Reservoir hydrocarbon potential of the Miocene Agbada Formation using RMS amplitude map and hydraulic flow unit model, Hatch Field offshore, Niger Delta Basin, Nigeria

Abstract

The Miocene Agbada Formation is the hydrocarbon-producing unit in the Niger Delta region because it has excellent stratigraphic and structural traps. Understanding the reservoirs' hydraulic flow characteristics in the Agbada Formation is necessary. The flow of fluids in a reservoir is controlled by the effective porosity of the reservoir that can be spatially correlated with root mean square (RMS) amplitude and HFUs.The study aims to produce an RMS map and HFUs model for reservoir units D and E in the Hatch Field Offshore Niger Delta Basin and determine the reservoirs' hydrocarbon potential using the reservoir seismic data, core analysis, and well-log data. The seismic attribute of RMS amplitude was applied for both reservoir units D and E in the Hatch field. The calculated FZI was categorised using a conditional statement with two HFUs. The hydraulic flow unit model for both reservoir units was built utilising a simulation grid design of 157x100x5 for reservoir unit D and 204x120x5 for reservoir unit E. The sequential indicator simulation (SISIM) algorithm was applied to simulate the HFUs model for reservoir units D and E. The RMS amplitude maps show bright spots that are possible hydrocarbon prospects in P1, P2, and P3 for reservoir unit D. However, reservoir unit E has bright spots that are also likely hydrocarbon prospects here named P4 and P5. The brighter amplitudes observed in prospects P4 and P5 signify significant amounts of hydrocarbons in reservoir unit E. The results of the hydraulic flow units’ model is represented by the spatial variability of flow units within the reservoir. The coefficient of determination between well-log data and the model results range from 0.9258 to 0.9655 and 0.8586 to 0.9868 for reservoir units D and E, respectively. A litho-saturation cross plot comparing lithofacies and HFUs confirms that HFU 1 comprises sandstone while HFU 2 is composed of marine shale. The reservoirs' spatial distribution of hydraulic flow units shows that unit D has poor hydraulic flow characteristics and hydrocarbon potential due to the high proportion of marine shale facies in HFU 2 compared to HFU 1. Reservoir unit E predominantly has a higher proportion of sandstone in HFU 1 compared to HFU 2, making it a better reservoir with good hydrocarbon potential than reservoir unit D.