New perspectives on supercritical methane adsorption in shales and associated thermodynamics

Understanding methane adsorption behavior in shales is fundamental for optimizing shale gas development as the adsorbed methane is a large portion of the subsurface shale gas resource. However, the adsorption mechanism of supercritical methane in shales and associated thermodynamics are poorly understood because the equation of state of the adsorbed methane is unmeasurable. This work analyzed adsorption equilibria (up to 32 MPa and 393.15 K) using a rigorous framework that can account for non-ideal gas properties and accurately extrapolate absolute adsorption uptakes from measured adsorption isotherms. The framework also allows a straightforward calculation of thermodynamic potentials relevant to adsorption such as enthalpy and entropy. Modelling results show that methane adsorption isotherms in shale under different pressures and temperatures are represented by a two dimensional adsorption isotherm surface. The density of the adsorbed methane in shales depends on temperature and pressure, which is always lower than the liquid methane density but higher than the corresponding gaseous methane density. The temperature-dependent and pressure-dependent characteristics of adsorbed methane density leads to the corresponding temperature-dependent and pressure-dependent measured/absolute adsorption isotherms. The maximum adsorption uptake of shales is independent of temperature and pressure. The isosteric enthalpy/entropy of adsorption and enthalpy/entropy of adsorbed methane are found to be temperature- and surface coverage-dependent. These new findings therefore not only clarify some historical misunderstandings of methane adsorption in shales for engineering application, but also provide a novel framework for interpreting methane adsorption behavior in shales and for determining the associated thermodynamics

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Application of laser scanning for rock mass characterization and discrete fracture network generation in an underground limestone mine

Terrestrial laser scanning (TLS) is a useful technology for rock mass characterization. A laser scanner produces a massive point cloud of a scanned area, such as an exposed rock surface in an underground tunnel, with millimeter precision. The density of the point cloud depends on several parameters from both the TLS operational conditions and the specifications of the project, such as the resolution and the quality of the laser scan, the section of the tunnel, the distance between scanning stations, and the purpose of the scans. One purpose of the scan can be to characterize the rock mass and statistically analyze the discontinuities that compose it for further discontinuous modeling. In these instances, additional data processing and a detailed analysis should be performed on the point cloud to extract the parameters to define a discrete fracture network (DFN) for each discontinuity set. I-site studio is a point cloud processing software that allows users to edit and process laser scans. This software contains a set of geotechnical analysis tools that assist engineers during the structural mapping process, allowing for greater and more representative data regarding the structural information of the rock mass, which may be used for generating DFNs. This paper presents the procedures used during a laser scan for characterizing discontinuities in an underground limestone mine and the results of the scan as applied to the generation of DFNs for further discontinuous modeling. Keywords: Rock mass characterization, Laser scanning, Discrete fracture network, I-site studi

Determining Coalbed Methane Production and Composition from Individual Stacked Coal Seams in a Multi-Zone Completed Gas Well

This work proposes a novel and cost-effective approach to determine coalbed methane (CBM) production and composition from individual coal seams in a multi-zone completed CBM well. The novel method uses water to cover individual coal seams in a low pressure CBM well followed by an Echometer fluid level survey to determine the water level. Corresponding gas flow measurements and natural gas chromatography analysis are used to determine gas production and composition from unique zones. A field test using this technology is conducted in Central Appalachia for a multi-zone CBM well containing 18 coal seams. Test results show that the shallow coal seams contribute the majority of the total CBM production in this multi-zone well, and the deeper coal seams contain more heavy hydrocarbons like ethane and propane

Adsorption Models for Methane in Shales: Review, Comparison, and Application

Finding an optimized adsorption model to estimate the true adsorbed quantity of methane in shale at reservoir conditions is fundamental for estimating the gas-in-place (GIP), and developing an accurate shale gas transport model. However, describing true methane adsorption behavior in shale is challenging because the density or volume of the adsorbed phase cannot be measured directly using current technology. There are several models available to describe the observed adsorption isotherms and extrapolate the true adsorbed quantity of methane, but a consensus model has not been reached by researchers. This work first revisits available absolute and Gibbs excess adsorption models for describing methane in shales. It then compares nine available adsorption models to assess the efficacy of each model in describing both high pressure and low pressure methane adsorption isotherms in shales. Three aspects of the adsorption model are compared: (1) the goodness-of-fit of each adsorption model, (2) interpretation of the observed test phenomena, and (3) predicted isotherms beyond test data. Comparison results show that even though the goodness-of-fit for each model is comparable, the dual-site Langmuir model is still superior to other available models in interpreting observed phenomena and extrapolating adsorption isotherms beyond test data. The successful application of the dual-site Langmuir model therefore lays the foundation for accurately estimating and extrapolating the deep gas resource and differentiating the accurate ratio of the adsorbed phase to bulk gas for use in shale gas transport models. This study also clarifies some inappropriate concepts and methods routinely used by the shale gas community

Kerogen nanoscale structure and CO2 adsorption in shale micropores

Gas storage and recovery processes in shales critically depend on nano-scale porosity and chemical composition, but information about the nanoscale pore geometry and connectivity of kerogen, insoluble organic shale matter, is largely unavailable. Using adsorption microcalorimetry, we show that once strong adsorption sites within nanoscale network are taken, gas adsorption even at very low pressure is governed by pore width rather than chemical composition. A combination of focused ion beam with scanning electron microscopy and transmission electron microscopy reveal the nanoscale structure of kerogen includes not only the ubiquitous amorphous phase but also highly graphitized sheets, fiber- and onion-like structures creating nanoscale voids accessible for gas sorption. Nanoscale structures bridge the current gap between molecular size and macropore scale in existing models for kerogen, thus allowing accurate prediction of gas sorption, storage and diffusion properties in shales