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The Al Shomou Silicilyte Member (Athel Formation) in the South Oman Salt Basin shares many of the characteristics of a light, tight-oil (LTO) reservoir: it is a prolific source rock mature for light oil, it produces light oil from a very tight matrix and reservoir, and hydraulic fracking technology is required to produce the oil. What is intriguing about the Al Shomou Silicilyte, and different from other LTO reservoirs, is its position related to the Precambrian/Cambrian Boundary (PCB) and the fact that it is a ‘laminated chert’ rather than a shale. In an integrated diagenetic study we applied microstructural analyses (SEM, BSE) combined with state-of-the-art stable isotope and trace element analysis of the silicilyte matrix and fractures. Fluid inclusion microthermometry was applied to record the salinity and minimum trapping temperatures. The microstructural investigations reveal a fine lamination of the silicilyte matrix with a mean lamina thickness of ca. 20 μm consisting of predominantly organic matter-rich and finely crystalline quartz-rich layers, respectively. Authigenic, micron-sized idiomorphic quartz crystals are the main matrix components of the silicilyte. Other diagenetic phases are pyrite, apatite, dolomite, magnesite and barite cements. Porosity values based on neutron density logs and core plug data indicate porosity in the silicilyte ranges from less than 2% to almost to 40%. The majority of the pore space in the silicilyte is related to (primary) inter-crystalline pores, with locally important oversized secondary pores. Pore casts of the silica matrix show that pores are extremely irregular in three dimensions, and are generally interconnected by a complex web or meshwork of fine elongate pore throats. Mercury injection capillary data are in line with the microstructural observations suggesting two populations of pore throats, with an effective average modal diameter of 0.4 μm. The acquired geochemical data support the interpretation that the primary source of the silica is the ambient seawater rather than hydrothermal or biogenic. A maximum temperature of ca. 45°C for the formation of microcrystalline quartz in the silicilyte is good evidence that the lithification and crystallization of quartz occurred in the first 5 Ma after deposition. Several phases of brittle fracturing and mineralization occurred in response to salt tectonics during burial. The sequences of fracture-filling mineral phases (dolomite - layered chalcedony – quartz – apatite - magnesite I+II - barite – halite) indicates a complex fluid evolution after silicilyte lithification. Primary, all-liquid fluid inclusions in the fracture-filling quartz are good evidence of growth beginning at low temperatures, i.e. ≤ 50ºC. Continuous precipitation during increasing temperature and burial is documented by primary two-phase fluid inclusions in quartz cements that show brines at 50°C and first hydrocarbons at ca. 70°C. The absolute timing of each mineral phase can be constrained based on U-Pb geochronometry, and basin modelling. Secondary fluid inclusions in quartz, magnesite and barite indicate reactivation of the fracture system after peak burial temperature during the major cooling event, i.e. uplift, between 450 and 310 Ma. A number of first-order trends in porosity and reservoir-quality distribution are observed which are strongly related to the diagenetic and fluid history of the reservoir: the early in-situ generation of hydrocarbons and overpressure development arrests diagenesis and preserves matrix porosity. Chemical compaction by pressure dissolution in the flank areas could be a valid hypothesis to explain the porosity variations in the silicilitye slabs resulting in lower porosity and poorer connectivity on the flanks of the reservoir. Most of the hydrocarbon storage and production comes from intervals characterized by preserved micropores, not hydrocarbon storage in a fracture system. The absence of oil expulsion results in present-day high oil saturations. The main diagenetic modifications of the silicilyte occurred and were completed relatively early in its history, i.e. before 300 Ma. An instrumental factor for preserving matrix porosity is the difficulty for a given slab to evacuate all the fluids (water and hydrocarbons), or in other words, the very good sealing capacity of the salt embedding the slab.

Diagenesis of a light, tight-oil chert reservoir at the Ediacaran/Cambrian boundary, Sultanate of Oman