History Matching and Production Data Analysis for Shale Gas and Oil Reservoirs: The Relevance of Incorporating the Correct Physics in Reservoir and Fracture Characterization

Recent research efforts have increasingly recognized the need for incorporating the correct physics to describe gas and liquids transport and phase behavior in nanoporous organic-rich shale reservoirs. However, current modeling schemes are restricted in their ability to model effects such as the influence of pore proximity on non-Darcy flow, fluid phase behavior, capillarity, heterogeneous wettability and multicomponent adsorption. Consequently, reservoir history matching, which is expected to provide insight in to the spatial distribution of rock and fracture properties, becomes less meaningful when these history-matched models are employed for reservoir performance predictions. In this work, we explore the range of over-corrections in fracture and shale matrix properties when the physics appropriate to shales is neglected. Comparisons are made for several case studies between the history matched models obtained with conventional numerical schemes and the correctly modified simulation models for shales. This investigative study reveals that the predictive capability of existing commercial simulation packages are severely compromised, thereby leading to inaccurate quantification of reserves, less success in the placement of productive wells and poor evaluations of project economics. The study described here underscores the need for the correct physics in order to quantify natural fracture densities and for improved estimation of the spatial distribution of reservoir properties and reservoir characterization in general. Introduction Production from low permeability shale gas reservoirs has become an important source of natural gas in US. During the period between 2007 and 2011, data show gross production from shale reaching 30 percent of total gross production in 2011 after comprising only 8 percent of gross production in 2007 (EIA, 2013). Transport in shales has been shown to be highly influenced by the presence of low permeability nano-pores, micro-cracks, larger fracture networks created during stimulation operation, adsorption of gas in the oil or gas wet organic matrix, non-darcy flow effects and the alteration of fluid properties due to the effect of confinement. Consequently, the development of realistic shale gas/liquid rich shale reservoir simulation models is currently a topic of active research worldwide. A realistic reservoir simulation model for shales is required to conceptualize field development strategies, evaluate reservoir performance, plan depletion strategies and evaluate facility requirements. Recent research efforts have increasingly recognized the need for incorporating the correct physics to describe gas and liquids transport and phase behavior in nanoporous organic-rich shale reservoirs. However, current modeling schemes are restricted in their ability to model effects such as the influence of pore proximity on non-darcy flow, fluid phase behavior, capillarity, heterogeneous wettability and multi-component adsorption. Gas shales primarily consist of four types of porous media; organic matter, inorganic matter, in-situ natural fracture networks and the hydraulic/induced fractures created during the stimulation operation. The organic matrix is mainly composed of kerogen and the inorganic matrix contains clay, quartz and calcite particles. The organic content in the shales is quantified in terms of the total organic carbon (TOC). TOC is measure of amount (in weight) of organic carbon present in the shale sample. TOC is generally reported in % by weight. Passey et al. (2010) showed that the grain density of organics is generally 50% to that of the rock minerals. Gas storage in organic matter is significant in