Natural fractures within Knox reservoirs in the Appalachian Basin: characterization and impact on poroelastic response of injection

Abstract

Understanding the distribution and orientation of natural fractures within Knox Groups is of significance in seeking potential CO2 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 CO2 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 CO2 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 CO2‐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.

The effect of natural fractures on CO2storage performance and oil recovery from CO2and WAG injection in an Appalachian basin reservoir

“…The production in the MCOF is along the western margin of faulting and fracturing of the Coshocton fracture zone 84 . Previous studies show that Copper Ridge dolomite in the MCOF is naturally fractured 44,78,85 . Natural fracture data, acquired in multiple wells in the MCOF through core description, indicate the presence of fractures in the study area 72 .…”

“…Different challenges exist when considering CO 2 or WAG injection as part of an EOR and CO 2 storage plan for carbonate reservoirs. Natural fractures may occur in carbonate reservoirs over various scales 2,43–48 . The presence of natural fractures with considerable spatial distribution across the field in low‐permeability carbonate reservoirs affects EOR and storage efficiency 45,46,49,50 .…”

The effect of Biot coefficient and elastic moduli stress–pore pressure dependency on poroelastic response to fluid injection: laboratory experiments and geomechanical modeling

“…Reservoir inflation, surface uplift, fracturing of the reservoir and/or caprock, fault activation, wellbore failure, and casing damage are examples of geomechanical‐related risks, which can have significant environmental consequences such as groundwater contamination due to CO 2 leakage, 3,4 and seismicity with possible ground motion due to fault activation 5–9 . Field tests, 2,10,11 laboratory experiments, 12–15 and geomechanical modeling 16–18 provide tools to evaluate the likelihood and severity of geomechanical responses. Before fluid injection, field tests can be used to characterize the hydromechanical characteristics of formations, fracture network parameters, as well as the state of stress in the caprock–reservoir formations 2,10 .…”

“…Geomechanical modeling is essential to assess different aspects of the geomechanical‐related risks quantitatively and ensure safety and security of CO 2 storage. The objective of the geomechanical modeling is to estimate injection‐induced stress and strain of the reservoir, caprock, and the other overlying formations up to the Earth's surface 16–18,20,21 . These geomechanical responses can then be interpreted to assess geomechanical risks.…”

“…Each approach can be selected by considering the objective of geomechanical modeling, complexity of the system (heterogeneity and anisotropy of the geological formations), and required modeling computational time. Analytical‐ and statistical‐based methods are computationally cheaper, but are constrained by the assumptions in the model (e.g., single‐phase flow modeling in a homogeneous isotropic system) 17 . Numerical solutions can be used to model multiphase flow behavior in an anisotropic heterogeneous geological system.…”