This paper revisits the unique Athel reservoir formation in a south Oman oil field, and gives an update on the latest hydraulic fracture treatment strategy used. To improve the understanding of fracture performance, various fracture diagnostic options have been field tested and details will also be presented.

The silicilyte reservoir in this field consists mainly of micro-crystalline silica with low matrix permeabilities (0.02 mD and lower). The slabs of rock of infra-Cambrian age are stratigraphically encased within salt and are geopressured with an initial reservoir pressure of 80,000 kPa (pressure gradient of 20 kPa/m). The formation is both a reservoir and source rock with large thicknesses up to 400m. The reservoir contains sour crude of 48 degree API gravity. The low permeability is further reduced due to abundant micro solution seams and concretions/cemented beds and numerous sealing faults and fractures. The field came on stream during 2000 and is being developed under depletion through vertical wells with multiple massive hydraulic fracture stimulation treatments. The favourable oil properties and highly undersaturated nature of the oil have been crucial features that have made economic primary depletion development possible despite the very low permeability. More wells are planned as part of the ongoing development and optimised fracture treatment design and treatment success is critical in meeting these objectives.

Pre 2006, the well design and stimulation approach of placing 2 massive fractures per well significantly improved productivity. To optimise further, the frac campaign in 2006 targeted 3 massive fractures in each of 3 wells for the first time. The initial production performance from these wells was higher than expected and a similar campaign with 3 fracs per well in each of 5 wells was carried out in 2007 to ensure adequate coverage across the pay zones. Frac campaigns continued in 2008 and 2009. The success of the fracture campaigns are key to unlocking the value of future development since similar treatment operations will also need to be applied to the gas injectors to exploit the large unproduced remaining STOIIP with miscible gas injection. Implementing this enhanced oil recovery (EOR) technique is expected to present many challenges; in particular vertical sweep efficiency.


The field, discovered in 1989 is located in the South Oman salt basin1&2, see Figure 1. To date, no analogue reservoirs have been identified other than an adjacent field at a distance of 5km away.

The Athel formation represents a unique record of the geological history for the Late PreCambrian-Early Cambrian. The reservoir formation consists mainly of micro crystalline quartz, 0.3 to 1 micron in diameter and other minerals (mica, feldspar, clay, and pyrite). The dominant lithofacies are laminated porous silicilyte, silica /carbonate cemented silicilyte and shaley silicilyte.

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