The Nile Delta is an emerging giant gas province with proven reserves of approximately 42 × 1012SCF. This resource has more than doubled in the last three years, largely from successful deep water exploration for Pliocene slope-channel systems. Proven reservoirs vary in age from Oligocene through Pleistocene. Source rocks include Jurassic coals and shales and the Lower Miocene condensed Qantara Formation shales. Additional source rocks may be present in condensed intervals of Cretaceous, Oligocene and Eocene age.Following Tethyan rifting and opening of the Mediterranean in the Jurassic, prominent Cretaceous mixed clastic and carbonate shelf edges aggraded vertically along a steep fault-bounded shelf-slope break (the ‘hingeline’) in northern Egypt, which exerts the fundamental control on reservoir distribution in Tertiary age strata. In late Eocene time, northern Egypt was tilted toward the Mediterranean during regional uplift associated with the opening of the Gulf of Suez and Red Sea rifts. Drainage systems shed reservoir quality sediments northward in a series of forced regressions. These regressions culminated in be-heading of the youngest deltas by subaerial erosion during the Messinian salinity crisis. Early Pliocene transgressions laid a thick sealing interval over the low-stand Messinian valley networks. Renewed deltaic deposition began at approximately 3.8Ma.The steep structural hingeline and faulted continental shelf created a large amount of accommodation space with relatively minor progradation of depositional systems. As a result, the primary play consists of slope-channel fairways in all levels. The Pliocene systems are the shallowest targets in the basin and future large reserve growth will come from the pre-Messinian strata.Nile Delta gas resources lie close to emerging and established markets in the Mediterranean. Challenges to capturing the deeper pre-Messinian prize include:establishing favourable economic terms for export and domestic markets;reducing drilling costs and optimization of wellbore patterns to develop multiple stacked objectives;working in deep water and high pressure environments;developing predictive models for pressure regressions in overpressured reservoir fairways;recognizing and exploiting thin bedded low resistivity pay.
The Barmer Basin is a failed continental rift of late Cretaceous–Eocene age in Rajasthan, NW India, containing prolific hydrocarbon resources, with 33 discoveries having been made in the last decade. The basin is predominantly oil-prone, although gas discoveries have been made in the deeper parts of the basin. Oils in the Barmer Basin are highly waxy, a result of the lacustrine nature of the source rocks that dominate the sedimentary fill of the basin. Detailed interpretation of the molecular composition of the oils defines three main oil groups that can be related to differing sources. The oils are all distinctively lacustrine in origin, although differing in specific source-facies characteristics. All of the oils are isotopically light, mostly in the −29‰ to −33‰ range.
Most oils in the northern Barmer Basin (groups 1A and 1B) are interpreted to have been generated from the Late Paleocene Barmer Hill Formation, an excellent oil-prone source rock with predominantly Type I lacustrine algal and bacterial kerogen. Group 2 oils are subordinate in abundance, occurring only in the southern part of the basin, and are interpreted to be at least partly sourced from the overlying Early Eocene Dharvi Dungar Formation, which is characterized by mixed Type I and Type III kerogen, and attains oil maturity only in the southern basin. Group 3 oils are less common, and are of higher maturity than the Group 1 oils, but also appear to have been generated from the Barmer Hill Formation where it was buried more deeply in the central and southern parts of the basin. However, recognition of probable Mesozoic sediments in sub-basins beneath the Tertiary Barmer Basin introduces a further source-rock candidate for the Group 3 oils. A high maturity hydrocarbon charge that is recognized in the gasoline-range hydrocarbons in the Group 2 oils of the southern Barmer Basin may also be from a Mesozoic source rock, or from the Barmer Hill Formation that is much more deeply buried in this part of the basin than in the north, and represents a more mixed oil- and gas-prone source.
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