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is a graduate student in geophysics at MIT. He studies the effects of large impacts on planetary evolution and is a member of the Mars Exploration Rover Athena Science Team. He also works on problems relating to the morphometry and morphogenesis of stromatolites and early skeletogenous metazoa.The stratigraphic architecture of a terminal Proterozoic carbonate ramp system (ca. 550 Ma, Nama Group, Namibia) was mapped quantitatively with digital surveying technologies. The carbonate ramp consists of a shoaling-upward ramp sequence in which thrombolite-stromatolite reefs developed at several stratigraphic levels. The reefs are associated with grainstone and heterolithic facies and exhibit diverse geometries and dimensions related to the position in the sequence-stratigraphic framework. Laterally extensive reefs with a tabular geometry developed when accommodation was relatively low, whereas discontinuous oblate dome-shaped reefs developed during times when accommodation space was relatively high. Collecting sedimentological and stratigraphic data digitally in an extensive canyon system allowed a comprehensive documentation of the three-dimensional (3-D) architecture and dimensions of the reefal buildups. Both deterministic and stochastic methods were used to extend outcrop observations to construct 3-D models that honor the observed stratigraphy. In particular, the accuracy with which dimensions of reefal buildups can be measured is critically important in the statistical modeling of the dome-shaped buildups. Calculations and corrections can be applied directly to the digital data set and serve as input during model building. The final 3-D model faithfully reproduces the outcrop distribution of facies and geological objects and has a high spatial resolution, compared GEOHORIZONS with petroleum industry reservoir models. The organization of the reefal buildups in the stratigraphic framework has direct implications for reservoir continuity and connectivity in analogous settings. The digital characterization and 3-D outcrop models presented in this article can be subsequently used to condition dynamic reservoir-simulation modeling of geologically similar areas.

The six surface-piercing salt domes of interior North Oman form prominent topographic and geological features in an otherwise flat, rocky desert environment. These domes in the central part of the Ghaba Salt Basin have been known since the 1950s but very little data has been published on them. Our geological survey in 2001 provided significant new lithological, stratigraphic, and sedimentological information on the rocks exposed in the domes. This paper provides a comprehensive overview of the morphology, geometry, structural geology and geological evolution of the salt domes. Furthermore, it incorporates relevant information from unpublished subsurface studies to place the new geological field data in the context of ongoing exploration for deep hydrocarbon plays in Oman. A wide variety of rocks is exposed in the salt domes: carbonates, clastics (conglomerates, sandstones, siltstones and clays), volcanics, evaporites and ‘caprocks’. Constituent rocks and structural style vary considerably from one dome to another, but at the surface the main lithological elements of the diapirs are carbonates and evaporites of the ‘Infracambrian’ (Late Precambrian to Early Cambrian) Ara Group, the uppermost unit of the Huqf Supergroup. Very large exotic blocks of bedded Ara carbonates––commonly hundreds of meters long––are well-exposed and form distinctive hills and ridges, thus allowing detailed field observations on intra-salt carbonate ‘stringers’ that have been carried up by rising diapiric salt. A close correlation exists between the facies of the carbonate exotics in the salt domes and Ara ‘stringer’ carbonates penetrated and extensively cored in recent deep exploration wells in the South Oman Salt Basin. This demonstrates the regional significance of the salt domes for the intra-salt ‘stringer’ hydrocarbon play in Oman. Our work has implications for the prospectivity of other ‘Infracambrian’ evaporite basins in Oman, and possibly also for time-equivalent (‘Hormuz’) salt basins elsewhere in the Middle East.

Early Palaeozoic-age non-associated gas fields operated by Petroleum Development Oman (PDO) in the Sultanate of Oman have traditionally comprised good reservoir quality sandstones located on three- or four-way dip-closed structural highs. While gas exploration success has continued over the last five years, this has been restricted to discoveries in much poorer quality ("tight") sandstone reservoirs. Significant challenges exist: target reservoirs are deep - over 4500 m (18,000 ft) with high reservoir temperatures (> 170°C). Porosities range from less than 3 to 10% with (ambient) permeabilities ranging from 0.001 to 1 mD. These tight reservoirs have elevated pressures (above hydrostatic) and many wells record GDT (Gas-Down-To) situations (i.e. no GWC recorded). Furthermore, basin modelling indicates that peak hydrocarbon generation occurred during the Palaeozoic and Mesozoic and may have continued until Early Tertiary times in some areas. A study was started in 2008 to analyse the above data applying a range of techniques including basin modelling, geochemistry, regional well results evaluation together with pressure data analysis and comparison with global analogues. This resulted in approval for a four well exploration campaign to evaluate diverse locations across north Oman addressing the quest for tight gas in a basin-centre setting. Drilling of the first exploration well started in late 2009 with the aim of proving the presence of deep gas accumulations and ultimately gain an indication of commercial attractiveness. This paper presents the key criteria expected to influence the deep gas play prospectivity (i.e. presence of favourable reservoir, hydrocarbon charge and retention) and the steps to mature this opportunity. We also highlight an approach to progressing an unconventional gas opportunity in a challenging geological environment, in the Middle East, where the maturation of this resource type is currently in its infancy.

The Ara intrasalt carbonate ‘stringer’ play is one of oldest petroleum occurrences known in the world (terminal Neoproterozoic to Early Cambrian age), and it constitutes one of the most complex and unconventional deep oil and gas plays in Oman. The reservoirs are commonly over-pressured, and consist of porous dolomitic carbonates that are encased in salt at depths of 3–5 km. The mostly shallow-water carbonates pose a challenge; both in terms of understanding the origin and spatial distribution of the various lithofacies, and in building predictive reservoir models. In addition, early phases of salt movement influenced carbonate sedimentation and dolomitization, the sedimentation of reservoir and source-rock facies and the structural development that later governed oil migration. While the thick halite sequences provide the seal for the intra-formational trapping of hydrocarbons, the geometry of these thick salt pillows (combined with deep, present-day burial of these reservoirs) affects seismic resolution. The intrasalt stringers were previously regarded as a self-charging hydrocarbon system, containing carbonate source rocks in close proximity or even within the dolomite reservoirs. More recent documentation of a presalt charge, in some of these stringers, adds a new level of complexity to this petroleum system. Carbonate intrasalt stringer exploration in the South Oman Salt Basin (SOSB) started with the unexpected discovery of moveable oil in Nasir-1 in 1976. This launched the first phase of stringer exploration that focused on the Birba and Dhahaban areas. Despite the addition of significant reserves during this campaign, the stringer play proved to be complex. Limited knowledge of the depositional systems and diagenetic history of the stringers made the predicton of reservoir quality difficult and the understanding of production behaviors next to impossible. Difficulty in delivering expected reserves forced the play to become dormant in 1986. The second phase of stringer exploration started in 1988 after a review of deep exploration opportunities that highlighted the play potential outside the proven Birba and Dhahaban areas. All wells drilled during this phase failed to discover commercial hydrocarbon accumulations, thus forcing the play to become dormant for a second time. This short-lived campaign, however, led to the Al Noor Athel discovery, a silicious tight reservoir also encased in the Ara salt. This discovery launched an Athel exploration campaign that lasted until 1997. The Athel campaign did not result in any further commercial discoveries either, however it revived the interest in the Ara stringers with the discovery of oil in Harweel Deep-1 in 1997. Continued success in the Harweel area has maintained interest in stringer exploration to this day and has led to the fast-track development of some Harweel stringer discoveries, which are now contributing significantly to PDO’s oil production. Since 2001, the play has been tested outside the Harweel fairway with limited success. A substantial part of the prospect portfolio remains untested mostly residing outside the Harweel area. Increasing the chance of exploration success will require significant improvements in seismic imaging, better prediction of reservoir occurrence, improved produceability from discovered reservoirs, and a better understanding of hydrocarbon charge history.