Hydrocarbons and Rift Systems in Northeast Africa
Apache Egypt Companies
Northeast Africa underwent numerous phases of continental extension and rifting beginning in the Permian and lasting to the Present-day (Fig. 1). Some of the resulting basins are prolific producers of hydrocarbons, while others are less so. This paper compares the tectonostratigraphy of three important basin complexes: the greater Sirt Basin, the Gulf of Suez–Northern Red Sea Rift, and the Sudan Rift System. These various rifts and their associated post-rift subsidence histories can be used to model less well explored basins in Africa’s numerous rift systems.
The first commercial oil discovery in the Sirt Basin was the A1-32 well drilled in 1958 by the Oasis Oil Company (Conoco/Marathon/ Amerada Hess) at Bahi Field. This well tested oil from the Paleocene Upper Satal Limestone, located on an inter-basinal regional platform. Since the discovery of the Bahi Field, approximately 45 billion barrels of proven hydrocarbon reserves have been found in the Sirt basin, which onshore covers an area of about 234,000 km2.
The “Sirt Basin” is actually a complex aggregate of several rifts, separated by large horsts or platforms (Fig. 1), and each with its own distinct tectonic and sedimentary history (Ibrahim, 1991; Baird et al., 1996; Ambrose, 2000; Hallett, 2002). Local rifting commenced in the Triassic (Thusu, 1996), perhaps also in the Permian, and was related to the initial opening of Neotethys (Stampfli, et al., 2001). Major phases of extension and subsidence subsequently occurred in the Jurassic-Early Cretaceous, Late Cretaceous, and Paleogene (Anketell, 1996; Van der Meer and Cloetingh, 1996; Ambrose, 2000; Hallett, 2002; Bosworth et al., 2005). Extension has persisted to the present-day in the Hon Graben and locally offshore.
The most important source rock in the Sirt Basin is the syn-rift marine Campanian Sirte Formation (Baird et al., 1996). The Sirte consists of dark, laminated, foraminifera-rich shale with total organic carbon (TOC) of 2-5%, occasionally greater than 10%, and maximum thickness in excess of 700 m (Hallett, 2002). Lacustrine and lagoonal source rocks are also known from the
Triassic Amal (~4-5% TOC) and the Early Cretaceous Sarir (Nubia) Formations (2-3% TOC) (Thusu, 1996; Hallett, 2002).
Numerous sandstone and carbonate reservoir units are present both in the pre-, syn- and post-rift stratigraphic intervals. Approximately 25% of the reserves are contained in Nubia facies sandstones, and over a third in Paleocene shallow-water carbonates (Baird et al., 1996).
Gulf of Suez – Northern Red Sea
Oil has been collected and utilized in the Gulf of Suez region since ancient times. Black oil surface seeps were present along the Sinai coast at Gebel Tanka and the Eastern Desert coast at Gebel el Zeit (“Oil Mountain” in Arabic; referred to as “Mons Petroleus” by the Romans). Oil was discovered by cable tool drilling at Gemsa Peninsula in 1886 at a depth of only 33 m (the de Bay-1 well). Subsequently, the first commercial oil well was drilled at Gemsa in 1908 by the Egyptian Oil Trust, eventually taken over by Anglo-Egyptian Oil Fields, Ltd. (EGPC, 1996). The principal reservoir was Middle Miocene porous and cavernous limestone (now referred to the Belayim Formation). Discovered proven reserves for the Gulf of Suez presently stand at about 11 billion barrels. The area of the Gulf of Suez basin is approximately 24,000 km2.
The Gulf of Suez is essentially a single, abandoned rift that initiated at the end of the Oligocene as a northern continuation of the Red Sea – Gulf of Aden rift system (Fig. 1; Robson, 1970; Garfunkel and Bartov, 1977). During the Middle Miocene, the Gulf of Aqaba – Dead Sea transform plate boundary formed and separated the Gulf of Suez from the northern Red Sea. During this same time interval the basin became isolated from both the Mediterranean and Indian Ocean and widespread evaporite deposition resulted, producing superb top seals for hydrocarbon accumulation.
As in the Sirt Basin, multiple source rocks are present in the Gulf of Suez. The richest units occur within the pre-rift, shallow marine “Brown Limestone” of the Campanian Duwi Formation, where TOC’s of over 20% have been measured. Source potential is also recognized in the overlying Eocene carbonate section (Barakat, 1982). During the main phase of rifting in the Early Miocene, foraminifera-rich marls were deposited in most of the basin depocenters and are referred to the Rudeis and Kareem Formations (Richardson and Arthur, 1988). These units are similar tectonostratigraphically and depositionally to the Sirte Formation. Their TOC’s are generally
lower and in the range of 1-3%, but like the Sirte their total thickness is large and often exceeds 1000 m.
Both pre- and syn-rift reservoir rocks are important in the Gulf of Suez. Unlike the Sirt Basin, however, the overwhelming majority of reserves thus far discovered occur in siliciclastic rocks.
Sudan Rift System
Exploration commenced later in the Sudanese basins than in Libya and Egypt. The first well to recover oil, Unity-1, was drilled by Chevron in 1978 in the Muglad Basin (Fig.1). This was followed by significant discoveries at Abu Gabra-1 (1979) and Unity-2 (1980), and later fields were also found in the Melut Basin. The proven recoverable reserves for the Sudan rift system are now estimated to be about 1.4 billion barrels, but large areas of these basins are relatively unexplored.
The Sudanese rift complex displays many similarities to the Sirt, and covers an even larger area (~300,000 km2). It is comprised of several NW-SE trending parallel basins (as in the Sirt) that initiated rifting in the Jurassic to Early Cretaceous (Schull, 1988). These major depocenters are connected by E-W structures that have been interpreted as transcurrent faults and associated small pull-apart basins (Bosworth, 1992). Extension was rejuvenated in several pulses during the Late Cretaceous and Paleogene.
Unlike the Sirt basins and Gulf of Suez, most segments of the Sudan rifts were never invaded by marine waters. Hence, all the proven source rocks are lacustrine in origin, and principally occur within the Aptian-Albian Abu Gabra Formation. TOC’s average 1.3% with a range of 1 to 5% (Schull, 1988). The Abu Gabra Formation reaches a maximum thickness of about 2 km.
The Abu Gabra source interval is overlain by the sand-rich Albian-Cenomanian Bentiu Formation that serves as one of the most important reservoirs in the Sudanese basins. Oil has also been discovered in siliciclastic reservoirs interbedded with the Early Cretaceous source intervals, and in overlying sandstones as young as the Paleocene.
Comparisons and Conclusions
All three of the rift systems discussed here display similar structural styles, although the rifting histories of the Sirt and Sudanese basins were
certainly longer-lived and, as a consequence, in some respects more complex than that of the Gulf of Suez. All three regions experienced minor effects of inversion during the regional “Santonian” and younger compressional events (reviewed in Guiraud and Bosworth, 1997), but this was not a significant factor in the evolution of any of the recognized hydrocarbon systems. Because marine waters were not present in most of the Sudanese basins, carbonate reservoirs are not an exploration target there. However, all three rift systems contain excellent reservoir rocks that are in close stratigraphic proximity to source intervals.
Although structuration and reservoir development are comparable in these three areas, source rock richness and volume are not. The marine shales and limestones of the Sirte and Duwi Formations show decidedly higher average and peak TOC’s than their lacustrine counterparts of the Sudanese rift system. Furthermore, the marine nature of the depositional systems in the Sirt and Gulf of Suez tended to produce more laterally continuous sealing formations, including both shales and evaporites. Given sufficient burial and time, the marine-dominated rift systems produced and trapped more hydrocarbons both in total volume and on a per acre basis.
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