Тип бассейна: Платформ
Подтип бассейна: Внутриплатформенный (интракратонный)
Класс бассейна: Синеклизный
Возраст бассейна: Древний - Палеозойский
Тип полезных ископаемых:
Геологический возраст начало:
Геологический возраст конец:
Площадь: 587971.44 км²
Illizi Basin
The Illizi Basin forms the southern part of аbroad intra-cratonic Palaeozoic depression extending over the greater Ghadames- Hamra region. It is flanked bуthe Amguid Spur to the west and the Tihemboka Arch to the east. The Palaeozoic crops out to the south towards the Hoggar Massif and plunges north below аthin unconformble Mesozoic cover. Its northern boundary is generally defined as the proximal limit of the Liassic evaporite sequence.
The basin is extremely prolific with eight fields of over 250 ММВОЕand total reserves of approximately 7 ВВОЕ. As in the Ghadames area to the north, the Tanezzuft and Frasnian source rocks are both preserved in the basin, charging fluvial, estuarine and shallow marine sandstone, ranging from Cambro-Ordovician to Carboniferous in age (Chiarelli 1978; Tissot et аl. 1984; Van de Weerd & Ware 1994; Daniels & Emme, 1995). Interbedded marine shales provide seals of varying effectiveness. The area is only very gently deformed and regional stratigraphic continuity tended to encourage long distance lateral migration. However, vertical migration was important locally through erosional windows in intra-formational shale seals, and also in proximity to the Tihemboka Arch, where faulting was more common.
The basin experienced аlong but relatively simple history, punctuated bуHercynian, Austrian and mid-late Tertiary deformational events. During the Palaeozoic, аthick sequence of sediments accumulated in аdepocentre immediately southwest of the modern basin (Tissot et al. 1984). Tanezzuft shales within this depocentre achieved very high maturities ( + 1.75% Ro) before the Hercynian and generated large volumes of oil and gas, which must subsequently have migrated northeast towards the central part of the Illizi Basin. Expulsion was terminated bуHercynian uplift and unroofing, and hydrocarbons generated at this time were largely dissipated.
Fig. 1. (а) Illizi Basin: Lower Silurian/Cambro-Ordovician Petroleum System. Three active and one extinct petroleum systems are recognized in the Illizi Basin: ( 1) аlate Palaeozoic system charged from аdepocentre to the southeast and subsequently dispersed during Hercynian (and Austrian) uplift and unroofing, (2) аCambro-Ordovician system (System 1) charged Ьуthe Lower Tanezzuft, (3) аLower Devonian reservoired system (System 11) charged bуUpper Tanezzuft Shale and (4) an Upper Devonian- Loweb Carboniferous reservoired system (System 111) charged ЬуFrasnian shales, from the northeastern depocentre and flanking areas to the northeast. The outcrop and Mesozoic subcrop of the Lower Tanezzuft source rockresponsible for System 1 are indicated. Cambro-Ordovician oil and gas accumulations are highlighted with аhachured pattern and preferred lateral migration directions are shown bуdashed arrows. The estimated presentday oil-gas maturity transition within the Mesozoic depocentre is shown Ьуаdashed line and the exhumed preHercynian depocentre southwest of the basin is indicated Ьуdiagonal lines. Source rocks in this area are thought to have charged palaeo-highs on the adjacent platf orm which subsequently remigrated into new structures after Austrian uplift and tilting. Late-stage meteoric invasion and flushing from the south is suggested bуopen arrows.
Partly based on information from Chiarelli (1978), Tissot et al. (1984), van de Weerd & Ware (1994) and Gauthier et al. (1995).and
However there is some evidence (Tissot et аl. 1984) suggesting аvery significant amount may have been preserved in аlarge palaeo-high just north of the Tin Fouye-Tabankort field.
During the Mesozoic, the Illizi Basin gradually subsided to the north and аsecond depocentre developed to the northeast along the flank of the Tihemboka Arch. Tanezzuft and Frasnian shales in this depocentre become mature in the Jurassic and early Cretaceous, first to the north and then progressively southwards. Oil and gas generated in the depocentre migrated out to charge low-relief structural closures on the flanking platform, while gentle regional structural axes encouraged longer distance migration, along the Tihemboka Arch to the south and west towards the Tin Fouye-Tabankort area.
Austrian def ormation f ollowed with uplift and unroofing of the Amguid Spur, Hoggar Massif and southern Tihemboka Arch. The north Tin Fouye-Tabankort palaeostructure was tilted out of closure at this time, and may have spilled entrapped hydrocarbons southwards to charge the Tin Fouye-Tabankort field and flanking structures (Tissot et аl. 1984).th
Generation continued during the later Cretaceous and early Tertiary with increasing amounts of gas migrating from the Mesozoic depocentre to the northeast, whereas the exhumed southwestern Palaeozoic depocentre remained inactive.
Many of the deeper reservoirs were partially and sometimes completely gas flushed at this time (Macgregor 1996 а,b), and oil and gas remigrated far to the south. Generation was terminated Ьуregional mid-Tertiary uplift, unroofing and northward tilting. Renewed hydrodynamic flow and freshwater recharge followed with flushing, spillage and partial dissipation of entrapped hydrocarbons (Chiarelli 1978). However, this destructive phase so far appears to have been gentle and most accumulations remain only slightly to moderately affected.
As аresult of this polyphase history, аnumber of petroleum systems developed in the basin at different times. Tissot et al. (1984) identified three f amilies of reservoired oil, which they correlated with the lower and upper Tanezzuft (Lower Acacus) and Frasnian shales. The two Silurian sourced oils are very similar and differ only in their maturity (Daniels & Emme 1995).
However, their distribution and stratigraphic position justifies the distinction. Based upon this oil-source correlation, it is possible to distinguish three petroleum systems still active in the basin and one extinct one as follows:
Extinct Tanezzuft-intra-Palaeozoic system.
Tanezzuft shales within the southwestern Palaeozoic depocentre achieved very high maturities before the Hercynian, when they must have generated very significant amounts of oil and gas.
Although speculative, it is рrоbаblеthis would have migrated outward to charge traps on the surrounding platform. Accumulations formed during this period would have been dispersed bуHercynian and Austrian unroofing. However, there is limited evidence to suggest that hydrocarbons spilled from some of these palaeo-fields remigrated later into Austrian aged closures nearby.e
Lower Tanezzuft-Cambro-Ordovician System 1 (Fig. l аand d). The Tanezzuft Shale extends over the entire basin varying in thickness from 200 to 500m and locally thinning over structural highs. As further to the north, the lowest part of the formation appears to bеthe most organically rich and is the source of hydrocarbons in the underlying Cambro-Ordovician accumulations.
Fig.1 (b)Illizi Basin: Silurian/Lower Devonian F6-F4 Petroleum System 11. The outcrop and Mesozoic subcrop of the upper Tanezzuft source rock responsiЫe for this system is indicated. Lower Devonian accumulations are highlighted with аhachured pattern and preferred lateral migration directions are shown Ьуarrows. Erosional windows in the Fбshale seal allowing upward migration into F4 reservoirs on the Talemzane Arch and downward migration of Frasnian oil into Fбreservoirs in the Ohanet area are outlined bуshort dashed lines. The estimated present-day oil- gas maturity transition is shown with аlong dashed line. The exhumed pre-Hercynian depocentre is shown bуdiagonal lines and possible remigration from Palaeozoic charged palaeo-accumulations into later post-mid-Cretaceous closures are indicated (after Tissot et а!. (1984)). Late Tertiary meteoric invasion and flushing from the south is suggested bуopen arrows and FбSand isosalinity contours (after Chiarelli (1978)).16)
Original ТОСcontent of this interval was рrоbаblуfairly high throughout the basin but was subsequently reduced in areas of more elevated maturities. It now varies from less than 2% in the east rising to 4% in the north and 8% in the west (Daniels &Emme 1995). Maturities range from 1.1 % Ro equivalent in the central part of the basin to 1.75% Ro in the southwest and northeast. Local very high maturities are associated with laccolith intrusions (Daniels & Emme 1995).
As well as аsource, the Tanezzuft provides an excellent regional seal for underlying Cambro Ordovician sandstone reservoirs (porosities 7-14% and permeabilities up to 250 mD).
Although of rather poor quality, their regional continuity has encouraged long distance lateral migration to the west, southwest and south along the flank of the Tihemboka Arch during later Mesozoic and early Tertiary. Pools in the Tin Fouye-Tabankort area were partially charged bуhigh-maturity oil and gas spilled from pre-Hercynian traps during the Austrian deformational event. Charge and migration ceased with mid-Tertiary uplift and unroofing to bеfollowed bуfreshwater aquifer recharge and flushing f rom the south. The system is very prolific, with some 1500 ММВОЕreserves.
Tanezzuft-Lower Devonian Fб, F4 System II (Fig. l b and d): Hydrocarbons in the Lower Devonian Fбand F4 sands were sourced from the upper part of the Tanezzuft Shale and perhaps interbedded shales within the overlying Acacus Formation. Although inferior in quality compared with the rich basal member of the Tanezzuft, they form аvery prolific source rock because of their thickness, regional extent and interdigitation with the Acacus which facilitated very efficient primary migration.so
Fig. 1 (d) Critical elements analysis for Illizi Basiпpetroleum systems, illustrating the spatial relationship and relative timing of critical structural, stratigraphic and thermal variables controlling h
gydrocarbon distribution in the Illizi Basin. Generation and expulsion from the Tanezzuft and Frasnian source within the Mesozoic depocentre started in the north and moved progressively south during the Cretaceous and early Tertiary. Preferred short to long distance moderate-impedance migration directions are indicated.ms
uThe Devonian Fбsands provide an excellent reservoir with porosities of 18-25% and permeaЬilities of аfew darcies (Alem et аl. this volume). Their stratigraphic continuity and position directly above the Acacus sands encouraged long distance lateral migration to the west and southwest. However, the overlying Fбshale seal was eroded along the flanks of the Tihemboka Arch, thus allowing southerly migrating hydrocarbons to pass up into F4 reservoir sands above. Further west in the Tin Fouye-Tabankort area, oil and gas migrating from the northeast рrоЬаЫуmixed with higher-maturity hydrocarbons from pre-Hercynian palaeo-accumulations.
Mid-Tertiary uplift brought primary migration to аclose and was followed bуvery active aquifer recharge and flushing. Fresh to brackish water and strong hydrodynamic flow are observed in the Fбsands across аlarge area in the central part of the basin. Accumulations in that area were strongly aff ected. Both Chiarelli (1978) and Alem. have suggestedthat the Tin Fouye-Tabankort accumulation is trapped hydrodynamically. Alternatively it may represent an originally structurally trapped accumulation now in the first phases of flushing and destruction. The petroleum system is extremely prolific, with 3500 ММВОЕreserves.
Frasnian to Upper Devonian-Carboniferous System IJI(Fig. 1 сand 1 d): The Frasnian shales extend across the central and northeastern part of the basin, outcropping to the south and subcropping the Mesozoic to the west. They vary in thickness between 25 and 110m thinning locally onto structural highs. Organic carbon content ranges from less than 2% in the southeast to 4-6% in the north and west. The kerogen is predominantly oil prone (although аmixed kerogen f acies becomes more dominant to the southeast). Present-day maturities increase northwards from 1.1 R0 in the central part of the basin to 1.3 R0 in the northeastern depocentre.
Fig.1 (с)Illizi Basin: Frasnian/Upper Devonian to Lower Carboniferous System III. The outcrop and Mesozoic subcrop of the Frasnian source rock responsiЫe for the Upper Devonian-Carboniferous system is indicated. Upper Devonian/Lower Carboniferous accumulations are highlighted bуаhachured pattern and preferred lateral and vertical migration directions are shown bуdashed arrows. Late Tertiary meteoric invasion and flushing from the south is suggested bуopen arrows and Upper Devonian isosalinity contours (after Chiarelli (1978)). (Refer to the legend for more detail.)
Peak oil expulsion is timed at early Cretaceous to mid-Tertiary and has charged overlying reservoirs in the Upper Devonian and Lower Carboniferous including the F2 sands, Tahara Sandstone and sands interbedded with the M'rar Formation. Porosities in the F2 reservoir typically range from 15 to 22% with permeaЬilities of 50-300 mD. The overlying Tahara and Carboniferous sandstones have rather poorer reservoir quality.
Migration was dominantly Iateral, southwards along low-relief structural axes. There also appears to have been аsignificant vertical component of migration through Austrian aged faults on the flank of the Tihemboka Arch. Тоthe north of the basin, аlocal erosional window in the Middle Devonian shales allowed the Frasnian source to charge Fбreservoirs in the Ohanet area (Tissot et а/. 1984) and FЗsands at Alrar.
As in the other sytems, mid-Tertiary uplift and unroofing appears to have terminated primary migration and charging. However hydrodynamic flushing was less severe than in the underlying Fбsands, perhaps because of lower stratigraphic continuity and proximity to the Tihemboka Arch. The system is very prolific, with total reserves of approximately 2000 ММВОЕ.
Data source: Palaeozoic petroleum systems of North Africa. David R.D. Boote, Daniel D. Clark-Lowes, Marc W. Trauti, 2016.
Ghadames (Berkine) basin
Geologic Setting
The Ghadames (Berkine) Basin is a large intra-cratonic basin underlying eastern Algeria, southern Tunisia and western Libya. The basin contains a series of reverse faults, providing structural traps for conventional oil and gas sourced from Devonian- and Silurian-age shales. The central, deep portion of the basin contains uplifted fault blocks formed during the CambrianOrdovician. The Ghadames Basin and its two significant shale formations, the Silurian Tannezuft and the Upper Devonian Frasnian, are located in the eastern portion of Algeria. Figures 1 and 2 provide the basin outline and shale thermal maturity contours for these two shale formations.
In Algeria’s portion of the Ghadames Basin, the Silurian Tannezuft Formation contains an organic-rich marine shale that increases in maturity toward the basin center. We have mapped a 28,130-mi2 higher quality prospective area for the Tannezuft Shale in this basin. The western and northern boundaries of the Tannezuft Shale prospective area are defined by the erosional limits of the Silurian and by minimum thermal maturity. The eastern border of the prospective area is defined by the Tunisia and Algerian border.
The central, dry gas portion of the Tannezuft Shale prospective area in the Ghadames Basin, covering 21,420 mi2, has thermal maturity (Ro) of 1.3% to over 2%. The remaining portion of the prospective area of 6,710 mi2 has an Ro between 1.0% and 1.3%, placing this area in the wet gas and condensate window.
Deposited above the Tannezuft is the areally more limited and thermally less mature Upper Devonian Frasnian Shale. We have mapped a 10,040-mi2 higher quality prospective area for the Frasnian Shale in the Ghadames Basin of Algeria. The western, northern and southern boundaries of the Frasnian Shale prospective area are set by the minimum thermal maturity criterion of 0.7% Ro. The eastern boundary of the prospective area is the Tunisia and Algeria border. The northern, eastern and southern outer ring of the Frasnian Shale prospective area in the Ghadames Basin, encompassing an area of 2,720 mi2, is in the oil window with Ro between 0.7% and 1.0%. The central 5,010-mi2 portion of the Frasnian Shale prospective area is in the dry gas window, with Ro of 1.3% to over 2%. In between is the 2,310-mi2 wet gas and condensate window for the Frasnian Shale, with Ro between 1.0% and 1.3%
Figure 1. Ghadames Basin Silurian Tannezuft Shale Outline and Thermal Maturity
Figure 2. Ghadames Basin Upper Devonian Frasnian Shale Outline and Thermal Maturity
Reservoir Properties (Prospective Area)
Silurian Tannezuft Formation. The depth of the gas prospective area of the Silurian Tannezuft Shale in the Ghadames (Berkine) Basin of Algeria ranges from 10,000 ft along the northern and eastern edge of the basin to 16,000 ft in the basin center, averaging 10,500 ft in the wet gas prospective area and 13,000 ft in the dry gas prospective area. The gross thickness of the Tannezuft Shale ranges from 30 to 200 ft, with an organic-rich average net thickness of 104 ft. The TOC of the Tannezuft Shale averages 5.7%. The lower portion of the formation is particularly organic-rich, with TOC values of up to 15%.
Upper Devonian Frasnian Formation. The depth of the prospective area of the overlying Upper Devonian Frasnian Shale ranges from 8,000 ft to 16,000 ft, averaging 8,500 ft in the oil-prone area, 9,500 ft in the wet gas/condensate area, and 13,000 ft in the dry gas area. The Frasnian Shale has a gross thickness of 50 to 500 ft, with an average organic-rich net thickness of 248 ft. The Frasnian Shale has TOC values ranging from 3% to 10%, with an average of 6%.
Resource Assessments
Silurian Tannezuft Shale. The Tannezuft Shale, within its 6,050-mi2 wet gas and condensate prospective area, has resource concentrations of 43 Bcf/mi2 of wet gas and 3 million barrels/mi2 of condensate. Within its larger 22,080-mi2 dry gas prospective area, the Tannezuft Shale has a resource concentration of 55 Bcf/mi2. The risked resource in-place for the 28,130-mi2 wet gas/condensate and dry gas prospective areas of the Tannezuft Shale is 731 Tcf of wet and dry gas and 10 billion barrels of condensate. Based on presence of clays but otherwise favorable reservoir properties, we estimate a risked, technically recoverable resource of 176 Tcf of wet/dry shale gas and 0.5 billion barrels of shale condensate.
Upper Devonian Frasnian Shale. The Frasnian Shale has resource concentrations of 44 million barrels/mi2 for oil in the 2,720-mi2 oil window; 10 million barrels/mi2 of condensate and 111 Bcf/mi2 of wet gas in the 3,840-mi2 wet gas/condensate window; and 134 Bcf/mi2 of dry gas in the 3,490-mi2 dry gas window. The risked resource in-place within the overall 10,050-mi2 prospective area is 496 Tcf of shale gas and 78 billion barrels of shale oil/condensate, with risked, recoverable of 106 Tcf for shale gas and 3.9 billion barrels for shale oil.
Data source: Technically Recoverable Shale Oil and Shale Gas Resources: Algeria.
U.S. Energy Information Administration (EIA). 2015
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