Porosity estimation in kerogen-bearing shale gas reservoirs

Abstract

Porosity is a fundamental petrophysical parameter in shale gas reservoirs that governs the space for hydrocarbon storage, and directly determines the free gas amount and absorbed gas capability. Technically, in kerogen-bearing shales, well-log derived porosity may yield inaccurate results as the porosity tools in response to both the kerogen and the liquid-filled pore spaces that are often undifferentiated. In this paper, we propose a new method for porosity estimation in kerogen-bearing shales, where porosity is assumed to be composed of both matrix porosity and kerogen porosity. The kerogen responses of density, sonic and neutron logs are first calculated from experimental data to calibrate porosity logs with the kerogen volume. The matrix porosity is then computed using the improved Wyllie equation based on the calibrated logging data with the kerogen influence removed. The kerogen porosity is estimated by a mass-balance relation based on the original total organic carbon (TOCo) and kerogen maturity characterized by the percentage of convertible organic carbon (Cc) and the transformation ratio (TR). Application of the new method to a shale gas reservoir in the Ordos Basin, China shows that the estimated porosity matches the core derived porosity satisfactorily well. Furthermore, the results also indicate that the shale kerogen porosity is relatively higher than the shale matrix porosity when the kerogen amount and maturity are high. The results of the study lead to a better understanding of the shale formation and thus contribute towards the better evaluation of shale gas reservoirs.