Assessment of Fault Sealing in the Gabo Field, Niger Delta, Nigeria

Abstract

This research assesses the sealing of the fault bounded stratigraphy of the Gabo Field, Niger Delta, Nigeria. Materials used comprises of 3D seismic volume in seg-y, ditch cuttings and well logs. The methods applied are standard fault plane evaluation techniques and they include seismic interpretation, well correlation, XRD analysis, and application of the Yielding et al., (1997) shale gouge ratio (SGR) algorithm for fault seal analysis. The tectonic framework was interpreted in terms of deformational, depositional and post-depositional structures. The order of magnitude of stress is SHmax > σv > Shmin. The juxtaposed strata relationships were analyzed by taking cross sections A-A1 and B-B1 and this showed the structural framework across the field. Cross section A-A1 showed that the depositional and post depositional structures are pinchouts (channel abandonment or switching) and shale smears respectively. The cross section B-B1, showed that the deformational structures are faults F1 and F2 – recognized as closely spaced normal faults and F3 is a syn-depoitional growth fault. The well correlation showed the vertical stratigraphy of the wells are comprised of cyclic succession of sands and shales and the shale thickness increased in intermediate sections. The X-ray diffraction (XRD) analysis of the shales showed that the predominant minerals are kaolinite, rutile, gypsum, albite, microcline and quartz. The rock property analysis showed that the net to gross ranges from 26.28 – 82.0% with an average of 73.7%. The volume of shale ranges from 18 – 73.72% with an average of 63.59%. The bulk density of the shales ranges from 2.379 – 2.692g/cc with an average of 2.46g/cc. The total porosity ranges from 0.159 – 0.317 with an average of 0.167 in the shales and 0.272 in the sand. The effective porosity range from 3.58 – 22.71 with an average of 6.028 in the shale and 20.13 in the reservoir. The drawdown mobility and temperature range is 2.2 – 4124.4mD/cP and 63.3 – 80.1oF respectively, while the average is 569mD/cP and 70.63oF respectively. The estimated pore pressure ranges from 0.4213 – 0.4762psi/ft with an average of 0.47psi/ft in the shales and 0.428 psi/ft in the sand. The fault seal analysis showed that the shale gouge ratio range from 0.2 – 0.7 and the stratigraphic juxtapositions are predominantly sand to sand, sand to shale and shale to shale. The results of this research reduces the fault seal uncertainty in the planning of oilfield development projects and enhanced pressure support for the recovery of bypassed hydrocarbons, most especially in compartmentalized reservoirs. In addition, the results of this research can be applied to similar deltaic successions around the world.