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Natural fractures within Knox reservoirs in the Appalachian Basin: characterization and impact on poroelastic response of injection
Author(s) -
Raziperchikolaee Samin,
Babarinde Ola,
Sminchak Joel,
Gupta Neeraj
Publication year - 2019
Publication title -
greenhouse gases: science and technology
Language(s) - English
Resource type - Journals
SCImago Journal Rank - 0.45
H-Index - 32
ISSN - 2152-3878
DOI - 10.1002/ghg.1933
Subject(s) - geology , geomechanics , poromechanics , permeability (electromagnetism) , geotechnical engineering , rock mass classification , fracture (geology) , drilling , stress (linguistics) , structural basin , comminution , petroleum reservoir , effective stress , mineralogy , petroleum engineering , geomorphology , porosity , materials science , porous medium , linguistics , philosophy , membrane , biology , metallurgy , genetics
Understanding the distribution and orientation of natural fractures within Knox Groups is of significance in seeking potential CO 2 storage zones with high practical storage capacity. Over 700 observations of natural fractures were interpreted on acquired resistivity and acoustic image logs collected at multiple well locations ranging in depth from 730 to 3900 m in the Knox Group interval on the western flank of Appalachian Basin. We evaluated the structural parameters of the fractures using statistical analysis. Natural fracture intensity was observed to increase up‐dip within the studied area. The present day maximum horizontal stress direction was derived using the interpretation of wellbore breakouts and drilling‐induced tensile fractures in image logs. Overall, a high percentage of fractures with varying dip directions were observed to strike subparallel to the contemporary maximum horizontal stress direction. Multiphase flow–geomechanics coupled numerical simulations and poromechanics analytical solutions were then used to study pressure and stress response of CO 2 injection into the fractured Knox reservoirs. In addition, we applied a dual permeability model combined with a fracture activation model to study the permeability enhancement and its effect on injection mass increase. We also showed the line source injection solution can reasonably predict stress changes of CO 2 injection into the deep saline formations. Results were analyzed to understand the potential effect of natural fractures in sandstone formations and fractured layers in thick carbonate formations on CO 2 ‐injected mass, time‐dependent stress evolution, and the ratio of stress to pore pressure changes. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.