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This paper evaluates the Cenomanian-Turonian Bahloul Formation as a new target for an unconventional shale oil play in the Sahel Basin, eastern Tunisia to increase the oil supply. A detailed geochemical (Rock-Eval pyrolysis and biomarkers) and mineralogical study was carried out on 44 drilled cutting samples of the Bahloul Formation from three wells (M-1, A-1, and T-2). The geochemical investigation highlighted variable total organic carbon (TOC) concentrations ranging from 0.20 to 6.65 wt.%, with the highest values recorded in the samples from the M-1 well (avg. 2.76 wt.%) and A-1 well (avg. 1.68 wt.%). The lowest TOC values are observed in the samples from the T-2 well (avg. 0.65 wt.% TOC). These organic matter (OM) contents reflect favorable conditions for the accumulation and preservation of OM controlled by both an oxygen minimum zone (OMZ), and restricted circulation in a “semi-silled” basin. This basin is marked by the presence of subsiding zones and paleohighs (Triassic salt domes, and horsts). Within the subsiding basin, the preserved OM contents are primarily marine OM (type II) with a minor contribution of terrestrial (type III) and/or bacterial/algal (type I) material. The nature of the OM (type II) and the mean hydrocarbon generation potential (HGP) of 9.26 kg HC/ton rock render Bahloul Formation an oil-prone source rock. Additionally, the thermal maturity of the OM preserved in this formation varies between late diagenesis (avg. Tmax = 427°C in M-1 well) and the early oil window (avg. Tmax = 438°C and 435°C, in A-1 and T-2, respectively). The average transformation ratio (TR) in wells A-1 and T-2 is estimated at 40%. Within these wells, the oil saturation index (OSI) reveals the presence of three “oil cross-over” intervals attributed to the high degree of oil source rock saturation (OSI > 100%) and the accumulation of hydrocarbons (HC). These “oil cross-overs” resulted in primary or secondary oil migration into Bahloul source rock. The primary oil migration is considered to be facilitated by the development of organic and nonorganic porosities and the onset of interconnected, continuous, oil-wet filets. On the other hand, the secondary migration seems to be favored by an intensely fracturing network in connection with open fracture systems and faults achieved during the basin’s geodynamic history. These “oil cross-overs” determine the presence of three target intervals in each of A-1 and T-2 wells. In A-1 well, these targets have a significant thickness (from 3 to 6m) but in T-2 well they are only 1–2m thick. The in situ oil reserves are estimated at 3.109 tons HC in the areas where OM is mature (7,000 km2), with a free HC quantity (avg. S1 = 20 % of HGP) of 6.108 tons HC. These volumes of HC can be liberated by hydraulic fracturing. The Bahloul Formation is ideal for hydraulic fracturing owing to its composition (limestone: 50-77% CaCO3 and a minor detrital fraction) and its high brittleness index (BI = 0.83 to 0.90).

Effective quantitative modeling of petroleum generation processes requires a reasonable knowledge of various factors controlling the transformation of organic matter into oil or gas. Nevertheless, it is widely accepted that thermal conductivity and temperature have the dominant roles in controlling generation. In Tunisia, previous source rocks burial and maturity modeling were mostly carried out using corrected borehole temperature after applying formula which were set to fit domains other than Tunisian basins. The main purpose of this work is to propose a suitable method of temperature correction to fit the studied area but more importantly to emphasize the impact of thermal conductivity on heat flow distribution. For that, a total of 222 temperature values including 170 bottom hole temperatures (BHT) and 52 drill stem tests (DST) were collected from 30 onshore and offshore boreholes. The proposed equation generates corrected temperature close to true formation temperatures. As thermal conductivity depends on the relationships between a sedimentary interval component, two equations were used to determine the conductivity of each unit which are the harmonic and the geometric means. To assess the importance of applied corrections, three scenarios were tested for an Albian source rock using the 1-D Basin-Mod software. The combination of corrected BHTs and thermal conductivity provide higher source rock maturation than when uncorrected data are used. Amounts of generated hydrocarbons are estimated to become two times higher. This would guide for complementary reserves estimations to be applied in the region for better calculation accuracy.

Upper Cretaceous deposits in central eastern Tunisia represent a potential proven source rocks from Cenomanian–Albian Fahdene and Turonian Bahloul Formations and reservoir rocks of Turonian Bireno, Douleb, and Campanian–Maastrichtian Abiod Formations. The latter form the main oil and gas field systems in onshore and offshore central eastern Tunisia. Seismic tectonics and seismic stratigraphy based on 2D seismic analyses calibrated to the petroleum well’s wireline logging led to the identification of source rock and reservoir sequence distribution between high platforms and subsiding basin areas. This structuring has been created by inherited deep-seated transtensive and transpressive flower faults (Kairouan-Sousse, Hdadja, El Jem, Mahdia, etc.) that are intruded by Triassic halokinetic evaporites. Geochemical analyses and modeling of the well and pseudo-well deposits using BasinMod 1D software from a plate river had permitted to differentiate kitchen areas, within the basin areas, that have high maturity level (late oil to gas generation phase) of Fahdene and Bahloul Cretaceous source rocks. The neighboring high flank structures might constitute good traps to accumulate expelled materials. The large-scale fault system and the dense fracture network related to the Kairouan Basin borders represent a preferential pathway for fluids to reach updip flank reservoir units. The geochemistry modeling was performed in order to characterize the maturity, generation, and expulsion timing of hydrocarbons. In addition, this study highlights the great gas shale potential steel remaining in the subsiding basin kitchens.

The Gabes Gulf located in the South Mediterranean Sea (Southeastern part of Tunisia) is a prolific petroleum-producing area with several oil and gas fields and it's the subject of significant discoveries. The area is affected by intense tectonic events and several stages of hydrothermal activities . During drilling at the MX area in NE of the Gabes Gulf, a magmatic intrusion has been encountered within a reservoir rock (i.e., Douleb Formation). The objectives of the present study are (1) to investigate the impact of the hydrothermal activities on this magmatic intrusion and (2) to characterize the potential modifications in its mineralogy and petro-physical properties that can affect the migration/accumulation of hydrocarbons. To do so we combine optical microscopy, X-ray diffraction, scanning electron microscopy, energy dispersive X-ray spectrometry, micro-Raman spectroscopy, electron microprobe analyses, and petro-physical measurements. Our results show that the initial magmatic intrusion (dolerite) is composed mainly of plagioclase , clinopyroxene , and olivine. Based on petrographic observations, this intrusion subjected to several stages of hydrothermal fluid alterations that modified the primary texture and mineralogy. Albite , calcite , ankerite , dolomite, pyrite , quartz, anatase , kaolinite, and chlorite are the main secondary mineral products. During this alteration process, carbonates, pyrite, and quartz precipitated in vesicles, forming amygdules structure with enveloped zones indicating a fluctuation of fluid chemistry during their formation. In addition, petrographic observations indicate an interaction between feldspars exsolution and metasomatic processes in the studied area. The dissolution mechanisms, as well as the textural modifications in the dolerite induced by the hydrothermal activity, are underlined by the presence of spherulites , pores, and micropores. Such modifications significantly improved the porosity of the dolerite body. Conversely, the new mineralization that filled the fractures and micro-fractures, have reduced the inter-pore connections, and thus reduced its permeability. The present work demonstrates the important role of hydrothermal activity on the petro-physical properties of magmatic intrusions and how it could facilitate the migration/accumulation of hydrocarbons. Our results open the door for further investigations to check the potential presence of hydrocarbons within this doleritic intrusion.

International audience; The present study is based on core petrographical analyses of an oil-producing Turonian carbonate reservoir in the Sfax area (central-eastern onshore of Tunisia). Sedimentological studies show that these Early-Middle Turonian carbonates consist of shallow marine bioclastic limestones, sometimes partly dolomitised, and are rich in rudists which can be associated to other bivalves, gastropods, oncoliths, benthic foraminifers and calcisphers. Facies are organised into metre-scale shallowing upward cycles, each comprising three units corresponding, from base to top, to the following: bedded, slightly argillaceous wackestones containing floating rudist debris and sometimes calcisphers; alternation of massively bedded partly dolomitised packstones rich in entire joined rudists and finely bedded wackestones-packstones containing miliolids, oncoliths and gastropods; and micritic carbonates, partly argillaceous, nodular shaped and laminated. In terms of reservoir properties, the highest values of helium porosity (reaching 27%) and permeability (reaching 700 mD) were measured in rudist-rich carbonates. Pores, which are partly filled with oil, mainly correspond to the Radiolitid cells. In addition, some diagenetic features such as dolomitisation, dedolomitisation and dissolution have created additional pores and have clearly enhanced the reservoir potential of these rudist-rich carbonates.

Permian rock samples from two wells (W-1 and W-2) drilled in the Jeffara basin (Southern Tunisia) were analyzed using the Rock Eval pyrolysis (RE) and Gas chromatography coupled to Mass Spectrometry (GC/MS). Oil indices from the same series were also examined. The two objectives pursued through this study were: (1) First, to geochemically characterize the Permian series in order to determine their source rock potential; (2) Second, to identify the origin of hydrocarbons occurring in the Permian layers through oil-oil correlations and oil correlations to source rocks candidates (Permian, Azzel, Fegaguira, and Zoumit). The attained results show that the lower part of the Permian series is rich in organic matter and may constitute a good source rock of an “Oil and Gas-prone” quality. The oil indices found in the top part of the Permian series were generated simultaneously by the Permian source rock and the Paleozoic source rock (Azzel and Fegaguira). The 1D basin modeling results indicate that, overall, the hydrocarbon generation started since the Permian (240 Ma) while oil expulsion took place during the Upper Triassic (230 Ma).

This study evaluates the geopetroleum assessment of the Ordovician series (El Atchane and El Hamra reservoirs) and the Triassic series (TAGI), in the Southern Chotts region, based on well logging data. The burial and thermal maturity history of the potential source rock Fegaguira Formation (Silurian in age) of the area, was accomplished using the BasinMod software. The generation and expulsion times of hydrocarbons in the region, as well as their quantities were also estimated. The Ordovician reservoirs (El Atchane and El Hamra) generally show the same petrophysical characteristics (the porosity of the two reservoirs varies between 5 and 12%) with a decrease in thickness from west to east until the total disappearance of the El Hamra Formation. This variation was related, on the one hand, to the bevelling of the Ordovician on the Telemzane arch and, on the other hand, to the erosive effects of the orogenic phases during Paleozoic (Taconic, Caledonian and Hercynian phases). The maturity history modeling of four wells in the south of the Chotts region shows that the Fegaguira source rock is mature and began generating hydrocarbons during the Early Cretaceous and expelled its hydrocarbons from the Paleogene in the wells 5 and 7 and from Cretaceous in the well 13 (at a SATEX of 10%). The Fegaguira source rock has not expelled in the well 19. The quantity of oil expelled by the Fegaguira source rock reached 36.3 bbl/acre ft rock and 33 bbl/acre ft rock in the wells 5 and 7 during Paleogene and 53.5 bbl/acre ft rock in the well 13.

This study documents the Cretaceous intraplate magmatic-hydrothermal activity in the Eastern margin of Tunisia. The magmatic occurrences are believed to be directly linked to deeply rooted faults, trending E–W, N–S and NW–SE, and which enabled basaltic magmas ascension. The settling of this magmatism was accompanied by circulation of hydrothermal fluids, generating a local abnormal geothermal gradient. Magmatic rocks suffered effects of hydrothermal alteration during magma cooling. Slightly deformed zones are characterised by superimposed static paragenesis which began in green schist facies (T = 450–350 °C) and ended by analcime crystallization at relatively low temperatures (T = 180–130 °C). Temperature increase and hydrothermal conditions led to the generation of a new mineral paragenesis around the enclosing sedimentary deposits. CO2, H2S, CH4 and N2 occurrences are also thought to be driven by this magmatic repartition. In addition, it is most likely that the gases, produced at deeper depth, migrated upwards along the highly permeable fault zones. The carbon isotopic signatures of selected gas samples suggest a thermogenic origin for methane and a crustal origin for CO2. The latter could have been generated through thermal breakdown of carbonate rocks via contact metamorphism or through increasing burial depth and high heat flow induced by the hydrothermal event in the studied 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.

This paper deals with an introduction to the preliminary exploration of possible gas shale reservoirs in Tunisia. A special focus was made for the Lower Silurian “Hot Shales” source rock which is more suitable to be a potential gas shale reservoir in the Ghadames basin.