This paper describes the use of an under balanced drilling (UBD) system in a remote desert exploration well to directly evaluate the hydrocarbon reservoir inflow potential. The integrated sub-surface and well design team, planning, activity execution and results are discussed, with an assessment of the added value realized. The lessons learnt will be used to optimize the subsequent exploration and appraisal drilling activities, and in the longer term, optimization of subsequent field development activities.The vision is effectively to inflow test all available hydrocarbon reservoirs while drilling, thereby generating a pseudo reservoir inflow profile as a function of depth without the uncertainty of drilling induced formation damage. To achieve this objective, the available under balance drilling operating parameters and drilling fluids, were proactively controlled. This allowed the rig crew to manage the inflow while drilling, and near well bore skin damage, reducing the uncertainty to optimize the reservoir information acquired. The activity was executed in Q3 2007.Inflow testing in a known 'non damaged state' while drilling exploration and appraisal wells in desert areas remote from hydrocarbon processing and export infrastructure helps to reduce overall project risk. In low permeability reservoirs, over balance drilling induced near wellbore reservoir inflow impairment, has historically delivered inconclusive inflow data, resulting in higher project uncertainty and higher costs. UBD reservoir characterization information may be used to reduce subsequent well flow testing activities, which in turn, lowers project costs, speeds up the field appraisal process and reduces waste.

The Falher Formation in the Deep Basin area of lllestei-n Canada contains several tight gas bearing sands overlain by per-meable conglomerates. Because of the low permeability, the gas cannot be drained from the sands by horizontal flow to the well bore. however, draw-down of the conglomerate could cause the gas to move upwards into the con-glomerate and subsequently to the well bore. As this would occur over a rela-tively large area it could provide an effective method of draining the tight sands. Reservoir simulation calculations using a simple model of a homogenous sand over-lain by conglomerate, yield a recovery factor of about 80% for a one section drainage area. With an average drainage area of 3.7 sections per well, leased upon current well spacing, the recovery factor would decrease to 45% visual examination, and porosity measure-ments of core material, suggest that, except for occasional obvious shale breaks, the sands are homogenous. F!owever, log evaluation shows that shaly zones and zones of higher water saturation are present, both of which are less permeable to gas than the clean sands. Correlation of these low nermeability zones between wells was unsuccessful, and their lateral extent is therefore assumed to be less than the current well spacing. A reservoir model containing the low per-meability zones was constructed by statis-tical analysis. Their lateral extenj was assumed to be equal to half the well spacing, and their position in the vertical sequence derived from the results of log analysis of 142 conglomerate/sand inter-vals. Simulations run using these models indi-cated that with the current well density, the recovery factor would probably be about 3S%, btit could be as low as 25%.

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