The intrasalt Athel silicilyte is a unique source and reservoir rock found in the South Oman Salt Basin, where slabs of Athel silicilyte are entrapped in salt domes at 4 to 5 km depth. Discovered in the early 90's, the play is characterized by light and sour oil, hard overpressures (19.8 kPa/m) and a high-porosity, low-permeability silica matrix rich in organic matter. The first two wells in the Al Noor field encountered over 300m of pay with a low permeability-thickness product from well tests of 8 to 9 md-m. Reserves of 15.0 x10⁶ m³ oil were established from expectation oil-in-place of 210x10⁶ m³. Production tests have shown both the challenges and the opportunities to produce from the unique reservoir. Average flow rates encountered to-date vary between 40 to 110 m³/d before reservoir stimulation.

The Athel silicilyte is part of the Athel Formation (Vendian to Early Cambrian Huqf Supergroup) of South Oman. The palaeogeographic setting at the time of deposition was a restricted shallow-marine basin, most probably a rift-basin setting, bounded by carbonate platforms along the rift margins. The deeper parts of the basin were periodically anaerobic, resulting in the preservation of substantial amounts of organic matter and the formation of hydrocarbon source rocks of exceptional quality and thickness (SPI = 28-65 ton HC/m²), one of which is the Athel Formation silicilyte. Present-day thicker (distal) silicilyte sections tend to have a higher average porosity than thinner (proximal) sections. The highest rates of accumulation are likely to have been in the distal parts of the silicilyte half-graben setting away from the source of clastic and carbonate input.

On a reservoir scale, four main lithofacies are recognized. Typically for the silicilyte is the intercalation of finely laminated, porous silicilyte with non-porous silica-cemented silicilyte. The latter act as vertical baffles to flow within the reservoir. More than 70% of the lithofacies are thinner than 1m. Cemented fractures are locally common, reducing the horizontal connectivity. In the absence of outcrop analogues, borehole imaging logs are extensively used to delineate and to correlate reservoir units in this unconventional source-rock play. The rock matrix consists up to 80% of microcrystalline quartz with high amounts of intercrystalline microporosity (up to 30%). The very small modal crystal size of 2-3 microns results in micro Darcy permeability. The silica matrix is considered to have been biochemically precipitated as primary micro-crystalline quartz at low temperatures.

Among the Huqf Supergroup source rocks, the Athel Formation silicilyte is unique: Finely disseminated kerogen occupies up to 10% of the rock volume, with a third of the organic matter concentrated in stylolites. Source rock extracts reflect the Cambrian age of the formation: light carbon isotope ratios (-37 to -35 % PDB), a strong predominance of C₂₉ over C₂₈ steranes and high 24-isopropyl/n-propyl cholestane ratios. The kinetic behavior of the Athel is similar to that of the Monterey Formation, which, like the Athel, generates oil at low temperatures. The Athel silicilyte is associated with thick evaporites and in the center of the South Oman Salt Basin is ‘sandwiched' between two thick salt sequences. The halite seals have prevented hydrocarbon expulsion from the silicilyte, resulting in high formation pressures (19.8 kPa/m) and high present-day oil saturations (65-90%). The absence of oil expulsion is evident from Rock Eval data, which are characterized by high production indices. The good correlation between S₁ and the generative potential S₁+S₂ suggests that hydrocarbons were indeed generated in situ and did not result from migration of hydrocarbons generated at deeper horizons.

A phase 1 project is currently underway to investigate ways of improving production rates and to reduce the unit technical cost of the development of this deep, high-pressure play in order to prove economic viability. Permeability has the greatest impact on productivity, hence new technology (multi-laterals, multiple hydraulic fractures) will be tested to increase performance.

AAPG Search and Discovery Article #90937©1998 AAPG Annual Convention and Exhibition, Salt Lake City, Utah