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In Tunisia, most borehole temperatures used to constrain the thermal histories of sedimentary basins were previously corrected using various methods, set to best fit domains other than the Tunisian basins. This study aimed to propose a new method of borehole temperatures correction suitable for the Jeffara Basin, southeastern Tunisia. 92 temperatur...
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Context 1
... < R o < 0.88 to the north (W-1, W-2, W-3, and W-4 wells) and to the southwest (W-9, W-10, and W-11 wells). Using corrected heat flow data, the immature- early mature zone has less geographical extent as compared to the previous test. The Silurian hot shales are immature ( R o = 0.66%) around W-7 well ( Figure 17) and are mid-mature ð 0.7 % < R o < 0.88 % Þ in the northern part around W-1, W-3, W-5, and W-6 wells and in the southern parts around the W-8, W-9, W-10, and W-11 wells. To the north and within the area neighboring W-2 and W-4 wells, the Silurian hot shales are predicted to be within the gas window ð 1.15 < R o < 1.16 % Þ . This late mature level of thermal maturity was not reached when testing the uncorrected heat flow. Such difference will no doubt affect hydrocarbon generation and expulsion processes. Most wells, modeled in this study, show comparable results, so only a few wells will be used as examples to illustrate the timing of hydrocarbon generation and expulsion. Based on uncorrected heat flow data, hydrocarbon generation from the Silurian hot shales began at 421 and 206 Ma in the W-9 and W-6, respectively, and continues to the present day. In all wells, either gas or liquid hydrocarbons have been generated. Cumulative generated quantities range from 1.6 to 35.4 mg HC/g TOC. However, at a saturation expulsion threshold (Satex) of either 5% or 10%, the Tannezuft Formation source rock is found to be incapable of expelling hydrocarbons. The saturation expulsion threshold, expressed in percent of total porous volume of rock, is defined as the quantity of generated hydrocarbon beyond which any produced excess will be expelled from the source rock (Cooles et al., 1986; Mackenzie and Quigley, 1988). Based on corrected heat flow data, the hydrocarbon generation from the Silurian source rock started at 422 Ma in W-9 and 280 Ma in W-6. All wells have produced either oil or gas. Cumulative generated quantities range from 4 to 68 mg HC/g TOC. The source rock started expelling hydrocarbons only at the W-2 and the W-4 wells (Satex = 5% or 10%). In these wells, gas and liquid hydrocarbon expulsion is considered significant with a maximum during the Late Cretaceous for the W-4 well attaining 51 mg/g TOC at a Satex of 5% (Figure 18). These results were mapped to show the spatial distribution of hydrocarbon expulsion in the Jeffara Basin at a Satex of 10% (Figure 19) and where the area around wells W2 and W4 is very pronounced. The thermal and maturation history results of the Silurian source rock in the Jeffara Basin using corrected heat flow via corrected BHTs are different from those obtained by Ferjaoui et al. (2001). For instance, the maturity map generated in the present study (after heat flow correction) shows that the Silurian source rock is late mature in the northern part of the Jeffara Basin (Figure 17). Whereas, it has been reported to be at a mid-mature stage, at the same location based on Ferjaoui et al. ’ s study. In addition, results derived from this study in terms of thermal maturity of the Tannezuft Formation source rock are consistent with the geochemical findings concluded by Rezouga et al. (2012) for the southeastern part of Tunisia showing a possible hydrocarbon migration path from W-2 and W-4 well locations (where the Silurian source rock is found to be in a late mature stage in this study, Figure 17) to the W-6 well locations. This is further supported by the fact that the W-6 well is producing light oil and condensate gas. It is most likely that this well was supplied by gas condensate from the late mature area located in the northern part of the Jeffara Basin, as identified in this study. Cross-plot BHT temperature correction proposed for the Jeffara Basin has been proven to be reasonably efficient. Its validity check was per- formed through the 1-D Jeffara Basin modeling and through comparisons of results using uncorrected temperatures, on one hand and proposed corrected data, on the other hand. Heat flow adjustments on corrected BHTs using the cross- plot method indicate that the northern part of the study area has higher heat flow ð 91 mW ∕ m 2 Þ than that obtained using uncorrected data ð 84 mW ∕ m 2 Þ , influencing thus the thermal maturity of the Silurian source rock. In the northern part of the study area (W-2 and W-4 wells), the Silurian source rock is in a late mature stage and has reached the gas window. This source rock generated liquid hydrocarbons and is currently producing gas and condensate. At the W-2 and W-4 wells, the Tannezuft (hot shale) have expelled oil and gas since the Late Cretaceous (51 mg/g TOC). The heat flow correction has influenced the maturity of the Silurian source rock, especially through the appearance of an area where the source rock is at a late mature stage, and also through an increase in the amounts of generated hydrocarbons, which are estimated to be five times higher than those obtained based on uncorrected data. In addition, the hydrocarbon expulsion at the W-2 and W-4 wells was significant and could have occurred even at a saturation expulsion threshold of 5%. The maturity results for the Tannezuft hot shales are not in complete agreement with the previously published maturity map of Ferjaoui et al. (2001) but concur with the study by Rezouga et al. ...
Context 2
... < R o < 0.88 to the north (W-1, W-2, W-3, and W-4 wells) and to the southwest (W-9, W-10, and W-11 wells). Using corrected heat flow data, the immature- early mature zone has less geographical extent as compared to the previous test. The Silurian hot shales are immature ( R o = 0.66%) around W-7 well ( Figure 17) and are mid-mature ð 0.7 % < R o < 0.88 % Þ in the northern part around W-1, W-3, W-5, and W-6 wells and in the southern parts around the W-8, W-9, W-10, and W-11 wells. To the north and within the area neighboring W-2 and W-4 wells, the Silurian hot shales are predicted to be within the gas window ð 1.15 < R o < 1.16 % Þ . This late mature level of thermal maturity was not reached when testing the uncorrected heat flow. Such difference will no doubt affect hydrocarbon generation and expulsion processes. Most wells, modeled in this study, show comparable results, so only a few wells will be used as examples to illustrate the timing of hydrocarbon generation and expulsion. Based on uncorrected heat flow data, hydrocarbon generation from the Silurian hot shales began at 421 and 206 Ma in the W-9 and W-6, respectively, and continues to the present day. In all wells, either gas or liquid hydrocarbons have been generated. Cumulative generated quantities range from 1.6 to 35.4 mg HC/g TOC. However, at a saturation expulsion threshold (Satex) of either 5% or 10%, the Tannezuft Formation source rock is found to be incapable of expelling hydrocarbons. The saturation expulsion threshold, expressed in percent of total porous volume of rock, is defined as the quantity of generated hydrocarbon beyond which any produced excess will be expelled from the source rock (Cooles et al., 1986; Mackenzie and Quigley, 1988). Based on corrected heat flow data, the hydrocarbon generation from the Silurian source rock started at 422 Ma in W-9 and 280 Ma in W-6. All wells have produced either oil or gas. Cumulative generated quantities range from 4 to 68 mg HC/g TOC. The source rock started expelling hydrocarbons only at the W-2 and the W-4 wells (Satex = 5% or 10%). In these wells, gas and liquid hydrocarbon expulsion is considered significant with a maximum during the Late Cretaceous for the W-4 well attaining 51 mg/g TOC at a Satex of 5% (Figure 18). These results were mapped to show the spatial distribution of hydrocarbon expulsion in the Jeffara Basin at a Satex of 10% (Figure 19) and where the area around wells W2 and W4 is very pronounced. The thermal and maturation history results of the Silurian source rock in the Jeffara Basin using corrected heat flow via corrected BHTs are different from those obtained by Ferjaoui et al. (2001). For instance, the maturity map generated in the present study (after heat flow correction) shows that the Silurian source rock is late mature in the northern part of the Jeffara Basin (Figure 17). Whereas, it has been reported to be at a mid-mature stage, at the same location based on Ferjaoui et al. ’ s study. In addition, results derived from this study in terms of thermal maturity of the Tannezuft Formation source rock are consistent with the geochemical findings concluded by Rezouga et al. (2012) for the southeastern part of Tunisia showing a possible hydrocarbon migration path from W-2 and W-4 well locations (where the Silurian source rock is found to be in a late mature stage in this study, Figure 17) to the W-6 well locations. This is further supported by the fact that the W-6 well is producing light oil and condensate gas. It is most likely that this well was supplied by gas condensate from the late mature area located in the northern part of the Jeffara Basin, as identified in this study. Cross-plot BHT temperature correction proposed for the Jeffara Basin has been proven to be reasonably efficient. Its validity check was per- formed through the 1-D Jeffara Basin modeling and through comparisons of results using uncorrected temperatures, on one hand and proposed corrected data, on the other hand. Heat flow adjustments on corrected BHTs using the cross- plot method indicate that the northern part of the study area has higher heat flow ð 91 mW ∕ m 2 Þ than that obtained using uncorrected data ð 84 mW ∕ m 2 Þ , influencing thus the thermal maturity of the Silurian source rock. In the northern part of the study area (W-2 and W-4 wells), the Silurian source rock is in a late mature stage and has reached the gas window. This source rock generated liquid hydrocarbons and is currently producing gas and condensate. At the W-2 and W-4 wells, the Tannezuft (hot shale) have expelled oil and gas since the Late Cretaceous (51 mg/g TOC). The heat flow correction has influenced the maturity of the Silurian source rock, especially through the appearance of an area where the source rock is at a late mature stage, and also through an increase in the amounts of generated hydrocarbons, which are estimated to be five times higher than those obtained based on uncorrected data. In addition, the hydrocarbon expulsion at the W-2 and W-4 wells was significant and could have occurred even at a saturation expulsion threshold of 5%. The maturity results for the Tannezuft hot shales are not in complete agreement with the previously published maturity map of Ferjaoui et al. (2001) but concur with the study by Rezouga et al. ...
Context 3
... < R o < 0.88 to the north (W-1, W-2, W-3, and W-4 wells) and to the southwest (W-9, W-10, and W-11 wells). Using corrected heat flow data, the immature- early mature zone has less geographical extent as compared to the previous test. The Silurian hot shales are immature ( R o = 0.66%) around W-7 well ( Figure 17) and are mid-mature ð 0.7 % < R o < 0.88 % Þ in the northern part around W-1, W-3, W-5, and W-6 wells and in the southern parts around the W-8, W-9, W-10, and W-11 wells. To the north and within the area neighboring W-2 and W-4 wells, the Silurian hot shales are predicted to be within the gas window ð 1.15 < R o < 1.16 % Þ . This late mature level of thermal maturity was not reached when testing the uncorrected heat flow. Such difference will no doubt affect hydrocarbon generation and expulsion processes. Most wells, modeled in this study, show comparable results, so only a few wells will be used as examples to illustrate the timing of hydrocarbon generation and expulsion. Based on uncorrected heat flow data, hydrocarbon generation from the Silurian hot shales began at 421 and 206 Ma in the W-9 and W-6, respectively, and continues to the present day. In all wells, either gas or liquid hydrocarbons have been generated. Cumulative generated quantities range from 1.6 to 35.4 mg HC/g TOC. However, at a saturation expulsion threshold (Satex) of either 5% or 10%, the Tannezuft Formation source rock is found to be incapable of expelling hydrocarbons. The saturation expulsion threshold, expressed in percent of total porous volume of rock, is defined as the quantity of generated hydrocarbon beyond which any produced excess will be expelled from the source rock (Cooles et al., 1986; Mackenzie and Quigley, 1988). Based on corrected heat flow data, the hydrocarbon generation from the Silurian source rock started at 422 Ma in W-9 and 280 Ma in W-6. All wells have produced either oil or gas. Cumulative generated quantities range from 4 to 68 mg HC/g TOC. The source rock started expelling hydrocarbons only at the W-2 and the W-4 wells (Satex = 5% or 10%). In these wells, gas and liquid hydrocarbon expulsion is considered significant with a maximum during the Late Cretaceous for the W-4 well attaining 51 mg/g TOC at a Satex of 5% (Figure 18). These results were mapped to show the spatial distribution of hydrocarbon expulsion in the Jeffara Basin at a Satex of 10% (Figure 19) and where the area around wells W2 and W4 is very pronounced. The thermal and maturation history results of the Silurian source rock in the Jeffara Basin using corrected heat flow via corrected BHTs are different from those obtained by Ferjaoui et al. (2001). For instance, the maturity map generated in the present study (after heat flow correction) shows that the Silurian source rock is late mature in the northern part of the Jeffara Basin (Figure 17). Whereas, it has been reported to be at a mid-mature stage, at the same location based on Ferjaoui et al. ’ s study. In addition, results derived from this study in terms of thermal maturity of the Tannezuft Formation source rock are consistent with the geochemical findings concluded by Rezouga et al. (2012) for the southeastern part of Tunisia showing a possible hydrocarbon migration path from W-2 and W-4 well locations (where the Silurian source rock is found to be in a late mature stage in this study, Figure 17) to the W-6 well locations. This is further supported by the fact that the W-6 well is producing light oil and condensate gas. It is most likely that this well was supplied by gas condensate from the late mature area located in the northern part of the Jeffara Basin, as identified in this study. Cross-plot BHT temperature correction proposed for the Jeffara Basin has been proven to be reasonably efficient. Its validity check was per- formed through the 1-D Jeffara Basin modeling and through comparisons of results using uncorrected temperatures, on one hand and proposed corrected data, on the other hand. Heat flow adjustments on corrected BHTs using the cross- plot method indicate that the northern part of the study area has higher heat flow ð 91 mW ∕ m 2 Þ than that obtained using uncorrected data ð 84 mW ∕ m 2 Þ , influencing thus the thermal maturity of the Silurian source rock. In the northern part of the study area (W-2 and W-4 wells), the Silurian source rock is in a late mature stage and has reached the gas window. This source rock generated liquid hydrocarbons and is currently producing gas and condensate. At the W-2 and W-4 wells, the Tannezuft (hot shale) have expelled oil and gas since the Late Cretaceous (51 mg/g TOC). The heat flow correction has influenced the maturity of the Silurian source rock, especially through the appearance of an area where the source rock is at a late mature stage, and also through an increase in the amounts of generated hydrocarbons, which are estimated to be five times higher than those obtained based on uncorrected data. In addition, the hydrocarbon expulsion at the W-2 and W-4 wells was significant and could have occurred even at a saturation expulsion threshold of 5%. The maturity results for the Tannezuft hot shales are not in complete agreement with the previously published maturity map of Ferjaoui et al. (2001) but concur with the study by Rezouga et al. ...
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Citations
... It presents the amount of heat that could be transmitted from substratum to surface, and it is considered as a crucial parameter influencing geological processes (Prensky, 1992;Beardsmore and Cull, 2001). Changes in crustal composition, in radiogenic heat and in subsurface temperatures, imply changes in heat flow (Beardsmore and Cull, 2001;Hartmann et al., 2005;Fuchs and Förster, 2013;Homuth et al., 2014;Bouaziz et al., 2015;Bédard et al., 2016;Mraidi et al., 2019Mraidi et al., , 2021El Barbary et al., 2022). Hence, a good knowledge of the terrestrial heat is essential for understanding the lithospheric thermal pattern and in turn allows to ascertain various geological processes tightly related to temperature as for example source rocks maturities (Bouaziz et al., 2015;Mraidi et al., 2021;Fjeldskaar et al., 2009;Xin et al., 2011;Liu et al., 2016). ...
... Changes in crustal composition, in radiogenic heat and in subsurface temperatures, imply changes in heat flow (Beardsmore and Cull, 2001;Hartmann et al., 2005;Fuchs and Förster, 2013;Homuth et al., 2014;Bouaziz et al., 2015;Bédard et al., 2016;Mraidi et al., 2019Mraidi et al., , 2021El Barbary et al., 2022). Hence, a good knowledge of the terrestrial heat is essential for understanding the lithospheric thermal pattern and in turn allows to ascertain various geological processes tightly related to temperature as for example source rocks maturities (Bouaziz et al., 2015;Mraidi et al., 2021;Fjeldskaar et al., 2009;Xin et al., 2011;Liu et al., 2016). ...
... In Tunisia, previously published heat flow data (Ben Dhia, 1983, 1987a, 1987b, 1990Bouaziz et al., 2015) were only based on temperature correction. However, one research was attentive to the appraisal of thermal conductivity and its essential effect on heat flow distribution combined to borehole temperature corrections. ...
... Alternatively, it might stem from a chemical process involving the direct precipitation of CaCO3. Comparable findings have been reported in the Tunisian South East (as mentioned by Gargouri, 2011;Bouaziz et al., 2015;Lakhdar et al., 2021) and the Tunisian Sahel (Tagorti, 1990). ...
The current study was conducted within the context of the Holocene era in Sebkha El-Guettiate, located in southeastern Tunisia. The aim was to determine the factors influencing the geochemical and mineralogical composition of sediments and to elucidate the sedimentary characteristics of the Holocene within the Sebkha core. We examined a sediment core extending 100 cm from this Sebkha, subjecting it to comprehensive analysis to uncover its sedimentological, mineralogical, and geochemical properties. Several techniques were employed to strengthen and validate the connections between geochemical and mineralogical analyses, including X-ray diffraction (XRD), X-ray fluorescence (XRF), scanning electron microscopy (SEM), and infrared (IR) spectroscopy, among others. Furthermore, statistical analyses utilizing principal component analysis (PCA) were applied to the results of the geochemical and mineralogical studies, aiding in the identification of patterns and relationships. A comprehensive mineralogical assessment of the core’s sediments revealed the presence and interpretation of carbonate minerals, evaporite minerals, and detrital minerals. Through the application of infrared (IR) spectrometer techniques to all sediment samples, we gained insight into the mineralogical components and the distribution of key elements such as quartz, kaolinite, calcite, feldspar, and organic carbon. The geochemical composition demonstrated a clear dominance of silica (SiO2), accompanied by fluctuations in carbonate percentages (CaCO3). The prominent major elements, primarily magnesium (Mg) and calcium (Ca) originating from dolomitization, sodium (Na) and chlorine (Cl) from halite, and calcium (Ca) from gypsum, exhibited varying levels. Results from Rock–Eval 6 pyrolysis indicated that the organic matter within the sediments is generally a mixture of terrestrial and aquatic origins. This study provides practical information that underscores the diverse origins contributing to Sebkha sediment formation, often influenced by saline systems.
... In Tunisia, all previous works on thermal histories modeling of sedimentary basins were carried out with temperature-corrected data only (Yukler et al. 1994;Bouaziz et al. 2015;Mabrouk et al. 2015;Ben Dhia 1983, 1987a. Correction was usually carried out using approaches proposed by Waples and Ramly (2001) and Waples et al. (2004). ...
... Most of these approaches are not suitable for Tunisian basins because they are functional at specific depths and are characteristic of their original basin. A single study that looked at temperature correction by adopting a temperature correction method suitable for the southern Tunisian basin (Jeffara basin) was achieved by Bouaziz et al. (2015) followed by another study that looked at both temperature and thermal conductivity corrections for the Djeffra basin (southern Tunisia) and was proposed by the current authors in Mraidi et al. (2019). ...
... This method consists of a linear cross-plot (X-Y). It has been previously, successfully, applied locally by Bouaziz et al. (2015) (in the Djeffara basin) and worldwide by Naidu (1971), Waples and Ramly (Waples and Ramly 1994), Vedova et al. (2001), andCrowell et al. (2012). ...
Eighteen wells located in the western part of the Gulf of Hammamet were modelled using Basin Mod 1D software in order to reconstruct the thermal and burial histories of the Lower Fahdene and Bou Dabbous source rocks and estimate the residual oil left in source rocks after expulsion. For that, quantification of the generation and expulsion amounts of hydrocarbons were simulated after thorough depiction of thermal data, lithostratigraphic and geochemical data and also model calibration and heat flow reconstruction.
The Lower Fahdene and the Bou Dabbous source rocks were crossed by eight wells out of the 18 studied wells. The burial history of the two source rocks was strongly influenced by tectonic events and uplift phases which had a direct impact on their maturity and generation histories. Indeed, the maturity of the Lower Fahdene source rock is not homogeneous throughout the study area. It varies from a marginally immature stage (W-4) to a mid-mature stage (W6). The same applies to the Bou Dabbous Formation where the maturity varies between the immature stage (W-12) to the middle stage of the oil window (W-8).
The Lower Fahdene source rock generated oil and gas but expulsion occurred only in the W6 Well. The cumulative amounts of generated hydrocarbon from the Lower Fahdene are 175.94*106 m3, and the that from the Bou Dabbous are 1545.72*106 m3. Three wells expelled oil from the Bou Dabbous Formation.
Key words: Western Gulf of Hammamet, 1D modeling, Lower Fahdene, Bou Dabbous, Maturity modeling, Hydrocarbon volumes, generated HC, expelled HC, retained HC.
... Basin Mod™ 1D of Platte River Associates Inc. BASINMOD™, has been used (Soltani, 2014;Bouaziz et al., 2015;Mraidi et al., 2021) for burial and maturity history modelling of source rocks and for assessment of hydrocarbon generation and expulsion in a pseudo well of the Kairouan basin. ...
... These authors argued that abnormal thermal heat related to volcanic activity had occurred during and after Albian and Cenomanian-Turonian source rock deposits. Althouh, in BasinMod modelling, volcanic activity cannot be incorporated in the software but it is indirectly appraised through Borehole Temperatures (BHT) after corrections (Chulli et al., 2002;Bouaziz et al., 2015;Mraidi et al., 2021), which is used for heat flow reconstruction. The effect of any additional heat is therefore recorded and can be seen through source rock maturation and its critical moment if any. ...
The eastern Tunisian margin is considered an Upper Cretaceous and Eocene petroleum province. It has been affected by Mesozoic rifting and Cenozoic compression. Several oil and gas shows and accumulations have been discovered in Upper Cretaceous carbonates within structural anticlinal closures. These anticlinal highs represent inherited rift platform horsts with hiatuses, unconformities and sediment erosion. Seismic sequence stratigraphy and seismic tectonic analyses of Mesozoic and Cenozoic horizons, delineate the control of deep-rooted transtensional and transpressional Flower structure fault corridors, intruded by Upper Triassic salt. Petroleum system modelling and time events chart reconstruction of real and pseudo-wells, indicate that Cretaceous source rocks maturation and hydrocarbon generation began during Late Cretaceous with expulsion occurring from Eocene to Pliocene times. Hence, Upper Cretaceous petroleum system dynamics is intimately linked to basin geodynamics; where hydrocarbon migration pathways could follow the migration, rotation and tilting of platform and basin blocks. The volume of Lower Fahden and Bahloul source rocks expelled hydrocarbons from the basin kitchens, is much greater than that found in the drilled anticlinal axis. These hydrocarbons could have been trapped along the platform-basin border flanks and may not have reached the highest position on the anticlinal crest closure. Such pathways explain the unaccounted-for hydrocarbon volumes. These volumes could be trapped along the faults seal branches, unconformities, pinchouts as well as in the evidenced progradational and reefal system tracts sequences in the flank borders of the platforms. These traps could represent new exploration targets as potential structural and stratigraphic plays.
... The tectonic subsidence in the Jeffara basin was seemly associated to the Mesozoic episodes of rifting occurred in passive margin conditions. However, it was aborted by an E-W compressive event related to the collision of European and African plates during Aptian-Albian times (Bouaziz et al., 2002(Bouaziz et al., , 2015Patriat et al., 2003). This compressional tectonic engendered some reverse slips of several ancient normal faults in the Jeffara basin and the inversion of the subsiding Ezzaouia-El Bibane areas (Touati et al., 1998) with partial erosion of Lower Cretaceous levels within uplifted blocks (Touati et al., 1998). ...
The Jeffara basin in Southeastern Tunisia is a part of a wide Jurassic-Cretaceous petroleum system extending from the Saharan platform to the Pelagian province in eastern Tunisia and northwestern Tripolitania. In this petroleum province, El Bibane and Ezzaouia offshore fields were discovered in 1982–1986 as NE-SW folded structural traps. Their present-day accumulations are stuck within the Cenomanian carbonates of the Zebbag Formation and the Kimmeridgian marine clastic sequence of the Mrabtine Member respectively. The tectono-thermal evolution and the burial history modelling of the source rocks using wells and gravity data allowed us to identify the relationship between the deep crustal structure of the Jeffara basin and the evolution of its petroleum systems. The gravity data analysis using inversion method shows that the Jeffara basin is associated with a regional major NW–SE positive gravity anomaly related to about 5 km crustal thinning from west to East. This crustal thinning setting have locally controlled the burial histories of Ezzaouia and El Bibane oil fields.
... The Paleozoic basins described by early tectonic events have been altered, leading to the development of several intracratonic and foreland basins (Aliev et al., 1971;Van de Weerd and Ware, 1994;Boote et al., 1998). From a petroleum system point of view, the major Ordovician melting favoured the prevailing of anoxic conditions during the Early Silurian and subsequently the deposition of one of the most important Paleozoic source rocks named the Tannezuft Formation (Wennekers et al., 1996;Guiraud et al., 2005;Vecoli et al., 2009;Bouaziz et al., 2015;Gambacorta et al., 2016;Echikh, 1998). Contrarywise, the Upper Silurian is marked by a relative shallowing-up witnessed by fluvial estuarine and deltaic deposits materialized by the uppermost part of the Tannezuft Formation and the Acacus Formation which bear significant reservoir potential. ...
Abstract:
Upper Silurian sediments of the uppermost Tannezuft Formation and the overlying Acacus A Unit in the Ghadames Basin of southern Tunisia are considered as an important oil and gas target. For that, four wells, spanning these reservoirs, are evaluated herein. The study uses well logging tools via the Interactive Petrophysics (IP) software to determine hydrocarbon bearing layers. A static model is also inferred.
The studied interval shows twenty-four sand bodies associated to the four petrophysical packages (T0 to T3) of the Uppermost Tannezuft and the nine petrophysical packages of the Acacus A (A1 to A9). Sand bodies show variable thicknesses (from 1.5 to 38m) and are laterally correlated following a North-West (NW) to South-East (SE) trend. They are composed of stacked thin bedded alternating sands and shales. The petrophysical packages A5 (A5-1 and A5a-2) and A9 (A9a and A9b) of the Acacus A are identified as the most interesting layers.
The computed petrophysical parameters of the sand bodies reveal a clay volume ranging between 8% and 29% with an average of 22%. The effective porosity ranges from 10% to 29%. Relatively high-water saturation is depicted in most sand bodies reaching up to 63%. In addition, and due to the complex matrix composition, relatively low permeabilities characterize reservoirs zones (an average of 20mD). The integration of all data using the IP software reveals significant accumulations of gas condensates. The volumetric assessment via static modeling using the Petrel software indicates that the A9b unit is, predominantly, the most prolific reservoir.
... This was confirmed through the variation of geothermal flux, identified in the region compared to the average geothermal gradient. In fact, the distribution of the geothermal flux in terms of "heat-flow density" (HFD) at the level of the Mediterranean basin and, in particular, at the southern segment of the Geotraverse (EGT-S) campaign, shows a heat flux anomaly superior than 100 MW/m 2 in the Jeffara region (Bouaziz et al., 2015;Gabtni, 2006;Mraidi et al., 2021;Fig. 12 (C)). ...
Permian rock samples from four wells drilled in the Jeffara (J1 and J2) and Dahar (D1 and D2) areas of southern Tunisia were evaluated using the Rock-Eval® Shale Play™ method. Quantification of most liquid hydrocarbon compound families released at specific temperature range for the Sh0 and Sh1 as well as Sh2 and S3 parameters was achieved with subsequent calculations of appropriate indices. In addition, stable carbon isotopes evaluation of Permian samples was carried out in order to estimate the origin of their fossilized organic matter. Biomarker analyses were also undertaken on Permian samples and other proven Paleozoic source rocks samples of the study area (Ordovician Azzel and Upper Silurian Fegaguira formations) for comparison purposes.
The results show that the Permian series encompass highly-rich organic matter intervals which may exceed 5%. The organic matter is of type II2-III, proven either by the Rock-Eval®, carbon isotopes and biomarker data. Permian samples from three wells (D1, D2, and J2) are found mostly at an early mature stage. Contrary, Permian samples from the J1 Well show abnormal Tmax temperatures testifying an overmature stage which could be related to abnormal heat flow around the Jeffara area. The depositional environment of the organic matter-rich Permian intervals is mainly suboxic of normal salinity, similar to the other Paleozoic investigated source rocks in the study area. Overall, this research comes to validate the occurrence within the Dahar and Jeffara areas of an active Permian oil/gas prone source rock, competitive to the other proven Paleozoic source rocks.
... Source rocks are the material basis for the formation of large and medium-sized oil and gas fields [1][2][3], since the discovery of oil and natural gas, source rock evaluation has always been an important work for geologists and geochemists and explorers to analyze the prospects of oil and gas exploration in basins or zones. Oil and gas resources related to lacustrine deposition account for more than 20% of the total resources. ...
In the Paleogene Shahejie Formation of Liaodong Bay Depression, two sets of main source rocks are developed, namely the Es 1 and the Es 3 Formation. In order to determine the characteristics, main controlling factors and patterns of source rock development, firstly, we comprehensively use source rock geochemical and logging data to establish TOC logging prediction models for source rocks in two formations; secondly, we predict the TOC plane distribution of the two layers separately according to the prediction model; then, we use the tectonic subsidence history and sedimentary background data of the study area to analyze its relationship with the source rock development and determine the main controlling factors for the source rock development; finally, the source rock deposition models are established according to the main controlling factors of source rock development. The results show the source rock of the Es 1 has high abundance of organic matter, the average TOC of the sample is as high as 2.41%, but the thickness of the source rock does not exceed 130 m; the abundance of source rocks in the Es3 is slightly worse than that of the Es1, the average TOC of the samples is 1.75%, the thickness of source rocks is generally larger, mainly 200-350 m; the rate of tectonic subsidence controls the thickness of the source rock, the amount of fracture extension controls the distribution shape of the source rock, and the degree of water stratification controls the degree of source rock enrichment; in the Es 1 Formation, the source rock deposition model is the deposition model of the salinity layered water body in the saline lake basin; in the Es3 Formation, the source rock deposition model is the deposition model of deep water temperature stratification in the separated lake basin. To determine the main controlling factors and depositional patterns of source rock development provides a direction for subsequent exploration of favorable areas.
... In Tunisia, all previous works on thermal histories modeling of sedimentary basins were carried out with temperature-corrected data only (Yukler et al. 1994;Bouaziz et al. 2015;Mabrouk et al. 2015;Ben Dhia 1983, 1987a. Correction was usually carried out using approaches proposed by Waples and Ramly (2001) and Waples et al. (2004). ...
... Most of these approaches are not suitable for Tunisian basins because they are functional at specific depths and are characteristic of their original basin. A single study that looked at temperature correction by adopting a temperature correction method suitable for the southern Tunisian basin (Jeffara basin) was achieved by Bouaziz et al. (2015) followed by another study that looked at both temperature and thermal conductivity corrections for the Djeffra basin (southern Tunisia) and was proposed by the current authors in Mraidi et al. (2019). ...
... This method consists of a linear cross-plot (X-Y). It has been previously, successfully, applied locally by Bouaziz et al. (2015) (in the Djeffara basin) and worldwide by Naidu (1971), Waples and Ramly (Waples and Ramly 1994), Vedova et al. (2001), andCrowell et al. (2012). ...
Abstract
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.
Keywords: Gulf of Gabes . Bottomhole temperature (BHT) . Drill stem test (DST) . Thermal conductivity . Albian source rock .
Heat flow
... The most common mean of correction is the Horner Plot. As this approach is only functional at specific conditions mostly not suitable for the Tunisian basins, the corrected geothermal gradient was estimated using temperature corrections as proposed by Bouaziz et al. [2]: where BHTc: corrected BHT, BHTuc: uncorrected BHT. Temperature at the ground surface is the other element needed for computing the average vertical thermal gradient for each studied well. ...
The heat flow (Q) of a sedimentary level depends on two basic parameters which are: temperature and thermal conductivity. However, so far in Tunisia, heat flow estimations are usually carried out based on temperature corrections only. This study tries to emphasize the effect of thermal conductivity variations on the thermal history of the Djeffara Basin, through the evaluation of its conductivity change following a high-resolution appraisal (5 m margin). The thermal flow, determined by the Fourier and the Bullard Plot methods, was estimated using the temperature corrections equation combined with the conductivity corrections based on porosity data. Consequently, we believe that a better reconstruction of the regional distribution of the thermal flow of the region in relation to its geodynamic evolution was achieved. The most realistic scenario compared to the geologic model shows an average heat flow equal to 82 mW/m², which is higher than the global average of about 64 mW/m².
