Regional 1D hydrocarbon maturation modelling of the Cenomanian–Turonian Lokpanta Shale, southern Benue Trough, Nigeria: Implications for the origin of Niger Delta deep sea oils

Abstract

Basin modelling, constrained by geochemical data from eight wells, was carried out, across the late Cretaceous and Early Palaeogene sediment packages of southeastern Nigeria sedimentary basins. The study was aimed at establishing the sediment burial history, thermal maturation of the source rock and timing of hydrocarbon generation. The Late Cenomanian to Early Turonian Lokpanta Shale, which is the basal unit of the Eze-Aku Formation in the Eze-Aku Group, consists of alternating dark grey to black shales, marl and siltstones. The upper sections are mainly alternating sandstones, shales and limestones. This unit is the key petroleum source rock for the basin. Numerical 1D basin model of the study area revealed that the Cenomanian to Turonian times was the main phase of rifting in the Benue Trough evidenced by rapid subsidence. Subsidence rates varied widely in all the wells studied, ranging from 29-61 m/Mya (million years ago) and averaging 44 m/Mya. Subsidence rates also varied widely through geological time from the Cretaceous to the Palaeogene. The Cenomanian-Turonian and the Maastrichtian ages recorded the highest subsidence rates (169.75 and 168.28 m/Mya, respectively). These phases of rapid subsidence correspond to the main phase of rifting (Cenomanian-Turonian) and periods of increased sediment supply (Campanian and Maastrichtian), due to rapid erosion and unroofing of the structurally inverted Benue Trough, post-Santonian. Vitrinite reflectance values (1.87-4.78% Ro) indicated that the Lokpanta source rock (Late Cenomanian-Early Turonian) is mature to overmature. The vitrinite maturation profiles and the geochemical data suggested the generation of hydrocarbon before the Santonian compressional uplift of the Abakaliki-Benue Trough with its resultant sediment folding, which displaced the depo-centre from the Abakaliki Basin to the Anambra and Afikpo platforms. The subsequent erosion and non-deposition in the Abakaliki Basin raised the Lokpanta Shale above the oil generative window. The renewed sedimentation in the Campanian resulted in sagging due to sediment load creating the Anambra Basin. The lack of an effective trapping mechanism in the pre-Santonian may imply that hydrocarbon generated before the uplift migrated away, probably to upper and/or lower horizons (observed as oil shows in the region); some of which may be contributing to the Niger Delta crude. This is evidenced by the correlation of the Niger Delta deep sea samples to the Cretaceous (Lokpanta Shale) source rock and occurrence of biomarkers of Cretaceous origin (ab-hopanes and oleananes in the Opuama Channel complex, northern depobelt, Niger Delta).

Geochemical and geomechanical evaluation of the Mungaroo Formation, offshore northwestern Australia

“…1D burial history models are a useful tool in hydrocarbon exploration because they provide a history of evolution of a source's rock transformation rate and thermal maturity through time (Peters and Cassa, 1994). Sedimentation rates vary across a basin, for this reason building multiple 1D subsidence models inside the area of interest is needed, since this will help to identify sedimentation tendencies, zones with the highest organic matter transformation ratio and explain the reasons of these variations (Afife et al, 2016;Amobi et al, 2019;Gawad et al, 2021).…”