A 3D basin modeling study of the factors controlling gas hydrate accumulation in the Shenhu Area of the South China Sea

Great advancement has been made on natural gas hydrates exploration and test production in the northern South China Sea.However,there remains a lot of key questions yet to be resolved,particularly about the mechanisms and the controls of gas hydrates enrichment.Numerical simulaution would play signficant role in addressing these questions.This study focused on the gas hydrate exploration in the Shenhu Area,Northern South China Sea.Based on the newly obtained borehole and multichannel reflection seismic data,the authors conducted an integrated 3D basin modeling study on gas hydrate.The results indicate that the Shenhu Area has favorable conditions for gas hydrate accumulation,such as temperature,pressure,hydrocarbon source,and tectonic setting.Gas hydrates are most concentrated in the Late Miocene strata,particularly in the structual highs between the Baiyun Sag and the Liwan Sag,and area to the south of it.It also proved the existence of overpressure in the main sag of source rocks,which was subject to compaction disequilibrium and hydrocarbon generation.It also shown that the regional fault activity is not conducive to gas hydrate accumulation due to excess gas seepage.The authors conjecture that fault activity may slightly weaken overpressure for the positive effect of hydrocarbon expulsion and areas lacking regional fault activity have better potential.

Assessment of hydrocarbon generation potential and thermal maturity of the deep offshore Lamu Basin, Kenya

In this study, the secondary well data for Cretaceous to Miocene cutting samples in four deep offshore exploration wells, i.e., Pomboo-1 in the north, Kubwa-1 in the central, Simba-1 and Kiboko-1 in the south of the deep offshore Lamu Basin were assessed for identifying source rock presence and examining thermal maturity of the source rocks. The 2D basin modelling was used to analyse the bulk gas transformation in the basin. Total organic carbon (TOC) content values for the wells range from 0.09 wt % to 2.23 wt % with an average of 0.78 wt %. The average organic richness is higher in the Upper Cretaceous (0.83 wt %) than in the Palaeogene (0.65 wt %), Lower Cretaceous (0.28 wt %) and Upper Jurassic (0.30 wt %). The S_(1) averages for the Upper Cretaceous are 3.76 mg HC/g rock in Pomboo-1 and 0.31mg HC/g rock in Kubwa-1. The S_(2) averages for the Upper Cretaceous are 5.00 mg HC/g rock in Pomboo-1 and 0.72 mg HC/g rock in Kubwa-1. Hydrogen index (HI) values vary between 4 and 512 mg HC/g TOC with an average of 157.09 mg HC/g TOC. Organic matters were identified as mixed types of Ⅱ-Ⅲ (oil and gas prone) and Ⅲ-Ⅳ (gas prone) kerogen in the potential source rocks. The HI and S_(2) yield values are exceptionally high for the observed TOC values in Pomboo-1. The vitrinite reflectance and Tmax values of deep offshore Lamu Basin are in the ranges of 0.38%–0.72% and 360–441 ℃, respectively. It suggests the existence of both immature and mature source rocks. Vitrinite reflectance maturity favours near coastal region in the Upper Cretaceous. These results explain why Pomboo-1, Kubwa-1, Simba-1 and Kiboko-1 wells were dry. The temperatures are still cool for hydrocarbon generation in deep offshore. The critical risk for deep offshore Lamu Basin is charge, primarily source presence, and a lack of definitive evidence of a deep-water marine source rock being present. The four wells penetrate good quality reservoir and seal rocks, but source rock presence and maturity remain the critical play risk in the deep offshore Lamu Basin.