The oil potential of Niger is mainly located in two large sedimentary basins: the Iullemeden Basin in the West and the Eastern Niger Basin in the East. These two basins cover 90% of the National Territory. Nowadays, exploration and exploitation activities take place in the Eastern Niger Basin, more particularly in the Termit-Basin.Despite the development of some deposits and recent discoveries, the Termit Basin, one of the largest Cretaceous to Tertiary trenches belonging to the West and Central African Rift System (WCARS), remains under-explored.The overall objective of this study is to assess the petroleum potential and kerogen type contained in the Donga bedrock of the Termit Basin.This study, which follows previous organic geochemical work, is based on the Rock-Eval6 method and Gas chromatography (CG-SM) method of analysis of source rock samples and crude oil from the Upper Cretaceous of Donga formation. The samples come from the following wells: Trakes N-1D, Minga-1, Douwani N-1, Kanga-1, and Koulele Deep-1.The Source rock evaluation of Well Douwani N-1 and Trakes N-1D, suggests that, the Donga Formation contains more Type II2 and II1 organic matters in the eastern basin than in the western basin, and is generally considered the moderate to good source rock.Pr/Ph is 1.57, the Tricyclic terpane content is higher than the Pentacyclic terpane content, the Gammacerane content is high, the ratio of Gammacerane to C30 Hopane is 1.05.The Donga Formation crude oil from Well Trakes N-1D is different from those from Well Trakes-1, as shown in the triangular chart of C27-C28-C29 Regular steranes, and hence is defined as Class IV. The cross plot of Gammacerane/C30 Hopane and C27/C29 Regular steranes provides a good approach to distinguish these four classes of crude oil.

This study is a contribution to the petrographic and petrophysical characterization of the reservoir sandstones of Yogou Formation in the Termit Sedimentary Basin (Niger). It focuses on the impact of diagenetic processes on the petrophysical properties of Campanian sandstones. The pore types are generally intergranular, intragranular, and rare microcracks. The porosity varies from 0.3% to 25.3% and the permeability ranges from 0.1 mD to 470.3 mD. Diagenetic features that influenced the reservoir quality evolution include mechanical and chemical compaction, precipitation of carbonate cement, clay mineral cement, the formation of quartz overgrowths, and dissolution of feldspar grains. Compaction and cementation reduced significant volumes of primary porosity and permeability. On the other hand, feldspar dissolution and quartz corrosion contributed to an increase in the volume of primary porosity of the sandstones. The Yogou Formation reservoir was subjected to a high diagenetic overprint resulting in marked reservoir heterogeneity. This study also demonstrated the effect of diagenetic processes on the quality of hydrocarbon reservoirs and showed that good quality reservoirs are mainly concentrated in the 2545 m to 2565 m depth range of the study area.