U.S. DEPARTMENT OF THE INTERIOR
U.S. GEOLOGICAL SURVEY
The Red Sea Basin Province: Sudr-Nubia(!) and Maqna(!) Petroleum Systems¹
Sandra J. Lindquist, Consultant to
U.S. Geological Survey, Denver, CO
World Energy Project
USGS Open-File Report 99-50-A
The major oil-prone source rock in the Gulf of Suez is the pre-rift, Upper Cretaceous (Senonian) marine Sudr Formation, particularly the Campanian Brown/Duwi Member, a uniform, organic-rich, uraniferous limestone. Late Cretaceous seas may have transgressed as far south as central Sudan and central Saudi Arabia (Schandelmeier and others, 1997; Mitchell and others, 1992; Beydoun, 1989). Brown/Duwi phosphatic shales crop out from as far north as Wadi Araba in the northern Gulf of Suez to Quseir on the Egyptian Red Sea (Figure 3b). Brown/Duwi age equivalents in the Midyan basin, at the Gulf of Aqaba junction with the eastern Red Sea coast, are largely terrigenous (Hughes and Filatoff, 1994), and other Midyan subsurface pre-rift rocks also have poor source quality (Cole and others, 1995).
In the Gulf of Suez, Brown/Duwi thicknesses are 25-70 meters. Total organic carbon content averages 2.6 wt % (Lelek and others, 1992), but values as high as 21 wt % have been measured in some Egyptian phosphate mines (Abdine and others, 1992). Kerogen is typically type II, with H/C ranging from 1.1 to 1.4 and O/C <0.1 (Alsharhan and Salah, 1997a). The Brown/Duwi source rock is thermally mature to oil (and locally gas) in numerous offshore and several onshore grabens of the Gulf of Suez. Oil expulsion from a typical Gulf of Suez source pod probably began 10-8 Ma (Abdine and others, 1992; Shahin, 1988) during the time of extensive evaporite deposition (Figure 6a and Figure 7a).
Oils from the Sudr Formation are identified by characteristics commonly associated with carbonate source rocks and saline depositional environments – relatively high sulfur content (>1%); pristane/phytane ratios of generally <1; the presence of the biomarker gammacerane; the presence of C27 and C30 steranes; significant tricyclic, tetracyclic, and pentacylcic terpanes; and high C35/C34 (Barakat and others, 1997). These oils are also typically low in wax content and isotopically light (d¹³C < -26 in aromatics and saturates), with relatively low C29, carbon preference index (CPI) <1, and a nickel/vanadium ratio <1 (Alsharhan and Salah, 1997a). These types of oils have been reported from as far south as Hurghada field at the mouth of the Gulf (Alsharhan and Salah, 1997a) to as far north as Ras Sudr field 280 km northwest (Rohrback, 1983).
Higher thermal gradients result in Miocene strata being thermally mature in the southern Gulf of Suez (Figure 6b and Figure 7b). Syn-rift and post-rift Miocene source rocks were deposited in a variety of settings with limited lateral extents, resulting in variable kerogen type but an overall more terrigenous nature than Upper Cretaceous counterparts. Pods of potential Miocene source rock are expected to exist everywhere within the Red Sea Province except for the youngest axial areas of both the Red Sea rift and the Gulf of Aqaba wrench system. The probable dominant source rock strata for this Tertiary petroleum system are in the Maqna Formation (Saudi Arabian nomenclature, Figure 2).
Source rocks as young as middle Miocene (Belayim) are mature in the deep Gemsa trough of the southwestern Gulf of Suez and in the Midyan basin of the northeastern Red Sea of Saudi Arabia (Alsharhan and Salah, 1997a). Lower Miocene (Rudeis) source intervals are mature in most grabens and some horsts at the mouth of the Gulf of Suez. Rudeis equivalents in the Midyan basin are at a wet-gas thermal-maturity stage.
Lower to middle Miocene source rocks at the southern end of the Gulf of Suez are type II to type III kerogen with hydrogen indices (HI) ranging from 100 to 700 mg HC/g TOC (gas prone to oil prone), total organic carbon content (TOC) commonly 1-4 wt % and hydrocarbon yields (S2) of 4-9 kg/ton (Alsharhan and Salah, 1997a). Data from farther south on the western shore of the Red Sea also confirm mixed oil-and-gas potential with yields of 6,000-28,000 ppm (Barnard and others, 1992). Equivalent source rocks of offshore Sudan range from poor to good in quality, with TOC to 1.9 wt %, HI reaching 200 mg HC/g TOC (gas potential), and thicknesses of 11-75 meters (Bunter and Abdel Magid, 1989a, b).
In the Saudi Arabian Midyan basin (north, near the Gulf of Aqaba) and Jaizan basin (south, near the Yemen border), the middle Miocene Maqna Formation is a good oil source with TOC averaging 1-2 wt % (maximum 14 wt %), HI averaging 200-300 mg HC/g TOC (maximum near 700), and hydrocarbon S2 yields averaging 2-6 mg HC/g rock (maximum 85) (Cole and others, 1995). Twenty-meter Maqna thicknesses are confirmed at Midyan -- likely the source rock of the discovered black oil -- but just 2-meter thicknesses were observed at Jaizan. The older Burqan and Tayran formations are tens of meters thick and regional in extent, but more gas prone with HI less than 200, TOC averaging 1.3 wt % or less, and S2 yields of <3 mg HC/g rock. The Burqan Formation is reported as the likely source for wet to dry gases tested at Jaizan. Oldest Miocene source rocks expelled oil from 11-10 Ma, whereas younger Maqna sources have been expelling from 5 Ma (Jaizan) to 2 Ma (Midyan) (Figure 6b and Figure 7b).
Oils from Miocene shales are identified by characteristics associated with more terrigenous kerogens and, thus, contrast with the previous Cretaceous Sudr oil descriptions. Sulfur content is low and generally <1%, wax high, pristane/phytane >1, CPI >1, nickel/vanadium =2, C29 high, carbon isotopes heavier (d¹³C > -26), and oleanane is the dominant biomarker instead of gammacerane (Barakat and others, 1997; Alsharhan and Salah, 1997a). Gamma field, near giant Morgan field and 110 km north of the Gulf of Suez junction with the Red Sea, is the northernmost Gulf of Suez field with production attributed to Miocene source rock (Barakat and others, 1997). Cole and others (1995) distinguish among potential Miocene source rocks at Midyan and Jaizan with analyses of tricyclics, hopanes, steranes and carbon isotopes. Miocene source rocks probably thicken appreciably in local depocenters not yet tested.
Upper Miocene (salt and post-salt) and Pliocene strata have source-rock potential in the Red Sea, perhaps also including the youngest axial areas of both the Red Sea rift and the Gulf of Aqaba. Individual beds are rich (TOC approaching 30 wt % but averaging 1-4 wt %) and prolifically oil prone (HI to 700, S2 yields as high as 144 mg HC/ g rock), but are thin where penetrated in the Red Sea and of unknown lateral extents (Cole and others, 1995; Barnard and others, 1992; Beydoun and Sikander, 1992; Bunter and Abdel Magid, 1989a, b). Hotter wells of the southern Red Sea Basin Province are thermally mature for oil at Upper Miocene to Pliocene level, and oil seeps around the southern islands probably originated from those horizons (Mitchell and others, 1992).
Jurassic marine source rock with mixed oil-and-gas potential is mature in the northernmost Gulf of Suez. Shahin (1997) cited unspecified carbon isotope and biomarker data to attribute 1.2 BBOIP potential (0.112 BBO proven recoverable) from a 700-sq-km area of Jurassic Khataba shale that generated and expelled oil from 20-10 Ma into four northern Gulf of Suez fields. Other Jurassic source rocks (Agula, Madbi) could be preserved in fault blocks of the southern Red Sea margin along the Eritrean and Yemeni coasts and on the southernmost Red Sea central platform at moderate depths south of the salt basins (salt basin location discussed under "Assessment Units"). They now might be overmature near the coasts, but possibly not on the central platform, which is cooler because sea-floor spreading is offset westward from the platform – via a transform fault – into the onshore Afar depression (Figure 3a).
Other Upper Cretaceous to Eocene carbonates and shales in the Gulf of Suez (Abu Qada, Matulla, Esna, Thebes, Khababa) are claimed as identifiable or nominated as potential contributing source rocks in the Gulf of Suez and are at maturity levels similar to the Brown/Duwi Limestone. Shahin (1997) attributed 8.4 BBOIP potential, with 1.6 BBO proven recoverable in October field (north central Gulf of Suez) and the surrounding area, to Matulla sources in the northern Gulf of Suez.
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U.S. Geological Survey Open-File Report 99-50-A