A detailed geochemical study of oil samples from an onshore field in the Niger Delta was carried out for their characterization and correlation. The samples were analyzed using Gas Chromatographic (GC), Gas Chromatographic-Mass Spectrometric (GC-MS) and Inductively Coupled Plasma-Mass Spectrometric (ICP-MS) analytical techniques. The results showed that CPI, Pr/Ph, Pr/nC 17 , Ph/nC 18 and odd/even ratios ranged from 0.91 to 1.17, 3.07 to 6.04, 0.39 to 0.80, 0.14 to 3.30 and 1.33 to 1.39 respectively. The concentration levels of Co, Cr, Cu, Fe, Ni and V ranged from 0.9 to 32, 6.2 to 24, 3.31 to 19.4, 11.4 to 1241, 26.3 to 144 and 11.0 to 29.7 pbb respectively. The Pr/nC 17 vs. Ph/nC 18 plot revealed two oil types; non-degraded and minor degraded oils, which were derived from organic matter deposited in transitional environments. This suggests that both oil types have identical source rocks. Also, CPI values of 0.91 to 1.17 indicated that the oils are thermally mature. Biomarker data also discriminated the oils into two groups on the basis of biodegradation and revealed that the oils are mature and generated at almost the same thermal maturity level. The results of Ni vs. V, Co/Ni vs. V/Ni cross plots and cluster analysis similarly revealed identical two oil types. The similarity in the results of both organic and inorganic geochemistry of these oils shows that an integrated organic and inorganic geochemical data provide a reliable tool for the evaluation, characterization and correlation of crude oils.
The India National Gas Hydrate Program Expedition 02 (NGHP-02) discovered gas hydrateat high saturation in sand reservoirs at several sites in the deepwater Bay of Bengal. To assess the potential response of those deposits to scientific depressurization experiments, comprehensive geologic models were constructed to enable numerical simulation for two sites. Both sites (NGHP-02-09 and NGHP-02-16) feature thick sequences of thinly-interbedded reservoir and non-reservoir facies at sub-seafloor depths less than 300 m and sub-sea depths of 2400 m or more. These settings pose significant challenges to current modeling capabilities. First, the thinly-interbedded reservoir architecture complicates the determination of basic reservoir parameters from both log and core data due to measurement resolution issues. Secondly, the fine scale variation in sediment propertiesimparts great contrasts in key parameters over very short distances, creating high gradients at multiple scales and varying orientations that necessitate careful design of high-definition simulation grids. Thirdly, the deposits include internal sources of water, as well as a range of complex boundary conditions, including variable permeability within the overlying mud-rich "seals," that complicate reservoir depressurization. Lastly, because of the unique combination of great water depth and relatively shallow sub-seafloor depth: models designed to maximize the dissociation rate impose large pressure drawdowns on relatively low-strength sediments. This condition renders the proper evaluation and integration of the geomechanical response to hydrate dissociation critical. In this report, we review the history of gas hydrate reservoir simulation, discuss methods for creating geologic input models, and summarize the key findings and implications of the collaborative NGHP-02 numerical simulation effort. Together, the studies confirm the viability of the modeled accumulations for scientific testing and identify key challenges related to the selection of specific test sites and the design of test wells.
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