oa Miqrat Formation (Cambrian) a Challenging, Tight Gas Play in Prograding Sheetflood Sands, Sultanate of Oman

The Miqrat Formation (middle Cambrian, Haima Supergroup) of North Oman is an identified deep, tight<br>(low permeability) gas reservoir that was deposited in an arid to semi-arid continental setting,<br>consequently it is biostratigraphically barren. It is dominated by finely interbedded, red-brown shales<br>intercalated with argillaceous and feldspathic/micaceous very fine- to fine-grained sandstones and<br>siltstones. These were deposited in alluvial and playa/lacustrine to sabkha environments with minor<br>aeolian intervals. The formation offers a variety of geological and well engineering challenges, largely<br>related to its depositional setting and age.<br>Facies relationships were controlled by a spectrum of sedimentary processes operating at different<br>scales. Important constraints, at a basin scale, are wet/dry climate cycles within a framework of<br>varying sedimentation rates and accommodation space. Developing accurate subsurface depositional<br>models is hampered by poor seismic resolution and a lack of reliable correlation events to constrain<br>palaeogeographic reconstructions and tie these to field-scale depositional models. With limited well<br>control, absence of biostratigraphic markers and non-unique wireline log characteristics, correlation of<br>similar-appearing sheetflood sands may be erroneous as these may correlate with time equivalent<br>flood margin or muddy playa deposits. The identification of correlatable markers is, therefore,<br>significant. Pilot studies applying chemostratigraphy suggest that this technique may prove to be a<br>useful tool for subdividing the Miqrat Formation.<br>Regional and in-field Miqrat well data, integrated with outcrop studies, provide the main input into<br>geological models and the basis for play maps and static reservoir modelling. However, many<br>challenges exist, especially for early appraisal activities. These include reservoir productivity<br>identification and “sweet-spotting”; assessment of gas mobility during drilling; petrophysical evaluation<br>(saturation/mobile phase identification). Additionally, the role of fractures needs to be understood in<br>achieving commercial rates, whilst fraccing and testing require innovative solutions to provide optimal<br>stimulation and reservoir assessment, respectively. Project attractiveness may rely on improvements in<br>seismic imaging, improved play models, better prediction of reservoir quality/fracture networks,<br>together with a better understanding of charge history and improved offtake rates.