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Predicting TOC, Organic Porosity and Gas Retention Distribution in a Shale-Gas System Using Petroleum Basin Modelling

Romero-Sarmiento, Maria-Fernanda *1; Lorant, François 1; Ducros, Mathieu 1; Carpentier, Bernard 1; Rohais, Sebastien 1; Moretti, Isabelle 1
(1) IFP Energies nouvelles, Rueil-Malmaison, France.

Natural gas can be stored as a condensed phase on shale matrix and organic materials or as conventional free gas in porous spaces (Lu et al., 1995). During the last decade, gas shale have been considered as important unconventional reservoirs in which part of the gas is stored in adsorbed state (Ross and Bustin, 2007). Several processes control fractionation and indeed retention mechanisms of gas hydrocarbons as the relative solubility of petroleum compounds in kerogen (Ritter, 2003), the gas adsorption on mineral surfaces (Brothers et al., 1991), in organic matter (Lamberson and Busting, 1993) or in nanopores of vitrinite (Ritter and GrΦver, 2005). In addition, several studies have paid attention to the distribution of pore system structures to further elucidate the gas storage process in these gas shale (Loucks et al., 2009). Most nanopores in these rocks are linked to the thermal cracking of the organic matter and are observed as intraparticle organic pores. This organic contribution to the shale porosity is a good candidate for "in situ" gas storage. Gas retention can be likely controlled by the evolution of TOC in the source rock. In this work, a method is proposed to calculate, at the basin scale, the evolution of TOC, organic porosity and gas retention capacity through time and space in shale gas. Application is done on a 3D basin model of the Barnett Shales in Texas calibrated for thermal maturity on Rock-Eval and vitrinite reflectance data. In order to predict the evolution of TOC within shale, an organic carbon balance was derived from a compositional kinetic approach containing 18 classes (Behar et al., 2008). Also, gas adsorption potential on organic material was calculated using a modified-Langmuir model implemented within the basin simulator which takes into account temperature and remaining TOC. To reproduce the present-day average TOC distribution, an initial TOC map was determined by inversion of 3D calculations. Original TOC from 5 to 8 % were consistent with observed TOC and maturity stages. Accordingly, organic matter cracking would be at the origin of more a half of the total shale porosity in mature zones. Applying the modified-Langmuir law, most retained gas in the Barnett Shale is concentrated in mature areas ranging from 40 to 100 kg/m2. Under these conditions, the Barnett Shale can generate more late gas by secondary cracking and simultaneously these generated gas can be likely retained in these higher maturities zones.

 

AAPG Search and Discovery Article #90142 © 2012 AAPG Annual Convention and Exhibition, April 22-25, 2012, Long Beach, California