesting that the shale have gas generating potential. The TOC values rangesfrom 1.3 to 3.0%, an indication of a good source rock of terrestrially derived organic matter. The high oxygen index (OI) (16.3 mgCO2g-1TOC), TS (1.35) and TOC/TS (1.5) suggest deposition in a shallow marine environment. Based on the kerogen type, shales from the studied area will equally generate oil and gas if its organic matter attained sufficient thermal temperature. Keywords: Shale, kerogen type, maturity, oil generation.

Pebbles taken from the bed of the Cretaceous Abeokuta Formation paraconglomerate near the Oluwa River were used to infer the depositional setting and the nature of the source area, through the integration of bivariate and ternary (sphericity-form and Zingg diagrams) analyses. Deposition in a river environment is indicated by the high sphericity values, ranging from 0.59 to 0.88 (average 0.70). Also, bivariate plots of the maximum projection sphericity (ψp) vs. oblate-prolate index (OPI) and flatness index (FI) vs. maximum projection sphericity (ψp) point to the domination of fluvial processes. Dominantly elongated, compact elongated, compact and compact-bladed pebbles are typical for sedimentary regime with prevalence of fluvial over beach processes. Co-existence of various pebbles shapes (mainly disc, rod-, and sphere-shaped), despite of the similar, predominantly quartz composition, may occur due to the different clast fabrics. This heterogeneity also indicates various transport distances and water energies, pointing to the multiple source areas.

This study was carried out to determine the rock mechanical properties relevant for hydrocarbon exploration and production by hydraulic  fracturing of organic rich shale formations in Anambra basin. Shale samples and wireline logs were analysed to determine the petrophysical, elastic, strength and in-situ properties necessary for the design of a hydraulic fracturing programme for the exploitation of the shales. The results obtained indicated shale failure in shear and barreling under triaxial test conditions. The average effective porosity of 0.06 and permeability of the order of 10-1 to 101 millidarcies showed the imperative for induced fracturing to assure fluid flow. Average Young’s modulus and Poisson’s ratio of about 2.06 and 0.20 respectively imply that the rocks are favourable for the formation and propagation of fractures during hydraulic fracking. The minimum horizontal stress, which determines the direction of formation and growth of artificially induced hydraulic fractures varies from wellto-well, averaging between 6802.62 to 32790.58 psi. The order of variation of the in-situ stresses is maximum horizontal stress>vertical stress>minimum horizontal stress which implies a reverse fault fracture regime. The study predicts that the sweet spots for the exploration and development of the shale-gas are those sections of the shale formations that exhibit high Young’s modulus, low Poisson’s ratio, and high brittleness. The in-situ stresses required for artificially induced fractures which provide pore space for shale gas accumulation and expulsion are adequate. The shales possess suitable mechanical properties to fracture during hydraulic fracturing. Application of these results will enhance the potentials of the onshore Anambra basin as a reliable component in increasing Nigeria’s gas reserves, for the improvement of the nation’s economy and energy security. Key Words: Hydraulic Fracturing, Organic-rich Shales, Rock Mechanical Properties, Petrophysical Properties, Anambra Basin