Sedimentological and facies architectural controls on hydrocarbon-bearing intervals in parts of the Niger Delta, Nigeria.
This study appraised sedimentological and facies architectural controls on reservoirs of Imaemi Field, offshore Niger Delta. This was with a view to incorporating sedimentological and facies architectural characteristics in exploring reservoirs and identifying transgressive-regressive sequences. It also intended to generate models of spatial variability of lithofacies architecture and petrophysical properties of reservoirs, at sub-interwell scale and related their association to hydrocarbon distribution. Well logs from 25 wells and core samples from 2 wells within the field were used for petrophysical, grain size, petrographic and heavy mineral analyses. Sequence boundaries were defined by transgressive-regressive technique and stratigraphic sections were built from logs. Quantitative lithofacies data yielded shale, sandy shale, silt, shaly sand, silty sand and sand occurrences used for sequential indicator simulation. Sequential Gaussian simulation was used for petrophysical properties and fluid saturation models. Eleven sequence boundaries named SB-1 to SB-11 were delineated in the field. Reservoir architectural analysis yielded 24 vertically stacked, youngest to oldest reservoir bodies (A-Sand to Q-Sand) within channel-fill, abandonment phase, delta plain and prodelta depositional settings. Traditional reservoir characterization and geostatistical simulations of lithofacies and petrophysical properties for H, I, J, L, M and N-Sands showed lithofacies spatial distribution, lenticular sand geometries, shale beds continuity, intra-reservoir flow barriers, shale volume (11.00 to 67.00 %), effective porosity (5.00 to 30.00%), permeability (0.02 to 5949.15 mD), pore aperture radii (0.05 to 0.29 ), effective pore radii (20.57 to 206.57 ) and hydrocarbon saturation (18 to 82%) distribution. Gas and oil saturation up to 82.00% were associated with cleaner sand intervals, except in M-Sand, where irregularity occurred; while low saturation (32.00%) in shale-rich portions was due to high surface area, low effective porosity, excessive percentage bond water and low pore aperture radii. Pore aperture radii (r) values less than 0.10 indicated wet intervals, while 0.10 and above depicted hydrocarbon presence. Compartmentalized pools in the reservoirs reflected lithofacies distribution and highlighted hydrocarbon-bypassed prone zones in the six sand bodies studied. Reserve growths potential occurred to the northwest, southwest and southeast of the area. The study concluded that, the spatial distribution of lithofacies and petrophysical properties were related and influenced hydrocarbon distribution.