The Ara Stringer Play in the South Oman Salt Basin contains sour oil and gas fields reservoired in<br>carbonate slabs encased within salt. Hydrocarbons occur in a depth range of 2.5 km to 5.5 km with<br>reservoir pressures ranging from hydrostatic (10-11 kPa/m) to near-lithostatic (22 kPa/m) gradients.<br>Similarly, in-situ hydrocarbon fluid densities vary widely, from 3 kPa/m to 8 kPa/m. Such variability in<br>reservoir pressure and fluid density present a challenge for the design of safe and cost-effective drilling<br>and completion strategies. Of particular concern is the combination of dry gas and hard overpressure,<br>which could lead to well head pressures of up to 100 MPa (14,500 psi) at 5km. To address this<br>uncertainty we have completed an integration of reservoir pressure data, seismic data, fluid PVT data<br>and geochemical data to allow the construction of a model for the risking of likely pressure regime and<br>hydrocarbon fluid types pre-drill.<br>Previous work has shown that stringers which have pore pressures close to a hydrostatic gradient<br>today, should have been highly overpressured prior to a “deflation” event in the geologic past. Our<br>observations on the hydrocarbon fluid characteristics support a scenario in which gas-condensate<br>accumulations have originated from a palaeo oil phase within overpressured reservoirs. These oil<br>accumulations were subsequently depressurised to allow separation and segregation of a gas phase.<br>In the event that a “deflated” stringer is re-pressurised due to further burial, the saturation pressure of<br>the mixture will be exceeded once again and the two-phase accumulation will revert back to a single<br>phase oil column. Therefore highly overpressured gas reservoirs are only expected when the oil and<br>gas phases are physically isolated prior to re-burial. Structural separation of the oil and gas legs of a<br>palaeo-accumulation in the Ara Stringer Play has been observed.<br>The consequence of a phase separation / segregation model of gas occurrence is that the density of<br>the segregated gas-condensate fluid is dependent upon the reservoir pressure (depth) at the time of<br>deflation to hydrostatic conditions. There is, therefore, a strong depth dependency to the predicted<br>fluid character, with in-situ density increasing with depth. This knowledge can be used to optimise<br>engineering decisions, rather than relying on the “worst-case scenario” of lowest density fluid<br>properties and highest reservoir pressures observed within the play.


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