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Abstract/Excerpt

Estimations of Both Initial and Residual TOC, Organic Porosity and Gas Retention Distribution in Source Rocks Using Petroleum System Modeling: Example from the Mississippian Barnett Shale in the Fort Worth Basin, Texas

Maria-Fernanda Romero-Sarmiento, Mathieu Ducros, Bernard Carpentier, Marie-Christine Cacas-Stentz, Sylvie Pegaz-Fiornet, Sylvie Wolf, Isabelle Moretti, and Sébastien Rohais
IFP Énergies nouvelles, Direction Géologie-Géochimie-Géophysique, Rueil-Malmaison Cedex – France

The available oil and gas in place in shale-resource systems generally depends on petroleum generation potential and on hydrocarbon retention capacities. The distribution of the total organic carbon (TOC) contents has indeed a direct impact on the potential volume of hydrocarbons generated and retained within the rock since the conversion of kerogen into organic compounds creates additional porosity where oil and gas can be stored. Both adsorption process and organic porosity creation are therefore related to the initial TOC, source rock kinetics and thermal maturity distribution. Thus to better characterize a source-rock target, we have to describe accurately several phenomena such as kerogen kinetics description, kerogen pore system evolution and gas adsorption mechanisms on remaining organic matter through maturation. Today, basin modeling calculators represents a really suited alternative to quantitatively predict the oil and gas volume retained within source rocks taking into account the thermal maturation of organic matter and its structural transformation through time. The main objective of this work is therefore to propose an efficient method to calculate, at the basin scale, the evolution of TOC, organic porosity and methane retention capacity in residual organic matter through time and space in unconventional source-rocks systems by means of petroleum basin modeling. The method is tested on a 3D basin model of the Mississippian Barnett Shale in the Fort Worth Basin (Texas -USA). TOC evolution and organic porosity variations through time are computed within the Lower Barnett Shale source rock. Gas adsorption potential on organic material was calculated using a based-Langmuir model which takes into account pressure, temperature and remaining solid organic matter. We firstly determined initial TOC consistent with observed average TOC values. Then we estimated that the organic porosity varied from 0 % in immature zones, to maximum 4 % in mature zones. Results show that in a mature zone of the Lower Barnett Shale, the volume of total methane generated was determined to be, for instance, 3 kg/m3 (60 scf/t) for an average present-day TOC of 4.5 wt.%. Applying the Langmuir-type equation within the basin simulator, the adsorbed gas from the same location was estimated to comprise more than 60% of the total methane generated volume. In the model, we finally estimated at the basin scale, that the volume of adsorbed methane in the Lower Barnett Shale ranges approximately between 20 to 60 scf/t (from 1 to nearly 3 kg/m3) in mature areas.

AAPG Search and Discovery Article #120098©2013 AAPG Hedberg Conference Petroleum Systems: Modeling the Past, Planning the Future, Nice, France, October 1-5, 2012