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The Northern Tunisia (Northern Africa) is a promising area for oil/gas exploration. The organic geochemitry analyses of more that 1000 source rock samples and 100 oil seeps and solid bitumens were performed using GC-MS, IRMS and Rock-Eval pyrolysis techniques. The oil seep samples were collected from the Northern onshore Tunisia, associated with fracture, fault and ftrata in the Mesozoic and Cenozoic reservoirs and seals. Three primary source rocks are studied corresponding to the Albian, Late-Cenomanian-Early Turonain and Ypresian, showing good to excellent oil/gas potential. Three secondary source rock levels of Barremian, Paleocene and Miocene age are also studied and were found to display localy low to fair source rock characteristics. Based on the geochemical data, the oil seeps from the Northeast and Northwest areas were sourced from the three primary source rocks. The Albian and the Late-Cenomanian-Early-Turonain source rocks are the major oil source in the areas. While in South area, the oil seeps was initially charged by the Albian source rock. The Late-Cenomanian-Early-Turonain is the second source rock sourcing several oil seeps. The Barremain source rock only partly contributed in the south area. The oil seeps were found in fractures associated to the NE-SW and NW-SE trending fractures.

The thrust belt domain of North Africa is an important hydrocarbon province in the Mediterranean Sea and northern Tunisia. In spite of the long history of exploration in northern Tunisia, little information is available on Ypresian source rock in the thrust belt area. In the presented study the generative potential, depositional environments, thermal maturity and oil seeps of the YpresianBouDabbous organic-rich facies were characterized by both Rock Eval and molecular analyses. The present study indicates that the BouDabbous Formation displays variable source rock potential within the different Tellian units (Kasseb, EdDiss, AinDraham and Adissa units). Organic matter content and petroleum potential are generally poor to fair (up to 1.95% and 6 kg of HC/t of rock respectively) and marine type II kerogen. An increasing maturity gradient from the SE (Kassseb unit) to the NW (Adissa unit) is well documented. Indeed, the BouDabbousfacies are: marginally mature in the front of the nappes (Kasseb unit), mature to late mature within Nefza-Ain Allega tectonic window and overmaturea long the Cap-Serrat-Ghardimaou Master Fault (Adissa unit). In addition, Oil/Oil and Oil/source rock correlations shows a positive genetic correlation between the oil seeps and the BouDabbous source rock.

The Central and Meridional Atlas of Tunisia, contains significant accumulations of oil in early Cretaceous aged reservoirs. The active cretaceous hydrocarbon system is a product of unique paleogeographic and tectonic events that led to cretaceous deposition of organic-rich source rocks.The analysis of different sources rocks from the Central and Meridional Atlas of Tunisia indicates that the Albian Lower Fahdene Fm has a substantial oil-generation potential. The Cenomanian-Turonian Bahloul Fm exhibits fair to high organic matter content and petroleum potential and is immature to mature. The Jurassic source rock, located in the Southern part of this area, exhibits fair to good organic matter content and petroleum potential.Molecular characterization indicates that most of the produced oils appear to be sourced from a predominantly shaly marine and mature source rock deposited in suboxic to oxic environment. Oil stains located in the northern part of the area seems to be sourced by a marly or argillaceous limestone. Oil-oil correlations and molecular characteristics of selected source rock samples and maturation models suggests that oils were generated from similar source rock and/or organic facies. The Lower Fahdene Fm is the best source candidate to generate these fluid samples. The integration of benzocarbazoles as geochemical molecules tracer has permitted a relative estimation of the lateral migration distance for the different accumulations of the area.

Geochemical data indicate that the Late Silurian-Early Devonian Fegaguira Formation is the main source rock that has been charged the Ordovician and the Triassic reservoirs in the Chotts basin, South of Tunisia. Its good to excellent geochemical characteristic and its convenient maturity range allow it to be nominated as a good shale reservoir. The reservoir assessment was based essentially on geochemical and mineralogical elements including: (1) source-rock distribution, thickness, organic richness, maturity level, petroleum generation and migration; (2) organic facies distribution, quality and kerogen transformation; and (3) mineralogical assessment, clay type and quartz richness. A geochemical database consisting of 224 cuttings samples of the Fegaguira Formation was used to determine its geochemical characteristics including mineralogy. The examined shales show different thickness distribution that decreases towards the south east. They were subdivided into three distinct units according to their diagraphic responses, lithology and organic richness. The two upper units exhibit good total organic carbon averaging 5%, an original hydrogen index averaging 560 mg HC/g of TOC suggesting that the Fegaguira Formation was originally rich in type II organic matter (oil and gas prone kerogen), maturity ranges from 0.7 to 1.1 % R0, transformation ratio is about 0.78% and quartz richness up to 16%. Detailed framework studies in petroleum geochemistry, lithostratigraphy and mineralogy combined with conventional modeling were used to estimate the unconventional oil and gas resources of the Fegaguira Formation. The important organic content, the carbon transformation ratio, the gas derived both from kerogen cracking and oil-to-gas cracking, including the calculated porosity and the quartz percentage suggest that the Feguiguira Formation is a promising reservoir.

Several wells have been drilled in the south eastern side of Tunisia but only two wells are producing. However, to better understand the petroleum system mechanism of the area, a geochemical study was performed including oil-oil and oil-source rock correlation that was proved to be an essential tool for assessing oils occurrence, source rocks characteristics, their depositional environments and their distributions. The geochemical study was followed by 1D basin modeling to better understand the petroleum system functioning of the area. The geochemical survey is based on the analysis of a total of 214 cutting samples and 6 crude oil samples. In a first part, potential Silurian and Ordovician source rocks were analyzed by Rock Eval to characterize their petroleum potential. In the second part, DST oil samples are correlated to Silurian and Ordovician source rocks using biomarkers and light hydrocarbon fraction. Migration distances calculation was based on carbozoles and benzocarbozoles. Rock Eval results show that Silurian Hot shales exhibit good petroleum potential with mature type II oil prone kerogen, while Ordovician Shales show poor to fair petroleum potential and contain bad preserved type II kerogen. Geochemical correlations study proved that the Silurian Hot shales are the main source rock in the basin and excluded any contribution from the Ordovician shales. Carbozoles and benzocarbozoles concentrations in the oils of the northern part of the area suggest close proximity to the source kitchen while oils from the southern part seem to be sourced by a kitchen located in Ghadames basin. The 1D modeling indicates that oil and gas generation from the Silurian hot shales began in the Carboniferous at about 360 Ma and reaches the maximum generation phase in the Upper Jurassic at about 160 Ma. The Hercynian unconformity surface was the main drain of secondary migration in the basin.