RESERVOIR ROCK

Pre-rift reservoir rocks of the Gulf of Suez contain volumes of ultimate recoverable reserves comparable to syn- and post-rift counterparts, but the post-rift formations have better reservoir properties (Table 2). Overall, pre-rift formations average 18% porosity and 200 millidarcies (geometric) permeability. Syn- and post-rift reservoirs average 21% porosity and 450 millidarcies (geometric) permeability. Table 2 compares allocation proportions derived from Petroconsultants (1996) with those reported by Salah and Alsharhan (1997). The latter allocate a larger percentage of reserves to syn- and post-rift reservoirs. Gulf of Suez reservoirs primarily produce Sudr-generated oils and from all stratigraphic horizons.

Pre-rift sandstones, shales, and minimal carbonates (all collectively called Nubia and equivalents, Figure 1) were deposited during cratonic stability in continental to shallow marine environments covering most of the present-day Red Sea region. The Nubia Formation ranges in age from Early Paleozoic to Early Cretaceous and is preserved in grabens throughout the Gulf of Suez and on the Red Sea margins. Preserved gross thicknesses exceed 1000 meters (3000 ft) with significant lateral continuity. Alsharhan and Salah (1997b) report Nubia net-pay thicknesses in the Gulf of Suez of 30-450 meters, porosities of 10-29%, permeabilities of 70-850 millidarcies, and known recovery factors of 15-60%. They estimate that Nubia reservoirs contain 19% of all Gulf of Suez production.

In contrast, Petroconsultants’ data indicate as much as 30% (3.5 BBOE) ultimate recoverable reserves could be in Nubia reservoirs, with average porosity of 19% and average permeability of 300 (geometric) or 700 (arithmetic) millidarcies (Table 2). The October field producing complex (36% of all Nubia reserves) has a net-pay-to-gross-thickness ratio of 0.2 for 700 meters (80% sandstone) with averages of 16% porosity, 236 millidarcies permeability, and 17% water saturation, and expected recovery of 45% (Lelek and others, 1992). Nubia pay cutoffs reported for Ramadan field (10% of all Nubia reserves) are 11% porosity, 10 millidarcies permeability and 9% clay content (Abdine and others, 1992).

Other significant reservoirs in the Gulf of Suez are in mixed lithologies of the shallow-marine, pre-rift Upper Cretaceous Nezzazat Group (14-19% of ultimate recoverable) and in composite syn-rift and post-rift Miocene strata (51-64% of ultimate recoverable). Similar to Nubia, the Nezzazat Group is found throughout the Gulf of Suez. Reservoir quality averages 18% porosity and 150 (geometric) millidarcies permeability, with 10% of reserves in carbonates. Trapping configurations and reservoir capability of Nezzazat equivalents outside the Gulf of Suez are unknown, but age-equivalent sediments of continental to marine character probably were deposited over most of the Red Sea area (Schandelmeier and others, 1997).

Miocene reservoir rocks (Figure 2) were deposited in environments ranging from deep marine to deltaic, coastal, and subaerial. They are preserved everywhere within the Red Sea Province except for the youngest axial areas of both the Red Sea rift and the Gulf of Aqaba. Areally and temporally, depositional conditions in the basins changed abruptly, resulting in a large variety of lithologies and facies. Major Miocene reservoirs from oldest to youngest are Rudeis (14-20% of ultimate recoverable), Kareem (23-24% of ultimate recoverable) and Belayim (10-11% of ultimate recoverable).

Rudeis reservoirs are dominated by sandstone lithologies, and reservoir properties average 22% porosity and 700 millidarcies (geometric) permeability. Comparable values for the Kareem and Belayim formations are 22% and 550 millidarcies and 22% and 300 millidarcies, respectively. The Kareem Formation is dominated by sandstone where productive, but one-third of Belayim reserves are in carbonates. Salah and Alsharhan (1997) report Kareem net-pay thickness to 195 meters, porosity from 9-33%, and permeability from 20-730 millidarcies.

Syn- and post-rift Miocene reservoir rocks outside the Gulf of Suez have minimal published information about reservoir quality. Saudi Arabian productive Maqna (mid-Miocene) carbonates at Midyan field have 20% porosity and 10 millidarcies permeability, and Sudanese Zeit-equivalent, productive (upper Miocene) dolomitic sandstones have 22% porosity and 29 millidarcies permeability (Petroconsultants, 1996).

SEAL ROCK

The regional seal in the Red Sea Basin Province is a post-rift, upper Miocene, province-wide salt, evaporite and shale sequence recognized locally by the names Zeit, South Gharib, Dungunab, Amber and Mansiyah. This major marine evaporitic basin formed during times of reduced subsidence, when activation of the Aqaba transform fault caused Red Sea separation to become more oblique. Locally, these formations have associated sandstones and carbonates that have been successfully tested as reservoirs. The salt is generally thicker in the central part of the province and in graben centers. Within the Gulf of Suez, the most massive salt unit (South Gharib) averages 200 meters in thickness, generally thickening southward toward the Red Sea to a local maximum of 900 meters. Diapirism is exhibited in the southern Gulf of Suez and in the Red Sea, resulting in local absence of salt, in contrast to its presence in massive domes and walls of at least several thousand meters thick. Significant salt and evaporites can also be present in the underlying upper middle Miocene (Serravalian) formations (e.g., Belayim).

The regional upper Miocene salt seal is not present in the youngest axial areas of both the Red Sea rift and the Gulf of Aqaba.

Other lesser but effective seals on the producing-field scale exist in thinner evaporite units, shales, and massive impermeable carbonates of various thicknesses and most geologic ages.