Quantitative evaluation of TOC, organic porosity and gas retention distribution in a gas shale play using petroleum system modeling: Application to the Mississippian Barnett Shale

Abstract

Shale reservoirs have not benefited from advanced modeling tools to the extent of conventional resources. Thus an approach is proposed to integrate key parameters, such as total organic carbon (TOC) content, methane adsorption and organic porosity in a basin simulator. Original TOC has an impact on both gas generated volume and gas retention within source rocks. The conversion of organic matter into hydrocarbons also creates additional intraparticle kerogen porosity in which oil and gas can be stored. In this work, a method is proposed to calculate the evolution of TOC, organic porosity and gas retention capacity (free versus adsorbed) through time in shale gas by means of petroleum system modeling. Gas adsorption potential on organic material is calculated using a Langmuir model, which accounts for pressure, temperature and remaining solid TOC. Organic porosity is calculated as the result of the change of the organic matter from solid immature kerogen to less dense fluid hydrocarbons during thermal maturation.The method is tested on a 3D basin model of the Mississippian Barnett Shale in Texas (USA). The computed organic porosity varies from 0% in immature zones, to a maximum of 4% of rock volume in organic-rich and mature zones. Computed retained methane in the Lower Barnett Shale ranges between 20 and 60 scf/t (from 1 to nearly 3 kg/m3) and is mainly concentrated in mature areas of the basin. Simulated results are consistent with available Barnett Shale data. Possible effects of assumptions made in the approach and perspectives are discussed.