Simulation and history matching of a shale gas reservoir using different models in Eagle Ford Basin

Abstract

Eagle Ford Shale in South Texas is one of the recent shale play in the US, which began developing in late 2008. To evaluate the reservoir performance and make the production forecasting for this reservoir, one multi-stage fractured horizontal well was modelled and history matching was done using the available 250 days of production data. Two different flow models of dual-porosity and multi-porosity have been examined. In the multi-porosity model, both approaches of instant and time-dependent sorption have been investigated. Also, two approaches of negative skin and transverse fractures were used to model the effect of hydraulic fracturing. For history matching of early production data, all the models were successfully matched; however, all models predict differently for production forecasting. Comparing both production forecasts for 10 years, the multi-porosity model forecasts 14% more than dual-porosity model. This is because in the dual-porosity model, only free porosity is considered and no adsorbed gas in micro-pores is assumed; in multi-porosity model, both macro and micro porosities are active in shale gas reservoir. It is concluded that the early production data is not reliable to validate the simulation and make the production forecasting. This is because in early production data, all gas are produced from the fracture system and the matrix contribution is not significant or it has not been started yet. Furthermore, the effect of matrix sub-division on the simulation was studied: the free gas in matrix can contribute to production more quickly when matrix sub-cells increase.