Sarah E. Gasda

Quantitative estimation of CO2 leakage from geological storage: Analytical models, numerical models, and data needs

Publisher Summary This chapter focuses on development of large-scale modeling tools to quantify potential CO2 leakage along existing wells. Geological storage of CO2 is emerging as one of the most promising options for carbon mitigation. While this approach appears to be technically feasible, a comprehensive risk assessment is required to determine the overall effectiveness and possible environmental consequences of this approach. One important part of such a risk assessment is an analysis of potential leakage of injected CO2 from the formation into which is injected, to other permeable formations or to the atmosphere. Such leakage is a concern because it may contaminate existing energy, mineral, and/or groundwater resources, it may pose a hazard at the ground surface, and it will contribute to increased concentrations of CO2 in the atmosphere.

Vertically averaged approaches for CO2 migration with solubility trapping

The long-term storage security of injected carbon dioxide (CO2) is an essential component of geological carbon sequestration operations. In the postinjection phase, the mobile CO2 plume migrates in large part because of buoyancy forces, following the natural topography of the geological formation. The primary trapping mechanisms are capillary and solubility trapping, which evolve over hundreds to thousands of years and can immobilize a significant portion of the mobile CO2 plume. However, both the migration and trapping processes are inherently complex, spanning multiple spatial and temporal scales. Using an appropriate model that can capture both large-and small-scale effects is essential for understanding the role of these processes on the long-term storage security of CO2 sequestration operations. Traditional numerical models quickly become prohibitively expensive for the type of large-scale, long-term modeling that is necessary for characterizing the migration and immobilization of CO2 during the postinjection period. We present an alternative modeling option that combines vertically integrated governing equations with an upscaled representation of the dissolution-convection process. With this approach, we demonstrate the effect of different modeling choices for typical large-scale geological systems and show that practical calculations can be performed at the temporal and spatial scales of interest. Abstract: Multiscale methods can in many cases be viewed as special types of domain decomposition preconditioners. The localisation approximations introduced within the multiscale framework are

Leakage of CO 2 Through Abandoned Wells: Role of Corrosion of Cement

The potential leakage of CO 2 from a geological storage site through existing wells represents a major concern. An analysis of well distribution in the Viking Formation in the Alberta basin, a mature sedimentary basin representative for North American basins, shows that a CO 2 plume and/or acidified brine may encounter up to several hundred wells. If carbon dioxide is geologically stored in regions, such as this, that have experienced intensive exploration for petroleum products, the acidified brine will come into contact with numerous abandoned wells. Corrosion of the cement that seals the well could lead to rapid leakage, so it is essential to determine the duration and intensity of exposure to the acid. Detailed numerical simulations with Dynaflow, incorporating a flash calculation to find the phase distribution and speciation in the brine, indicate that the carbonated brine may spend years in contact with the cement in abandoned wells. Preliminary results from an ongoing experimental study of cement corrosion indicate that the rate of attack is rapid, when the pH of the solution is low, so the risk of leakage will be high if the acidic brine can flow through an annulus and bring fresh acid into contact with the cement.

Upslope plume migration and implications for geological CO2 sequestration in deep, saline aquifers

Recent investigations regarding CO2 sequestration in deep saline aquifers have focused on characterization of the injected plume, its migration within the aquifer over time, and possible leakage out of the aquifer. To study these complex flow systems, simplified models are sometimes used to describe both plume evolution and the amount of leakage. Simplifications may include an assumption of perfectly horizontal geological formations, negligible capillary pressure, and symmetry of the injection plume. In this study, we explicitly test the limits of the assumption of a horizontal aquifer through numerical simulation of typical injection scenarios in continental sedimentary basins. Our approach is to simulate injection of CO2 into a confined saline aquifer for an extended period (we have used 15 years) and examine the effect of different degrees of slope, as well as other system parameters, on plume asymmetry using measures such as the location of the centroid of the CO2 plume. Dimensional analysis of this system shows that the centroid migrates upslope in proportion with buoyancy, aquifer permeability, and slope, whereas increased porosity and CO2 viscosity mitigate upslope migration of the centroid. The results of this study show that the effect of slope can be ignored for many aquifers likely to become CO2 sequestration sites in North America. However, slope will be more important for higher permeability aquifers, such as the site used in the Sleipner sequestration project in the North Sea.

Modelling Geomechanical Impact of CO2 Injection and Migration Using Precomputed Response Functions

When injecting CO2 or other fluids into a geological formation, pressure plays an important role both as a driver of flow and as a risk factor for mechanical integrity. The full effect of geomechanics on aquifer flow can only be captured using a coupled flow-geomechanics model. In order to solve this computationally expensive system, various strategies have been put forward over the years, with some of the best current methods based on sequential splitting. In this present work, we seek to approximate the full geomechanics effect on flow without the need of coupling with a geomechanics solver during simulation. We do this by means of precomputed pressure response functions. At grid model generation time, a geomechanics solver is used to compute the mechanical response of the aquifer for a set of pressure fields. The relevant information from these responses is then stored in a compact form and embedded with the grid model. We test the accuracy and computational performance of our approach on a simple 2D model and a more complex 3D model, and compare the results with those produced by a fully coupled approach as well as from as simple decoupled method based on Geertsmas uniaxial expansion coefficient.

Vertically integrated models with coupled thermal processes

CO2 storage in geological formations involves coupled processes that affect the migration and ultimate fate of injected CO2 over multiple length and time scales. For example, coupling of thermal and mechanical process has implications for storage security, including thermally induced fracturing and loss of caprock integrity in the near wellbore environment. This may occur when CO2 is injected at a different temperature than reservoir conditions, e.g. Snohvit injection, potentially leading to large temperature, density and volume changes within the plume over space and time. In addition, thermally induced density changes also impacts plume buoyancy that may affect large-scale migration patterns in gravity-driven systems such as Utsira storage site. This interaction becomes particularly important at temperatures and pressures near the critical point. Therefore, coupling thermal processes with fluid flow should be considered in order to correctly capture plume migration and trapping within the reservoir. A practical modeling approach for CO2 storage at the field scale is the vertical-equilibrium (VE) model, which solves partially integrated conservation equations for flow in two lateral dimensions. This class of models is well suited for strongly segregated flows, as can be the case for CO2 injection. In this paper, we extend the classical VE model to non-isothermal systems by vertically integrating the coupled heat transport equations, focusing on the thermal processes that most impact the CO2 plume. The model allows for heat exchange between the CO2 plume and the surrounding environment assuming thermal equilibrium across the plume thickness for relatively thin plumes. We investigate the validity of simplifying assumptions required to reconstruct the fine-scale thermal structure from the coarse-scale model solution. The model concept is verified for relatively simple systems. The results of this work demonstrate the potential for reduced models to advance our understanding of the impact of thermal processes in realistic storage systems.

Dense, viscous brine behavior in heterogeneous porous medium systems

The behavior of dense, viscous calcium bromide brine solutions used to remediate systems contaminated with dense nonaqueous phase liquids (DNAPLs) is considered in laboratory and field porous medium systems. The density and viscosity of brine solutions are experimentally investigated and functional forms fit over a wide range of mass fractions. A density of 1.7 times, and a corresponding viscosity of 6.3 times, that of water is obtained at a calcium bromide mass fraction of 0.53. A three-dimensional laboratory cell is used to investigate the establishment, persistence, and rate of removal of a stratified dense brine layer in a controlled system. Results from a field-scale experiment performed at the Dover National Test Site are used to investigate the ability to establish and maintain a dense brine layer as a component of a DNAPL recovery strategy, and to recover the brine at sufficiently high mass fractions to support the economical reuse of the brine. The results of both laboratory and field experiments show that a dense brine layer can be established, maintained, and recovered to a significant extent. Regions of unstable density profiles are shown to develop and persist in the field-scale experiment, which we attribute to regions of low hydraulic conductivity. The saturated-unsaturated, variable-density groundwater flow simulation code SUTRA is modified to describe the system of interest, and used to compare simulations to experimental observations and to investigate certain unobserved aspects of these complex systems. The model results show that the standard model formulation is not appropriate for capturing the behavior of sharp density gradients observed during the dense brine experiments.

Upscaled Models for CO2 Migration in Geological Formations with Structural Heterogeneity

Geological carbon sequestration involves large-scale CO2 migration and immobilization within geometrically heterogeneous storage formations. Recent modeling studies have shown that structural features along the upper boundary of a storage formation can significantly decrease updip CO2 migration speed and increase structural trapping. This impact depends on caprock roughness, which can be present at different spatial scales--from seismic-resolution features such as domes, traps, and spill points to centimeter-scale rugosity observed at outcrops. The ability to resolve all relevant features within large-scale domains is not always practical, and thus upscaled modeling approaches may be required. We propose an alternative modeling approach, the VE model, which is based on the vertical equilibrium assumption. This type of simulator is well suited for modeling CO2 migration in gravity-dominated systems. The Utsira Formation is one such system due to the strong buoyancy effects are observed in the seismic data. We use 4D seismic data and our VE modeling tool to understand the physical parameters that control CO2 migration in the Utsira. Given the uncertainty in some important parameters--CO2 density, porosity, and topography of the top Utsira--we determine the range of uncertainty in CO2 and rock properties that is supported by the data.

Significance of slope on CO2 sequestration in deep sedimentary formations

Recent investigations regarding CO2 sequestration in deep, saline aquifers have focused on characterization of the injected plume, its migration within the aquifer over time, and possible leakage out of the aquifer. As part of our efforts to understand and quantify leakage potential in CO2 storage systems, a semi-analytical solution has been developed that describes the plume shape evolution as well the amount of leakage, with a focus on leakage along abandoned wells. The semi-analytical solutions require a number of simplifying assumptions, including a perfectly horizontal aquifer, negligible capillary pressure, and symmetry of the injection plume. Each of these assumptions can be tested systematically through application of more general numerical simulators. For example, in typical sedimentary basins, it is common to have sloping aquifers with a vertical rise of up to 3-4 km over the total horizontal length of the basin (hundreds of kilometers). Although the slope may only be 1% or less, the effects on the upward migration of the CO2 plume may be significant over the time scales appropriate for carbon sequestration. Similarly, the role of capillarity in these systems may be significant due to capillary diffusion or to capillary exclusion. In this study, we use a general two-phase numerical simulator to assess the limitations of the assumptions required to derive semi-analytical solutions to these systems. For example, we can simulate injection of CO2 into a confined saline aquifer for an extended period (we have used 30 years) and examine the effect of different degrees of slope on the centroid and maximum upslope extent of the plume. These measures of plume asymmetry can then be related to an appropriate dimensionless grouping that takes into account the fluid properties and aquifer characteristics. In this presentation we will present results from these simulations and discuss their implications regarding the extent to which CO2 injection systems can be simplified.

Chapter 10 – Leakage of CO2 Through Abandoned Wells: Role of Corrosion of Cement

The potential leakage of CO 2 from a geological storage site through existing wells represents a major concern. An analysis of well distribution in the Viking Formation in the Alberta basin, a mature sedimentary basin representative for North American basins, shows that a CO 2 plume and/or acidified brine may encounter up to several hundred wells. If carbon dioxide is geologically stored in regions, such as this, that have experienced intensive exploration for petroleum products, the acidified brine will come into contact with numerous abandoned wells. Corrosion of the cement that seals the well could lead to rapid leakage, so it is essential to determine the duration and intensity of exposure to the acid. Detailed numerical simulations with Dynaflow, incorporating a flash calculation to find the phase distribution and speciation in the brine, indicate that the carbonated brine may spend years in contact with the cement in abandoned wells. Preliminary results from an ongoing experimental study of cement corrosion indicate that the rate of attack is rapid, when the pH of the solution is low, so the risk of leakage will be high if the acidic brine can flow through an annulus and bring fresh acid into contact with the cement.