Science of Carbon Storage in Deep Saline Formations: Process Coupling across Time and Spatial Scales

Science of Carbon Storage in Deep Saline Formations: Process Coupling across Time and Spatial Scales summarizes state-of-the-art research, emphasizing how the coupling of physical and chemical processes as subsurface systems re-equilibrate during and after the injection of CO2. In addition, it addresses, in an easy-to-follow way, the lack of knowledge in understanding the coupled processes related to fluid flow, geomechanics and geochemistry over time and spatial scales. The book uniquely highlights process coupling and process interplay across time and spatial scales that are relevant to geological carbon storage.

• Includes the underlying scientific research, as well as the risks associated with geological carbon storage
• Covers the topic of geological carbon storage from various disciplines, addressing the multi-scale and multi-physics aspects of geological carbon storage
• Organized by discipline for ease of navigation

• Language: English
• Publisher: Elsevier Science
• Release date: Sep 6, 2018
• ISBN: 9780128127537

Book preview

States

Chapter 1

Overview of Geological Carbon Storage (GCS)

Pania Newell¹ and Anastasia G. Ilgen²,    ¹Department of Mechanical Engineering, The University of Utah, Salt Lake City, UT, United States,    ²Geochemistry Department, Sandia National Laboratories, Albuquerque, NM, United States

Abstract

Geological carbon storage (GCS) is a promising technology for mitigating increasing concentrations of carbon dioxide (CO2) in the atmosphere. The injection of supercritical CO2 into geological formations perturbs the physical and chemical state of the subsurface. The reservoir rock, as well as the overlying caprock, can experience changes in the pore fluid pressure, thermal state, chemical reactivity and stress distribution. These changes can cause mechanical deformation of the rock mass, opening/closure of preexisting fractures or/and initiation of new fractures, which can influence the integrity of the overall geological carbon storage (GCS) systems over thousands of years, required for successful carbon storage.

GCS sites are inherently unified systems; however, given the scientific framework, these systems are usually divided based on the physics and temporal/spatial scales during scientific investigations. For many applications, decoupling the physics by treating the adjacent system as a boundary condition works well. Unfortunately, in the case of water and gas flow in porous media, because of the complexity of geological subsurface systems, the decoupling approach does not accurately capture the behavior of the larger relevant system.

The coupled processes include various combinations of thermal (T), hydrological (H), chemical (C), mechanical (M), and biological (B) effects. These coupled processes are time- and length-scale- dependent, and can manifest in one- or two-way coupled behavior. There is an undeniable need for understanding the coupling of processes during GCS, and how these coupled phenomena can result in emergent behaviors arising from the interplay of physics and chemistry, including self - focusing of flow, porosity collapse, and changes in fracture networks. In this chapter, the first section addresses the subsurface system response to the injection of CO2, examined at field and laboratory scales, as well as in model systems, addressed from a perspective of single disciplines. The second section reviews coupling between processes during GCS observed either in the field or anticipated based on laboratory results.

Keywords

Geological carbon storage; coupled processes

Acknowledgments

This material was prepared by PMN and AGI with support from the Center for Frontiers of Subsurface Energy Security (CFSES), an Energy Frontier Research Center funded by the U.S. Department of Energy, Office of Science, Basic Energy Sciences under Award DE-SC0001114, awarded to the University of Texas and Sandia National Laboratories. Sandia National Laboratories is a multimission laboratory managed and operated by National Technology and Engineering Solutions of Sandia, LLC., a wholly owned subsidiary of Honeywell International, Inc., for the U.S. Department of Energy’s National Nuclear Security Administration under contract DE-NA0003525.

Introduction

Geological sequestration of carbon dioxide (CO2) known as geological carbon storage (GCS) is a proposed technology to store CO2 produced by large point sources into deep, porous, and highly permeable rock formations for permanent storage. These geological formations are required to have certain characteristics. For instance, they should be at over 850 m below the ground surface as well as be overlain by one or multiple impermeable formations (caprock) to prevent upward migration of CO2. Additionally, the storage formation should have sufficient porosity and permeability to hold large amounts of CO2. Some examples of the proposed types of geological storage units are:

• Deep saline formations,

• Unmineable coal seams,

• Depleted oil and gas reservoirs, and

• Basalt formations.

The main focus of this book is on deep saline formations. Deep saline formations or deep brine reservoirs exist worldwide, making them accessible targets for CO2 storage. These deep geological formations are usually at depths greater than 850 m, which allows storage of CO2 in a supercritical (sc) state, and therefore in larger volumes. The buoyant scCO2 plume is expected to persist over centuries if not thousands of years until CO2 predictably dissolves into the formation brine. Therefore, as noted earlier, it is necessary that the storage formation is overlain by an impermeable layer (caprock) to limit the upward migration of buoyant scCO2. In general, various geochemical and physical trapping mechanisms would prevent the CO2 from migrating to top surfaces (IPCC, 2005).

Perturbation of Subsurface During GCS

The injection of supercritical CO2 into the subsurface perturbs the pressure (and, therefore, the state of stress), chemical, thermal, and biological steady-state or equilibrium conditions. Additional complexity is introduced because of the presence of two distinct and immiscible phases (e.g., scCO2 and brine), resulting in a two-phase fluid flow in the system. After CO2 injection, the re-equilibration of the system is nonlinear in space and time, with different processes proceeding along vastly different timescales. For example, some geochemical reactions take place within days, while others, with slow kinetics, require decades or even thousands of years (Ilgen and Cygan, 2016). Similarly, flow within nanoporous caprock may take hundreds of years to advance, while the same distance in sandstone will be traveled by fluids in minutes.

Perturbation of stress and geomechanical response plays a prominent role in both short- and long-term performance of GCS; however it plays the most crucial role in the physical trapping during CO2 injection (Rutqvist, 2012). Physical trapping prevents the upward migration of CO2 through one or multiple layers of impermeable caprock above the storage formation. Physical trapping can also be provided through capillary forces in the porous rock formation. However, because of the combined effect of these mechanisms (e.g., structural and capillarity) over time, the dominant mechanism can change as time progresses (Wu et al., 2014).

Immediately following the injection of CO2, the structural trapping mechanism plays the leading role in retaining CO2 within the storage formation. In the presence of faults, they can act either as barriers or preferential leakage pathways, depending on the permeability of the fault, which may impact the structural trapping mechanism of GCS (Wu et al., 2014). Injection of CO2 into the rock formation can also change the pore pressure and the stress state of the geological formation which may trigger seismic events (reservoir, basement, and caprock). As noted earlier, the geomechanical events (e.g., fracturing) are caused by changes in the stress field as a result of CO2 injection (e.g., change in the pore pressure). This coupling between deformation and change in the pore pressure can be expressed as:

(1.1)

is the pore pressure (scalar).

Fig. 1.1 shows possible geomechanical events during GCS. Ground–surface movement and microseismic events are geomechanical responses which have been observed at various CO2 storage sites. As a result of change in the pore pressure during GCS, pre-existing fractures and faults may be re-activated or new fractures may form within the reservoir, caprock, or overburden, which could lead to new leakage pathways.

Figure 1.1 Schematic of geomechanical processes associated with GCS in deep saline formations. Source: From Rutqvist, J., 2012. The geomechanics of CO2 storage in deep sedimentary formations. Geotech. Geol. Eng. 30 (3), 525–551.

The effectiveness of the GSC does not only depend on physical trapping, but also geochemical trapping mechanisms. Chemical reactions are triggered by the injection of CO2 because of perturbation of the existing state of the aquifer. The chemical reactions of scCO2 with rock minerals are very complex due to the dependency on rock type and porosity, rock compositions, available reactive surface area, etc. (Silva et al., 2015). Carbonate-rich (carbonate-cemented) rock assemblages are most vulnerable to chemical attack by CO2, because of the fast dissolution rate of carbonate minerals, compared to other mineral types. Other grain cement materials (e.g., quartz cement) are less reactive and exhibit less alteration of both chemical and mechanical properties on the timescales examined in the field and laboratory. Initially dry scCO2 becomes partially wet as it moves through the formation and interacts with formation brine. This humid scCO2 can form water films on the water-wetting mineral surfaces, with reactivity of these films deviating from the reactions observed in the systems where activity of water is not limited. Chapter 4, Experimental Studies of Reactivity and Transformations of Rocks and Minerals in Water-Bearing Supercritical CO2, by Loring et al. (this volume) provides more details on this subject.

Natural analog sites show that some CO2 is sequestered as carbonate minerals over geologic time periods. Dissolution of CO2 into parent brine, or solubility trapping, is necessary for further carbonation reactions (mineral trapping). Mineral trapping refers to the formation of carbonates from the parent mineral assemblage. To date, to estimate the CO2 storage capacity, the focus has been on physical trapping and/or solubility trapping. These estimates assume that there are no geochemical reactions taking place with CO2 injection, flow, and dissolution (IPCC, 2005). Some recent studies suggest that geochemical reactions may take several thousands of years to have a significant impact, because of slow rates of mineralization (Xu et al., 2011). Even though geochemical trapping (e.g., solubility and mineral trapping) takes a long time, it is the safest and most effective trapping mechanisms (Kempka et al., 2014).

Since CO2 injection perturbs the chemical state of the subsurface, it can also disrupt microbial metabolism and alter microbial communities. Microbial reactions can impact the integrity, capacity, and safety of CO2 storage sites. Specifically, microbial population can either inhibit or enhance mineral dissolution, which leads to a decrease in the storage capacity that could eventually cause fracture initiation and propagation to the overlaying formations and affect the storage integrity (Gniese et al., 2014). Study of the saline aquifer near Ketzin, Germany has shown that microorganisms can adapt to the high concentration of CO2 within 5 months and become more metabolically active (Gniese et al., 2014). Okyay and Rodrigues (2015) studied CO2 sequestration through microbially induced calcium carbonate precipitation and observed that the microbial species or strains influence the rate of microbially induced calcium carbonate precipitation and concentration of CO2. In this environment, the pH and growth medium components are the main abiotic factors affecting CO2 sequestration. They reported that an increase in brine pH lead to enhanced CO2 sequestration by the growth medium, while the growth medium components affect both the urease activity and CO2 sequestration. These efforts have focused on characterizing the subsurface microbial community at the individual level. However, to have an in-depth understanding of microbial feedback at a GCS site, understanding the microbial community beyond simple biodiversity characterizations is needed. Moreover, it is essential to conduct in situ field-scale experiments in addition to in vitro studies to validate results from lab-scale studies and provide biological relevance based on the real geology of the system (Mu and Moreau, 2015). An in-depth discussion on the effect that CO2 injection has on microbial communities is provided in Chapter 12, Field Observations, Experimental Studies, and Thermodynamic Modeling of CO2 Effects on Microbial Populations, by Thompson et al. (this volume).

Another important perturbation that takes place during injection of CO2 is introduction of a thermal gradient in the geologic formation (Kopp et al., 2006). The geothermal gradient typical for saline aquifers is on average 25–30°C/km. The temperature of injected CO2 is expected to be the same as the ground surface temperature at the injection site. The density of CO2, as well as its solubility in the brine, will be influenced by the change in temperature (Sun et al., 2015). Most studies on geological storage of carbon dioxide ignore the temperature impact on the overall behavior of the system. However, in some cases such as In Salah (Gor and Prévost, 2013) and Ketzin sites (Ivanova et al., 2013), temperature was an important factor influencing the coupled behavior of the storage unit. Gor and Prevost (Gor and Prévost, 2013) numerically investigated the influence of the CO2 injection temperature on caprock integrity, and predicted additional stress development within caprock. These stresses will become tensile and surpass the tensile strength of the caprock creating fractures within the caprock. Ivanova et al. (2013) showed that when CO2 replaced brine, the elastic properties of porous media are impacted. At the Ketzin site, the migration of CO2 was tracked via 3D time-lapse seismic data and it was observed that the temperature within the reservoir in the vicinity of the injection well increased from 34°C to 38°C. This temperature change did not have an impact on seismic response but had a significant impact on CO2 mass which can be explained by the change in the density of CO2. Kopp et al. (2006) used numerical simulations to identify physical processes, which produce temperature variations in the vicinity of the injection well. Sun et al. (2015) showed that the existence of a temperature field strengthens the convective effect and enhances the dissolution of CO2. The detailed review of the thermal impact of CO2 injection is presented in Chapter 11, Thermal Processes During Geological Carbon Storage: Field Observations, Laboratory and Theoretical Studies, by Ivanova et al. (this volume).

Injection of CO2 into reservoir formation and introduction of two-phase fluid flow alters hydrological conditions of the subsurface with the impact reaching beyond the CO2 plume boundaries (Birkholzer and Zhou, 2009). For instance, an industrial CO2 storage project can generate a subsurface plume with linear dimensions of the order of 10 km or more, while a pressure gradient of 1 bar may be recorded over 100 km within the reservoir region (Pruess et al., 2003). The magnitude and extent of the pressure buildup as well as hydraulic communications will dictate the extent of the impact. Moreover, the change in the pore pressure may cause degradation within the caprock and create local high-permeability regions. As a result of injection, the formation uplift may influence the subsurface flow pattern. These are just a few examples of processes influencing geohydrological behavior of GSC and more in-depth discussion is provided in Chapter 5, Reactive Transport Modeling of Geological Carbon Storage Associated With CO2 and Brine Leakage, by Dai et al. (this volume).

Coupled Processes

So far, we have discussed the individual physics expected during GCS. However, a comprehensive assessment of GCS requires accounting for coupled processes occurring at different spatial scales ranging from nanometers to kilometers and temporal scales ranging from a nanosecond to thousands of years. The following sections will address the basics of the coupling phenomena, for which the details can be found in this book. The schematic of two-way process coupling is shown in Fig. 1.2.

Figure 1.2 Coupled processes during GCS.

To ensure GCS safety, understanding the long-term impact of CO2/brine/rock interactions on the mechanical behavior of a storage unit is necessary. Chemical reactions between CO2, reservoir, and caprock may affect geomechanical properties of rocks through mineral dissolution and mass removal, or because of stress-corrosion (subcritical fracturing) effects. Chemical-mechanical (CM) coupling response to the injection of CO2 was observed in the field (Hosni et al., 2016; Hovorka et al., 2013; Rinehart et al., 2016), and in laboratory studies (Aman et al., 2018; Guen et al., 2016; Hangx et al., 2013; Lamy-Chappuis et al., 2016; Lisabeth et al., 2017; Vialle and Vanorio, 2011; Yasuhara et al., 2017). There is also evidence for coupled chemical and mechanical alteration of rocks collected at natural CO2 storage site analogs (Burnside et al., 2013; Busch et al., 2014; Kampman et al., 2016). Chemical–mechanical coupling will be addressed in depth in Chapter 15, Coupled Chemical--Mechanical Processes Associated with the Injection of CO2 into Subsurface, by Ilgen et al. (this volume).

Alterations of rock fabric, porosity, fracture permeability, and chemical reactions may also alter the flow in the subsurface, with observed hydrological-chemical (HC) coupling. Chemical reactions may cause (1) changes in the permeability and porosity through precipitation and dissolution, (2) changes in density and viscosity of the fluids, (3) changes in temperature (if reactions are exo- or endothermic), and (4) changes in fluid pressure. These changes will influence the fluid flow and thus the rate of transport of the chemical species, resulting in two-way coupling (Tsang, 1991). Steefel and Lasaga (1990) studied the evolution of dissolution patterns in a two-dimensional flow field in fractured rock using numerical modeling and showed the channelization of flow occurring where coupled flow and dissolution are transport-controlled. Note, in the subsurface systems, chemical transformations can either be kinetically (reaction rate) controlled, or transport-controlled. Mineral dissolution can increase fracture aperture and thus the permeability. If the processes are controlled by kinetic mineral dissolution rate, the permeability changes are spatially more diffused and the flow channelization is less pronounced (Tsang, 1991). To predict the evolution of permeability and porosity due to chemical reactions, methods such as upscaling constitutive relationships, simplified empirical models or multiscale/multiphysics approaches should be incorporated in the transport models. However, developing these techniques requires a fundamental scientific understanding of rock texture and porosity evolution under different chemical conditions (Nogues et al., 2013), which can be obtained through laboratory and field observations.

Hydrological-mechanical (HM) coupling is also observed in the subsurface systems, including when these systems are perturbed by the injection of CO2. This two-way coupling has been recognized for several decades and it was first presented by Biot (1941). The injection of CO2 into a reservoir will displace and compress the ambient groundwater and thus overpressurize the target reservoir. This overpressure will increase the pore pressure, which has the potential to cause stress changes leading to fracture in reservoir or caprock and/or re-activation of existing faults/fractures and potentially compromising the caprock. These interactions between fluid flow and rock mechanics are referred to as hydromechanical coupling. The rock formation can deform either as a result of changes in external loads or internal pressures. Vilarrasa et al. (2010) explained this through both direct and indirect HM coupling. Direct HM coupling consists of two phenomena: (1) solid–fluid coupling, where porosity changes due to applied load leading to change in the fluid pressure or mass; and (2) fluid–solid coupling which is a change in fluid pressure or mass as a result of changes in the volume of the geological media. Indirect HM coupling arises because of the change in hydraulic or mechanical properties in response to strain. Through these coupling schemes, we can determine conditions where mechanical failure could occur, so the injection pressure cannot exceed this limit. Rutqvist et al. (2008) showed that potential for shear failure (e.g., re-activation along pre-existing fractures) is usually higher than the potential for tensile failure for three types of stress regimes: (1) an isotropic stress regime; (2) a compressional stress regime; and (3) an extensional regime.

Researchers (Rutqvist et al., 2007; Vidal-Gilbert et al., 2009) have shown that simplified analytical solutions may not accurately predict the maximum pressure, therefore, these systems should be solved as fully coupled systems. Through coupling between fluid flow and mechanical deformation, we have the ability to describe the mechanical and hydraulic behavior of a fault, and the change in the stress tensor and pressure on the fault slip (Jha and Juanes, 2014). Jha and Juanes (2014) numerically investigated the coupling of multiphase flow and fault poromechanics by employing a rigorous formulation of nonlinear multiphase geomechanics through the increment in mass of fluid phases instead of the change in porosity. This framework allows investigation of fault slip and induced seismicity in underground reservoirs as a result of fluid flow coupled with mechanical deformation.

Thermal–hydrological–mechanical–chemical–biological (THMCB) coupling is expected in the GCS systems, given that all these components exhibit the two-way coupling behavior reviewed above. These system responses are coupled with coherent links between deformation, flow, and transport processes (Bai and Elsworth, 2000). For example, geochemical perturbation caused by CO2 injection is manifested in mineral precipitation and dissolution, which causes changes in porosity, wettability, and pore diffusion coefficients, modifying pore networks and transport properties (Chagneau et al., 2015). When deformation of the reservoir rock is significant and causes activation of fractures in both reservoir and caprock, these preferential flow paths (fractures) also alter flow properties of the system. Chemical reactions taking place in the fractures may either seal or widen a fracture aperture, further altering the sealing properties of caprock, storage capacity of the reservoir, and the overall performance of the system. The injection of CO2 may also act as a driving force to shift the microbial community structure (Wilkins et al., 2014).

An accurate assessment of long-term performance of GCS requires a sophisticated method to represent THMCB coupling occurring in the systems. Researchers used various numerical tools such as TOUGHREACT-FLAC3D (Gou et al., 2016), and Sierra Mechanics (Martinez et al., 2013; Newell et al., 2016) to account for these coupled processes through various coupling techniques such as one-way, two-way loose coupling, and two-way tight coupling. To solve these systems numerically, the governing equations are defined through the laws of conservation of mass or momentum or energy, satisfying the continuity of the dependent variables, applying the constitutive relationships and initial and boundary conditions. For coupled systems, in addition to the individual conservation laws, the coupled conservation laws must be jointly and simultaneously satisfied as well. These coupled processes can only be decoupled when an individual process becomes relatively dominant compared to others. Various coupled processes are later addressed in detail in chapters by Pawar and Guthrie, Pyrak-Nolte, Ilgen et al., Zhang and Wu, and Kim et al. within this volume.

Although, the robustness and complexity of numerical models have been increasing over the last decades, they typically focus on a select subset of these processes, which limits their ability to predict the overall behavior of these complex systems accurately. To overcome this issue, one approach would be to develop a new framework that accounts for all the processes involved in these systems or simply couple our existing tools, which account for individual processes in detail. Each approach is sophisticated and has its own challenges (Bai and Elsworth, 2000). Accounting for different spatial and temporal scales, coupling these processes, verifying and validating our numerical techniques, etc., remain challenging.

On the laboratory scale, when coupled experiments are performed, decoupling the physics is a daunting task. The complexity arises because of separation of scales within a highly dynamic environment. The injection of CO2 into the rock formation drives the fluid–rock system into far-from-equilibrium conditions. The processes returning the system to equilibrium or steady-state conditions are highly nonlinear and depend on the generalized driving forces such as chemical potential differences, and changes in fluid pressure and stress. These driving forces combined with the mechanical framework of porous media span from nanometers to kilometers (Steefel et al., 2013). Experimental studies of coupled processes in GCS are limited because of complex temperature and pressure requirements, as well as conventional approaches that tend to evaluate a system from a single discipline prospective. Most of the experimental work relies on simplified physics occurring in the selected range of spatial scale mainly because scale is one of the major limitations for conducting experiments.

Issues of Scales and Heterogeneity

Macroscopic phenomena observed during GCS ultimately arise because of pore-scale processes taking place in the rock formations. Developing quantitative relationships that link molecular- to pore-scale processes to reservoir scale remains a fundamental research challenge. This task is further complicated by heterogeneity of the porous medium, two-phase fluid flow, thermal, chemical, and stress gradients in the subsurface systems (Gao et al., 2017).

The molecular scale processes refer to chemical reactions, both homogeneous and heterogeneous, as well as molecular diffusion, which become increasingly important in fine-grained tight rock formations (e.g., shale caprock).

Pore scale refers to the scale of processes taking place within porous media. In a typical geological setting, pore sizes can range from a few nanometers (in shale), to microns (in sandstone—sometimes to hundreds of microns, and even mm scale). At the pore scale, parameters such as pore connectivity and roughness control the mobility of CO2 leading to brine displacement patterns, capillary trapping of CO2 within the pore space, as well as dissolution of CO2 into brine, and reactions between dissolved CO2 and mineral assemblage. Since geochemical transformations become significant over longer timescales (years), most of the experimental studies so far focused on the faster reactions (dissolution and precipitation of calcite), while longer-term geochemical effects on the pore-scale processes have been addressed using modeling approaches (Gao et al., 2017). Despite progress in recent years, modeling and understanding the fundamental behavior of the multiphase flow and reactive transport at pore scale remains a challenging task. This is mainly due to the fact that multiple, coupled physiochemical changes dynamically occur within the complex system (Middleton et al., 2012).

Core-scale laboratory experiments provide useful data for understanding various trapping mechanisms within GSC. Various studies have investigated the two-phase flow of CO2–brine systems using X-ray computed tomography (CT). Krishnamurthy et al. (2017) used Darcy and invasion-percolation modeling to match the experimental data from the core-scale CT measurements of CO2 flow through Berea Sandstone. Each modeling approach captured different features of the CO2 plume, but neither one of them produced a sufficient match. Therefore, additional model development to capture the combined effects of gravity and capillary forces that control CO2 flow in subsurface is needed.

Shi et al. (2009) used CT images to analyze CO2 saturation influenced by heterogeneity of the Tako Sandstone. Perrin et al. (2009) conducted X-ray CT study on core samples and confirmed that the spatial distribution of CO2 is strongly correlated with the variation of porosity and permeability. They also noted that the heterogeneity in the samples can impact the CO2 distribution. Krause et al. (2009) used underlying physics of the pore scale to understand multiphysics flow experiments conducted on the core-scale samples. They showed that history matching core-scale multiphase flow experiments provides valuable information to simulate CO2 sequestration at the reservoir scale.

Reservoir scale encompasses spatial and temporal evolution of the CO2 plume across a reservoir with a given injectivity, storage capacity, and potential pathways for CO2 leakage (Middleton et al., 2012). Multiple computational tools have been developed to simulate and predict the fate of the CO2 plume at this scale. The data obtained from various sites can be used to verify and validate the computational tools.

Heterogeneity defined as a dependency of rock properties on location in space is another important issue in understanding the coupled processes within subsurface systems. Inherent heterogeneity of geologic units, and discontinuities, such as natural fractures, are key contributors to heterogeneity of the system. Anisotropy, or dependence on property change with direction, is another characteristic of almost any geological system. The nonlinear behavior of fractured anisotropic formations defines the fluid exchange, and therefore chemical reactivity, and pressure evolution between fractures and porous rock matrix (Bai and Elsworth, 2000).

Commercial-Scale GCS Projects and Current Challenges

There are currently 21 commercial-scale GCS projects either in operation or under construction globally, such as Sleipner, Snøhvit, Korea-CCS 1, Korea-CCS 2, Texas Clean Energy, etc. The GCS projects are technically feasible, however, they have not been fully considered from a perspective of economic efficiency. (Bergstrom and Ty, 2017). One of the biggest challenges is to match sequestration sites to CO2 sources, which requires fundamental understanding of coupled THMCB processes that define the long-term fate of CO2 in the subsurface (Benson and Cole, 2008).

Selection of GCS sites depends on the storage capacity of the aquifer (available pore space) as well as permeability. This is a complex estimation, because the available pore space as well as the predicted pressure buildup are the constraints and it is not clear which one has a greater impact. Szulczewski et al. (2011) showed that the properties of the aquifer are the dominant factors in how much CO2 can be injected into a reservoir. They also indicated that the pressure constraints are limiting factors for shorter injection periods, while space constraints are more important for longer injection periods. Moreover, Birkholzer et al. (2009) modeled CO2 migration and pressure response in an idealized, laterally open groundwater system and reported the hydraulic characteristics of sealing are strongly affected by pressure buildup. The impact of the pressure buildup has also been investigated numerically through modeling of closed and semiclosed geological formations (Taoa et al., 2013). These models can provide assessments of CO2 storage capacity induced by the brine displacement and the transient domain-averaged pressure buildup. The seal performance is also influenced based on whether the closed or semiclosed formations are considered (Wilkins et al., 2014).

There are numerous remaining challenges impeding further development of GCS. For instance, due to the geometrical complexity and heterogeneity of many deep saline formations, rock properties vary spatially, which makes site characterization a complex task. Therefore, geomechanical parameters obtained during laboratory core-scale testing may not apply uniformly at the reservoir scale (Kopp et al., 2006). Even though numerical models can be constructed for reservoir scale, they lack resolution to capture rock heterogeneities and discontinuities (fractures) that dictate scCO2 flow in the subsurface.

Another challenge which has not been sufficiently explored is the difficulty in characterizing the possible damping of pressure propagation across faults, heterogeneity, or the possibility of pressure relaxation by brine flow into overlaying and underlying formations (Birkholzer and Zhou, 2009). Obtaining representative fluid samples from the deep subsurface for chemical and microbiological characterization is also a challenge. Additionally, the timescale associated with microorganisms and the creation of their physicochemical requirements for cultivation is very short. This low temporal scale makes it challenging to conduct any laboratory experiments and/or numerical modeling.

The coupled chemical–mechanical processes taking place during GCS have only been assessed on relatively short timescales (months at most), and highlighted the importance of fast-reacting carbonate minerals. However, slower chemical reactions, such as carbonation of feldspars, may alter storage reservoir properties over longer timescales required for successful storage of carbon dioxide. Thus, it is essential to conduct experiments over longer periods of time or provide novel solutions to overcome this limitation. However, the complexity of reproducing these reactions (chemical–mechanical coupling) on a laboratory timescale is undeniable.

Finally, upscaling and using the information from lower/higher scales in numerical simulations should also be added to the list of challenging tasks. Moreover, utilizing the experimental data conducted at different scales compared to the computational model is another important issue to address.

Summary

This book summarizes the current state-of-the-art research on GCS, with emphasis on physical and chemical processes as subsurface systems re-equilibrate during and after the injection of CO2. The unique purpose of this book is to highlight processes (e.g., individual and coupled) across time and spatial scales relevant to GCS. The book contains 18 chapters including this introduction, organized as follows: a chapter addressing the similarities between CO2-enhanced oil recovery (EOR) and GCS, 10 chapters addressing the individual processes through laboratory or numerical investigations, then four chapters addressing some of the most critical coupled processes observed in GCS, followed by a chapter on engineering and monitoring aspects in GCS, and finally closing remarks summarizing scientific discoveries and challenges associated with GCS and future research needs.

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Chapter 2

CO2 Enhanced Oil Recovery Experience and its Messages for CO2 Storage

Larry W. Lake¹, Mohammad Lotfollahi¹ and Steven L. Bryant²,    ¹The University of Texas at Austin, Austin, TX, United States,    ²University of Calgary, Calgary, AB, Canada

Abstract

The first CO2 to recover crude oil was injected into reservoirs in the early 1960s. Since then over 100 enhanced oil recovery (EOR) projects have been implemented in the United States. These projects encompass temporal and spatial scales ranging from over a half-century field-scale injections, to the laboratory-scale experiments.

CO2-EOR and CO2 storage differ due to the distinct end-goals of CO2 injection. Nevertheless, the basic processes of injecting CO2 into a porous formation, retaining the CO2 in the formation, interactions of the CO2 and resident fluid, the chemical reactions between fluid and rock, operational considerations, and the necessary understanding of the physical processes are similar.

Lessons from CO2-EOR that inform CO2 storage in oil reservoirs as well as in brine-filled structures include: (1) volumetric sweep efficiency was inherently low during many EOR floods, and methods for improving it are valuable; (2) large injection rates are possible without exceeding original reservoir pressure, but only when correspondingly large fluid-production rates are maintained; (3) detecting injected fluid movement in a reservoir remains a challenge; and (4) significant storage (or retention) of CO2 in subsurface during EOR is occurring, though ascertaining the exact amounts using data routinely available to the public is difficult, thus emphasizing the importance of accurate wellhead and surface facility inventories (rates and pressures) for carbon storage operations cannot be ignored. Operationally, lessons learned from EOR include (5) surface CO2 leaks are rare and no caprock breaches were detected during EOR, which have resulted in (6) minimal need for monitoring.

Keywords

Enhanced oil recovery; CO2

Acknowledgments

Larry W. Lake holds the Shahid and Sharon Ullah Chair. Mohammad Lotfollahi holds a PhD degree in Petroleum Engineering from The University of Texas at Austin. Steven L. Bryant holds the Canada Excellence Research Chair in Materials Engineering for Unconventional Oil Reservoirs. This work was supported by Center for Frontiers of Subsurface Energy Security, an Energy Frontier Research Center funded by the U.S. Department of Energy, Office of Science, Basic Energy Sciences under Award DE-SC0001114. We are indebted to the reviewers and Dr. David J. Goggin for several helpful