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This paper presents a hydrocarbon volumetric assessment approach for multiphase reservoirs. The methodology is based upon mass material balance in both gas condensate and wet gas systems and permits for oil/condensate volumetric determination utilizing a novel concept referred to as pseudo formation volume factor (Bo*). This method allows for a continuous oil/condensate volumetric assessment across all four hydrocarbon phases: black oil, volatile oil, gas condensate, and wet gas. A Duvernay field application example is presented. In conventional oil/condensate volumetric methods, a discontinuity is observed at the boundary between undersaturated gas and oil systems when you move across the mapped phases. The discontinuity results from an inconsistent oil/condensate volumetric approach between oil and gas primary phases. Oil/condensate volumetrics is a function of an oil formation volume factor (Bo) in oil systems while, in comparison, a function of a condensate-gas ratio (CGR) in gas systems. This volumetric assessment inconsistency is exemplified in areas of multiple phases, where operators are mapping oil/condensate from wet gas to black oil over a localized area. Realistically, a distinct boundary between in-situ fluid phases does not exist; rather, this change in phase is gradual. The traditional Bo is a volumetric comparison of the live-oil volume to the dead-oil volume of an equivalent unit mass of oil. Evolved gas from the live-oil volume creates the volumetric shrinkage observed within the dead-oil volume. The fundamental basis of the Bo is a mass material balance and can be expressed as a ratio of the dead-oil density to the live-oil density if the mass of evolved gas is accounted for. The Bo* approach applies the same mass material balance concept to the recovered standard condition condensate within the gas-condensate and wet gas system. This condensate shrinkage concept, however, is not based upon the evolved gas from the oil, since the primary phase is gas in the gas-condensate and wet gas systems. In contrast, the Bo* concept is a density comparison of the standard condition condensate recovered at the surface to its associated density in the gas phase at downhole pressure and temperature conditions. The fundamental assumption in the Bo* mass balance solution is ideal gas behavior. The gross live-fluid gas density is corrected to the live-fluid gas density of the standard condition condensate only. This is based upon a liquid component mass balance ratio within the recombined fluid, applied to the gross live-fluid density. The Bo* however, can also be algebraically solved for, which is the recommended approach. Like the traditional Bo, the Bo* is a strong predictive function of the mapped initial gas-oil ratio (GOR). An apparent boundary transition between the Bo and Bo* correlations is observed in the expected 3,200 SCF/STB range of GOR. Both the Bo and the Bo* can also be predictively linked to the hydrocarbon maturity, pressure, and temperature mapping. Hydrocarbon volumetric assessment utilizing the Bo* approach determines oil/condensate volumes by applying a Bo (oil phase) or Bo* (gas phase), correlated to a mapped predictive variable such as GOR. Gas volumes are subsequently a function of the calculated oil/condensate in-place and the mapped GOR. The Bo* approach is volumetrically equivalent to a traditional volumetric approach in gas systems and is based upon fundamental mass balance concepts. The advantage of the Bo* methodology is the ability to consistently and continuously assess oil/condensate volumetrics across contiguous oil and gas phase windows. |
