Porosity

The porosity of a porous medium is given the symbol of φ and is defined as the ratio of void space, or pore volume, to the total bulk volume of the rock. This ratio is expressed as either a fraction or a percentage. When using a value of porosity in an equation, it is nearly always expressed as a fraction. The term hydrocarbon porosity refers to that part of the porosity that contains hydrocarbon. It is the total porosity multiplied by the fraction of the pore volume that contains hydrocarbon. Porosity values range from 10% to 40% for sandstone type reservoirs and 5% to 15% for limestone type reservoirs.¹

The value of porosity is usually reported as either a total or an effective porosity, depending on the type of measurement used. The total porosity represents the total void space of the medium. The effective porosity is the amount of the void space that contributes to the flow of fluids. This is the type of porosity usually measured in the laboratory and used in calculations of fluid flow.

The laboratory methods of measuring porosity include Boyle’s law, water saturation, and organic-liquid saturation methods. Dotson, Slobod, McCreery, and Spurlock have described a porosity-check program made by 5 laboratories on 10 samples.² The average deviation of porosity from the average values was ±0.5% porosity. The accuracy of the average porosity of a reservoir as found from core analysis depends on the quality and quantity of the data available and on the uniformity of the reservoir. The average porosity is seldom known more precisely than to 1% porosity (e.g., to 5% accuracy at 20% porosity). The porosity is also calculated from indirect methods using well log data, often with the assistance of some core measurements. Ezekwe discusses the use of various types of well logs in the calculation of porosity.³ Logging techniques have the advantage of averaging larger volumes of rock than in core analysis. When calibrated with core data, they should provide average porosity figures in the same range of accuracy as core analysis. When there are variations in porosity across the reservoir, the average porosity should be found on a volume-weighted basis. In highly fractured, rubblized, or vuggy carbonate reservoirs, the highest porosity rock may be neither cored nor logged, and hydrocarbon volumes based on core or log porosity averages may be grossly underestimated.