Naturally fractured carbonate reservoirs hold well over 100 billion barrels of heavy oil worldwide. Thermally Assisted Gas Oil Gravity Drainage (TAGOGD) is a new and novel thermal EOR technique, which has applicability in selected reservoirs. In conventional isothermal GOGD, vertical fractures cause the gas-oil contact in the fracture system to advance ahead of the gas-oil contact within the matrix blocks, causing the oil in these blocks to become mobile. The addition of heat in the fractures generates additional hydrocarbon gas cap, lowers the viscosity of the oil, and accelerates conventional GOGD, as seen in the 220 cp heavy-oil Qarn Alam field in Oman. Pilot results in the Qarn Alam field support the commerciality of this process, and a first-of-it's-kind steam injection project is being implemented. The economic success of the Qarn Alam project depends on the ability to credibly predict steam requirements and oil production. Two key oil production mechanisms are heat transport through the fractures and into the matrix, and subsequent gas cap generation due to thermal volatilization of the oil. The process mechanisms involved in TAGOGD were validated through laboratory experiments, while the field forecast model results were validated by history matching pilot performance data. A fully integrated workflow of fracture characterization, integrated reservoir physics, and static and dynamic modeling has enabled uncertainties and risks involved in developing the Qarn Alam field to be managed in a scenario based design approach. Introduction The Qarn Alam field is a highly fractured carbonate field that lies atop a salt diapir in Northern Oman. The 6 km long and 3 km wide field forms a relatively high-relief anticline with a N-NE by S-SW orientation. The reservoir is relatively compact dome-shaped structure, with a maximum oil column of 165 m. The main oil bearing reservoirs, the Shuaiba and Kharaib formations, are separated by a very low permeability oil bearing zone called the Hawar. The crest of the Shuaiba is located at 212 mss, and the original oil water contact is ∼375 mss. Fracturing occurs throughout all zones, and is believed to be contiguous and in hydraulic communication with a very active aquifer. The initial oil saturation is about 95% and initial water saturation is connate water. The matrix porosity is high (∼30%), while the matrix permeability ranges between 5 md-20 md. Under primary production, the reservoir produces on average about 100 m3/day of 16o API "heavy" oil, at a GOR of 10 m3/m3.

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The authors were the first to report that gas-condensate relative permeability will increase with increasing velocity. This positive rate effect, which was later confirmed by other investigators, was attributed to the coupling of the flow of the two phases and was referred to as the "positive coupling" effect. The observation was made in tests conducted at velocities where the effect of "inertia" was not significant. The objective of the latest study was to investigate the competition between the two effects of "negative inertia" and "positive coupling" on gas-condensate relative permeability at velocities up to one order of magnitude above the velocity boundary with significant inertia. The maximum tested velocity was 700 m/day, which was representative of the flow regime within fractions of a meter from the wellbore of a typical producer. The tests were conducted on different cores at various interfacial tension (IFT) values. The results have shown that "inertia" was dominant in cores saturated with 100% gas at the tested conditions. However, as the condensate saturation increased, an improvement in relative permeability due to "positive coupling" was observed over the entire range of velocities at all values of IFT tested. This resulted in the generation of unique relative permeability curves, showing decreasing relative permeability with increasing velocity at low condensate saturations, and increasing relative permeability with increasing velocity at high condensate saturations. This trend was observed mainly for the gas phase. Previously published data had indicated that inertia reduced the gas relative permeability at high velocity. The data has been used to develop empirical correlations, which relate the change of gas-condensate relative permeability to variations in fluid saturation, velocity and IFT.