Reservoir Volume Calculator

The formation volume factor represents how much a barrel of reservoir oil shrinks once it reaches the surface and dissolved gas comes out of solution, so it's defined as reservoir barrels per stock-tank barrel — always a number greater than 1. Dividing hydrocarbon pore volume by this factor converts a reservoir-condition oil volume down to the smaller stock-tank barrel volume that would actually be measured and sold at the surface.

Original oil in place is the total oil physically present in the reservoir's pore space, calculated purely from the rock's geometry and fluid properties. Recoverable reserves is a smaller number reflecting that real reservoirs never produce 100% of that oil — natural drive energy declines, some oil remains trapped in isolated pockets, and economic limits end production before full depletion — which is why a recovery factor, typically well under half, is applied on top of OOIP.

Even in a productive oil zone, some water remains permanently trapped in the smallest pore spaces and on rock surfaces due to capillary forces — this is called irreducible water saturation, and it never gets displaced or produced. Since that fraction of pore space holds water rather than oil, it has to be subtracted out of pore volume before the oil-in-place calculation, which is exactly what the hydrocarbon pore volume step does.

A volumetric estimate is only as accurate as its four input parameters — area, thickness, porosity, and water saturation — which typically come from well logs, core samples, or seismic interpretation and always carry some uncertainty, especially early in a field's life before much production data exists. That's why reservoir engineers commonly cross-check a volumetric estimate against a material-balance calculation, which uses actual production and pressure history instead of static rock properties, once enough production data is available.