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ABSTRACT: Wellbore integrity to ensure efficient, economical, and environmentally friendly operations is a significant and fundamental challenge for CO2 sequestration wells. The carbonation reaction between Portland cement and CO2 can change the microstructure of the cement skeleton, change the cement mechanical properties, damage the annular seal, and finally induce CO2 leakage. This study utilizes an integrated approach including a CO2-cement degradation test, mechanical tests for strength and elastic properties, X-Ray Fluorescence (XRF) and X-Ray Diffraction (XRD) for composition analysis, and finite element analysis for failure evaluation. The mechanical test results show that the carbonation reaction can improve the sealing effect of the cement during the early stage of degradation (~2 weeks). Mechanical and geochemistry test results show that the carbonation reaction would fundamentally change the composition and microstructure of the cement matrix after long-term CO2 degradation, thereby inducing significant decreases in strength, and enhanced porosity, and permeability. The numerical results indicate that during long-term CO2 injection, the sealing effect of the cement would decrease gradually, and the cement sheath is more likely to fail under external loads arising from wellbore pressure and temperature variations. The mechanical and geochemical test results also show that the temporal variations of cement strength and Ca2+ composition have a strong similarity, which should be further analyzed for possible correlation. In summary, this study provides an integrated approach to qualitatively and quantitatively evaluate the cement degradation and predict failure of CO2 sequestration wells. The allowable wellbore pressure and temperature ranges can be provided for different degrees of cement sheath degradation to assist the field operations and cement slurry design of CO2 sequestration wells. 1. INTRODUCTION The unwanted leakage from the CO2-injection wells impedes the stable and economic industrialization of the CO2 geological sequestration. Therefore, maintaining wellbore integrity becomes a priority task to ensure a successful CO2 sequestration project (Zhang et al. 2019, Xu et al. 2022). For CO2-injection wells, the carbonation reaction between Portland cement and CO2 is a complicated process controlled by CO2 concentration, presence of water, age of the cement, pressure, temperature, and the level of intactness of the cement matrix (Zhang et al. 2021, 2022a). Oilwell cement and CO2 reaction have been extensively investigated by various laboratory studies, including the influence of pressure and temperature (Barlet-Gouedard et al. 2006; Omosebi et al. 2017), reaction period (Barlet-Gouedard et al. 2006), and presence of various additives (Barlet-Gouedard et al. 2006). The major chemical reactions between CO2 and different compositions in the cement are presented in Figure 1 and Equation 1 to 5 (Kashef-Haghighi et al. 2015).

ABSTRACT: Conducting safe and effective waste disposal and sequestration processes relies on an accurate determination of the reservoir extent and the prevailing boundary conditions. Due to the limitations surrounding the acquisition and analysis of the reservoir geometry, waste disposal, cuttings re-injection, and CO2 sequestration studies are based on simplifying assumptions regarding the lateral and vertical fluid flow boundary conditions. These assumptions can jeopardize the study’s outcomes, especially for green fields. Common boundary conditions considered are limited to either open (steady-state) or closed (semi-steady state) lateral boundaries, alongside a complete or partially sealing caprock. This study uses pressure transient analysis to provide a quantitative tool to assess a wider variety of fluid flow boundary conditions. We show that a short drawdown followed by a pro-longed buildup test can identify the fluid flow boundary condition, including closed, open, semi-open, and infinite systems. The significant difference in CO2 storage capacity and the different geomechanical risks associated with various fluid flow boundary conditions suggest that the presented methodology should be considered prior to fluid injection scenarios. 1 INTRODUCTION Geologic sequestration is an increasingly important strategy to dispose of drilling fluids, saltwater, and hazardous waste and to reduce the CO2 concentration in the atmosphere (Mortezaei et al., 2021). The most viable CO2 sequestration targets include deep saline aquifers and mature hydrocarbon fields (Garcia et al., 2010; Sarhosis et al., 2018; Bachu, 2003; Holloway, 2001; Holloway and Savage, 1993; Klara et al., 2003). The fluid flow boundary conditions of the target storage medium need to be known to predict the target formation’s storage capacity, the spreading of the injected plume, and the geomechanical risks associated with the pore pressure increase. The current practices commonly consider an assortment of simplified boundary conditions that include open and closed boundaries when it comes to sequestration.

CO2 sequestration and injection projects are being intensively studied and conducted throughout the world. The CO2 has to be trapped below a caprock and the trap itself occurs in a complex geological setting which creates a complex geometrical model. Increased pore pressure may result in uplift of the formation and generation of new fractures or reactivation of existing structures that will generate preferred fluid flow pathways along which dissolved CO2 which may escape into the atmosphere or freshwater zones above, or result in seismicity in the region. In order to assess and mitigate these geomechanical risks, a thorough simulation coupling fluid flow through porous media and geomechanics of a realistic representation of the reservoir as well as the overburden is required. Many aspects of geomechanics and reservoir simulation coupling has been studied using idealized horizontal layer basin structures that share the same discretization of the reservoir for the two simulators, and few modeling studies of real reservoirs are carried out, but limited effort has been made for mitigating the fractures forming at the cap rock in a real reservoir. The shared earth model of a candidate shallow CO2 sequestration site in the state of Missouri was separately discretized before coupled simulation in the finite element software and reservoir simulator predicted fracture formations. A coupling module was developed which uses the relative spatial position of Finite Element nodes compared to Finite Difference grid blocks to relate the two simulation grids. Fluid flow properties such as reservoir pressure and fluid saturations are taken from the reservoir simulation and are fed into the finite element simulation model, from which a new state of stress together with new porosities and pseudo compressibility values are calculated and are used to update the reservoir model. Results of this study are used for predicting the best CO2 injection location and injection rates to provide maximum storage capacity and injection rates for safe sequestration. This approach also predicts the critical pore pressures which result in formation of extensional or shear fractures at different places in caprock. This knowledge is then used for determining type, time and amount of sealant to inject for mitigation of flow through caprock fractures so that storage of CO2 at required injection rate is maintained.