PETROLEUM OCCURRENCE

Surface oil seeps in the Red Sea Basin Province occur in two major areas (Mitchell and others, 1992; Beydoun, 1989). In the northeastern Red Sea, bordering Saudi Arabia and south of the Gulf of Aqaba, coastal seeps probably are related to active faulting associated with the Aqaba transform system. The southern Red Sea has seeps around the salt-cored Farasan and Dahlak Islands, along most of the Eritrean coast (southwestern Red Sea), and along the southern Saudi Arabian and Yemeni coasts (southeastern Red Sea), including several salt domes (e.g., Jaizan and Salif).

More than 1900 wells in the Gulf of Suez delineate 60 fields plus an equal number of one-well reported discoveries, for a total of 120 fields. The remaining province area has fewer than 100 well penetrations with three confirmed productive areas (offshore Tokar Delta of Sudan, offshore Eritrea, offshore and onshore northwestern Saudi Arabia). Exploratory wells are distributed over the entire Red Sea area, and most had oil or gas shows.

Hydrocarbon accumulations in the Red Sea Basin Province likely exceed 22 BBOE in place, with ultimate expected recoveries of 11.75 BBOE (Petroconsultants, 1996). Fifty-five percent of that ultimate volume has been produced. Of the overall ultimate volumes, approximately 13.5 % is gas (9.53 TCF) and 2.5% is condensate. Just 8-9% of the gas and condensate has been produced.

Known Sudr-Nubia(!) accumulations (Figure 3b) are expected to ultimately recover 10.75 BBOE, with 6.42 BBOE already produced (Petroconsultants, 1996). Sudr-Nubia(!) field sizes in MMBOE are characterized by means of 101 (arithmetic) and 8 (geometric), a median of 9.5 and a mode of 5 (Figure 5, Table 1). API gravities average 28, but range from 12 to 58. Production GORs are typically less than 10,000 cfg/bo. Known Maqna(!) accumulations (Figure 3c) will ultimately recover just under 1 BBOE, with 24 MMBOE having been produced from the southern Gulf of Suez. Maqna(!) field sizes in MMBOE have means of 58 (arithmetic) and 7 (geometric), a median of 5.8 and a mode of 10 (Figure 5, Table 1). API gravities range from 20 to 58, but average around 40. Production GORs to date are less than 5,000 cfg/bo.

Total reserve distribution by reservoir rock is shown in Table 2 for the Gulf of Suez (dominantly the Sudr-Nubia(!) total petroleum system), with proportions reported by Salah and Alsharhan (1997) contrasted with proportions derived from the Petroconsultants data base (Petroconsultants, 1996). Half or more of all reserves are in syn- and post-rift Tertiary rocks, particularly the Kareem Formation. Somewhat fewer reserves are in pre-rift reservoirs, particularly Nubia equivalents. Petroconsultants’ data identifies Nubia sandstones as being the dominant reservoir rocks. The Maqna(!) petroleum system has its largest known accumulations outside the Gulf of Suez where approximate Kareem equivalents trap most discovered hydrocarbons.

Hydrocarbon migration paths range from rather simple cross-fault juxtapositions of mature source and reservoir (e.g., Ramadan field, Abdine and others, 1992) to what must be more tortuous cross-fault migrations combined with upward migrations through fault blocks to a seal (e.g., October field, Lelek and others, 1992).