Review Paper/

Multiphase Modeling of Geologic Carbon Sequestration in Saline Aquifers by Karl W. Bandilla1 , Michael A. Celia2 , Jens T. Birkholzer3 , Abdullah Cihan3 , and Evan C. Leister2

Abstract Geologic carbon sequestration (GCS) is being considered as a climate change mitigation option in many future energy scenarios. Mathematical modeling is routinely used to predict subsurface CO2 and resident brine migration for the design of injection operations, to demonstrate the permanence of CO2 storage, and to show that other subsurface resources will not be degraded. Many processes impact the migration of CO2 and brine, including multiphase flow dynamics, geochemistry, and geomechanics, along with the spatial distribution of parameters such as porosity and permeability. In this article, we review a set of multiphase modeling approaches with different levels of conceptual complexity that have been used to model GCS. Model complexity ranges from coupled multiprocess models to simplified vertical equilibrium (VE) models and macroscopic invasion percolation models. The goal of this article is to give a framework of conceptual model complexity, and to show the types of modeling approaches that have been used to address specific GCS questions. Application of the modeling approaches is shown using five ongoing or proposed CO2 injection sites. For the selected sites, the majority of GCS models follow a simplified multiphase approach, especially for questions related to injection and local-scale heterogeneity. Coupled multiprocess models are only applied in one case where geomechanics have a strong impact on the flow. Owing to their computational efficiency, VE models tend to be applied at large scales. A macroscopic invasion percolation approach was used to predict the CO2 migration at one site to examine details of CO2 migration under the caprock.

Introduction Carbon capture and sequestration (CCS) is seen as a possible option to reduce anthropogenic carbon emissions in the near-term (Intergovernmental Panel on Climate Change 2005; Pacala and Socolow 2005). In CCS, carbon dioxide (CO2 ) is captured from large stationary sources (e.g., coal-fired power plants and natural gas processing) and is stored in the subsurface for long time periods, on the order of thousands of years. Saline aquifers are considered the most likely geologic carbon sequestration 1 Corresponding

author: Department of Civil and Environmental Engineering, Princeton University, Princeton, NJ 08544; 609-258-5426; [email protected] 2 Department of Civil and Environmental Engineering, Princeton University, Princeton, NJ 08544. 3 Earth Sciences Division, Lawrence Berkeley National Lab, Berkeley, CA 94720. Received May 2014, accepted November 2014. © 2015, National Ground Water Association. doi: 10.1111/gwat.12315

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(GCS) targets due to their high storage capacity and ubiquity throughout the world, and therefore sequestration in deep saline aquifers is the focus of this article. CO2 enhanced oil recovery (EOR) operations and the associated modeling are not considered in this article, as the CO2 sources for such operations are usually not anthropogenic, and the objective is not CO2 storage but increased hydrocarbon production. Figure 1 shows a conceptualization of CO2 injection into a saline aquifer. In order for CCS to be an effective carbon emission reduction strategy, the injected CO2 needs to stay isolated from the atmosphere for thousands of years. Owing to the density difference between the injected CO2 and the resident brine, CO2 migrates upward until it reaches a barrier, usually a low-permeability “caprock.” In the case of caprock imperfections, CO2 may migrate to the shallow subsurface and the atmosphere along concentrated leakage pathways (e.g., faults, fractures, and abandoned wells) and, much

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Figure 1. Conceptualization of a CO2 injection into a saline aquifer; taken from Intergovernmental Panel on Climate Change (2005).

more slowly, along sloped caprocks. Owing to the injection-induced pressure increase, high-salinity brine from the injection formation may also migrate along concentrated leakage pathways and reach the shallow subsurface. Aside from causing brine migration, the pressure increase may also cause stress changes in the rock matrix, resulting in reactivation of faults, triggering of seismic events, fracturing of the injection formation and caprock, and creation of surface uplift. Injection of CO2 into a brine-filled formation will lead to chemical reactions, including CO2 dissolving into brine and possible precipitation/dissolution of minerals. Both geochemical and geomechanical effects may impact the migration of CO2 and brine by altering flow paths (e.g., clogging existing pores or creating additional pore space through fracturing). The main questions relating to environmental safety of a subsurface CO2 injection operation are: does the injected CO2 stay contained in the subsurface; does the migration of CO2 or resident brine reach underground sources of drinking water (USDW); does the injectioninduced increase in pressure damage the caprock, re-open existing fractures and faults, or induce seismic events? In addition to the questions related to storage safety, there are also operational questions, such as: does the target formation provide sufficient storage space for the planned operation; are porosity and permeability high enough to safely accommodate the required injection rate, or are multiple wells necessary; what is the Area of Review as defined in the U.S. regulations (i.e., the area with CO2 present or where elevated formation pressure may NGWA.org

lift brine to a USDW); is active pressure management necessary to sustain the injection operation? To answer these questions one needs to understand the flow of both CO2 and brine in the subsurface. Mathematical modeling is routinely used to predict the fluid movement taking into account a variety of processes such as multiphase flow, geochemistry, and geomechanics. Different processes may need to be modeled at different spatial scales (e.g., flow in the injection formation coupled with flow along the outside of abandoned wells). Several modeling studies for GCS have been published, however usually little attention is given to the choice of the level of complexity of the conceptual model. In this article, we review a set of commonly used multiphase modeling approaches with different levels of conceptual complexity that have been applied to the problem of CO2 sequestration, and examine what types of modeling approaches have been used to answer specific questions related to carbon sequestration. The goal of this article is to present a framework for conceptual model complexity by reviewing the available GCS modeling approaches and how these approaches have been applied to a set of real and hypothetical GCS sites. To accomplish this we first present a description of existing modeling approaches that represent the relevant physical processes. Then, the application of the modeling approaches is discussed using a set of example sites. The set of example sites is not a comprehensive list of all sites (real or hypothetical) where GCS modeling has been conducted. Rather the sites are chosen to represent specific modeling challenges (e.g., high permeability at K.W. Bandilla et al. Groundwater 53, no. 3: 362–377

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Sleipner, impact of geomechanics at In Salah). Where possible, actual GCS sites are chosen to demonstrate the capabilities of available modeling approaches under realistic conditions. The article ends with a summary and a discussion of which modeling approaches are used to answer different kinds of questions.

Modeling Approaches Models for CO2 injection, migration, and possible leakage take many different forms, with a correspondingly wide range of model complexity. For CO2 injection into a deep saline aquifer, the system always involves two fluid phases, so a set of multiphase flow equations must be written. The additional system components included in the model define the level of complexity. These include decisions about: whether to include explicit models for different components of the overall phases, which leads to multicomponent equations; whether to include thermal effects; whether to include geochemistry; whether to include geomechanics; how to deal with couplings in the resulting set of equations; how to incorporate heterogeneities and what spatial scale to resolve in the system; and the overall timescale for a simulation and how that affects the processes that need to be modeled. In this section, we present a broad range of modeling options, organized in a hierarchy that moves from most complex to progressively less complex. The most complex models may need to be solved on massively parallel supercomputers, while the simplest can be solved with pencil and paper. Basic Equations Mass Balance Equation All models use some version of a mass balance equation, with one mass balance equation for each component of each phase. In most practical systems involving CO2 injection, the mass balance equations are modified by either summing them over the phases or summing over the components. When mass exchange among phases is included in the model, the equations are usually summed over the phases to write a balance equation for the total mass of each component in the system. On the other hand, if mass exchange between phases can be neglected, the equations are often written in terms of balances for each fluid phase. The volumetric flux vector needed for the mass balance equations is assumed to follow the multiphase version of Darcy’s Law. In order to create a closed system of equations, additional equations are needed, including constitutive relationships between capillary pressure and saturation and between relative permeability and saturation, and constraints such as that the phase saturation must sum to one. Typical forms for the constitutive relationships include the Brooks and Corey parameterization (Brooks and Corey 1964) and the van Genuchten-Mualem form (Mualem 1976; van Genuchten 1980). Hysteresis is often present in these functions, especially for the 364

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capillary pressure and the nonwetting phase relative permeability. Appropriate models for hysteresis, including modifications to the amount of trapped nonwetting phase (corresponding to trapped CO2 ), can be found in Land (1968); Scott et al. (1983); Spiteri et al. (2005), and Joekar-Niasar et al. (2013). Because the main fluid properties for each of the fluid phases—density and viscosity—depend on the phase pressure, temperature, and composition, equations of state need to be defined. Functional forms for brine and CO2 have been given by Span and Wagner (1996); Fenghour et al. (1998); Pruess and Spycher (2007), and Peng and Robinson (1976). A more detailed description of these multiphase multicomponent flow equations can be found in Helmig et al. (2013). Energy Equation The energy balance equation takes the same general form as the mass balance equations but with different definitions of the conserved quantities. For energy, we will usually assume local equilibrium among the phases and therefore write the energy equation summed over all phases. For the energy balance equation ,the conductive heat flux is usually expressed using a version of Fourier’s Law. Component Partitioning Equations In most CO2 -brine systems equilibrium partitioning is assumed (Fuller et al. 2006), and the partitioning is usually fairly simple, with a small amount of CO2 dissolving into the brine and a very small amount of water evaporating into the CO2 -rich phase. In these cases, when both phases are present at a location in space, the dissolved components will be at their solubility limits under equilibrium conditions. When only one phase is present, the mass fraction of the dissolved component in that phase will be at or below the solubility limit. The mass fraction of dissolved salts in the brine phase (i.e., the salinity) can also be included explicitly in the analysis. In the case of salts, there is no exchange with the CO2 -rich phase, but the salts may precipitate into the solid phase as the H2 O evaporates into the CO2 -rich phase. Geochemistry The dissolution of CO2 into the brine phase can drive a series of geochemical reactions with the rock or other solid material (e.g., well cements) present in the system. An overview of the kinds of reactions that take place can be found in Rochelle et al. (2004). From a fluid migration modeling perspective, these reactions are usually only important when they drive significant changes in flow properties (porosity, permeability, relative permeability function, and capillary pressure function). In those cases the coupling between flow and geochemistry needs to be taken into account, and both the multiphase, multicomponent fluid transport and the associated geochemical reactions need to be modeled. In cases where there is no significant effect on the flow, geochemistry can usually be ignored, unless geochemical signatures are being used NGWA.org

in a monitoring scheme. While shallow aquifers can be expected to be the primary receptors for leaking CO2 and brine, modeling of the geochemical impacts on those aquifers is usually not directly coupled to GCS models. The geochemistry of such aquifers is modeled in separate models, with the influx of CO2 and/or brine set as a boundary condition. Therefore, modeling of geochemistry in shallow aquifers is not considered in this article. Geomechanics The injection-induced changes in the stress field can lead to reactivation and creation of fractures. These fractures may have an impact on the migration of CO2 and brine through an increase of porosity and permeability. If the impact is significant, flow and geomechanics may need to be closely coupled. Changes in porosity and permeability are modeled through constitutive relationships given either by empirical analytic expressions (Davies and Davies 2001) or by differential equations (e.g., Preisig and Pr´evost 2011). In many cases the impact on flow is small, compared to other aspects of geomechanics (i.e., induced seismicity, reactivation of existing faults, and fracturing of the caprock). Unless surface deformation is of interest, geomechanical effects can often be neglected when modeling carbon sequestration. To ensure safe storage it is often sufficient to determine pressure thresholds (e.g., fracture pressure), and to design injection operations to limit the pressure increase below the threshold. For a thorough discussion of the impact of geomechanics on carbon sequestration, the reader should refer to Rutqvist (2012).

Model Complexity Hierarchy Many different forms and combinations of the basic equations discussed in the previous section have been used to simulate CO2 injection and migration, as well as potential leakage. In this section, a broad hierarchy of models is described, ranging from strongly coupled, highly resolved three-dimensional (3D) numerical simulators that require supercomputers to simple analytical solutions that can be computed with pencil and paper (Figure 2). In moving systematically through the hierarchy, the major assumptions are highlighted and the associated mathematical simplifications are described. Coupled Multiprocess Models When geomechanical and/or geochemical effects cause changes to basic flow properties like rock permeability and porosity or fluid densities, there is clearly a two-way coupling between flow and mechanics and flow and chemistry. Feedback from the flow in the rock with altered properties can drive further changes in chemistry or mechanics. Changes in temperature affect the stress field and fluid properties, and therefore heat transport may need to be included in a model. The coupling among fluid flow, heat transport, geochemistry, and geomechanics leads to the most general model formulation. The resulting system of coupled, nonlinear partial differential NGWA.org

Figure 2. Model complexity hierarchy ranging fully coupled multiprocess models to simple analytic solutions.

equations will need to be solved in its entirety, involving a very large computational effort with the concomitant need for very large amounts of parametric information and input data. Parameters will include not only all required parameters to describe the rock properties (both flow and mechanics) and the rate coefficients for the geochemical reactions, but also the feedbacks among the different processes and parameters such as changes in rock properties due to mechanics and reactions. Hysteresis in many of the parametric functional relationships may also be important and will need to be included in the equations. In simulations involving three dimensions, especially with highly resolved grid spacing, the computational requirements become very severe. As such, these kinds of complete and tightly coupled models, when available, are usually applied to answer specific research questions. In many cases, the focus of such studies is on either geomechanics or geochemistry, and the other process is neglected (e.g., Johnson et al. 2004; Rutqvist et al. 2007; Preisig and Pr´evost 2011). Highly resolved coupled models may also be used to study process details in the hope of deriving simplified relationships to be used in more practical calculations. One such example is the detailed study of convective instabilities (Huppert and Woods 1995; Lindeberg and Wessel-Berg 1997; Ennis-King and Paterson 2005; Riaz et al. 2006; Farajzadeh et al. 2007; Pruess 2008; Gasda et al. 2011). Simplified Multiphase Models For most practical calculations, some simplified version of the very general model described in the previous section is used. Two of the most common simplifications are (1) to assume that geochemical interactions with the rock do not alter the permeability or porosity significantly and do not lead to any significant precipitation of carbonates, and (2) that geomechanical effects do not alter rock properties significantly. In cases where both simplifications are applied, geochemistry is ignored and geomechanics is incorporated through K.W. Bandilla et al. Groundwater 53, no. 3: 362–377

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simple compressibility coefficients in the flow equations. To include additional simplifications, considerations of space and timescales usually play an important role. For example, a model for early times may ignore component partitioning because the amount of CO2 dissolved in brine (and the amount of H2 O dissolved in the CO2 -rich phase) will be small and might be ignored. In addition, for cases with small changes in temperature, isothermal conditions may be assumed. With these two restrictions, the resulting model simplifies considerably, and becomes a multiphase flow model that includes capillary pressure (with or without hysteresis), buoyancy, and pressuredriven flow. When component partitioning can be ignored, the equations are usually solved for phase saturation, and the primary unknowns are two phase saturations and two phase pressures. The equation set involves two mass balance equations for the two phases, Darcy’s equation for the two phases, the constraints that saturations sum to one, and relationships between capillary pressure and saturation and relative permeability and saturation. These simplifications lead to the form of many of the available simulators for multiphase flow, including simulators developed by various National Laboratories such as TOUGH2 (Pruess et al. 1999; Zhang et al. 2008), STOMP (White and Oostrom 1996), and NUFT (Nitao 1998) as well as commercial simulators such as Eclipse (Schlumberger 2010) and CMG-GEM (Computer Modelling Group 2010). It should be noted, that these multiphase simulators do not necessarily incorporate all the simplifications mentioned above. Many of the simulators allow for nonisothermal conditions and include component transport (e.g., for CO2 -brine solubility). Based on published studies, the majority of carbon sequestration modeling is conducted using simplified multiphase models. Vertical Equilibrium Models One of the most important characteristics of CO2 brine systems is the large density difference between CO2 and brine which leads to strong gravity segregation in the system. If the timescale for this gravity segregation to occur is short relative to the timescale of the overall system being modeled, it is reasonable to assume the segregation occurs very quickly (instantaneously, in the limit). The segregated system will have negligible velocity in the direction perpendicular to the top and bottom confining layers (termed vertical here, as most CO2 injection formations are close to horizontal), and the functional form of the pressure variation along that direction, for each phase, can be derived by setting the Darcy flow component in that direction to zero. Assuming that each of the phase densities is constant within the formation, the vertical pressure profile can be reconstructed based on a single pressure value. Models that use this kind of structured pressure profile are often referred to as vertical equilibrium (VE) models. Assuming VE means that the governing partial differential equations do not have to be solved along the vertical direction, so integration of the governing equations along that direction is natural. A 366

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detailed derivation of the integrated governing equations can be found in Nordbotten and Celia (2012). Based on the reconstructed pressure profiles for both CO2 and brine and the fine-scale capillary pressure function, the fine-scale saturation profiles can be reconstructed. Integration of the fine-scale saturation profile gives the coarse-scale saturation. Given that this can be done for all reconstructed pressure profiles, the result is a relationship analogous to the local capillary pressure function, but now using the integrated, or coarse-scale, variables. This coarse-scale capillary pressure function is often referred to as a pseudo-function in petroleum engineering (Lake 1989). With this coarse-scale capillary pressure function and with the constraint that the coarsescale saturation of brine and CO2 need to sum to one, the integrated equations can be solved for the four primary unknowns: the two representative phase pressures and the two integrated saturations. Note also that the fine-scale capillary pressuresaturation function dictates the shape of the vertical saturation profile. The vertical region within which the brine saturation changes from a value of 1 to a value close to its residual saturation is called the capillary transition zone. The thickness of this zone affects the functional form of the coarse-scale coefficients in the coarse-scale equations. Similar to capillary pressure, other processes that are defined at the fine scale need to be redefined to be valid at the coarse scale. For instance, while locally phase partitioning usually occurs on short timescales, so that local equilibrium is a good assumption, this is often not a good assumption when applied over the entire thickness of a formation. To capture the diffusive and convective mixing involved in coarse-scale dissolution an additional coarse-scale equation is necessary. This kind of model is described in detail in Gasda et al. (2011) and applied to a large-scale field problem in Gasda et al. (2012a). Hysteresis in the coarse-scale model can also be included by transferring the equations from the fine scale to the coarse scale (Doster et al. 2013). The resulting model can effectively deal with capillary trapping, dissolution trapping, and structural trapping. It should be noted, that most of the processes, such as mass exchange and hysteresis, are usually included in the simplified multiphase models described above, but they all apply only to a single scale (the fine scale). Simplified VE Models Analytical Solutions Additional simplifying assumptions can be made to the VE model, eventually leading to an equation that can be solved analytically or semianalytically. One such assumption is that the capillary transition zone associated with the VE saturation profile is small, so that the thickness of the transition zone can be ignored and therefore assumed to go to zero. This gives a sharp interface between the two segregated fluids. In this case, the vertically integrated relative permeability function NGWA.org

becomes a linear function of the vertically averaged saturation, independent of how nonlinear the localscale relative permeability function is. Sharp interface models provide simplified solutions, even with no other assumptions, although they generally still need to be solved numerically. Significant additional simplification can be achieved with the assumption of a horizontal, homogeneous formation with impermeable bounding formations both above and below the injection formation. In this case, a simple model for the CO2 plume shape can be derived, assuming a single vertical injection well with constant injection rate. While the resulting equation generally needs to be solved numerically, an analytic solution exists for conditions typical of CO2 injection operations. Details can be found in Nordbotten and Celia (2012). Semianalytical Solutions Including Leakage along Wells The simplified VE models presented in Section “Analytical Solutions” can be combined with large-scale solutions for pressure response in layered aquifer-aquitard systems that have some number of potentially leaky wells. The general idea is to combine the solutions of the simplified VE models discussed in Section “Analytical Solutions” to give the fundamental solution for the influence of the injection wells. In any well that is leaking, the flow along that well will lead to a pressure drawdown in the vicinity of the well, and this pressure drop must be accounted for in the overall pressure solution. The local pressure decrease will be accompanied by an upconing of the CO2 -brine interface, if CO2 is present at the leaking well. This upconing also needs to be included in the analysis—see Nordbotten and Celia (2006) for such a solution. Along any leaking well, some of the leaking fluid may escape into permeable layers that are encountered along the vertical direction. This gives a source of mass into that permeable layer (aquifer) as well as a pressure perturbation. The pressure response couples together the pressures in all layers, so that a pressure equation is solved at any given time that involves pressures at all wells in all of the permeable layers in the system. While the local pressure solutions are treated analytically, the effective coefficients in the equations change with time because of the evolution of the CO2 plume(s). This requires discrete time-stepping, to incorporate the nonlinearities into the equation set. As such, the resulting algorithm is semianalytical, because analytical solutions are used in space but discrete time steps are used to march forward in time. Details of the resulting algorithm can be found in Nordbotten et al. (2009); Dobossy et al. (2011), and Nordbotten and Celia (2012). Single-Phase Models A different simplification approach is to assume that the multiphase flow region is small compared to the modeled domain, and that multiphase flow dynamics have negligible impact on the pressure response outside of the multiphase region. Therefore, the large-scale pressure impacts of carbon sequestration can be modeled NGWA.org

using single-phase equations, with a volume-equivalent injection of brine instead of CO2 . Single-phase models have been used both for simple generic models (e.g., Zhou et al. 2009; Cihan et al. 2013) and for realistic basin-scale modeling (e.g., Nicot 2008; Huang et al. 2014). Macroscopic Percolation Models Invasion percolation (Wilkinson and Willemsen 1983), a form of percolation theory (Flory 1941; Broadbent and Hammersley 1957), is particularly suitable for simulating slow motion of immiscible fluids in porous media. In invasion percolation models the porous medium is represented by a lattice of pore bodies connected by pore throats. An invading fluid displaces a residing fluid based on fixed rules in a quasi-steady framework. The algorithm scans through the lattice for sites (i.e., pores) that are connected by a continuous path of invading fluid and that can be invaded if threshold conditions are satisfied. The lattice site with the lowest entry threshold is then filled with invading fluid, and the algorithm scans for the next connected site to invade. It should be noted, that this algorithm applies to the pore scale, which is a much finer scale than necessary for GCS modeling. To apply invasion percolation models at larger spatial scales, lattice sites may be used to represent a macroscopic domain instead of single pore (Kueper and McWhorter 1992; Yortsos et al. 1993; Ioannidis et al. 1996; Glass et al. 2001; Glass and Yarrington 2003). Each macroscopic domain is then defined by local effective properties (i.e., equivalent pore size or equivalent entry pressure, or local capillary pressuresaturation and relative permeability functions), and cells are invaded based on threshold conditions just as in pore-scale invasion percolation models. Owing to the larger scale of the macroscopic lattice sites, additional forces, such as buoyancy (Meakin et al. 1992) need to be incorporated into the threshold conditions. Also, processes that are directly modeled at the pore scale may need to be included as effective parameters (Haines 1930; Berg 1975; Frette et al. 1992; Carruthers 2003). As a result of the relatively simple underlying algorithms, the macroscopic invasion percolation models are computationally very efficient, and can therefore represent heterogeneity at resolutions that are much finer than can be used in conventional continuum-based models. However, viscous effects are not accounted for in these models. There are attempts to include viscous effects into the invasion percolation models (Carruthers and de Lind van Wijngaarden 2000; Glass et al. 2001), but further research is required to incorporate the coupled effects of capillary, buoyancy, and viscous forces into the invasion percolation models.

Model Applications The modeling approaches discussed above have been applied at several existing and planned CO2 injection sites to address questions related to GCS in deep saline aquifers. The majority of applications have occurred at K.W. Bandilla et al. Groundwater 53, no. 3: 362–377

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Table 1 Overview of Example CO2 Sequestration Sites Site

Injection Mass (Mt)

Project Purpose

References

Illinois Basin

1 5000–12,500

Sleipner

15 (ongoing since 1998 at ∼1 Mt/year) 2.5 (2008) 0.2 Mt/year since 2009 1500

Storage pilot Hypothetical basin-wide industrial storage Industrial storage

Frailey et al. 2011 Zhou et al. 2010; Person et al. 2010; Bandilla et al. 2012b Torp and Gale 2004

Storage research Storage pilot Hypothetical industrial storage

Wright 2007 Hosseini et al. 2013 Celia et al. 2011

In Salah Cranfield Wabamun Lake

the site-scale encompassing a single injection operation consisting of one or more injection wells. The models are usually used to answer questions related to plume migration, pressure build-up and storage capacity. The following three site-scale example sites (Table 1) are discussed to highlight the use of different modeling approaches: Sleipner, Cranfield, and In Salah. As CCS has not yet been deployed to the extent that multiple projects access the same formation over large areas, we discuss here basin-scale applications based on hypothetic injection operations, with the main focus on the pressure response and dynamic capacity estimates. The Illinois Basin and the Wabamun Lake area are used as examples for such basinscale models (Table 1). The list of example sites is not meant to be comprehensive, but rather to show how the modeling approaches discussed in this article have been applied to actual sites. Illinois Basin The Illinois basin is a large sedimentary basin underlying the states of Illinois and Indiana. The basal Mount Simon Sandstone formation of the Illinois Basin is a target for ongoing and planned CCS operations because of its high storage capacity and permeability. Currently, CO2 is being injected into the Mount Simon at the ADM-Decatur site as part of a pilot study. Simplified multiphase models were used to support well design and injection operations, to determine injectivity and plume development, and to analyze monitoring data (Senel and Chugunov 2012). The model included the Mount Simon Sandstone and the lower part of the Eau Claire Shale, and the petrophysical parameters varied spatially and were based on bore logs from the injection and monitoring wells and on seismic data. The modeling effort is ongoing and few results had been published at time of the writing of this article. Owing to the Mount Simon Sandstone’s large thickness, lateral extent, and high permeability along with the proximity of a large number of stationary CO2 sources, the impact of industrial-scale injection of CO2 into the Mount Simon Sandstone has been investigated in three recent studies (Birkholzer and Zhou 2009; Person et al. 2010; Zhou et al. 2010; Bandilla et al. 2012a). The focus of the studies was to determine if the Mount Simon’s 368

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storage capacity is large enough to receive hundreds of Mt of CO2 per year over a significant time, and if such a basin-wide sustained injection would negatively impact the salinity of drinking water resources developed for the Chicago metropolitan area. The study conducted at Lawrence Berkeley National Laboratory (Birkholzer and Zhou 2009; Zhou et al. 2010) used the 3D simplified multiphase flow simulator TOUGH2 to predict CO2 and brine migration induced by CO2 injection at a regional injection center in the center of the Illinois Basin, while Person et al. (2010) and Bandilla et al. (2012a) used VE simulators to model injection of CO2 at the locations of existing stationary CO2 sources. The three models had a similar lateral extent, covering between 200,000 and 300,000 km2 . In the vertical, Person et al. (2010) included the Mount Simon Sandstone only; the LBNL model included the primary caprock, whereas Bandilla et al. (2012a) also added several other overlying formations. The total injection rates varied from 80 to 200 Mt/year, with injections lasting either 50 or 100 years. The three studies came to similar conclusions regarding CO2 plume migration, with CO2 plumes remaining local to the injection sites, even over decades of postinjection modeling. The three studies also agreed that the industrial-scale CO2 injection would lead to a basin-wide pressure increase (Figure 3), although the Person et al. (2010) study predicted a much lower pressure increase than the other two studies. A detailed analysis of the studies shows that this difference can be explained by higher values of rock compressibility chosen by Person et al. (2010). Sleipner At the Sleipner injection, located in the North Sea off the coast of Norway, CO2 captured from a natural gas processing facility is injected about 1 km below the seafloor into the highly permeable Utsira Sand formation (Torp and Gale 2004). The Utsira is interspersed by several low permeable, discontinuous mudstone lenses that act as baffles for the vertical flow of CO2 . As the CO2 is injected at the bottom of the Utsira formation, it is distributed throughout the entire thickness, although the aforementioned mudstone layers lead to significant vertical structuring. Based on the NGWA.org

Figure 3. Pressure increase in the Mount Simon Sandstone after 50 years of continuous injection: (a) injection of a combined 100 Mt/year at a regional injection center (20 wells) using a simplified multiphase model (from Birkholzer & Zhou 2009), (b) injection of approximately 200 Mt/year distributed among 100 injection sites using a VE model (from Bandilla et al. 2012a).

seismic surveys nine distinct plumes within the vertical extent of the Utsira Formation can be identified, leading to the conceptualization that the Utsira sand is divided into nine sandstone layers which are separated by mudstone layers (Chadwick et al. 2004). Several modeling studies have been based on the Sleipner injection site, with modeling approaches ranging from coupled multiprocess models to invasion percolation models and VE models. Simplified 3D multiphase models were used for injectivity and capacity estimates (Baklid et al. 1996; Zweigel et al. 2000) and to show that the existence of thin mudstone baffles can explain the vertical plume structuring found from the seismic surveys (Lindeberg et al. 2000). Johnson et al. (2004) and Audigane et al. (2007) used two-dimensional (2D) multiprocess models (flow and geochemistry) to investigate solubility, convective mixing, and mineral trapping. The studies found that chemical reactions had little impact on the sandstone, while potentially decreasing porosity in the shale layers, and showed that solubility trapping was the dominant trapping mechanism, while mineral trapping could be neglected. Singh et al. (2010) and Cavanagh (2013) used macroscopic invasion percolation models that included gravitational and capillary forces to model the CO2 migration in the ninth layer and compared the results to seismic data and simplified multiphase simulators. They found that gravity and capillarity were the dominant forces which explained the relatively good match of the macroscopic invasion percolation models to the measured NGWA.org

plume footprint (Singh et al. 2010). The discrepancy between predicted and measured plumes at later times was explained by uncertainty of the caprock topography (Cavanagh 2013). Nilsen et al. (2011) compared simplified multiphase models and VE models for the top-most layer (ninth layer) of the Utsira, and found good agreement between the two modeling approaches (Figure 4); as the grid in the simplified multiphase models was refined, the difference between the simplified multiphase models and the VE models decreased. Other studies using VE models of the ninth layer include a study by Gasda et al. (2012b) to estimate sensitivity of the CO2 plume to porosity, temperature and topography, and a study by Mykkeltvedt and Nordbotten (2012) to estimate the rate of convective mixing and dissolution in the formation. In Salah At the In Salah site, located in Algeria, CO2 from a natural gas processing facility was injected into the water-leg of an active gas field (Wright 2007). Computer modeling has been used for injection design and to predict the CO2 plume migration at In Salah. For instance, Ringrose et al. (2009) used the simplified multiphase simulator Eclipse (Schlumberger 2010) to study the sooner-than-expected arrival of CO2 at a nearby monitoring well. They found that a high-permeability pathway with permeabilities on the order of 1 to 4D was necessary to explain the short arrival times, and that a fault may function as such a pathway. K.W. Bandilla et al. Groundwater 53, no. 3: 362–377

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Figure 4. CO2 saturation at the top of the ninth layer of the Utsira formation after injection of 5 × 106 m3 of CO2 over 50 years (end of injection) and 100 years after injection ceases (end of simulation) based on a simplified multiphase model and a vertical equilibrium model; taken from Nilsen et al. (2011).

Owing to relatively low permeability of the injection formation and barren land surface, the injection-induced surface uplift patterns could be established using satellite data (Vasco et al. 2010). Several coupled multiprocess modeling studies have used the surface uplift to improve the conceptual model of the injection and overlying formations. Rutqvist et al. (2010) and Rinaldi and Rutqvist (2013) coupled the flow simulator TOUGH2 and the geomechanics simulator FLAC (Figure 5). They found that while the uplift at one of the wells could be explained by deformation of the injection zone alone, the uplift at the other well required that the lower part of the caprock deformed as well. This led to the conclusion that the lower part of the caprock had to be permeable enough to allow for limited fluid flow (Rutqvist et al. 2010). Using a refined geologic model and assuming time-dependent permeability and fracture zone activation they were able to predict the surface uplift in both magnitude and pattern (Figure 5), confirming the conceptual model of a fracture zone intercepting the horizontal injection well. They also concluded that the fracture zone was confined in the caprock and did not reach the overlying aquifer (Rinaldi and Rutqvist 2013). In a different study, Morris et al. (2011) coupled the flow simulator NUFT to the geomechanics simulator 370

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SYNEF by assuming that the feedback from the deformation to the flow field was negligible. The geologic model included a set of faults intercepting the injection formation that acted either as enhanced flow paths or flow barriers. They found that a fault intersecting the well needed to be extended into the caprock to explain the surface uplift pattern. However, their model was not sensitive to the vertical extent of the fault, and therefore the authors could not determine if the fault extended into the overlying aquifer. Preisig and Pr´evost (2011) used a model of the In Salah injection site to study the impact of temperature on the creation and reactivation of fractures. Unlike the modeling studies discussed above, Preisig and Pr´evost (2011) used a fully coupled model where the governing equations for flow and geomechanics were solved simultaneously, instead of sequentially, to study the impact of temperature on the creation and reactivation of fractures. The authors found that a temperature difference between the host rock and injected CO2 of 20 ◦ C was sufficient to create fractures in the caprock that were similar to the ones observed at In Salah. Cranfield The Cranfield site, located in southwestern Mississippi (USA), is currently being operated as an EOR field NGWA.org

Figure 5. Simulated (a) and measured (b) surface uplift above injection well KB-502 at In Salah (taken from Rinaldi and Rutqvist 2013).

by Denbury Onshore, LLC. In conjunction with the EOR operations, the Southeast Regional Carbon Sequestration Partnership (SECARB) is injecting CO2 into the water-leg of the field as part of a pilot project. Choi et al. (2011) modeled the impact of the EOR operation on the most northern part of the oil field using the simplified multiphase simulator CMG-GEM (Computer Modelling Group 2010). Model pressure predictions for the EOR operation phase showed good agreement with measurements at four existing wells, and a sensitivity analysis showed that the model was not sensitive to the boundary conditions, but quite sensitive to changes in permeability. Hosseini et al. (2013) also used CMG-GEM, but the domain was limited to the vicinity of the pilot-scale injection operation including some of the EOR injection and production wells. While most chemical reactions were neglected, the exsolution/dissolution of methane and CO2 in brine was included, because the resident brine at Cranfield was found to be saturated with methane. The breakthrough times of CO2 at the monitoring wells were used as model validation. The differences between modeled and measured breakthrough times were attributed to problems with the CO2 monitoring approach. To further investigate the impact of dissolved methane on the CO2 and brine migration, Doughty and Freifeld (2013) modeled the first year of the CO2 pilot-injection at Cranfield using the simplified multiphase nonisothermal simulator TOUGH2 (Pruess et al. 1999; Zhang et al. 2008) in conjunction with the equation-of-state module EOS7C (Oldenburg et al. 2004) for CO2 , methane, and brine (Figure 6). The domain was modeled as being radially symmetric with the injection well at the center. The permeability and porosity were assumed to be constant in the radial direction, but varied in the vertical direction based on log data from the injection well. Oscillations in the predicted CO2 and methane concentrations at the monitoring wells showed that multiple distinct flow paths connect the injection well to the monitoring wells, while the temperature signal indicated the relative size of those flow paths (Doughty and Freifeld 2013). The differences between measured and modeled CO2 and NGWA.org

methane arrival times at the monitoring wells suggested that a radially symmetric description of the site may not be sufficient to capture the complexity of existing flow paths. Data from the Cranfield site are also being used to define the S3 modeling test case for the Sim-SEQ model comparison study (Mukhopadhyay et al. 2012), where modelers at several institutions are simulating the pilotscale injection operation using a variety of simulators (both simplified multiphase and VE approaches) based on the same domain characterization data. The goal of the study is to investigate how the choices by the modelers (e.g., modeling approach, inclusion of processes, and, boundary conditions) impact the model predictions. Preliminary results from the Sim-SEQ study show that the choice of modeling approach can have a strong impact on model predictions. For instance, predicted CO2 arrival times at a monitoring well varied from 19 to 57 days for the four models used in the study (Mukhopadhyay et al. 2014). Wabamun Lake Celia et al. (2011) chose Wabamun Lake, located in Alberta, Canada, as a test site to study both CO2 and brine leakage along abandoned wells. While there are currently no CCS projects in the Wabamun Lake area, the underlying geology is suitable for CO2 injection and several large stationary CO2 sources with a combined emission rate of about 30 Mt/year are located in the vicinity. A total of 1146 old wells were identified with known location and completion depth for this study (Figure 7a). The effective well permeability was associated with large uncertainty, and was therefore treated stochastically based on each well’s “deep leakage potential” as defined and quantified by Watson and Bachu (2008 and 2009). The study used a simplified VE approach in combination with a one-dimensional (1D) model for flow along the abandoned wells to determine both CO2 and brine leakage. Celia et al. (2011) found that CO2 leakage depended on the number of abandoned wells intercepted by the CO2 plume, which in turn K.W. Bandilla et al. Groundwater 53, no. 3: 362–377

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Figure 6. Model results for 365 days of CO2 injection at the Cranfield site using a radially symmetric TOUGH2 model; taken from Doughty and Freifeld (2013).

depended on the formation depth (greater depth, fewer wells) and on formation parameters controlling plume spread (e.g., permeability and porosity). They also found that vertical correlation of effective well permeability had a strong impact on leakage to the surface, as a single lowpermeability segment may prevent leakage (Figure 7b). Most of the CO2 leakage rates to the surface modeled by Celia et al. (2011) were below 0.1% of the injected mass, suggesting that leakage along abandoned wells was not a significant leakage risk in the Wabamun Lake area. It should be noted, that the large number of potentially leaky wells would have led to a large number of grid cells for a simplified multiphase model, making the kind of MonteCarlo type study of well permeability uncertainty used by Celia et al. (2011) infeasible due to high computational costs.

Summary In this article we review the most common approaches for GCS modeling and show examples of how these modeling approaches have been applied to simulate CO2 and brine migration processes at existing and planned CO2 sequestration sites. The approaches range from complex, fully coupled, 3D reservoir simulators to simplified semianalytic solutions. 372

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Representing all processes (i.e., multiphase flow, geomechanics, and geochemistry) in a GCS model leads to a system of coupled nonlinear 3D governing equations which is usually solved numerically. In many cases one or more of the processes can be neglected, leading to less complex modeling approaches. Considering only multiphase flow processes (i.e., the impact of both geomechanics and geochemistry on flow is neglected) leads to the simplified multiphase modeling approach. In other words, the problem is simplified by neglecting processes, while the 3D structure of the domain is retained. Neglecting processes leads to a reduction in computational effort, as well as a reduction in the complexity of input parameters (e.g., no rock mineralogy or chemical rate coefficients). Carbon sequestration modeling can be further simplified by assuming that CO2 and brine segregate by buoyancy on a timescale that is small compared to the time-frame of interest. This assumption is termed VE and allows for algebraic pressure reconstructions that are used for vertical integration of the 3D governing equations, leading to a 2D vertical equilibrium modeling approach. Parameters such as intrinsic permeability and porosity are vertically averaged. In comparison to simplified multiphase models, VE models are further simplified by reducing the number of spatial dimensions by NGWA.org

Figure 7. (a) Spatial distribution of existing wells in the Wabamun Lake area, Canada over a 50 × 50 km domain; (b) CO2 fractional mass leakage to a shallow aquifer for correlated (blue) and uncorrelated (red) well segment permeability, taken from Celia et al. (2011).

one, while no additional processes are neglected and the spatial variability of parameters is retained. VE models can be further simplified by assuming homogeneous and horizontal formations, no-flow boundaries at the top and bottom, and no capillary transition zone (i.e., sharp interface), allowing for semianalytical solutions. For cases where the expected CO2 plume area is small compared to the modeling domain, it is often valid to assume that multiphase flow dynamics have little impact on the far-field pressure response, which allows the use of single-phase models. While single-phase models cannot predict the migration of CO2 , they are often useful tools for questions related to the large-scale pressure response to injection operations, including the estimation of the Area of Review. A different simplification approach is to assume that flow resistance due to viscosity is negligible, which leads to macroscopic invasion percolation models, where the migration of fluids is based on capillary pressure and gravity. While the flow processes are simplified, the 3D distribution of parameters is retained. The computational efficiency allows models developed for site-scale evaluations to be applied at fine spatial scales. The following example sites were chosen to illustrate the use of the different modeling approaches: the Illinois Basin (USA), the Sleipner project (Norway), the In Salah project (Algeria), the Cranfield site (USA), and the Wabamun Lake site (Canada). Table 2 gives an overview of the modeling approaches that have been applied at the sample sites. In general, the sites surveyed here indicate that the choice of modeling approach depends on the question that the model is supposed to answer. In the majority of cases simplified multiphase models are used when the main interest is the injection pressure (injectivity) and site-scale migration of supercritical CO2 . NGWA.org

At Cranfield small-scale heterogeneity appears to have a significant impact on CO2 migration by providing preferential pathways, and spatially discretized models are necessary to capture those preferential flow paths. While simplified multiphase models were usually used for cases with small-scale heterogeneity, VE models may also be applicable for cases where vertical heterogeneity is small compared to the horizontal heterogeneity. Of the sites surveyed for this review, In Salah is the only site where coupled models have been applied. The use of coupled models is necessitated by the feedbacks of geomechanics on the flow. Based on the questions asked and modeling approaches chosen at the example sites, full coupling of geochemistry and flow does not appear to be necessary, leading to the conclusion that the impact of chemical reaction on permeability and porosity of the injection formation is considered negligible compared to other processes. However, sequential coupling of simplified multiphase models with geochemistry simulators is a useful tool for questions related to long-term storage safety (e.g., dissolution of CO2 into brine) and for interpreting monitoring data. As the domains of interest become larger, the modeling approaches become simpler due to increasing computational cost and data scarcity. The basinscale models reviewed here were either simplified multiphase models with coarse spatial resolution or VE models. Model questions were related to storage capacity and basin-scale pressure response and brine migration, rather than CO2 migration and injectivity. Semianalytic approaches, such as the simplified VE model applied at Wabamun Lake, become attractive in cases with favorable geologic settings (e.g., relatively homogeneous domain) and when models need to be run a large number of times (e.g., for Monte-Carlo type studies K.W. Bandilla et al. Groundwater 53, no. 3: 362–377

373

374

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∼30,000 (100 km radius) Coupled (flow + geochemistry) 2D (cylindrical)

18

60

60

Site scale

Site scale

Site scale

Site scale

Coupled (flow + geochemistry) 3D Coupled (flow + geochemistry) 2D (vertical)

24 (estimated)

5 km wide

2 (estimated) ∼26

6

∼50 (4 km radius)

Site scale

Site scale

Site scale Site scale

Site scale

Site scale

Simplified vertical equilibrium

Coupled (flow + geomechanics) 3D; coupling through sequential application of flow and geomechanical simulator Coupled (flow + geomechanics) 2D (vertical); Direct coupling of governing equations Simplified multiphase Simplified multiphase

400

Site scale

Coupled (flow + geomechanics) 3D; sequential coupling in each time step

Vertical equilibrium

Macroscopic invasion percolation and simplified multiphase Vertical equilibrium and simplified multiphase

600 m wide

Coupled (flow + geochemistry) 2D (vertical)

Simplified multiphase with embedded mesh Vertical equilibrium with sharp interface Vertical equilibrium with capillary transition zone and multiple layers Simplified multiphase

Approach

Site scale

640

Wabamun Lake Basin scale 2500

Cranfield

In Salah

Sleipner

Site scale

Basin scale 241,000 Basin scale 230,000 Basin scale 302,000

Illinois Basin

Domain (km2 )

Scale

Site

Table 2

Study on impact of model coupling and on impact of temperature on stress field Model calibration and migration prediction Validate numerical model through history matching of pressure measurements Model calibration based on data from pilot-scale injection Study of the value of temperature and methane data for calibration Probabilistic study of basin-wide well leakage

Study on using surface uplift to determine location and extent of faults; sensitivity analysis to determine depth of fault Study on using surface uplift to determine location and extent of faults

Injection operation design, CO2 plume migration prediction Investigation of solubility and mineral trapping Investigation of dissolution/mineralization and trapping mechanisms Model calibration, plume prediction, and comparison of modeling approaches Compare plume predictions from different modeling approaches Determine upscaled convective mixing rates

CO2 and brine migration CO2 and brine migration CO2 and brine migration

Model Purpose

Overview of Modeling Studies at the Example Sites

Doughty and Freifeld 2013 Celia et al. 2011

Hosseini et al. 2013

Ringrose et al. 2009 Choi et al. 2011

Preisig and Pr´evost 2011

Morris et al. 2011

Mykkeltvedt and Nordbotten 2012 Rinaldi and Rutqvist 2013

Singh et al. 2010; Cavanagh 2013 Nilsen et al. 2011

Audigane et al. 2007

Senel and Chugunov 2012 Johnson et al. 2004

Zhou et al. 2009 Person et al. 2010 Bandilla et al. 2012a

References

of uncertainty). The computational cost would make the use of simplified multiphase or spatially discretized VE models infeasible for such studies. Macroscopic invasion percolation models are also computationally efficient, but at this point the applicability of this approach to the problem of GCS appears limited to cases where viscous effects are negligible compared to buoyancy effects.

Acknowledgments This work was supported in part by the Department of Energy under Award No. DE-FE009563; the National Science Foundation under Grant EAR-0934722; the Environmental Protection Agency under Cooperative Agreement RD-83438501; and the Carbon Mitigation Initiative at Princeton University. Funding to Lawrence Berkeley National Laboratory was provided by the Assistant Secretary for Fossil Energy, Office of Sequestration, Hydrogen, and Clean Coal Fuels, through the National Energy Technology Laboratory, under the USDOE contract DE-AC02-05CH11231.

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