--> A New Petrophysical Model for Shale Gas Reservoir Evaluation

2019 AAPG Eastern Section Meeting:
Energy from the Heartland

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A New Petrophysical Model for Shale Gas Reservoir Evaluation


Shale gas reservoir contains a large group of minerals as well as the organic matter, making the rock much more heterogeneous than it appears. The co-existence of multiple minerals as well as organic matter makes the interpretation of porosity and water saturation of shale gas reservoir very difficult. Another reason causing the difficulty is that gas within shale could be free gas and adsorbed gas. Lots of studies have been completed to estimate the organic matter richness measured by total organic carbon (TOC), mineral composition, mechanical properties, etc., using wireline logs. However, a well-developed, reliable method for estimating porosity of shale gas reservoir has not been designed, resulting in the limitation in shale gas reserve assessment, numerical simulation, etc. Compared to porosity interpretation, water saturation in shale has been much less discussed. This research is to propose a new petrophysical model for estimating the porosity and water saturation of shale gas reservoirs. Shale is divided into three parts: clay minerals with pores among clay minerals, non-clay minerals with pores within or among non-clay minerals, and organic matters with pores within organic matter. Fluids within these three types of pores are different due to the different origin of fluids within these pores. Assumptions should be made to support the interpretation of porosity and water saturation, including the type of fluids within the three parts, the ratio of pores within the three parts, and the physical properties of these fluids (water, free gas and adsorbed gas). SEM images and core testing are necessary to assess these assumptions and provide data for validation of the petrophysical model. The porosity can be calculated using gamma ray log, neutron porosity log, and density log with the assumptions. The water saturation can also be interpretation based on this model. A general trend of the porosity interpreted from this model is that high TOC content causes a higher porosity of shale gas reservoirs with high or over thermal maturity, and more clay volume causes a lower effective porosity. This model has been successfully used in the porosity and water saturation estimation of Marcellus Shale, southwestern PA and Longmaxi Shale, Sichuan Basin.