North Africa Shale Systems Insights


Aptian–Albian oil shale unconventional system as registration of Cretaceous oceanic anoxic sub-events in the southern Tethys (Bir M’Cherga basin, Tunisia)

Former EGI Visiting Scientist Rachida Talbi, along with Affiliate Scientist Reg Spiller, and EGI Director Raymond Levey recently published new research on the southern Tethys (Bir M’Cherga basin) Tunisia. Rachida visited EGI for a month in early 2017 in support of developing our understanding of shale systems in North Africa.

Abstract

The Bir M’Cherga basin (North-east Tunisia), with about 600 km2 area, had recorded four Middle Cretaceous source rocks well stratigraphically correlated with the four known oceanic anoxic sub-events: OAE1a, OAE1b, OAE1c, and OAE1d. Variety of lithology, thickness and organic richness had characterized these source rocks. The sedimentary tectonic analysis, the petrology and geochemistry study established the petroleum system of these source rocks. Basin formation began early in the Barremian–Aptian interval by synsedimentary tectonics reactivating old basement faults. During the Aptian–Albian, the formed basin had a depocenter that recorded thicker black shales while its NW and SE edges remained raised under the Triassic halokinetic activities. The evolution of the sedimentary filling during this period generated two sedimentary cycles corresponding to two filling second-order fining and thickening upwards sequences. The black shales that constitute these source rocks are formed between subtidal and external platform environment and are interbedded with juxtaposed high organic rich layers and poor ones. The rich organic facies consists of dark shale that constitutes the source rock. The poor organic beds formed by light grey and nodular limestones constitute an intra host reservoir.

a) Aptian main structural elements of Tunisian showing study area (Boltenhagen 1981; redrawn); b) schematic structural map of study area. Image courtesy of Talbi et al. 2018.

Thereby, petroleum system consists in an “unconventional oil shale hybrid systems with a combination of juxtaposed organic-rich and organic-lean intervals associated to open fractures”. The kerogen is essentially amorphous, with marine planktonic origin and low ligneous organic matter contribution. This organic material of dark facies had been well preserved in an anoxic environment with little or no energy. Light grey limestones were of oxic-to-sub-oxic environment. The stage of the thermal evolution for these source rocks provided by IH/Tmax diagram is of the “oil window”. The average transformation ratio (TR) is estimated as 45% suggesting thus black shales are oil shale resources which still close about untransformed 55% of its hydrocarbon generating potential. The expulsion and release of oil into these source rocks are proven by the observation of hydrocarbons filling micro-cracks and by the variable values of the oil saturation index OSI ranging from 0 to 138%. The latter exceeds 100% near the paleo-high reliefs indicating two “oil crossover” areas attributed to the high degree of oil source rock saturation and accumulation of hydrocarbons considered ideal for hydraulic fracturing. This oil crossover is a consequence of secondary migration into black shale source rock, achieved by various faults created during the distensive phase that were reactivated again several times.

Talbi, R. & Lakhdar, R. & Smati, A. & Spiller, R. & Levey, R. (2018). Aptian–Albian oil shale unconventional system as registration of Cretaceous oceanic anoxic sub-events in the southern Tethys (Bir M’Cherga basin, Tunisia). Journal of Petroleum Exploration and Production Technology. 10.1007/s13202-018-0577-6.

© The Author(s) 2018