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In the context of geologic carbon dioxide (CO2) sequestration, the storage effectiveness of a caprock–reservoir system is a function of the properties of both the caprock and reservoir – namely, the ability of the caprock to prevent upward leakage of CO2 (caprock sealing capability), the mechanical response of the reservoir and caprock (by evaluating in situ stress changes), and the extent and degree to which CO2 can be trapped over long periods of time. In this work, all three parameters were considered to evaluate the storage effectiveness of the Cambrian–Ordovician sequence of the Northern Appalachian Basin. We constructed a series of hydro‐mechanical models to investigate interactions between CO2 flow and geomechanical processes and to evaluate the three aspects of storage performance. Models were built to evaluate two scenarios: (1) single reservoirs with a single overlying caprock, and (2) systems comprising multiple reservoirs and multiple intermediate caprock units in addition to the primary (uppermost) caprock unit. The overall conclusion of the work is that focusing only on one aspect of storage effectiveness might not necessarily warrant long‐term CO2 storage. Results of the sensitivity analysis for the single caprock–reservoir system show that each storage effectiveness metric has its own control parameters. A comparison among three stacked caprock–reservoir systems in different parts of the study area shows that each location in the study area could be appropriate for one of the storage effectiveness metrics. Therefore, we conclude that the screening process to select the best site for CO2 sequestration should be based on an evaluation of all three metrics. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

Assessing the mechanical integrity of the caprock-reservoir system is necessary to evaluate the practical storage capacity for geologic [Formula: see text] storage. We used a combination of well-log and experimental data to estimate the statistical distribution (mean and variance) of rock mechanical properties of Cambrian-Ordovician strata within the Northern Appalachian region of Ohio and studied their heterogeneity throughout the study area. Empirical correlations between static-dynamic moduli of carbonate and sandstone formations of the Northern Appalachian Basin were developed. The state of stress (the orientation and magnitude of the maximum horizontal stress) for caprock and reservoir formations in the Cambrian-Ordovician sequence was determined at multiple well locations to understand the regional variability of these properties throughout the study area. The maximum horizontal stress ([Formula: see text]) azimuth was estimated from image logs for six wells and S-wave anisotropy data for five wells. The [Formula: see text] magnitude was estimated by analytical and numerical modeling of stresses around the wellbore calibrated to the occurrence of wellbore breakouts and drilling-induced fractures in three wells as a function of depth. The results of assessing the [Formula: see text] magnitude and stress regime in the caprock and reservoirs in the Cambrian-Ordovician sequence using rock mechanical data acquired in this study, well-log data, and drilling data indicate that both parameters vary throughout the study area. In this work, we determined how integrating different types of data from multiple wells allowed us to estimate mechanical properties and characterize the spatial variability (laterally and vertically) of in situ stress for Cambrian-Ordovician caprock and reservoirs throughout the study area. A combination of different methods — numerical, analytical, and stress polygon — is used to estimate the in situ stress magnitude, especially [Formula: see text], regionally on a formation-by-formation basis. The results of this work can be used to improve our understanding the complex nature of stress in the Northern Appalachian Basin.

Biot coefficient and elastic moduli are typically assumed to have a constant value for analyzing poroelastic effects of fluid injection. To investigate the stress-pore pressure dependency of Biot coefficient and elastic moduli, we conducted a series of laboratory experiments on a porous dolomite core sample from a reef in Michigan basin. We varied the confining stress as well as the pore pressure in the experiments. Then, modeling was performed using analytical poroelastic solutions and a coupled two-phase flow-geomechanical numerical simulation (for CO 2 injection). The modeling results show that the variability of Biot coefficient and elastic moduli should be included in the geomechanical modeling to accurately predict the poroelastic responses of injection (i.e., stress changes and surface uplift). Using a constant stress-independent Biot coefficient elastic moduli, which is the assumption in poroelastic modeling, leads to underestimation of the stress change and surface uplift due to injection compared to a realistic stress-pore pressure dependent Biot coefficient, which is updated at each time step of injection modeling. Modeling results indicate that decreasing elastic modulus combined with Biot coefficient increase due to the fluid injection could lead to a larger surface uplift and stress changes in the reservoir. In addition, the stress changes and uplift due to injection are a function of initial in situ stress due to Biot coefficient and elastic modulus stress-pore pressure dependency.

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.

CO 2 cyclic stimulation (huff and puff) is a method for increasing well productivity after primary and secondary production. In this work, we study the feasibility and estimated enhanced oil recovery of CO 2 huff and puff for light oil lowpressure and low-permeability reservoirs using numerical simulation supported by experimental and field test data. We performed CO 2 huff and puff numerical modeling to (1) understand the effect of operational and geological parameters on incremental oil recovery and (2) also history match a huff and puff pilot test. The reservoir model is based on available geologic data and experimental PVT data in depleted oil reservoirs similar to those in the Appalachian Basin. The previous huff and puff operations in the Appalachian basin have been used in a wide range of operational parameters such as CO 2 injected mass and CO 2 cycles. Simulation results in this study, using a pseudomiscible approach in a black oil model, show that the injection rate and the mixing parameter are the main parameters affecting incremental oil recovery. There is a nonlinear relationship between CO 2 injected mass (beyond 200 MT) and incremental recovery. Also, permeability heterogeneity can significantly affect CO 2 huff and puff performance and should be accounted in the model. In addition to the parametric study, numerical simulations focusing on matching primary production data and pressure data from the CO 2 injection period during a huff and puff pilot test in a depleted oil reservoir were performed with sensitivity to uncertain parameters. Homogenous and composite single wellbore models were built for the history match. Uncertain parameters include the permeability of each zone and relative permeability relationships. Simulation results of the matched model show the importance of considering bottom hole pressure during huff and puff as a matching parameter to evaluate the model's uncertain parameters (such as permeability) accurately. A comparison of the oil−water relative permeability of the matched model with the core-flood experimental data, using a Clinton sandstone core, is also discussed.

In this study, a statistical‐based methodology is used to evaluate the poroelastic effects of injection during CO2 geologic sequestration in a closed reservoir. We constructed a series of hydromechanical models to evaluate the poroelastic effect of injection by quantifying total stress changes inside the reservoir, reservoir displacement, and surface uplift. The models are representative of closed carbonate reef reservoirs of the Michigan basin. A combination of experimental design for seven independent parameters (depth, caprock and reservoir Young's modulus, caprock and reservoir Poisson's ratio, pressure, and Biot's coefficient) and response surface modeling was used to develop statistical‐based reduced‐order models. We performed 147 numerical simulations to develop simplified models. The poroelastic model responses were captured using a standard quadratic model with full interaction terms, as well as a reduced model with only statistically significant coefficients. The interpretation of reduced‐order models, using R2 loss method, shows that while surface uplift depends mainly on the depth of the reservoir, stress increase depends mainly on Biot's coefficient. The developed statistical‐based models provide a quick tool to evaluate the poroelastic effect of injection into the closed carbonate reservoirs of the Michigan basin. Reduced‐order models were then combined with a Monte Carlo simulation to perform poroelastic uncertainty analyses and achieve a better understanding of the poroelastic performance of CO2 storage in the closed carbonate system of the Michigan basin. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

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