A method using Eagle Ford organic shale from Texas predicts key unconventional reservoir properties, total organic carbon (TOC), and fracture pressure gradient (FG). Applying petrophysical and rock-physics models from previous work to the available well-log data generates the required logs for calibration, i.e., shear sonic, TOC, organic porosity, and saturation. Prestack seismic data can be evaluated using synthetic forward modeling and can be conditioned further to improve AVO response. Simultaneous prestack inversion to derive acoustic-impedance (AI) and shear-impedance (SI) volumes can be run, and TOC can be derived from those volumes by linear interpolation. Fracture gradient (which also can be thought of as "frackability") is related directly to Poisson's ratio and effective stress and can be estimated from elastic properties. The fracture gradient is related nonlinearly and inversely to TOC, i.e., assuming laterally and vertically homogeneous pore-pressure distribution inside the spatially limited block of the Eagle Ford Shale, higher TOC results in lower FG and hence better frackability.

A fracture is usually assumed as a set of smooth parallel plates separated by a constant width. However, the flow characteristics of an actual fracture surface would be quite different, affected by tortuosity and the impact of surface roughness. Though several researchers have discussed the effect of friction on flow, their efforts lack corroboration from experimental data and have not converged to form a unified methodology for studying flow on a rough fracture surface. In this study, we have shown an integrated methodology, involving experiments, stochastics and numerical simulations that incorporate the fracture roughness and the friction factor, to describe flow on a rough fracture surface. Laboratory experiments were performed to support the study and the flow contributions from the matrix and the fracture were matched through modified cubic law. Observations suggest that the fracture apertures need to be distributed to accurately model the experimental results. The methodology successfully modeled fractured core experiments, which were earlier not possible through parallel plate approach. A gravity drainage experiment using an X-ray CT scan of a fractured core has also validated the methodology. Introduction The search for hydrocarbons has been expanded into harder-to-evaluate formations, where potential and profitable hydrocarbon reserves are located. The prime candidate among those is the naturally fractured reservoirs, where large quantities of reserves are still left unexplored because of the complexities associated with a fractured reservoirs. Understanding the fluid flow characteristics of fractures is very important to model flow through fractures. This requires basic knowledge of flow from core studies. This research is aimed at studying fluid flow though a single fracture from simple core experiments and provide an effective methodology to simulate the flow behavior. Previous Research Efforts Early investigators based their idea that a parallel plate concept would be utilized to understand the concept of fluid flow through fractures. The first comprehensive work on flow through open fractures was by Lomize1. He used parallel glass plates and demonstrated the validity of the cubic law as long as the flow was laminar. He introduced the concept of defining the impact of surface roughness based on empirical data. Later he developed a flow regime chart that takes into account the effects of roughness and turbulent flow in open fractures. It was Snow 2 who used this concept to simulate real fractures. Iwai 1 conducted a comprehensive study of fluid flow through a single fracture and investigated the validity of the cubic law of fluid flow through a single natural fracture. One of the important features of his experiments was that the fracture planes had contact area as well as roughness.

This paper describes an integrated workflow that determines the minimum number of petro elastic models required to adequately predict elastic properties for a given flow scale. The workflow involves the formulation of scale-dependent petro-elastic models (PEM) and petroelastic facies from well logs. Then through an error evaluation technique, determines the minimum number of PEMs required and the maximum vertical grid size limit for the flow scale. The validity of the fine scale PEMs across different scales is also tested in the workflow.Elastic properties of reservoir rocks can be predicted through petro-elastic models which relate fluid and intrinsic reservoir properties to elastic properties through mathematical functions or rock physics models. Although we would like to generate PEMs at flow scale, very often the PEMs are generated from logs that are consistent with core data. A PEM is lithology and rock fabric specific. In an upscaled flow model, the lithologies or textures are mixed. Fine scale PEMs may no longer adequately describe the elastic properties of the reservoir at flow and seismic scale.Prediction is improved in a flow model that integrates all available measurements. Scale inconsistencies of the measurements need to be addressed for better integration and prediction. In this paper we will show that through a unique and iterative approach, PEMs must be generated at flow scale for improved integration. The methodology has been tested with synthetic data and resulted in a better predictive flow scale model, which is consistent across all scale resolutions.

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