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Fig. 13. Correlation of the early Silurian shift between Gamma ray and TOC

Figure 13 Correlation of the early Silurian shift between Gamma ray and TOC

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E-mail address: elmohology@yahoo.fr © 2014 Elsevier Ltd. All rights reserved. During these last years, considerable attention has been given to unconventional oil and gas shale in northern Africa where the most productive Paleozoic basins are located (e.g. Berkine, Illizi, Kufra, Murzuk, Tindouf, Ahnet, Oued Mya, Mouydir, etc.). In most petroleum systems, which characterize these basins, the Silurian played the main role in hydrocarbon generation with two main ‘hot’ shale levels distributed in different locations (basins) and their deposition was restricted to the Rhuddanian (Lllandovery: early Silurian) and the Ludlow-Pridoli (late Silurian). A third major hot shale level had been identified in the Frasnian (Upper Devonian). Southern Tunisia is characterized by three main Paleozoic sedimentary basins, which are from North to South, the southern Chotts, Jeffara and Berkine Basin. They are separated by a major roughly E-W trending lower Paleozoic structural high, which encompass the Mehrez-Oued Hamous uplift to the West (Algeria) and the Nefusa uplift to the East (Libya), passing by the Toug- gourt-Talemzane-PGA-Bou Namcha (TTPB) structure close to southern Tunisia. The forementioned major source rocks in southern Tunisia are defined by hot shales with elevated Gamma ray values often exceed- ing 1400 API (in Hayatt-1 well), deposited in deep water environments during short lived (c. 2 Ma) peri- ods of anoxia. In the course of this review, thickness, distribution and maturity maps have been established for each hot shale level using data for more than 70 wells located in both Tunisia and Algeria. Mineralogical modeling was achieved using Spectral Gamma Ray data (U, Th, K), SopectroLith logs (to acquire data for Fe, Si and Ti) and Elemental Capture Spectroscopy (ECS). The latter technique provided data for quartz, pyrite, carbonate, clay and Sulfur. In addition to this, the Gamma Ray (GR), Neutron Porosity (®y), deep Resistivity (R,) and Bulk Density (p,) logs were used to model bulk mineralogy and lithology. Biostratigraphic and complete geochemical review has been undertaken from published papers and unpublished internal reports to better assess these important source intervals.
E-mail address: elmohology@yahoo.fr © 2014 Elsevier Ltd. All rights reserved. During these last years, considerable attention has been given to unconventional oil and gas shale in northern Africa where the most productive Paleozoic basins are located (e.g. Berkine, Illizi, Kufra, Murzuk, Tindouf, Ahnet, Oued Mya, Mouydir, etc.). In most petroleum systems, which characterize these basins, the Silurian played the main role in hydrocarbon generation with two main ‘hot’ shale levels distributed in different locations (basins) and their deposition was restricted to the Rhuddanian (Lllandovery: early Silurian) and the Ludlow-Pridoli (late Silurian). A third major hot shale level had been identified in the Frasnian (Upper Devonian). Southern Tunisia is characterized by three main Paleozoic sedimentary basins, which are from North to South, the southern Chotts, Jeffara and Berkine Basin. They are separated by a major roughly E-W trending lower Paleozoic structural high, which encompass the Mehrez-Oued Hamous uplift to the West (Algeria) and the Nefusa uplift to the East (Libya), passing by the Toug- gourt-Talemzane-PGA-Bou Namcha (TTPB) structure close to southern Tunisia. The forementioned major source rocks in southern Tunisia are defined by hot shales with elevated Gamma ray values often exceed- ing 1400 API (in Hayatt-1 well), deposited in deep water environments during short lived (c. 2 Ma) peri- ods of anoxia. In the course of this review, thickness, distribution and maturity maps have been established for each hot shale level using data for more than 70 wells located in both Tunisia and Algeria. Mineralogical modeling was achieved using Spectral Gamma Ray data (U, Th, K), SopectroLith logs (to acquire data for Fe, Si and Ti) and Elemental Capture Spectroscopy (ECS). The latter technique provided data for quartz, pyrite, carbonate, clay and Sulfur. In addition to this, the Gamma Ray (GR), Neutron Porosity (®y), deep Resistivity (R,) and Bulk Density (p,) logs were used to model bulk mineralogy and lithology. Biostratigraphic and complete geochemical review has been undertaken from published papers and unpublished internal reports to better assess these important source intervals.
Fig. 1. Global Risked Gas In-Place of Shale Gas Resources (TCF). Southern Tunisia is characterized by three main basins (Fig. 2) in, which the Berkine Basin bears Risked Gas In- Place about 61Tcf and technically recoverable resource about 18Tcf.
Fig. 1. Global Risked Gas In-Place of Shale Gas Resources (TCF). Southern Tunisia is characterized by three main basins (Fig. 2) in, which the Berkine Basin bears Risked Gas In- Place about 61Tcf and technically recoverable resource about 18Tcf.
Fig. 2. The three main sedimentary basins characterizing the southern Tunisia: southern Chotts, Jeffara and Berkine basins.
Fig. 2. The three main sedimentary basins characterizing the southern Tunisia: southern Chotts, Jeffara and Berkine basins.
Fig. 3. Hercynian subcrop map of the Ghadames Basin (Soua, 2012a and reference therein): Paleozoic geology and main structural features, 1. Precambrian, 2. Cambrian, 3. Ordovician, 4. Early Silurian, 5. Ludlow-Pidoli-Geddinian, 6. Late Silurian, 7. Devonian, 8. Carboniferous, 9. Permian, 10. structural paleohigh, 11. subbasin.
Fig. 3. Hercynian subcrop map of the Ghadames Basin (Soua, 2012a and reference therein): Paleozoic geology and main structural features, 1. Precambrian, 2. Cambrian, 3. Ordovician, 4. Early Silurian, 5. Ludlow-Pidoli-Geddinian, 6. Late Silurian, 7. Devonian, 8. Carboniferous, 9. Permian, 10. structural paleohigh, 11. subbasin.
Fig. 4. Four differently oriented geoseismic cross sections showing the main structural styles affecting the Berkine and Jeffara Basins: (1) SW-NNE cross section passing from southern Algeria through the Jeffara Basin; (2) N-S to E-W cross section passing from Algeria through southern Tunisia and Western Libya; (3) NW-SE to E-W Cross section from Algeria to Libya and (4) N-S cross section from southern Libya to Jeffara Basin.
Fig. 4. Four differently oriented geoseismic cross sections showing the main structural styles affecting the Berkine and Jeffara Basins: (1) SW-NNE cross section passing from southern Algeria through the Jeffara Basin; (2) N-S to E-W cross section passing from Algeria through southern Tunisia and Western Libya; (3) NW-SE to E-W Cross section from Algeria to Libya and (4) N-S cross section from southern Libya to Jeffara Basin.
Fig. 5. Simplified lithostratigraphic correlation of the Paleozoic of southern Tunisia and neighboring countries (modified and updated from Craig et al., 2008). Intention is given for the three studied sedimentary basins of southern Tunisia (southern Chotts, Jeffara and Berkine) and distribution of the three hot shale units (Rhuddanian, Ludlow- Pridoli and Frasnian Hot shales) through these basins.
Fig. 5. Simplified lithostratigraphic correlation of the Paleozoic of southern Tunisia and neighboring countries (modified and updated from Craig et al., 2008). Intention is given for the three studied sedimentary basins of southern Tunisia (southern Chotts, Jeffara and Berkine) and distribution of the three hot shale units (Rhuddanian, Ludlow- Pridoli and Frasnian Hot shales) through these basins.
Fig. 6. Main sedimentary basins characterizing the Northern African margin (modified from Liining et al., 2000a; Craig et al., 2008),
Fig. 6. Main sedimentary basins characterizing the Northern African margin (modified from Liining et al., 2000a; Craig et al., 2008),
Fig. 7. E-W (Algeria) and N-S (southern Tunisia) composite cross-section showing different lithostratigraphic relationship and structural styles characterizing the Berkine and southern Chotts basins.
Fig. 7. E-W (Algeria) and N-S (southern Tunisia) composite cross-section showing different lithostratigraphic relationship and structural styles characterizing the Berkine and southern Chotts basins.
Fig. 8. Different stage nomenclature used for the Ordovician through Devonian plotted against the global eustatic curve during these key periods. General sea-level change coastal onlaps and sequence terminology are compiled from Hardenbol et al. (1998), Haq and Al-Qahtani (2005), Haq and Shutter (2008) and Snedden and Liu (2010). The Ordovician glaciation and eustatic curve data are provided from Loydell (1998), Nielsen (2004) and Achab and Paris (2007).
Fig. 8. Different stage nomenclature used for the Ordovician through Devonian plotted against the global eustatic curve during these key periods. General sea-level change coastal onlaps and sequence terminology are compiled from Hardenbol et al. (1998), Haq and Al-Qahtani (2005), Haq and Shutter (2008) and Snedden and Liu (2010). The Ordovician glaciation and eustatic curve data are provided from Loydell (1998), Nielsen (2004) and Achab and Paris (2007).
Fig. 9. Thickness map of the early Silurian (Rhuddanian Hot shale unit).
Fig. 9. Thickness map of the early Silurian (Rhuddanian Hot shale unit).
Fig. 10. Lithostratigraphic description of the Rhuddanian Hot shale level from El Borma-407(Soua, 2009a): (1) general aspect of the organic-rich Rhuddanian Hot shale unit; (2) pyrite framboids; (3) iron concretion; (4) different pyrite framboid sizes distribution; (5) quartz and (6) Graptolites, quartz and iron concretion.
Fig. 10. Lithostratigraphic description of the Rhuddanian Hot shale level from El Borma-407(Soua, 2009a): (1) general aspect of the organic-rich Rhuddanian Hot shale unit; (2) pyrite framboids; (3) iron concretion; (4) different pyrite framboid sizes distribution; (5) quartz and (6) Graptolites, quartz and iron concretion.
Fig. 11. Early Silurian Argiles principales Formation and its equivalents distribution and facies in Algeria, Tunisia and Libya (modified after Craig et al., 2008).
Fig. 11. Early Silurian Argiles principales Formation and its equivalents distribution and facies in Algeria, Tunisia and Libya (modified after Craig et al., 2008).
Fig. 12. Distribution of the Gamma ray and TOC (inferred from well logging tools) of four different wells: LASE-1, CEM-1, HYT-1 and SET-1 (after Rezouga et al., 2012a).
Fig. 12. Distribution of the Gamma ray and TOC (inferred from well logging tools) of four different wells: LASE-1, CEM-1, HYT-1 and SET-1 (after Rezouga et al., 2012a).
Fig. 14. Mean Uranium enrichment factor [EF(U)] and Gamma ray distributions (A) EF(U) distribution map, maximum values are interpreted as maximum redox conditions (B) Gamma ray distribution.
Fig. 14. Mean Uranium enrichment factor [EF(U)] and Gamma ray distributions (A) EF(U) distribution map, maximum values are interpreted as maximum redox conditions (B) Gamma ray distribution.
Fig. 15. Early Silurian (Rhuddanian Hot Shale) organic carbon distributions (%TOC) (data compiled after Ghenima, 1993; Daniels and Emme, 1995; Macgregor, 1998; Boote et al., 1998; Echikh, 1998; Saidi et al., 1998).
Fig. 15. Early Silurian (Rhuddanian Hot Shale) organic carbon distributions (%TOC) (data compiled after Ghenima, 1993; Daniels and Emme, 1995; Macgregor, 1998; Boote et al., 1998; Echikh, 1998; Saidi et al., 1998).
Fig. 16. Early Silurian Argiles principales Formation composite section. Gamma ray and TOC are from OZ-1 well (Soua, 2009a), biostratigraphy is taken from Lg-3, ST-1 and Tt- 1 (Bonnefous, 1963; Jaeger et al., 1975 and Vecoli et al., 2009) and the 3 Coie curve is from the Tt-1 well (Vecoli et al., 2009). (See above-mentioned references for further information.)
Fig. 16. Early Silurian Argiles principales Formation composite section. Gamma ray and TOC are from OZ-1 well (Soua, 2009a), biostratigraphy is taken from Lg-3, ST-1 and Tt- 1 (Bonnefous, 1963; Jaeger et al., 1975 and Vecoli et al., 2009) and the 3 Coie curve is from the Tt-1 well (Vecoli et al., 2009). (See above-mentioned references for further information.)
Fig. 18. Spectral gamma-ray log of the organic-rich early Silurian Argiles Principales Formation in well HWA-1 (Berkine Basin) (Fig. 2, for location). Generally speaking, th Hot shale interval is enriched in uranium, with maximum concentrations of 116 ppm, whereas thorium and potassium values remain rather constant. CGR is compute gamma-ray (Th and K radiation), SGR = spectral gamma-ray. Fig. 17. Spectral gamma-ray log of the organic-rich early Silurian Argiles Principales Formation in well HYT-1 (Berkine Basin) (Fig. 2, for location). Generally speaking, the Hot shale interval is enriched in uranium, with maximum concentrations of 154 ppm, whereas thorium and potassium values remain rather constant. CGR is computed gamma- ray (Th and K radiation), SGR = spectral gamma-ray.
Fig. 18. Spectral gamma-ray log of the organic-rich early Silurian Argiles Principales Formation in well HWA-1 (Berkine Basin) (Fig. 2, for location). Generally speaking, th Hot shale interval is enriched in uranium, with maximum concentrations of 116 ppm, whereas thorium and potassium values remain rather constant. CGR is compute gamma-ray (Th and K radiation), SGR = spectral gamma-ray. Fig. 17. Spectral gamma-ray log of the organic-rich early Silurian Argiles Principales Formation in well HYT-1 (Berkine Basin) (Fig. 2, for location). Generally speaking, the Hot shale interval is enriched in uranium, with maximum concentrations of 154 ppm, whereas thorium and potassium values remain rather constant. CGR is computed gamma- ray (Th and K radiation), SGR = spectral gamma-ray.
Fig. 19. SpectroLith logging and Elemental Capture Spectroscopy (ECS) providing Quartz, Pyrite, Carbonate and Clay contents as well as major elements (e.g. Al, Fe, Si, K, Ti) for the early Silurian Hot shale interval in the HYT-1 well.
Fig. 19. SpectroLith logging and Elemental Capture Spectroscopy (ECS) providing Quartz, Pyrite, Carbonate and Clay contents as well as major elements (e.g. Al, Fe, Si, K, Ti) for the early Silurian Hot shale interval in the HYT-1 well.
Main fractions and their relative proxies. Table 2 synthesis). Lyons et al. (2003) proposed that presence of relatively important syngenetic pyrite amount could therefore explain enrichment in iron such recorded in these Hot shales and reported earlier from different core or well description (e.g., Jaeger et al., 1975; Massa, 1985; Chandoul, 1989; Ben Ferjani et al., 1990; Lining et al., 2000a; Soua, 2009a; Rezouga et al., 2012a). It is assumed that reactions of bacterial sulfate-reduction, which are mandatory for the formation of pyrite (Riquier et al., 2005) gener- ate sulfide ions (HS~) that combine with reactive iron (Berner, 1984). Sedimentary pyrite forms often a metastable FeS (Riquier et al., 2005), which react therefore with oxidized intermediate sul- fur species and transform consequently into a stable form of Fe2S
Main fractions and their relative proxies. Table 2 synthesis). Lyons et al. (2003) proposed that presence of relatively important syngenetic pyrite amount could therefore explain enrichment in iron such recorded in these Hot shales and reported earlier from different core or well description (e.g., Jaeger et al., 1975; Massa, 1985; Chandoul, 1989; Ben Ferjani et al., 1990; Lining et al., 2000a; Soua, 2009a; Rezouga et al., 2012a). It is assumed that reactions of bacterial sulfate-reduction, which are mandatory for the formation of pyrite (Riquier et al., 2005) gener- ate sulfide ions (HS~) that combine with reactive iron (Berner, 1984). Sedimentary pyrite forms often a metastable FeS (Riquier et al., 2005), which react therefore with oxidized intermediate sul- fur species and transform consequently into a stable form of Fe2S
Thickness, organic-richness (TOC), Tmax, relative vitrinite reflectance and source type of the early Silurian Hot shale from selected wells (data compiled from Rezouga et al., 2012a). Relative Vitrinite reflectance (Ro%) is calculated as demonstrated by Jarvie et al. (2007); see Eq. (3).
Thickness, organic-richness (TOC), Tmax, relative vitrinite reflectance and source type of the early Silurian Hot shale from selected wells (data compiled from Rezouga et al., 2012a). Relative Vitrinite reflectance (Ro%) is calculated as demonstrated by Jarvie et al. (2007); see Eq. (3).
Major and trace elements normalized to Al and mineralogical composition of the early Silurian Hot shale from Cherouq-1; Hayatt-1 and Hawa-1. (Rickard, 1975; Wilkin and Barnes, 1996; Bond et al., 2004). Pres- ence of the sulfur species (S) may be provided by H2S, which is gen- erally available in or near the redox boundary by several species such as Oz, NO?~, MnO>, FeOOH, which is believed to be an elemen- tary intervention for the formation of pyrite (Middelburg, 1991; Suits and Arthur, 2000; Riquier et al., 2005). Several authors admit that pyrite forms in the redox boundary as well as in euxinic set- tings of water column (Calvert and Karlin, 1991; Middelburg, 1991; Riquier et al., 2005). Pyrite framboid size is also important in detecting redox boundary and euxinic conditions (Bond et al.,
Major and trace elements normalized to Al and mineralogical composition of the early Silurian Hot shale from Cherouq-1; Hayatt-1 and Hawa-1. (Rickard, 1975; Wilkin and Barnes, 1996; Bond et al., 2004). Pres- ence of the sulfur species (S) may be provided by H2S, which is gen- erally available in or near the redox boundary by several species such as Oz, NO?~, MnO>, FeOOH, which is believed to be an elemen- tary intervention for the formation of pyrite (Middelburg, 1991; Suits and Arthur, 2000; Riquier et al., 2005). Several authors admit that pyrite forms in the redox boundary as well as in euxinic set- tings of water column (Calvert and Karlin, 1991; Middelburg, 1991; Riquier et al., 2005). Pyrite framboid size is also important in detecting redox boundary and euxinic conditions (Bond et al.,
Fig. 20. Maturity Contour map of the early Silurian Hot shale level (Ro%). Vitrinite reflectance has been converted from T,,3x values.
Fig. 20. Maturity Contour map of the early Silurian Hot shale level (Ro%). Vitrinite reflectance has been converted from T,,3x values.
Fig. 21. Thickness map of the Frasnian Hot shale level.
Fig. 21. Thickness map of the Frasnian Hot shale level.
Fig. 22. Depth map of the Frasnian Hot shale level.
Fig. 22. Depth map of the Frasnian Hot shale level.
Fig. 23. Maturity Contour map of the Frasnian Hot shale level (Ro%).
Fig. 23. Maturity Contour map of the Frasnian Hot shale level (Ro%).
Fig. 24. Well correlation of the Frasnian in the southern Tunisia (HZ-1, EC-2, RR-1, CS-1 and SET-1). The Frasnian shales exhibit two different Hot shale levels winferred fron the increased gamma-ray values. The gamma-ray cutoff line represents 125 API in wells with a shale baseline of 80-90 API.
Fig. 24. Well correlation of the Frasnian in the southern Tunisia (HZ-1, EC-2, RR-1, CS-1 and SET-1). The Frasnian shales exhibit two different Hot shale levels winferred fron the increased gamma-ray values. The gamma-ray cutoff line represents 125 API in wells with a shale baseline of 80-90 API.
Fig. 25. Biostratigraphic correlations of the Frasnian Hot shales in the EC-1 and EC-2 wells (data are compiled from Realini et al., 1970)
Fig. 25. Biostratigraphic correlations of the Frasnian Hot shales in the EC-1 and EC-2 wells (data are compiled from Realini et al., 1970)
Fig. 26. Spectral gamma-ray log of the organic-rich early Silurian Argiles Principales Formation in well HYT-1 (Berkine Basin) (Fig. 2, for location). Generally speaking, the Frasnian Hot shale intervals are enriched in uranium, with maximum concentrations near 35 ppm, whereas thorium and potassium values remain rather constant. CGR is computed gamma-ray (Th and K radiation), SGR = spectral gamma-ray.
Fig. 26. Spectral gamma-ray log of the organic-rich early Silurian Argiles Principales Formation in well HYT-1 (Berkine Basin) (Fig. 2, for location). Generally speaking, the Frasnian Hot shale intervals are enriched in uranium, with maximum concentrations near 35 ppm, whereas thorium and potassium values remain rather constant. CGR is computed gamma-ray (Th and K radiation), SGR = spectral gamma-ray.
Fig. 28. Frasnian Hot Shales organic carbon distributions (%TOC) (data compiled after Ghenima, 1993; Daniels and Emme, 1995; Macgregor, 1998; Boote et al., 1998; Echikh, 1998; Saidi et al., 1998). Fig. 27. Gamma ray, total organic carbon and mineralogy (quartz, chlorite and illite) vertical distribution in the EC-2 well (Soua, 2009a)
Fig. 28. Frasnian Hot Shales organic carbon distributions (%TOC) (data compiled after Ghenima, 1993; Daniels and Emme, 1995; Macgregor, 1998; Boote et al., 1998; Echikh, 1998; Saidi et al., 1998). Fig. 27. Gamma ray, total organic carbon and mineralogy (quartz, chlorite and illite) vertical distribution in the EC-2 well (Soua, 2009a)
Thickness, organic-richness (TOC), Tmax, relative vitrinite reflectance and source type of the Frasnian Hot shale from selected wells.
Thickness, organic-richness (TOC), Tmax, relative vitrinite reflectance and source type of the Frasnian Hot shale from selected wells.
The higher molecular weight n-alkanes reveal a wide range of normal alkanes extending from nCz9 to nC39. The moderate molec- ular weight n-alkanes and acyclic isoprenoids such as pristine and phytane occur also in low concentrations in the Frasnian black shales displaying a smooth homologous series within the higher molecular weight n-alkane. This may suggest a significant input of higher land plant organic matter into these sediments. The
The higher molecular weight n-alkanes reveal a wide range of normal alkanes extending from nCz9 to nC39. The moderate molec- ular weight n-alkanes and acyclic isoprenoids such as pristine and phytane occur also in low concentrations in the Frasnian black shales displaying a smooth homologous series within the higher molecular weight n-alkane. This may suggest a significant input of higher land plant organic matter into these sediments. The
Major and trace elements normalized and mineralogical composition of the Frasnian Hot shale from Hayatt-1.
Major and trace elements normalized and mineralogical composition of the Frasnian Hot shale from Hayatt-1.
Fig. 30. Ludlow-Pridoli organic rich (Hot) shales distribution in southern Tunisia and neighboring countries (data compiled after Legrand, 1962; Heybroek, 1963; Balducchi and Pommier, 1970; Berry and Boucot, 1973; Legrand, 1985; Kriz, 2008; Belhaj and Saidi, 2010; Rezouga et al., 2012b). Using well-logging techniques (ECS, SpectroLith, SGR, Resistiv- ity, Sonic, etc.) as specified for the early Silurian, the Frasnian Hot shales unit is shown to yield higher proportion of quartz than in the early Silurian with slight predominance over clay minerals, which are represented by illite, and chlorite without recording kao- linite (Fig. 27). This predominance is not always evident from lat- eral distribution point of view, where ammonoid shaly facies is recorded near the Algerian side (Realini et al., 1970). Pyrite, feld- spars and carbonates are also described from Frasnian Hot Shales unit (Ghenima, 1993). The mineral composition of the Frasnian Hot shales inferred from the spectroLith logging and ECS tool from the Hayatt-1 well is shown in the Fig. 29. Four main events in the
Fig. 30. Ludlow-Pridoli organic rich (Hot) shales distribution in southern Tunisia and neighboring countries (data compiled after Legrand, 1962; Heybroek, 1963; Balducchi and Pommier, 1970; Berry and Boucot, 1973; Legrand, 1985; Kriz, 2008; Belhaj and Saidi, 2010; Rezouga et al., 2012b). Using well-logging techniques (ECS, SpectroLith, SGR, Resistiv- ity, Sonic, etc.) as specified for the early Silurian, the Frasnian Hot shales unit is shown to yield higher proportion of quartz than in the early Silurian with slight predominance over clay minerals, which are represented by illite, and chlorite without recording kao- linite (Fig. 27). This predominance is not always evident from lat- eral distribution point of view, where ammonoid shaly facies is recorded near the Algerian side (Realini et al., 1970). Pyrite, feld- spars and carbonates are also described from Frasnian Hot Shales unit (Ghenima, 1993). The mineral composition of the Frasnian Hot shales inferred from the spectroLith logging and ECS tool from the Hayatt-1 well is shown in the Fig. 29. Four main events in the
Fig. 31. E-W geoseismic cross section within the southern Chotts Basin and southwards Melghir trough showing the principal structural styles dominating the area.
Fig. 31. E-W geoseismic cross section within the southern Chotts Basin and southwards Melghir trough showing the principal structural styles dominating the area.
Consequently the Fasnian Hot shales, which present two dis- tinctive units, present a relative richness in quartz and carbonate that may help to be brittle and shatter, which is good parameter for hydraulic fracturing. First Hot shales Unit could be detected from the mineral composi- tion, which are chronologically: (1) richness in the amount of clays composed essentially from chlorites and illites (Fig. 27 EC-2), (2) a development of a peak in Quartz content, which could reach up to 70%, (3) increase of the Pyrite content around 10% and (4) a devel- opment of carbonate composition with almost 50%. The second Frasnian Hot shales unit expresses increasing values in Pyrite (14%), which may be indicative of anoxic to euxinic condition development concomitant to increasing and important carbonate Fig. 32. Well correlation of the Ludlow-Pridoli Hot shale level in the southern Algeria (SMR-1, SMRE-1 and TO-1 wells).
Consequently the Fasnian Hot shales, which present two dis- tinctive units, present a relative richness in quartz and carbonate that may help to be brittle and shatter, which is good parameter for hydraulic fracturing. First Hot shales Unit could be detected from the mineral composi- tion, which are chronologically: (1) richness in the amount of clays composed essentially from chlorites and illites (Fig. 27 EC-2), (2) a development of a peak in Quartz content, which could reach up to 70%, (3) increase of the Pyrite content around 10% and (4) a devel- opment of carbonate composition with almost 50%. The second Frasnian Hot shales unit expresses increasing values in Pyrite (14%), which may be indicative of anoxic to euxinic condition development concomitant to increasing and important carbonate Fig. 32. Well correlation of the Ludlow-Pridoli Hot shale level in the southern Algeria (SMR-1, SMRE-1 and TO-1 wells).
Thickness, organic-richness (TOC), Tmax, relative vitrinite reflectance and source type of the Ludlow-Pridoli Hot shale from selected wells (data compiled from Belhaj and Saidi, 2010), relative Vitrinite reflectance (Ro%) is calculated as demonstrated in Eq. (3). Table 6
Thickness, organic-richness (TOC), Tmax, relative vitrinite reflectance and source type of the Ludlow-Pridoli Hot shale from selected wells (data compiled from Belhaj and Saidi, 2010), relative Vitrinite reflectance (Ro%) is calculated as demonstrated in Eq. (3). Table 6
Fig. 34. Total organic carbon (%TOC) of the Ludlow-Pridoli Hot shale vs. depth in the southern Chotts Basin using BGL-1, HBR-1, ALG-1 and FNG-1 (data compiled after Cunningham, 1989). Messaoud oil field (South-central Algeria), which are thought to be the principal source for the Cambrian reservoirs and are named the Late Silurian shales (Balducchi and Pommier, 1970, p. 484). In addi- tion, the age equivalent Oued Ali shales, which present the same lithologic characteristics, had been also described by Berry and Boucot (1973) in a regional Silurian synthesisas well as recently by Kriz (2008). Several wells on the southern Melghir trough (the natural continuity of the Tunisian Chotts Basin, Fig. 31) have pen- etrated the Fegaguira shales (TO-1, SMR-1, SMRE-1, EHT-1, RS-1, see Fig. 30 for location, Figs. 31 and 32) confirming the continuity of the southern Chotts Basin (Fig. 33). In the Tunisian side (south- ern Chotts Basin), the ‘“Fegaguira” term has been given by the petroleum companies during the 1980s (e.g. Lizotte and Chebbi, 1983). In spite of the several palynological investigations, Gothlan- dian Hot shales have been described by Cunningham (1988, 1989) in the same area where he confused it with the high gamma ray values of early Silurian Hot shales situated southwards to the TTPB structural high. In the Southern Chott Basin (northern flank of the TTPB structure) tilted fault block closures and erosional pinch-outs have been described by Lizotte and Chebbi (1983) and Ben Ferjani et al. (1990) forming an exploration fairway (Fig. 33). These black shales consist of radioactive hot shale layers alternating with silty gray shales, showing a lesser amount of radioactivity. Abundant The Ludlow-Pridolian Hot Shale unit of the Fegaguira Forma- tion can be easily identified in well logs (Fig. 33) because of its high natural radioactivity of up to 250 API and even more in other wells Comprehensive organic geochemical description of the Fegagu- ira Hot shales unit in southern Tunisia was given earlier by Cunningham (1988), Inoubli et al. (1992), Saidi et al. (1998), Belhaj and Saidi (2010) and Rezouga et al. (2012b).
Fig. 34. Total organic carbon (%TOC) of the Ludlow-Pridoli Hot shale vs. depth in the southern Chotts Basin using BGL-1, HBR-1, ALG-1 and FNG-1 (data compiled after Cunningham, 1989). Messaoud oil field (South-central Algeria), which are thought to be the principal source for the Cambrian reservoirs and are named the Late Silurian shales (Balducchi and Pommier, 1970, p. 484). In addi- tion, the age equivalent Oued Ali shales, which present the same lithologic characteristics, had been also described by Berry and Boucot (1973) in a regional Silurian synthesisas well as recently by Kriz (2008). Several wells on the southern Melghir trough (the natural continuity of the Tunisian Chotts Basin, Fig. 31) have pen- etrated the Fegaguira shales (TO-1, SMR-1, SMRE-1, EHT-1, RS-1, see Fig. 30 for location, Figs. 31 and 32) confirming the continuity of the southern Chotts Basin (Fig. 33). In the Tunisian side (south- ern Chotts Basin), the ‘“Fegaguira” term has been given by the petroleum companies during the 1980s (e.g. Lizotte and Chebbi, 1983). In spite of the several palynological investigations, Gothlan- dian Hot shales have been described by Cunningham (1988, 1989) in the same area where he confused it with the high gamma ray values of early Silurian Hot shales situated southwards to the TTPB structural high. In the Southern Chott Basin (northern flank of the TTPB structure) tilted fault block closures and erosional pinch-outs have been described by Lizotte and Chebbi (1983) and Ben Ferjani et al. (1990) forming an exploration fairway (Fig. 33). These black shales consist of radioactive hot shale layers alternating with silty gray shales, showing a lesser amount of radioactivity. Abundant The Ludlow-Pridolian Hot Shale unit of the Fegaguira Forma- tion can be easily identified in well logs (Fig. 33) because of its high natural radioactivity of up to 250 API and even more in other wells Comprehensive organic geochemical description of the Fegagu- ira Hot shales unit in southern Tunisia was given earlier by Cunningham (1988), Inoubli et al. (1992), Saidi et al. (1998), Belhaj and Saidi (2010) and Rezouga et al. (2012b).
Fig. 35. Biostratigraphy of the Ludlow-Pridoli-Geddinian Fegaguira/Oued Ali (Haj Brahim) Formation (acritarch assemblages and biozones by Dummond and Rasul, 1985).
Fig. 35. Biostratigraphy of the Ludlow-Pridoli-Geddinian Fegaguira/Oued Ali (Haj Brahim) Formation (acritarch assemblages and biozones by Dummond and Rasul, 1985).
Fig. 36. Maturity Contour map of the Ludlow-Pridoli Hot shale level (Ro%).
Fig. 36. Maturity Contour map of the Ludlow-Pridoli Hot shale level (Ro%).
significant name came from the Libyan Murzuk Basin by Desio (1936). Unfortunately, it presents rather small area of extension (in southern Tunisian) southwards the southern flank of the TTPB structural high (Figs. 9, 11, 14 and 15). Northern extension of the Rhuddanian Hot Shales reaches the Jeffara Basin (e.g. ST-1, Tt-1 wells, Fig. 2) and pinches out toward the Sidi Toui - Melaab uplift (Fig. 2), which are thought to be the natural continuity of the Nefusa uplift (eastern Libya). Recent recoverable gas assessments pertains geologically to three main basins (southern Chott, Jeffara and Berkine basins). These sedimentary basins had experienced different structural styles and sedimentation patterns (Figs. 4, 5 and 7). The most significant source rock is the early Silurian (Rhud- danian and maybe through Aeron age in southern Tunisian Berkine Basin) Hot shale unit, which is the lower part of the Argiles Princi- pales Formation of Jaeger et al. (1975) commonly and traditionally labeled Tannezuft Formation by Petroleum geologists due to its Fig. 37. Gamma ray, TOC and mineralogical composition vertical distribution in the ALG-1 well (data compiled after Cunningham, 1989; Belhaj and Saidi, 2010; Rezoug: et al., 2012b).
significant name came from the Libyan Murzuk Basin by Desio (1936). Unfortunately, it presents rather small area of extension (in southern Tunisian) southwards the southern flank of the TTPB structural high (Figs. 9, 11, 14 and 15). Northern extension of the Rhuddanian Hot Shales reaches the Jeffara Basin (e.g. ST-1, Tt-1 wells, Fig. 2) and pinches out toward the Sidi Toui - Melaab uplift (Fig. 2), which are thought to be the natural continuity of the Nefusa uplift (eastern Libya). Recent recoverable gas assessments pertains geologically to three main basins (southern Chott, Jeffara and Berkine basins). These sedimentary basins had experienced different structural styles and sedimentation patterns (Figs. 4, 5 and 7). The most significant source rock is the early Silurian (Rhud- danian and maybe through Aeron age in southern Tunisian Berkine Basin) Hot shale unit, which is the lower part of the Argiles Princi- pales Formation of Jaeger et al. (1975) commonly and traditionally labeled Tannezuft Formation by Petroleum geologists due to its Fig. 37. Gamma ray, TOC and mineralogical composition vertical distribution in the ALG-1 well (data compiled after Cunningham, 1989; Belhaj and Saidi, 2010; Rezoug: et al., 2012b).
Thickness, organic-richness (TOC), Tmax and source type of the organic-rich upper Ordovician from selected wells. have been established (Kuuskraa et al., 2011; Rezouga et al., 2012a; Bacon et al., 2013) marking good gas retention with risked gas in place around 60Tcf and technically recoverable resource around 20Tcf (Fig. 1). However, in this contribution we will not discuss the proven and estimated gas/oil reserves within these shale plays but we will discuss only the geological potentiality (distribution, biostratigraphy, wireline logging characters, mineral, chemostrati- sraphic and depositional environment) point of view. These three main gas/oil shale plays (Fegaguira/Oued Ali, Argiles Principales and Aouinet Ouinine Formations) are characterized by special lat- 2ral and vertical distribution in the above cited studied basins. The main interesting character is the preservation of an important organic matter in the northern flank of the TTPB uplift system, which permitted the deposition of Hot shales pertaining to the Feg- aguira/Oued Ali Formation during the late Ludlow-Pridoli times Table 7
Thickness, organic-richness (TOC), Tmax and source type of the organic-rich upper Ordovician from selected wells. have been established (Kuuskraa et al., 2011; Rezouga et al., 2012a; Bacon et al., 2013) marking good gas retention with risked gas in place around 60Tcf and technically recoverable resource around 20Tcf (Fig. 1). However, in this contribution we will not discuss the proven and estimated gas/oil reserves within these shale plays but we will discuss only the geological potentiality (distribution, biostratigraphy, wireline logging characters, mineral, chemostrati- sraphic and depositional environment) point of view. These three main gas/oil shale plays (Fegaguira/Oued Ali, Argiles Principales and Aouinet Ouinine Formations) are characterized by special lat- 2ral and vertical distribution in the above cited studied basins. The main interesting character is the preservation of an important organic matter in the northern flank of the TTPB uplift system, which permitted the deposition of Hot shales pertaining to the Feg- aguira/Oued Ali Formation during the late Ludlow-Pridoli times Table 7
Fig. 38. Other oil and gas shale reservoir potential in southern Chotts Basin (southern Tunisia); (1) Ordovician oil/gas shale reservoir assessment and (2) Permian oil/gas shale reservoir assessment.
Fig. 38. Other oil and gas shale reservoir potential in southern Chotts Basin (southern Tunisia); (1) Ordovician oil/gas shale reservoir assessment and (2) Permian oil/gas shale reservoir assessment.
Fig. 39. Ordovician oil and gas shale potential in the Berkine Basin (southern Tunisia) inferred from TOC distribution of the upper Jeffara organic rich shales
Fig. 39. Ordovician oil and gas shale potential in the Berkine Basin (southern Tunisia) inferred from TOC distribution of the upper Jeffara organic rich shales
Fig. 40. Spectral Gamma Ray and Th/K ratio showing the position of the Frasnian unconformity just above the two Hot shale levels equivalent of the Kellwasser anoxic events. The Rhuddanian Hot Shales in southern Tunisia are distributed southwards to the TTPB structural high within the Berkine and Jeff- ara Basins (Fig. 2). The thickness of these hot shales is given in the Table 1 and Fig. 9 and range from 0 m to 160 m in general. In the southern Tunisian Berkine Basin they range between 25m and 125m while in the Jeffara Basin they range between 25m and 35 m. From mineral point of view, the Rhuddanian Hot shales are characterized by brittle minerals such as 40% of quartz, 50% car- bonate, 35% clays (chlorite, kaolinite, illite) and 20% of pyrite as mean percentages (Table 2; Fig. 19). The uranium enrichment fac- tor, calculated for the Basin in this contribution is shown in the Fig. 14 and could expect values ranging between 1 and 4.6, which are very correlatable with the iso-values of Gamma ray (Fig. 14). This is interpreted as the area of maximum redox condition, which expect maximum of organic-richness. This is evident from the Fig. 13, which compares the vertical evolution of GR and TOC from the four different wells of Berkine Basin (AMC-1, HWA-1, OZ-1 and SNN-1) and from the Fig. 15, which allows distinguishing the lat- eral evolution of mean TOC within the Basin. Maturity vitrinite reflectance (Ro%) ranges between 0.65 and 1.85 (Fig. 20) denoting five maturity zones in southern Tunisian Berkine Basin, which are: (1) immature to the north and near the TTPB structural high, (2) oil window, which characterizes the median part, (3) peak oil, (4) late oil/wet gas and (5) wet gas or preservation and maybe it goes through dry gas zone (Fig. 20). All these parameters allow good The late Ludlow-Pridoli Hot shales are very comparative to the Rhuddanian organic-rich hot shale. They are developed only north- wards to the TIPB structural high and represent the principal source rock of the Southern Chott Basin. These Hot shales are also believed to be the principal source for the giant Hassi Messoud oil field (Heybroek, 1963; Balducchi and Pommier, 1970) labeled late Silurian shales or Fegaguira Shales. It has been assumed that they have the same sedimentological characteristics of Oued Ali Forma- tion. In the Southern Chott Basin, their presence is important in petroleum point of view but the chosen name (Lizotte and Chebbi, 1983) is not reliable because of the large distance of the type section (Hassi Fegaguira, Fig. 30) in one hand and the different country of origin in the other hand (Algeria). As it is the case for the Silurian shales where it has been chosen to label them Argiles Prin- cipales Formation instead of Tannezufft Formation, it is proposed in this contribution to confine the term “Fegaguira/Oued Ali For- mation” for the Algerian side and suggest “Haj Brahim Formation” inferred from HBR-1 well where it has been the best studied bio- stratigraphically and geochemically (Chebbi and Lizotte, 1985; Dummond and Rasul, 1985; Cunningham, 1989; Belhaj and Saidi, 2010; Rezouga et al., 2012b). The late Ludlow-Pridoli Haj Brahim shales are highly radioactive characterized by up to 250 API (GR), which allow attributing to them the Hot Shale character (Fig. 33). Their thickness ranges (where they are identified) from 15m (CHR-1) to 100 m (ALG-1) with a mean depth of 3500 m in the Southern Chott Basin. It becomes deeper toward the North where the Chott Basin is thought to be more subsiding. The Haj Brahim Hot Shales are also characterized by thermal maturity ranging between 0.7 and 1 (Ro%) making it within oil window and peak
Fig. 40. Spectral Gamma Ray and Th/K ratio showing the position of the Frasnian unconformity just above the two Hot shale levels equivalent of the Kellwasser anoxic events. The Rhuddanian Hot Shales in southern Tunisia are distributed southwards to the TTPB structural high within the Berkine and Jeff- ara Basins (Fig. 2). The thickness of these hot shales is given in the Table 1 and Fig. 9 and range from 0 m to 160 m in general. In the southern Tunisian Berkine Basin they range between 25m and 125m while in the Jeffara Basin they range between 25m and 35 m. From mineral point of view, the Rhuddanian Hot shales are characterized by brittle minerals such as 40% of quartz, 50% car- bonate, 35% clays (chlorite, kaolinite, illite) and 20% of pyrite as mean percentages (Table 2; Fig. 19). The uranium enrichment fac- tor, calculated for the Basin in this contribution is shown in the Fig. 14 and could expect values ranging between 1 and 4.6, which are very correlatable with the iso-values of Gamma ray (Fig. 14). This is interpreted as the area of maximum redox condition, which expect maximum of organic-richness. This is evident from the Fig. 13, which compares the vertical evolution of GR and TOC from the four different wells of Berkine Basin (AMC-1, HWA-1, OZ-1 and SNN-1) and from the Fig. 15, which allows distinguishing the lat- eral evolution of mean TOC within the Basin. Maturity vitrinite reflectance (Ro%) ranges between 0.65 and 1.85 (Fig. 20) denoting five maturity zones in southern Tunisian Berkine Basin, which are: (1) immature to the north and near the TTPB structural high, (2) oil window, which characterizes the median part, (3) peak oil, (4) late oil/wet gas and (5) wet gas or preservation and maybe it goes through dry gas zone (Fig. 20). All these parameters allow good The late Ludlow-Pridoli Hot shales are very comparative to the Rhuddanian organic-rich hot shale. They are developed only north- wards to the TIPB structural high and represent the principal source rock of the Southern Chott Basin. These Hot shales are also believed to be the principal source for the giant Hassi Messoud oil field (Heybroek, 1963; Balducchi and Pommier, 1970) labeled late Silurian shales or Fegaguira Shales. It has been assumed that they have the same sedimentological characteristics of Oued Ali Forma- tion. In the Southern Chott Basin, their presence is important in petroleum point of view but the chosen name (Lizotte and Chebbi, 1983) is not reliable because of the large distance of the type section (Hassi Fegaguira, Fig. 30) in one hand and the different country of origin in the other hand (Algeria). As it is the case for the Silurian shales where it has been chosen to label them Argiles Prin- cipales Formation instead of Tannezufft Formation, it is proposed in this contribution to confine the term “Fegaguira/Oued Ali For- mation” for the Algerian side and suggest “Haj Brahim Formation” inferred from HBR-1 well where it has been the best studied bio- stratigraphically and geochemically (Chebbi and Lizotte, 1985; Dummond and Rasul, 1985; Cunningham, 1989; Belhaj and Saidi, 2010; Rezouga et al., 2012b). The late Ludlow-Pridoli Haj Brahim shales are highly radioactive characterized by up to 250 API (GR), which allow attributing to them the Hot Shale character (Fig. 33). Their thickness ranges (where they are identified) from 15m (CHR-1) to 100 m (ALG-1) with a mean depth of 3500 m in the Southern Chott Basin. It becomes deeper toward the North where the Chott Basin is thought to be more subsiding. The Haj Brahim Hot Shales are also characterized by thermal maturity ranging between 0.7 and 1 (Ro%) making it within oil window and peak
Fig. 41. playfairway maps of the studied oil/gas shale plays, (A) the early Silurian Hot shale, (B) the Frasnian Hot shale and (C) the Ludlow-Pridoli Hot shale
Fig. 41. playfairway maps of the studied oil/gas shale plays, (A) the early Silurian Hot shale, (B) the Frasnian Hot shale and (C) the Ludlow-Pridoli Hot shale
Fig. 42. Ternary diagram (quartz-calcite-clay) of the Cherouq-1 and Hayatt-1 wells (early Silurian Hot shale) and Hayatt-1 well (Frasnian Hot shale) showing tt mineralogical compositions for the gas/oil shale potential.
Fig. 42. Ternary diagram (quartz-calcite-clay) of the Cherouq-1 and Hayatt-1 wells (early Silurian Hot shale) and Hayatt-1 well (Frasnian Hot shale) showing tt mineralogical compositions for the gas/oil shale potential.
Related topics:
Oceanic Anoxic EventsGhadames Basin
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