Favorable conclusions on the porosity, reservoir height, fluid saturations, and pressure (and implied phase distribution) of a petroleum reservoir, based on single well measurements, are insufficient for both the decision to develop the reservoir and for the establishment of an appropriate exploitation scheme.
Advances in 3-D and wellbore seismic techniques, in combination with well testing, can increase greatly the region where knowledge of the reservoir extent (with height, porosity, and saturations) is possible. Discontinuities and their locations can be detected. As more wells are drilled, additional information can enhance further the knowledge of the reservoir’s peculiarities and limits.
The areal extent is essential in the estimation of the “original-oil (or gas)-in-place.” The hydrocarbon volume, VHC, in reservoir cubic ft is
where A is the areal extent in ft2, h is the reservoir thickness in ft, ϕ is the porosity, and Sw is the water saturation. (Thus, 1 – Sw is the hydrocarbon saturation.) The porosity, height, and saturation can of course vary within the areal extent of the reservoir.
Equation (1-2) can lead to the estimation of the oil or gas volume under standard conditions after dividing by the oil formation volume factor, Bo, or the gas formation volume factor, Bg. This factor is simply a ratio of the volume of liquid or gas under reservoir conditions to the corresponding volumes under standard conditions. Thus, for oil,
where N is in stock tank barrels (STB). In Equation (1-3) the area is in acres. For gas,
where G is in standard cubic ft (SCF) and A is in ft2.
The gas formation volume factor (traditionally, res ft3/SCF), Bg, simply implies a volumetric relationship and can be calculated readily with an application of the real gas law. The gas formation volume factor is much smaller than 1.
The oil formation volume factor (res bbl/STB), Bo, is not a simple physical property. Instead, it is an empirical thermodynamic relationship allowing for the reintroduction into the liquid (at the elevated reservoir pressure) of all of the gas that would be liberated at standard conditions. Thus the oil formation volume factor is invariably larger than 1, reflecting the swelling of the oil volume because of the gas dissolution.
The reader is referred to the classic textbooks by Muskat (1949), Craft and Hawkins (revised by Terry, 1991), and Amyx, Bass, and Whiting (1960), and the newer book by Dake (1978) for further information. The present textbook assumes basic reservoir engineering knowledge as a prerequisite.
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