Тип бассейна: Платформ
Подтип бассейна: Внутриплатформенный (интракратонный)
Класс бассейна: Синеклизный
Возраст бассейна: Древний - Палеозойский
Тип полезных ископаемых:
Геологический возраст начало:
Геологический возраст конец:
Площадь: 1837442.5 км²
Taoudenni Basin
The Taoudenni Basin, North Africa’s largest sedimentary basin, is located in western Mauritania, northern Mali and southwestern Algeria. Of the four petroleum wildcat wells drilled to date, the Abolag-1 well, Mauritania, yielded gas shows in Infracambrian (Neoproterozoic) stromatolitic carbonates. We present details of the different plays of the basin from the Chenache`ne region in Algeria. The Infracambrian is generally composed of three sedimentary packages: a basal sandstone (a unit of the Douik Group), overlain by carbonates (the Hank Group), sandstones and shales (the Dar Echeikh Group). The play is sourced by Infracambrian organic-rich black shales. In neighbouring Mauritania these were penetrated by water wells and shallow boreholes, containing in places .20% TOC. In the Hank Group the best reservoirs are associated with fractured intervals. The Dar Echeikh Group includes several potential reservoir units with porosities of up to 26%. Potential petroleum trap types in the Algerian part of the Taoudenni Basin are associated with folds, the basal Palaeozoic unconformity, and Infracambrian and Triassic– Jurassic half-graben.
Petroleum systems
Source rocks
In parts of the Taoudenni Basin, an excellent, organic-rich hydrocarbon source rock, described as black shale, exists in the Infracambrian formations. Data that would allow a reliable assessment of the lateral and vertical extent of these clays are currently unavailable. Regional modelling studies have demonstrated, however, that this source rock was deposited in a synrift context which could give rise to great thickening in the vicinity of major faults in the region.
Reservoirs
The Proterozoic series, also known as the Hank Series, is represented by detritic and limestone formations that developed between the two major unconformities on the Precambrian basement and beneath the Eocambrian tillite. This series is subdivided into three groups (Fig. 1).
Fig. 1. Reservoir properties of the Hank Series (see the text for details)
Douik Group – known as G1, G2 and G3 – or ‘lower detritic assemblage’. This sandstone assemblage has a lateral extent that is impossible to predict in our Algerian study sector. It appears to disappear around the 50W meridian at Chenache´ne. Reservoir qualities are medium.
Hank Group – known as C1 –C9. This stromatolite limestone assemblage has a broad extent from the Mauritanian Adrar to Grizim, a distance of 1200 km. The thicknesses visible at outcrop to the south of Eglab vary between 19 and 35 m. These limestones are often compact and hard, with poor petrophysical characteristics. When fractured they can form hydrocarbon reservoirs, as in the case of the Abolag-1 well in Mauritania, which release small amounts of gas. Above the stromatolite limestones, ferruginous sandstones appear to be continuous with fine –medium, generally friable, saccharoidal sandstones known as the Kerboub facies. Their thicknesses vary from 20 m at Chegga to 16 m at Tilemsi.
Dar Cheikh Group, which is divided into four subgroups:
– CG 1 and CG 3 subgroup, which consists of light –greenish, sometimes saccharoidal, medium–coarse sandstones with porosities of 7–18% and thicknesses of 5 –20 m;
– CG 4 and CG 5, a subgroup of sandstones that are generally clean, sometimes friable and quite porous, quite well developed in the region, and could form a good reservoir. Thicknesses range from 8 to 22 m. Porosities are of the order of 6– 19%;
– CG 6–CG 7 subgroup, which has two sandstone reservoir levels: a basal level with locally good reservoir characteristics (e.g. at Chegga), where mean porosity is in the order of 21%; or medium (e.g. at Mokrid), where porosity varies between 2.5 and 13%. The thickness is only 5–6 m. A friable summit reservoir sometimes occurs in the Kerboub sandstones. These form a reservoir 25 –40 m thick. Porosity is 12 –26% at Chegga and 13 –25% at M’dennah;
– CG 8–CG 9 and CG 10 subgroup, which is not very well developed in the east. It is 47 m thick at Chegga, and porosities vary from 8 to 15%. The sandstones are fine –medium with cross-bedding, and rapidly pass into compact limestone-containing sandstones.
Traps
Structural and sedimentological investigations have identified different types of traps that may exist within the perimeter of Chenache`ne. Type A, a purely structural trap corresponding to folding induced by the transpressive tectonics at the end of the Proterozoic (Fig. 2a).
Fig. 2 (a) The different trapping styles present in the Chenache`ne area, including traps formed under the Palaeozoic deposits to the south of Chenache`ne. Traps can be structural, stratigraphic or combination traps. Good reservoirs with sufficient thickness potentially allow large accumulations of hydrocarbons when trapping conditions are similar to styles B and D. Trapping style A: closed or along-fault anticlinal structures, frequently associated with the north– south-trending strike-slip faults of Oued Chenache`ne and Oued Souss.
Type B, which corresponds to a mixed trap and affects only the basal sandstone series when it is covered by the limestone series. The extent of this type of trap is interesting because this structural feature can be found along all the north– south faults, and particularly towards the south beneath the Palaeozoic series (Fig. 2b).
Fig. 2. (Continued) (b) Structural cross-section of the eroded and rotated fault-blocks in the Ninian region, East shetland Basin (from Albright et al. in Allen & Allen 1990). Trapping style B: only present in the Basal Sandstone series when in contact with source rocks (here, the Carbonates Group). Trapping style C: all traps developed in extensional or transtensional syntectonic depositional context; (c) Different trapping styles present in the Chenache`ne area, including traps formed under Palaeozoic deposits to the south of Chenache`ne. Traps can be structural, stratigraphic or a combination. Good reservoirs with sufficient thickness potentially allow large accumulations of hydrocarbons when trapping conditions are similar to styles B and D. Trapping style D: stratigraphic traps formed by the transpression of the Cambrian on to truncated pinched-out Infracambrian sandstones (mainly within the Uppen Sandstone series).
Type C, which includes all of the traps found in sedimentation contemporary with extensional tectonics (of the North Sea type) (Fig. 2b).
Type D, which is a conventional stratigraphic trap given the arrangement of the Infracambrian series that dips southwards beneath the Palaeozoic series and bioherms to embedded stromatolites (Fig. 2b).
Conclusions
-The Taoudenni Basin, located in western Mauritania, northern Mali and southwestern Algeria, represents North Africa’s largest sedimentary basin.
- The Infracambrian of the Chenache`ne region in Algeria is generally composed of three sedimentary packages: (1) a basal sandstone unit of the Douik Group overlain by (2) carbonates of the Hank Group and (3) sandstones and shales of the Dar Echeikh Group.
- The play is sourced by Infracambrian organicrich black shales which in neighbouring Mauritania were penetrated by water wells and shallow boreholes, containing in places .20% TOC.
- In the carbonate-dominated Hank Group, the best reservoirs are associated with fractured intervals. The sandstones of the Dar Echeikh Group contain several potential reservoir units with porosities of up to 26%.
- Potential petroleum trap types in the Algerian Taoudenni Basin are associated with folds, the basal Palaeozoic unconformity and Infracambrian and Triassic – Jurassic half-grabens.
Mali
Two deep hydrocarbon exploration wells have been drilled in the Mali part of the Taoudenni Basin, Atouila-1 (TD: Ordovician) and Yarba-1 (TD: Infracambrian) (Fig. 3).
Fig. 3. Overview of lithologies and organic richnesses of the Infracambrian strata in surface exposures and wells. Also shown are Infracambrian extensional structures and thermal maturities for the Taoudenni Basin (see the text for references). Organic-rich strata and features possibly hinting at the presence of organic-rich strata are marked in bold. Corg strata, organic-rich strata. Infracambrian sediments are included in both Precambrian and Cambro-Ordovician. Locality ID-numbers: (1) black sericitic phyllites, turbidites on Pre-Pan-African continental slope, younger carbonates probably organically lean (Anti-Atlas, Morocco); (2) organically lean carbonates, siliciclastics and volcanics (Ougarta Range, West Algeria); (3) organic-rich strata in multiple Infracambrian horizons, organic-rich Oued Sous Formation best developed between El Mzereb and El Mreiti. ‘Burning Shales’ (Mauritanian Taoudenni Basin); (4) black shales in half-graben basins (Algerian Taoudenni Basin); (5) organically lean sandstones (Iullemeden Basin, Niger); (6) infracambrian strata penetrated by wells Ammonite-1, Bahrein-1, Dessouky-1 and Siwa-1; no information on lithologies (Western Desert Basin, Egypt); (7) Palaeoproterozoic black shales (Gabon); (8) organically lean shales (west margin Murzuq Basin); (9) marble and siliciclastics (east margin Al Kufrah Basin); (10) mostly continental (organically lean) siliciclatics; few thin beds with dark shale horizons (NE Libya); (11) pre-Pan-African black limestones, underlain by 1.8 Ga quartzites; post-Pan-African half-graben basins with mainly continental infill (Ahnet Basin); (12) diamictite and black limestones (Ethiopia); (13) conglomerates, greywackes and siltstones deposited as Pan-African molasse in intramontane
Infracambrian organic-rich strata with TOC values of up to 5% (Pe´lites de la se´rie de Nara) have been described from outcrops in northern Mali (Dars 1960, p. 65, fig. 3; Villemur 1967). Dars (1960, p. 334) reported that the foliation surfaces of the ‘schistes de Drabegue’ (equivalent of the ‘pe´lites de l’Azlaf’ in the Mauritanian Hank area) in the region of Bamako in southern Mali are coated in bitumen.
In 2002–2003 Sonatrach-DNGM studied the Infracambrian in outcrops in Mali and produced an unpublished report ‘Evaluation du Potential Pe´trolier des Bassins Se´dimentaires du Mali’. In the Gara Assaba area (258180 2800N, 38480 2700W) they sampled black shales interbedded with fine-grained sandstones belonging to the Formation ‘Pe´lites de l’Azlaf’, which yielded a residual (post-weathering, post-maturation) TOC of 1.4%. In the Hank area (288450 N, 308310 E) Sonatrach–DNGM noted probable lagoonal black shales onlapping a conophyton reef and a sedimentary breccia (pers. comm. Dr S. Sacko 2005).
The top of the Infracambrian sequence in the Taoudenni Basin is locally characterized by an angular unconformity, overlain by CambroOrdovician strata. In the eastern part of the Taoudenni Basin (Yarba-1 area) the upper part of the Infracambrian sequence is eroded beneath the Hercynian unconformity.
Source: Infracambrian petroleum play elements of the NE Taoudenni Basin (Algeria). A. Rahmani, A. Goucem, S. Boukhallat, N. Saadallah, 2018.
Infracambrian hydrocarbon source rock potential and petroleum prospectivity of NW Africa. S. Lüning, S. Kolonic, M. Geiger, B. Thusu, J. S. Bell and J. Craig. 2009
Следующий Бассейн: Gourara