Abstract
Routine laboratory measurements of preserved oil-based-mud (OBM) cores are used to calibrate reservoir porosity (Φ) and water saturation (Sw). As well as being accurate in ‘clean’ sands, properly conducted OBM core analysis is also accurate in shaly-sand reservoirs. The water volume measured by laboratory Dean-Stark extraction includes physically-bound water within the clay, but not its chemically-bound water.
The OBM core porosity, Φcore, and Sw can be used together as a pair and will lead to an accurate evaluation of hydrocarbon pore volume (HPV) per unit rock volume. HPV evaluations from the OBM ‘core’ [Φcore (1 - Swcore)] and from log-derived ‘total’ porosity [Φt (1 - Swt)] and ‘effective’ porosity [Φe (1 - Swe)] methods should all give the same result.
Core data from a shaly-sand formation are compared with results from some widely-used log analysis models, including the Archie models. The original Waxman-Smits-Thomas model is discussed, but we had insufficient data to include it in the quantitative comparisons.
As tested, a reasonable quality match to the OBM core Swt and HPV is given by the Normalised Waxman-Smits and Dual-Water models and also by the Modified Simandoux, Indonesia, Simandoux and Cyberlook models, when their outputs are taken as total water saturation (Swt). If their output is taken as the usual Swe, together with Φe, their HPV results are significantly lower than those from the OBM core data.
The most accurate evaluation method, the OBM core analysis, can be used to calibrate shaly-sand log models. This process will lead to improved estimates of oil- and gas-in-place in shaly sands, and also to better resistivity-Sw models for worldwide application when OBM cores are not available.
