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Initial evaluation of advantageous synergies associated with simultaneous brine production and CO2 geological sequestration
Abstract
Mitigation of global atmospheric carbon emissions requires a worldwide ramping up of CO2 capture and sequestration (CCS) implementation in the next decades. While CCS could be deployed in isolation, there is also the possibility to consider CO2 injection within a much broader framework of reservoir and resource management including active water (brine) management. The goal of this study is to provide an initial analysis of three identified synergies related to active brine management in CCS operations. The potential advantages of coupling simultaneous brine production to a large-scale CO2 geological sequestration operation are explored through three separate modeling studies. Our results demonstrate that brine production can provide important pressure-control benefits, including increased injectivity potential through reduction of the injection well pressure, significant reduction of the extent of the Area of Review, within which operators must procure property rights and monitor and remediate potential leakage pathways, and reduction in the risk of CO2 and brine leakage. The latter is especially important in reservoirs, like many in North America, where a significant number of potential leakage pathways, particularly abandoned wells, may exist within the Area of Review. We also observe that brine production has minimal impact on the overall shape of the CO2 plume, with plume shape and extent strongly governed by formation parameters.
... [11][12][13][14] Brine extraction can also increase the available CO 2 storage capacity, limit the area of site characterization and risk assessment, decouple neighboring GCS operations by minimizing the pressure overlap areas, and enhance CO 2 trapping efficiency. 13,[15][16][17] Extracted brine can be used as a feedstock for both desalination plants and cooling/heating facilities or can be reinjected in different over-or underlying saline formations for disposal purposes. 13,17 In recognition of the high cost of brine handling process, 18 Birkholzer et al. 12 and Cihan et al. 19 explored different design approaches to minimize the extraction volume of brine while maintaining the controlled pressure at stressed faults in the storage zone below critical values. ...
... 13,[15][16][17] Extracted brine can be used as a feedstock for both desalination plants and cooling/heating facilities or can be reinjected in different over-or underlying saline formations for disposal purposes. 13,17 In recognition of the high cost of brine handling process, 18 Birkholzer et al. 12 and Cihan et al. 19 explored different design approaches to minimize the extraction volume of brine while maintaining the controlled pressure at stressed faults in the storage zone below critical values. To extract the smallest possible volume of brine, they treated the locations and extraction rates of the wells as variables in an optimization framework. ...
... This is due to the drastic difference between the propagation velocities of a pressure signal and a leakage plume in the subsurface environments. 13,17 Hence, reservoir pressure can be managed by leakage control wells located far away from the injection site until a leakage event happens. It should be noted that such operational conditions will also allow for satisfying the EPA requirement of developing the extraction system as an emergency response tool that is actively operated when a leakage event occurs. ...
Injecting CO2 into deep geologic formations for storage purposes induces large pressure build‐up that risks caprock integrity. Naturally occurring faults or pressure‐induced fractures in the caprock can act as conductive leakage pathways resulting in potential contamination of the overlying shallow aquifers. Previous studies explored using brine extraction to manage such elevated pressure in the storage formation. In this paper, we extended the use of this technique to control far‐field brine leakage. Extraction wells are placed in the storage zone to reduce the leakage flow through reversing the pressure‐gradient locally, while minimizing the brine concentrations in the escaped‐fraction by utilizing the dilution capacity of the overlying formations. The developed approach incorporated the Genetic Algorithm with transport model simulations to optimize well‐placements and extraction‐rates. An approximately 8m long intermediate‐scale tank designed to mimic brine leakage migration in the field was used to validate this approach as field data are not available. We further evaluated the approach numerically using a hypothetical leakage scenario at the Vedder storage formation in San‐Joaquin basin to assess its practicality for field implementation. The results showed that storage zone heterogeneity and fractures’ permeabilities can significantly affect the optimum locations and pumping rates of the extraction wells. Brine leakage can be controlled by extracting a native‐brine volume less than 50% of the injected CO2 volume. The target concentrations in the shallow aquifer determines the extraction rates required to control a leakage through a fracture or a buried thrust fault. The study is useful to develop remediation strategies for carbon storage operations. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd.
... In addition, these injection policies depend on several factors, including the physical properties of the formation rocks, such as the local heterogeneity of reservoir regions. Furthermore, additional control factors must be included in the optimization of the well's schedule when simultaneous development plans/schemes are being considered, such as producing brine from saline aquifers to reduce pressure build-up and potentially increase storage efficiency [60] and/or produce brine that is reinjected into the reservoir to improve the dissolution mechanism [61]. Things may become even more complicated when considering economic decisions that require trade-offs between costs and benefits (additional costs vs. additional CO 2 storage capacity) that can be achieved under different development plans (brine production/recycling). ...
... To mitigate these issues and, therefore, comply with the pressure management policy, several researchers have proposed development schemes and plans that aim at extracting brine from aquifers to potentially increase the amount of CO 2 that can be effectively injected and to control pressure build-up at saline aquifer storage sites. For example, Court et al. [61] and Buscheck et al. [62] demonstrated in synthetic models the significant benefits of pressure control through brine production. They showed that brine production had no significant effect on the conformational shape of the CO 2 plume, as the latter depends on the characteristics of the storage formation. ...
To mitigate dangerous climate change effects, the 195 countries that signed the 2015 Paris Agreement agreed to “keep the increase in average global surface temperature below 2 °C and limit the increase to 1.5 °C” by reducing carbon emissions. One promising option for reducing carbon emissions is the deployment of carbon capture, utilization, and storage technologies (CCUS) to achieve climate goals. However, for large-scale deployment of underground carbon storage, it is essential to develop technically sound, safe, and cost-effective CO2 injection and well control strategies. This involves sophisticated balancing of various factors such as subsurface engineering policies, technical constraints, and economic trade-offs. Optimization techniques are the best tools to manage this complexity and ensure that CCUS projects are economically viable while maintaining safety and environmental standards. This work reviews thoroughly and critically carbon storage studies, along with the optimization of CO2 injection and well control strategies in saline aquifers. The result of this review provides the foundation for carbon storage by outlining the key subsurface policies and the application of these policies in carbon storage development plans. It also focusses on examining applied optimization techniques to develop CO2 injection and well control strategies in saline aquifers, providing insights for future work and commercial CCUS applications.
... The increased aquifer pressure due to the injected CO 2 may result in the mechanical instability of the formation. To mitigate this risk, several concepts of pressure management were suggested in earlier studies [9][10][11][12][13]. ...
... Simultaneous brine production [9][10][11] is an alternative method to passive extraction. The methodology was verified through the industrial-scale project, Gorgon CCS in Australia [25]. ...
Structural trapping is the primary mechanism for intensive CO2 sequestration in saline aquifers. This is the foundation for increasing global CO2 storage; gradual switch to preferable trapping mechanisms, such as residual saturation, dissolution, and mineral trapping, will require a long-time scale. The major constraints limiting the storage capacity of structural trapping are formation pressure and structure size. Over-pressure owing to CO2 injection causes a disruption of seal integrity indicating a failure in geological sequestration. The other constraint on storage capacity is a spill point determining geological storage volume. Overflowing CO2, after filling the storage volume, migrates upward along the aquifer geometry with buoyancy. This study proposes a methodology to maximize CO2 storage capacity of a geological site with a substructure created by an interbedded calcareous layer below spill point. This study provides various conceptual schemes, i.e., no brine production, simultaneous brine production and pre-injection brine production, for geological CO2 storage. By the comparative analysis, location of brine producer, production rate, and distance between injector and producer are optimized. Therefore, the proposed scheme can enhance CO2 storage capacity by 68% beyond the pressure and migration limits by steering CO2 plume and managing formation pressure.
... As a result, pressure build up will limit the effective storage capacity of the saline aquifer (Birkholzer and Zhou, 2009); in order to control the previous, the extraction of brine from the aquifer has been proposed to potentially increase the effective volume of CO 2 that can be injected into an aquifer. Following this idea, Buscheck et al. (2011a) and Court et al. (2012) already demonstrated important pressure control benefits through brine production using synthetic models. However, they showed that brine production does not affect significantly the CO 2 plume shape and concluded that this depends strongly on the formation characteristics. ...
... However, they showed that brine production does not affect significantly the CO 2 plume shape and concluded that this depends strongly on the formation characteristics. Court et al. (2012) and Bandilla and Celia (2017) also proved that brine production can be used to reduce the areas at risk of CO 2 leakage and brine migration outside the storage reservoir. ...
CO2 storage capacity in saline aquifers can dramatically be reduced by pressure build up due to the CO2 injection process. In this paper, a novel optimisation strategy that maximises the CO2 storage capacity utilisation and net profits before tax is presented in a scenario of simultaneous CO2 injection and brine production to help control pressure build up and increase the effective storage capacity. The strategy is tested at the region surrounding the Forties and Nelson fields, assuming both as pure saline aquifer traps. The optimisation was performed considering constraints such that the CO2 plume distribution does not migrate outside the license boundaries, the fracture pressure is not reached within the reservoir, and the CO2 injection and brine production rates occur within feasible limits. The problem was first formulated analytically with the aid of surrogate models, and then optimised using the SIMPLEX and Generalized Reduced Gradient methods.
Results for the Forties and Nelson fields show that by allowing five brine production wells producing up to 2.2 MMtonnes/year, the CO2 storage capacity increased between 112-145% compared to the case where no brine production is practiced.
... Other studies related to brine production and its role in pressure management include Court et al. [2012b], who considered impacts of brine production on the Area of Review (AoR), Bandilla et al. [2012b], who considered reduction of the AoR for different production scenarios for a site-scale model based on the Mount Simon Formation, and Birkholzer et al. [2012], who simulated use of production wells to control pressure build-up along a fault zone. ...
... The possible use of extracted brines has been the subject of several recent studies. Court et al. [2012b] considered a range of possible synergistic activities associated with brine production. In addition to pressure management, reduction in the size of the AoR, and reduction of leakage potential, they also considered possible desalination of produced water to enhance water availability for either industrial, agricultural, or domestic use. ...
Carbon capture and storage (CCS) is the only viable technology to mitigate carbon emissions while allowing continued large-scale use of fossil fuels. The storage part of CCS involves injection of carbon dioxide, captured from large stationary sources, into deep geological formations. Deep saline aquifers have the largest identified storage potential, with estimated storage capacity sufficient to store emissions from large stationary sources for at least a century. This makes CCS a potentially important bridging technology in the transition to carbon-free energy sources. Injection of CO2 into deep saline aquifers leads to a multicomponent, multiphase flow system, in which geomechanics, geochemistry, and nonisothermal effects may be important. While the general system can be highly complex and involve many coupled, nonlinear partial differential equations, the underlying physics can sometimes lead to important simplifications. For example, the large density difference between injected CO2 and brine may lead to relatively fast buoyant segregation, making an assumption of vertical equilibrium reasonable. Such simplifying assumptions lead to a range of simplified governing equations whose solutions have provided significant practical insights into system behavior, including improved estimates of storage capacity, easy-to-compute estimates of CO2 spatial migration and pressure response, and quantitative estimates of leakage risk. When these modeling studies are coupled with observations from well-characterized injection operations, understanding of the overall system behavior is enhanced significantly. This improved understanding shows that, while economic and policy challenges remain, CO2 storage in deep saline aquifers appears to be a viable technology and can contribute substantially to climate change solutions.
... For industrial-scale CO 2 injection in saline formations, pressure buildup is a limiting factor in CO 2 sequestration capacity and risk mitigation because it drives CO 2 and brine migration (Birkholzer and Zhou, 2009). As a means to mange pressure buildup and to control CO 2 and brine migration, Lawrence Livermore National Laboratory (LLNL) and Princeton University have been collaborating on the development of Active CO 2 Reservoir Management (ACRM), which combines brine extraction and treatment and residual-brine reinjection with CO 2 injection (Buscheck et al., , 2012a(Buscheck et al., , 2012bCourt et al., 2011bCourt et al., , 2012Court, 2011). This concept is being considered for specific CCS sites in the state of Wyoming (Surdam et al., 2009) and off the coast of Norway (Bergmo et al., 2011). ...
... Competition for pore space: which includes natural gas storage, liquid waste disposal, shale gas, and other uses Court et al., 2012;Court, 2011) Regulatory and demographic constraints: which can vary from state to state If all of these attributes pertain to a single CO 2 reservoir, Buscheck et al. (2011b) has named this singleformation ACRM ( Figure 2). ACRM may also be deployed using separate formations in "tandem", with one formation being utilized for CO 2 storage and a separate formation being utilized for the purpose of brine reinjection ( Figure 3). ...
We introduce a hybrid two-stage energy-recovery approach to sequester CO and produce geothermal energy at low environmental risk and low cost by integrating geothermal production with CO capture and sequestration (CCS) in saline, sedimentary formations. Our approach combines the benefits of the approach proposed by Buscheck et al. (2011b), which uses brine as the working fluid, with those of the approach first suggested by Brown (2000) and analyzed by Pruess (2006), using CO as the working fluid, and then extended to saline-formation CCS by Randolph and Saar (2011a). During stage one of our hybrid approach, formation brine, which is extracted to provide pressure relief for CO injection, is the working fluid for energy recovery. Produced brine is applied to a consumptive beneficial use: feedstock for fresh water production through desalination, saline cooling water, or make-up water to be injected into a neighboring reservoir operation, such as in Enhanced Geothermal Systems (EGS), where there is often a shortage of a working fluid. For stage one, it is important to find economically feasible disposition options to reduce the volume of brine requiring reinjection in the integrated geothermal-CCS reservoir (Buscheck et al. 2012a). During stage two, which begins as CO reaches the production wells; coproduced brine and CO are the working fluids. We present preliminary reservoir engineering analyses of this approach, using a simple conceptual model of a homogeneous, permeable CO storage formation/geothermal reservoir, bounded by relatively impermeable sealing units. We assess both the CO sequestration capacity and geothermal energy production potential as a function of well spacing between CO injectors and brine/CO producers for various well patterns and for a range of subsurface conditions.
... This approach aims to increase the effective storage capacity of CO 2 and control pressure build-up at saline aquifer storage sites. Studies by Court et al. [21] and Buscheck et al. [22] have demonstrated the significant advantages of brine production in controlling pressure without impacting the conformational shape of the CO 2 plume. However, brine production comes with additional costs and logistical requirements. ...
... As site characterization provides information on geologic parameters such as porosity, intrinsic permeability and capillary entry pressure, this is an unavoidable uncompromisable part of capital costs [86]. Operational costs which include hydrogen dehydration [140], gas separation, and saline water desalination are also substantial in value [193]. ...
The current rate of global warming is greatly increasing greenhouse gas emissions which is only set to worsen the planet's environmental condition. In ensuring a sustainable future, it has become necessary to move away from fossil fuels and adopt renewable energy sources as the primary source of energy generation. Dependency of renewable energy sources on the environment, however, has entailed storing the excess generated energy in bulk for times of need. Hydrogen storage in subsurface porous media has contended to be the buffer for energy storage. Still in infancy, there is little known about the consequences associated with storing hydrogen in naturally existing (depleted oil and gas reservoirs, and saline aquifers) as well as artificially intervened (salt caverns) subsurface geological media. This review article aims to define, characterize, and summarize the different types of subsurface geological media currently considered viable for underground hydrogen storage. Present in this article is also an elaboration of hydrogen's physiochemical properties and the resulting potential interactions that may occur, prospects that need to be addressed and challenges that need to be overcome in ensuring hydrogen's large scale geological storage.
... Fang and Li (2014) have reported that constant pressure injection operation is preferable to the constant rate injection operation in Jianghan Basin. The smaller the well spacing between the injection well and production well, the earlier the CO 2 could be produced in the production well, and the greater the pressure-drop at the bottom of the injection well (Court et al., 2012). Producing brine from CO 2 injection interval and then re-injection into the overlying shallower aquifers can improve CO 2 injectivity and reduce the risks of leakage, and at the same time increase CO 2 storage capacity by 30% or more (Hosseini and Nicot, 2012). ...
The industrial development of Xinjiang is facing serious carbon emissions and water shortage problems in this region. It is urgent to find a sustainable development way. CO2 geological storage combined with enhanced water recovery (CO2-EWR) is a win-win technology that can increase CO2 geological storage potential and obtain abundant groundwater resources meanwhile. A 3D heterogeneous geologic model was built to estimate the potential of field-scale CO2 geological storage combined with enhanced water recovery according to the seismic, well logging data and well testing data of the Cretaceous Donggou Formation in the eastern Junggar Basin of China. Twelve injection-production scenarios were designed. The results show that CO2-EWR technology can greatly reduce the pressure buildup with the minimum pressure increase of 1.3 MPa and thus increase CO2 injection with a maximum cumulative amount of 100 Mt, three times more than that for sole CO2 injection. Also, it can enhance total production of deep saline water by a factor of ~100 compared to that for sole water production. Formation parameters such as permeability, porosity and slope of the reservoir primarily control the migration and dissolution of CO2. The heterogeneity of the reservoir plays an important role in the CO2 spatial distribution and even saline water production. One injection well with constant rate injection of CO2 and one production well with constant pressure production of saline water scenario is the preferred option in engineering practice of eastern Junggar Basin, which can obtain the maximum amount of CO2 injection and saline water resources. This study provides a technical reference for implementation of CO2-EWR at the field-scale or industrial-scale to solve CO2 emission reduction and water shortage problems.
... Post-storage processing considers both the dehydration of the hydrogen (which can be substantial [42]) as well as separation from other gasses utilised or produced through biological processes. One such method to add value, suggested by Court et al. for CO 2 storage, is the additional desalination of the extracted saline water (in water stressed regions) to provide use in either industry, agriculture or domestic applications [97]. Desalination is a cost intensive process which may be necessary if offshore production/storage is necessary. ...
To reduce effects from anthropogenically induced climate change renewable energy systems are being implemented at an accelerated rate, the UKs wind capacity alone is set to more than double by 2030. However, the intermittency associated with these systems presents a challenge to their effective implementation. This is estimated to lead to the curtailment of up to 7.72 TWh by 2030. Through electrolysis, this surplus can be stored chemically in the form of hydrogen to contribute to the 15 TWh required by 2050. The low density of hydrogen constrains above ground utility-scale storage systems and thus leads to exploration of the subsurface.
This literature review describes the challenges and barriers, geological criteria and geographical availability of all utility-scale hydrogen storage technologies with a unique UK perspective. This is furthered by discussion of current research (primarily numerical models), with particular attention to porous storage as geographical constraints will necessitate its deployment within the UK. Finally, avenues of research which could further current understanding are discussed.
... This is particularly important in uncertainty analysis, allowing different geological realizations to be run quickly to see potential impacts of different interpretations, and when new information comes through from field operations (Dance et al., 2019). The ability of numerical models to conform to observed plume migration is vital for demonstrating compliance with regulators, that is, within a specified area of review (Court et al., 2012; ...
Plain Language Summary
Geological carbon storage is a promising technique to reduce greenhouse gas emissions. Captured carbon dioxide is generally injected into a subsurface reservoir over 1,000 m underground, displacing resident brine and eventually becoming trapped underneath a low‐permeability caprock seal. However, at several industrial‐scale storage sites around the world, the carbon dioxide has migrated laterally away from the injection well much quicker than anticipated and followed pathways that are not predicted by models. It is crucial that these models can predict the migration and demonstrate safe storage to owners and policy makers. In this work, we show that one source of the discrepancy is the omission of the impacts of small‐scale rock heterogeneities in these models. We experimentally characterize rock cores from a North Sea reservoir at high resolution, and through rigorous multiscale modeling show that centimeter‐meter‐scale heterogeneities in the rock structure, for example, small mudstone layers in sandstone, can cause rapid migration at larger, meter‐kilometer scales. Carbon dioxide can migrate up to 200% faster in the presence of layered heterogeneities. These heterogeneities are ubiquitous in nature and provide an explanation for the behavior seen at storage sites worldwide. Our modeling approach incorporates this behavior, improving the predictability and control of storage operations.
... To maximize the CO 2 storage capacity into a given reservoir during a limited period, techniques that reduce the reservoir pressure buildup, such as brine extraction before injection and variable injection rates, have been proposed and studied in numerical simulations. [12][13][14][15][16] Brine withdrawal is consistently found to be very effective at controlling serious pressure buildup and for maintaining a desired injectivity for large-scale CO 2 injection in saline aquifers, but this type of pressure control would cause the additional environmental problem of brine water disposal. Continuous injection with varying injection rates was found to have no significant effects on the overall pressure buildup in several studies, 12,[17][18][19] but it was suggested that it may influence the injectivity and storage capacity. ...
Past reservoir simulations of carbon dioxide (CO2) storage in saline aquifers have shown that the injection procedure can influence CO2 storage efficiency and injectivity. To investigate the influence of injection rate and timing on reservoir dynamics and storage performance, scenarios of continuous and intermittent injections were devised for storing 1 million tonnes of CO2 per year for 30 years and were assessed through numerical simulations on saline aquifers constructed with real field data. Our results show that almost all the intermittent injections need higher injection pressure than the constant injection for the same targeted amount of CO2. Only one intermittent injection showed the potential to have a lower injection pressure than the constant injection. The injectivity for the constant injection consistently declines over the years, while the intermittent injections result in an injectivity above a reference value for some years, with the number of years that maintain the injectivity linearly increasing with the length of the injection break. The injectivity for an intermittent injection peaks a few years later after the injection starts. Intermittent injections improve the residual and solubility trapping by up to 15% only in the first few years of injection, but the differences in trapping efficiencies among all the injections are within a few percent in the long term. Therefore, the intermittent injections would be useful for a CO2 storage project to make the best use of a reservoir in 5–10 years under the injection pressure restrictions. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.
... They indicated that injection-induced overpressure particularly in the near-well regions can be relieved by producing water from dedicated water production wells and that the treated saline waters can be used as cooling water for power plants [14,23], but the adverse consequences are the associated higher costs of the intervention operations [24]. The brine extraction combined with CO 2 injection could effectively reduce the reservoir pressure, and the amount of CO 2 dissolved in the brine will increase significantly due to the extraction of saline water, thereby improving the security of CO 2 storage [25][26][27]. ...
CO 2 geological storage (CGS) proved to be an effective way to mitigate greenhouse gas emissions, and CO 2 -enhanced water recovery (CO 2 -EWR) technology may improve the efficiency of CO 2 injection and saline water production with potential economic value as a means of storing CO 2 and supplying cooling water to power plants. Moreover, the continuous injection of CO 2 may cause a sharp increase for pressure in the reservoir system, so it is important to determine reasonable reservoir pressure control strategies to ensure the safety of the CGS project. Based upon the typical formation parameters of the China Geological Survey CO 2 -EWR test site in the eastern Junggar Basin, a series of three-dimensional (3D) injection-extraction models with fully coupled wellbores and reservoirs were established to evaluate the effect of the number of production wells and the well spacing on the enhanced efficiency of CO 2 storage and saline production. The optimal key parameters that control reservoir pressure evolution over time are determined. The numerical results show that a smaller spacing between injection and production wells and a larger number of production wells can enhance not only the CO 2 injection capacity but also the saline water production capacity. The effect of the number of production wells on the injection capacity and production capacity is more significant than that of well spacing, and the simulation scenario with 2 production wells, one injection well, and a well spacing of 2 km is more reasonable in the demonstration project of Junggar Basin. CO 2 -EWR technology can effectively control the evolution of the reservoir pressure and offset the sharp increase in reservoir pressure caused by CO 2 injection and the sharp decrease of reservoir pressure caused by saline production. The main controlling factors of pressure evolution at a certain spatial point in a reservoir change with time. The monitoring pressure drops at the beginning and is controlled by the extraction of water. Subsequently, the injection of CO 2 plays a dominant role in the increase of reservoir pressure. Overall, the results of analysis provide a guide and reference for the CO 2 -EWR site selection, as well as the practical placement of wells.
... Optimization of well placement, CO 2 injection rates, and brine cycling for geological carbon sequestration can significantly reduce the mobile CO 2 fraction，variable-speed injection is more conducive to raising the immobile CO 2 fraction [8][9][10]. At the same time, it is also found that the smaller space between injection and production wells, the earlier break-through time of CO 2 , the greater pressure drop at the bottom of the injection wells [11]. The physical parameters, salinity, and boundary conditions of the reservoir will affect the reservoir pressure change and the CO 2 storage efficiency during the injection and extraction process [12]. ...
Xinjiang is the major energy production area, and one of the regions with the most serious water resources scarcity issues in China. In particular, the coal-fired power and coal chemical industry base in East Junggar Basin has faced severe carbon emissions and water shortages. Based on the 3D heterogeneous geologic model of the East Junggar Basin, the research of field-scale CO2 enhanced water recovery (CO2-EWR) was carried out to provide technical reference for the future field-scale CO2-EWR engineering practice in Xinjiang to solve the carbon emission and water shortage issues. The CO2-EWR technology can greatly relieve the reservoir pressure buildup, with a maximum cumulative CO2 injection and storage of 100 Mt (3 times more than CO2 Geological Storage only) and a maximum saline water production of 129.4 Mt (100 times more than saline water production only).
... 7,19 It should be noted that brine production via vertical wells has limited impact on the CO 2 plume shape. 24 Court found that a single ring of four vertical brine production wells, placed outside of the outer extent of the CO 2 plume (in order to avoid CO 2 breakthrough), has negligible steering potential on the CO 2 plume. 25 Brine produced downdip of CO 2 injection can strongly influence CO 2 migration; however, without brine production, buoyancy drives CO 2 updip. ...
Within the context of CO2 geological storage, excessive pressure build-up is undesirable because it increases the risks of CO2 plume leaks into unwanted zones, reduces the storage capacity of the formation, and can limit the life of a storage project. In this study, we designed a brine extraction field pilot project for pressure management and plume control in the Hosston Formation at the Devine Test Site (DTS) in Texas. We investigated the possibility of using seismic and tracer data to monitor pressure front and injected fluids plume. Seismic surveys provide the volumetric coverage needed to understand the 3D subsurface fluid and pore pressure front movement; however, the limit of seismic detectability may be influenced by Hosston Formation initial pore pressure. The range of minimum pore pressure increase needed to produce detectable P-wave and S-wave seismic velocities is investigated. Simulation study of active pressure management system (APMS) and passive pressure management system (PPMS) at the DTS is performed using the numerical simulator CMG-STARS to demonstrate the possibility of controlling pressure build up in the storage formation. The estimation of pore pressure increase from flow simulations will help us to understand if the pressure changes during brine injection and extraction can be detected using seismic response. Study findings show that 4D seismic is an appropriate monitoring tool considering the level of expected increase in pressure at the DTS and that, as expected, brine extraction is successful in controlling the pressure build up and potentially can steer the plume at the DTS. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd.
... To relieve the increase of average reservoir pressure, many brine-extraction based storage strategies were proposed for pressure management during CO2 injection [11][12][13]. However, these strategies have a major challenge of dealing with a large volume of extracted brine. ...
The closed-loop version of surface dissolution strategy is one of the safest techniques for CO2 storage as it greatly reduces the risks associated with buoyant CO2 leakage and aquifer pressurization, and eliminates the problem of brine disposal. However, large injection rates are crucial for the feasibility of closed-loop surface dissolution, and these rates could be constrained by the operation strategies and the buildup of average reservoir pressure. In this work, we compare two operating strategies to attain the optimal safe storage rates and find that the optimal operation is the multiple-rates injection. This provides the maximum injection rates and smallest well counts needed to satisfy a given storage target. The impact of elevated average reservoir pressure under infinite-acting boundary condition is quantified and evaluated for injection operation up to 30 years.
... However, the pure industrial-scale injection of CO 2 will not only lead to the severe pressure buildup thereby limiting CO 2 storage capacity and security (Birkholzer et al. 2009;Yamamoto et al. 2009), but also add to huge costs incurred by both industries and governments. Supercritical CO 2 -enhanced brine recovery (EBR) and enhanced geothermal system (EGS) have been proposed to be a win-win method for the enhancement of CO 2 storage capacity and supplement of water resource and energy supply (Bergmo et al. 2011;Birkholzer et al. 2012;Court et al. 2012;Buscheck et al. 2012;Fang and Li 2014). Especially for the high valueadded brine resources in deep saline aquifers, brine recovery enhanced by supercritical CO 2 may be more attractive to the investors since the pure industrial-scale production of brine will lead to a significant decrease in the formation pressure and brine production efficiency. ...
Deep brine recovery enhanced by supercritical CO2 injection is proposed to be a win–win method for the enhancement of brine production and CO2 storage capacity and security. However, the cross-flow through interlayers under different permeability conditions is not well investigated for a multi-layer aquifer system. In this work, a multi-layer aquifer system with different permeability conditions was built up to quantify the brine production yield and the leakage risk under both schemes of pure brine recovery and enhanced by supercritical CO2. Numerical simulation results show that the permeability conditions of the interlayers have a significant effect on the brine production and the leakage risk as well as the regional pressure. Brine recovery enhanced by supercritical CO2 injection can improve the brine production yield by a factor of 2–3.5 compared to the pure brine recovery. For the pure brine recovery, strong cross-flow through interlayers occurs due to the drastic and extensive pressure drop, even for the relative low permeability (k = 10⁻²⁰ m²) mudstone interlayers. Brine recovery enhanced by supercritical CO2 can successfully manage the regional pressure and decrease the leakage risk, even for the relative high permeability (k = 10⁻¹⁷ m²) mudstone interlayers. In addition, since the leakage of brine mainly occurs in the early stage of brine production, it is possible to minimize the leakage risk by gradually decreasing the brine production pressure at the early stage. Since the leakage of CO2 occurs in the whole production period and is significantly influenced by the buoyancy force, it may be more effective by adopting horizontal wells and optimizing well placement to reduce the CO2 leakage risk.
... A unique aspect of geological carbon storage is the large-scale injection of massive amounts of CO 2 , which could have unintended adverse environmental consequences including possible leakage of fluids from the injection formation to shallow drinking-water aquifers or to the atmosphere, and possible induced seismicity associated with the elevated fluid pressures [IPCC, 2005;Celia et al., 2011;Zoback and Gorelick, 2012;Pawar et al., 2015;Jones et al., 2015]. While these risks are potentially important, it appears that proper site selection, site characterization, and possible pressure control through brine extraction, can minimize both of these risks [Bergmo et al., 2011;Birkholzer et al., 2012;Court et al., 2012a;Juanes et al., 2012;Nogues et al., 2012;Zhang et al., 2013;Tao and Bryant, 2014;Vilarrasa and Carrera, 2015]. The overall result is that the environmental benefits of carbon storage are expected to significantly outweigh the potential environmental risks of large-scale injection, especially given the large benefits associated with keeping average temperature increases below 28C. ...
Carbon capture and storage (CCS), involves capture of CO2 emissions from power plants and other large stationary sources and subsequent injection of the captured CO2 into deep geological formations. This is the only technology currently available that allows continued use of fossil fuels while simultaneously reducing emissions of CO2 to the atmosphere. Although the subsurface injection and subsequent migration of large amounts of CO2 involve a number of challenges, many decades of research in the earth sciences, focused on fluid movement in porous rocks, provides a strong foundation on which to analyze the system. These analyses indicate that environmental risks associated with large CO2 injections appear to be manageable.
... IJGGC-1974; No. of Pages 19 Breunig et al., 2013; Buscheck et al., 2011 Buscheck et al., , 2012 Court et al., 2012; Deng et al., 2012; Dempsey et al., 2014; Heath et al., 2013 Hermanrud et al., 2013 Roach et al., 2014). The trade-off between achieving early pressure relief and delayed CO 2 breakthrough has been identified as a key challenge. ...
Carbon capture, utilization and storage (CCUS) seeks beneficial applications for CO2 recovered from fossil fuel combustion. This study evaluated the potential for removing formation water to create additional storage capacity for CO2, while simultaneously treating the produced water for beneficial use. The process would control pressures within the target formation, lessen the risk of caprock failure, and better control the movement of CO2 within that formation. The project plans to highlight the method of using individual wells to produce formation water prior to injecting CO2 as an efficient means of managing reservoir pressure. Because the pressure drawdown resulting from pre-injection formation water production will inversely correlate with pressure buildup resulting from CO2 injection, it can be proactively used to estimate CO2 storage capacity and to plan well-field operations. The project studied the GreenGen site in Tianjin, China where Huaneng Corporation is capturing CO2 at a coal fired IGCC power plant. Known as the Tianjin Enhanced Water Recovery (EWR) project, local rock units were evaluated for CO2 storage potential and produced water treatment options were then developed. Average treatment cost for produced water with a cooling water treatment goal ranged from 2.27 to 2.96 US$/m3 (recovery 95.25%), and for a boiler water treatment goal ranged from 2.37 to 3.18 US$/m3 (recovery 92.78%). Importance analysis indicated that water quality parameters and transportation are significant cost factors as the injection-extraction system is managed over time. The study found that in a broad sense, active reservoir management in the context of CCUS/EWR is technically feasible. In addition, criteria for evaluating suitable vs. unsuitable reservoir properties, reservoir storage (caprock) integrity, a recommended injection/withdrawal strategy and cost estimates for water treatment and reservoir management are proposed.
... For this purpose, coupled hydro-mechanical simulations are applied to account for the interaction between hydraulic and mechanical processes, potentially triggering fault slip and dilation resulting in, e.g., new or enhanced leakage pathways for formation fluids. To minimise pressure perturbation due to fluid injection, and thus fault fluid flow, simultaneous fluid injection and production from storage reservoirs is discussed as one efficient mitigation measure to be applied in geological underground utilisation (Kempka et al., 2015b; Tillner et al., 2013b; Court et al., 2012; Bergmo et al., 2011; Buscheck et al., 2011). For future investigations, we extend the assumptions made in the present study by the implementation of heterogeneous fault zones with spatial variations in porosity and permeability as well as related non-uniform architecture and fault inclination . ...
Injection of fluids into deep saline aquifers causes a pore pressure
increase in the storage formation, and thus displacement of resident brine.
Via hydraulically conductive faults, brine may migrate upwards into
shallower aquifers and lead to unwanted salinisation of potable groundwater
resources. In the present study, we investigated different scenarios for a
potential storage site in the Northeast
German Basin
using a three-dimensional (3-D) regional-scale model that includes four major fault zones. The focus was on assessing
the impact of fault length and the effect of a secondary reservoir above the
storage formation, as well as model boundary conditions and initial salinity
distribution on the potential salinisation of shallow groundwater resources.
We employed numerical simulations of brine injection as a representative
fluid.
Our simulation results demonstrate that the lateral model boundary settings
and the effective fault damage zone volume have the greatest influence on
pressure build-up and development within the reservoir, and thus intensity
and duration of fluid flow through the faults. Higher vertical pressure
gradients for short fault segments or a small effective fault damage zone
volume
result in the highest salinisation potential due to a larger vertical fault
height affected by fluid displacement. Consequently, it has a strong impact
on the degree of shallow aquifer salinisation, whether a gradient in salinity
exists or the saltwater–freshwater interface lies below the fluid displacement
depth in the faults. A small effective fault damage zone volume or low fault
permeability further extend the duration of fluid flow, which can persist
for several tens to hundreds of years, if the reservoir is
laterally confined. Laterally open reservoir boundaries, large effective fault damage zone volumes and intermediate reservoirs significantly reduce vertical brine
migration and the potential of freshwater salinisation because the origin
depth of displaced brine is located only a few decametres below the shallow
aquifer in maximum.
The present study demonstrates that the existence of hydraulically
conductive faults is not necessarily an exclusion criterion for potential
injection sites, because salinisation of shallower aquifers strongly depends
on initial salinity distribution, location of hydraulically conductive
faults and their effective damage zone volumes as well as geological boundary
conditions.
... Different authors (Bergmo et al., 2011;Court et al., 2012;Tillner et al., 2013a;Nielsen et al., 2013) demonstrated that formation fluid extraction supports geological CO 2 storage by increasing storage efficiency and reducing reservoir pressure elevation. Depending on the target formation depth, extracted fluids may be used for geothermal heat recovery or disposed according to national environmental regulations. ...
We assessed the synergetic benefits of simultaneous formation fluid extraction during CO2 injection for reservoir pressure management by coupled hydro-mechanical simulations at the prospective Vedsted storage site located in northern Denmark. Effectiveness of reservoir pressure management was investigated by simulation of CO2 storage without any fluid extraction as well as with 66% and 100% equivalent volume formation fluid extraction from four wells positioned for geothermal heat recovery. Simulation results demonstrate that a total pressure reduction of up to about 1.1 MPa can be achieved at the injection well. Furthermore, the areal pressure perturbation in the storage reservoir can be significantly decreased compared to the simulation scenario without any formation fluid extraction. Following a stress regime analysis, two stress regimes were considered in the coupled hydro-mechanical simulations indicating that the maximum ground surface uplift is about 0.24 m in the absence of any reservoir pressure management. However, a ground uplift mitigation of up to 37.3% (from 0.24 m to 0.15 m) can be achieved at the injection well by 100% equivalent volume formation fluid extraction. Wellbased adaptation of fluid extraction rates can support achieving zero displacements at the proposed formation fluid extraction wells located close to urban infrastructure. Since shear and tensile failure do not occur under both stress regimes for all investigated scenarios, it is concluded that a safe operation of CO2 injection with simultaneous formation fluid extraction for geothermal heat recovery can be implemented at the Vedsted site.
... CO2/brine surface dissolution has advantages over standard CO2 injection approach in its significant reduction of storage risks associated with buoyant CO2 leakage and aquifer pressurization. Also compared with other brineextraction based strategies [6,7], surface dissolution eliminates the problem of brine disposal. The operation process of CO2/brine surface dissolution strategy mainly involves brine extraction from formation, surface transport of brine, mixing of brine and capture CO2, and injection of CO2saturated brine into storage formation (Figure 1). ...
Among various CO2 injection strategies, CO2/brine surface dissolution is one of the most promising techniques for optimizing injectivity, pressure management, storage efficiency and storage security. Like other storage schemes, the feasibility of large scale implementation strongly depends on the injectivity, which could be limited by the prohibition of fracture initiation. In this work, we calculated the maximum safe injection rate for surface dissolution with consideration of the induced thermoelastic stress during operation. Impact of wells interference is also analysed in field-scale application. Some measures are proposed to reduce limitations on injectivity.
... Many CO 2 reservoir studies of pressure management use separate, single-mode CO 2 -injection wells and brineextraction wells [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] and the trade-off between early pressure relief and delayed CO 2 breakthrough has been identified as a key operational challenge. Early pressure relief requires close well spacing between the CO 2 injectors and brine producers, but delayed CO 2 breakthrough at brine producers requires large spacing [10]. ...
We present a reservoir management approach for geologic CO2 storage that combines CO2 injection with brine extraction. In our approach, dual-mode wells are initially used to extract formation brine and subsequently used to inject CO2 . These wells can also be used to monitor the subsurface during pre-injection brine extraction so that key data is acquired and analyzed prior to CO2 injection. The relationship between pressure drawdown during pre-injection brine extraction and pressure buildup during CO2 injection directly informs reservoir managers about CO2 storage capacity. These data facilitate proactive reservoir management, and thus reduce costs and risks. The brine may be used directly as make-up brine for nearby reservoir operations; it can also be desalinated and/or treated for a variety of beneficial uses.
... CO 2 capture costs, sequestration safety, and public acceptance have been recognized for a number of years [1] . Receiving more recent attention are water-use demands from CO 2 capture, porespace competition with emerging activities, such as shale-gas production, and induced seismicity [11,12]. Besides parasitic energy and water costs associated with CO 2 capture, the primary technical driver for the most challenging implementation barriers is overpressure caused by CO 2 injection. ...
Large-scale geologic CO 2 storage (GCS) can be limited by overpressure, while geothermal energy production is often limited by pressure depletion. We investigate how synergistic integration of these complementary systems may enhance the viability of GCS by relieving overpressure, which reduces pore-space competition, the Area of Review, and the risks of CO 2 leakage and induced seismicity, and by producing geothermal energy and water, which can defray parasitic energy and water costs of CO 2 capture.
... 27 Pressure management via brine extraction can provide many other benefi ts, such as increased storage capacity, reduced failure risk, smaller area for monitoring, less interference with other subsurface activities, and manipulation of the CO 2 plume. [28][29][30][31] On the other hand, brine extraction requires pumping, transportation, possibly treatment, and disposal of substantial volumes of extracted brackish or saline water, all of which can be technically challenging and expensive. 32 Reservoir management via brine extraction can be a valuable strategy in projects where pressure increase is a real concern, but due to the expected cost brine extraction is unlikely to be become a standard component of large-scale CO 2 sequestration projects. ...
This paper discusses the current guidance given by the United States Environmental Protection Agency (EPA) on delineating the so-called Area of Review (AoR) for the permitting of geologic carbon sequestration (GCS) projects. According to the EPA's regulatory framework for GCS, the AoR refers to the region surrounding the CO2 injection well(s) wherein leakage of CO2 and/or the migration of formation fluids could possibly endanger overlying groundwater resources. Our evaluation of the current framework for delineating the size of this area finds unnecessary conservatism in the definition of the critical pressure, which could lead to a heavy burden on permit applicants that seek to get regulatory compliance, in particular for very large GCS projects. We propose a risk-based re-interpretation of this framework, separating the total Area of Review into different sub-areas with different regulatory requirements depending on whether the concern is about free-phase CO2 or pressure-driven brine migration. This leads to a tiered AoR definition in which the projected region of CO2 plume extent would have the highest regulatory standards regarding site characterization, monitoring, and corrective action. The requirements in the AoR outside this central region would be less burdensome because of a narrower focus on major pathways for brine leakage such as unplugged wellbores and large faults. We expect that this revised framework would allow for a reduction in the cost of regulatory compliance for projects with very large injection volumes, while ensuring that the objective of protecting valuable groundwater resources is preserved.
... In addition, the influence of formation parameters on CO 2 migration and dissolution, as well as on reservoir pressure under operational conditions, also presents a primary concern for a CO 2 -EWR full-chain system. Currently, the research regarding the sensitivity of formation parameters and reservoir pressure management have been relatively widely investigated [13][14][15][16][17][18][19]; however, relatively few studies have concentrated on the impact of well arrangements and formation parameters under a withdrawal condition of deep saline water [20]. Kobos et al. [21] created a two-dimensional injection-extraction model of saline aquifers using the TOUGH2 software and found that the accu-mulations of pressure in the reservoir could also be mitigated effectively, even when the pumping wells were at a 6 km distance from the injector of CO 2 , and the CO 2 migration distance was an exponential function of the injection rate and time. ...
CO2 geological storage, when combined with deep saline water recovery (CO2-EWR), not only achieves the relatively secure storage of CO2 that was captured from the coal chemical industry, due to lower pressure, but also enhances saline water for drinking and industrial or agricultural utilization. This storage will undoubtedly become a win–win choice for the enhancement of energy security and for the promotion of regional development in China, particularly for western regions with a relative shortage of water resources and a more fragile ecological environment. In this paper, a three-dimensional injection–extraction model is established that uses the TOUGH2/ECO2N program according to typical formation parameters of a coal chemical industry in the Xinjiang Uyghur Autonomous Region. Numerical results showed that under the guarantee of sufficient water conditions, 1.73 × 108 tons of saline water could be produced when the CO2-EWR is adopted. Well arrangements and formation parameters are also analyzed, and the following conclusions can be drawn: arrangements of pumping wells, such as pumping well number, pumping rate and distance, have considerable influences on the reservoir pressure, and in addition, the sensitivity of pressure on the distance and pumping rate decreases as their values increase. In view of these features, it is necessary to find an optimal point to achieve the best combination of pressure, the leakage time and the amount of dissolution. Formation parameters primarily control the mechanism of CO2 migration and dissolution. Salinity in the salt water has the greatest impact on CO2 dissolution trapping followed by permeability and porosity. The arrival time that is allowable for saline water production primarily depends on porosity followed by the permeability ratio and the arrangements of pumping wells. The reservoir pressure change that is caused by parameters is not obvious compared with setting pumping wells. Overall, CO2-EWR technology is a potential strategic choice for China, particularly in western regions. Additionally, the analysis results provide a reliable guide and reference for CO2 storage site selection, as well as the practical arrangements of wells.
... Further major concern is that pressurization may force displaced brines to migrate along leakage pathways from the storage formation into shallow groundwater reservoirs with potable water resources [4]. To prevent overpressurisation and associated risks in saline aquifers the extraction of formation water from the storage reservoir by active brine production concurrent to CO 2 injection has been shown to be a potential strategy [5][6]. Even with passive water production which requires that aquifer pressure exceeds the hydrostatic pressure near the production well, the pressure build-up in the formation can be significantly reduced especially in the near--driven pressure management relief via targeted brine extraction in particular at discrete geological features with a higher risk potential such as critically stressed faults to prevent (re-)activation. ...
Geological storage of CO2 in deep saline aquifers is considered as option for reducing anthropogenic greenhouse gas emissions into the atmosphere. Most often the same aquifers might allow for provision of geothermal energy potentially resulting in a competitive situation. Within the frame of the present study we evaluated the feasibility of synergetic utilisation of a reservoir suitable for both, CO2 storage and geothermal heat exploitation, by 3D numerical simulations of simultaneous CO2 and brine (re-) injection and brine production. Based on structural and petrophysical data from a prospective storage site in the North East German Basin different scenarios were investigated taking into account reservoir permeability anisotropy and varying flow related descriptions of existing faults. Simulation results show that for an isotropic horizontal permeability distribution synergetic use is feasible for at least 30 years. Nevertheless, permeability anisotropy and open faults do have an impact on the CO2 arrival time at the brine production well and should be taken into account for implementation of a synergetic utilisation in the study area.
... The second test problem is a countercurrent vertical redistribution of a CO 2 bank in the center of an aquifer. Even though this is not a very realistic scenario, this The parameters used in the section are characteristic for the Mount Simon formation in the Illinois Basin in 1.5 − 3km depth [Court et al., 2012]. We have summarized them inTable 7 ...
In the most basic description, flow and transport of CO2 in geological formations are governed by the equations of mass conservation, Darcy's law and appropriate constitutive relationships. This leads to a set of cou-pled non-linear partial differential equations, for which accurate discretiza-tions in space and time are needed. A popular approach is to rewrite the equations into a pressure equation (of elliptic/parabolic character) coupled with one or more transport equations (of hyperbolic/parabolic character). In the appropriate limits, this system can be split into an elliptic pressure equation coupled with a hyperbolic conservation law, for which efficient solution methods exist. However, most problems of practical interest are at least in parts outside these limits, and solution approaches must be sought which are robust in terms of a wide range of flow regimes. In this chapter we discuss the theoretical and practical aspects of im-plementing solution strategies utilizing an implicit pressure equation cou-pled to an explicit mass transport. We see that in many cases, non-trivial generalizations of the limiting cases need to be considered. These generalizations have been explored by researchers in various applications, however, a modern exposition is not available. Our goal is thus to provide a self-contained description of a robust solution strategy covering the solubility ranges and flow regimes of interest for practical simulation of CO2 storage.
... For industrial-scale CO 2 injection in saline formations, pressure buildup is a limiting factor in CO 2 sequestration capacity and risk mitigation because it drives CO 2 and brine migration (Birkholzer and Zhou, 2009). As a means to mange pressure buildup and to control CO 2 and brine migration, Lawrence Livermore National Laboratory (LLNL) and Princeton University have been collaborating on the development of Active CO 2 Reservoir Management (ACRM), which combines brine extraction and treatment and residual-brine reinjection with CO 2 injection (Buscheck et al., 2011aBuscheck et al., , 2012aBuscheck et al., , 2012b Court et al., 2011b Court et al., , 2012 Court, 2011). This concept is being considered for specific CCS sites in the state of Wyoming (Surdam et al., 2009) and off the coast of Norway (Bergmo et al., 2011). ...
... As discussed earlier, pressure buildup can limit CO 2 storage capacity for industrial-scale GCS because it is the main physical drive for potential risks, such as induced seismicity and CO 2 and brine leakage (Birkholzer and Zhou, 2009). As a means to manage pressure buildup and to control CO 2 and brine migration, investigators are considering pressure management approaches, such as Active CO 2 Reservoir Management (ACRM), which combines extraction and beneficial consumptive use of brine with CO 2 injection (Buscheck et al., 2011aBuscheck et al., , 2012aBuscheck et al., , 2012b Court et al., 2011a Court et al., , 2011b Court et al., , 2012), and Impact Driven Pressure Management (IDPM)Figure 1. An actively managed, two-stage, integrated geothermal–GCS system, using binary-cycle power generation, is shown in a saline, permeable, sedimentary formation.Birkholzer et al., 2012). ...
We analyze an adaptable, multi-stage, energy-recovery approach to reduce carbon intensity through sustainable geothermal energy production and secure geologic CO 2 storage (GCS) with low environmental risk in saline, sedimentary formations. We combine the benefits of the approach proposed by Buscheck (2010), which uses brine as the heat-transfer working fluid, with those of the approach first suggested by Brown (2000) and analyzed by Pruess (2006), using CO 2 as the working fluid, and then extended to saline-formation GCS by Randolph and Saar (2011a). We also use pressure management to reduce the risks of induced seismicity and CO 2 and brine leakage (Buscheck et al., 2012a; Court et al., 2012, 2011a, 2011b). Our approach can involve up to three stages, with stage one of the three-stage version involving recirculation of formation brine as the working fluid. In this paper we analyze a two-stage version, with stage one involving production (and net removal) of formation brine for heat recovery and to provide pressure management/relief for CO 2 injection. Net removal of produced brine is achieved by applying it to a beneficial consumptive use: feedstock for fresh water production through desalination, saline cooling water, or make-up water injected into a nearby reservoir operation, such as in Enhanced Geothermal Systems (EGS), where there can be a shortage of working fluid. For stage one, it is important to find feasible utilization/disposition options to reduce the volume of blowdown, which is the residual brine requiring reinjection into the geothermal-GCS reservoir (Buscheck et al. 2012a, 2012b). During stage two, which begins as CO 2 reaches the producers; co-produced brine and CO 2 are the working fluids. We present reservoir analyses of two-stage, integrated geothermal-GCS, using a simple conceptual model of a homogeneous, permeable reservoir, bounded by relatively impermeable sealing units. We assess both CO 2 storage capacity and geothermal energy production as a function of well spacing between CO 2 injectors and brine/CO 2 producers for various well patterns.
... A comprehensive review is presented by of progress, since the SRCCS, on several of these CCS implementation challenges: water management; sequestration safety; pore-space competition; legal and regulatory; and public acceptance. Active CO 2 Reservoir Management (ACRM), applied to CO 2 Capture, Utilization, and Storage (CCUS), is being considered as a means of addressing these implementation barriers (Buscheck et al., 2011aBuscheck et al., , 2011bBuscheck et al., , 2011c Court et al., , 2011b Court et al., , 2011c Neal et al., 2011). ACRM combines brine production with CO 2 injection with the primary goal of enhancing reservoir performance to provide safe, secure, and efficient CO 2 storage. ...
CO2 capture, utilization, and storage (CCUS) in deep geological formations is regarded as a promising means of lowering the amount of CO2 emitted to the atmosphere and thereby mitigating global climate change. For commercial-scale CO2 injection in saline formations, pressure buildup can limit CO2 storage capacity and security. Issues of interest include the potential for CO2 leakage to the atmosphere, brine migration to overlying potable aquifers, and pore-space competition with neighboring subsurface activities. Active CO2 Reservoir Management (ACRM) combines brine production with CO2 injection to relieve pressure buildup, increase injectivity, spatially and temporally constrain brine migration, and enable beneficial utilization of produced brine. Useful products may include freshwater, cooling water, make-up water for oil, gas, and geothermal reservoirs, and electricity generated from extracted geothermal energy. By controlling pressure buildup and fluid migration, ACRM can limit interactions with neighboring subsurface activities, reduce pore-space competition, and allow independent assessment and permitting. ACRM provides benefits to reservoir management at the cost of extracting brine. The added cost must be offset by the added benefits to the storage operation and/or by creating new, valuable uses that reduce the total added cost. We review potential uses of produced brine and conduct a numerical study of potential reservoir benefits. Using the NUFT code, we investigate CO2 -injector/brine-producer strategies to improve CO2 storage capacity and minimize interference with neighboring subsurface activities. Performance measures considered in this study include magnitude of vertical brine migration and areal extent and duration of pressure buildup. We consider ranges of CO2 -storage-formation thickness and permeability and caprock-seal thickness and permeability, comparing injection-only cases with ACRM cases with a volumetric production-to-injection ratio of one. The results of our study demonstrate the potential benefits of brine production to CO2 -storage operations. The economic value of these benefits will require more detailed, site-specific analyses in future studies.
... Much of this resource base exists in locations, such as the Midwest, where the need also exists to reduce CO 2 emissions and where the cost of electricity is relatively high (Buscheck, 2010). Lawrence Livermore National Laboratory (Buscheck et al., 2011aBuscheck et al., , 2011bBuscheck et al., , 2011c Aines et al., 2011) and Princeton University (Court et al., 2011aCourt et al., , 2011b), are developing an approach, called Active CO 2 Reservoir Management (ACRM), which combines CO 2 injection, brine production and desalination, and residual-brine reinjection to produce fresh water, and, if formation temperatures are high enough, geothermal energy (Buscheck, 2010). Besides fresh-water production, ACRM can also enable other beneficial utilization options for the produced brine, such as water for cooling purposes, the extraction of mineral commodities, and make-up water for reservoir pressure support in oil, gas, and geothermal energy production (Buscheck et al., 2011bBuscheck et al., , 2011c Harto and Veil, 2011; Bourcier et al., 2007 Bourcier et al., , 2011). ...
Increased reliance on geothermal energy and CO 2 capture and sequestration (CCS) in deep geological formations are both regarded as a promising means of lowering the amount of CO 2 emitted to the atmosphere and thereby mitigate climate change. We investigate an approach to produce geothermal energy and to sequester CO 2 at low cost and risk by integrating geothermal production with CCS in sa-line, sedimentary formations where a significant portion of the U.S. geothermal resource base resides. For industrial-scale CO 2 injection in saline formations, pressure increase can be a limiting factor in storage capacity and security, while geothermal energy production can be limited by pressure depletion. Our approach utilizes Active CO 2 Reservoir Management, which combines brine production with CO 2 injection to enable more cost-effective and secure CO 2 storage. The complementary CCS and geothermal systems are integrated synergistically, with CO 2 injection providing pressure support to maintain productivity of geothermal wells, while brine production provides pressure relief and improved injectivity for CO 2 injectors. A volumetric balance between injected and produced fluids mitigates the environmental and economic risks of reservoir overpressure (CCS concern) or underpressure (geothermal concern), including induced seismicity, insufficient well productivity or injectivity, subsidence, and fluid leakage either to or from overlying formations. We investigate the tradeoff between pressure relief at CO 2 injectors and CO 2 breakthrough time at geothermal brine producers for both vertical and horizontal wells, and address the influence of forma-tion dip and permeability heterogeneity. The combined influence of buoyancy and layered heterogeneity delays CO 2 breakthrough at geothermal production wells, particularly when the permeability contrast is large. Our results indicate adequate pressure relief at CO 2 injectors can be attained, while delaying CO 2 breakthrough at production wells for 30 or more years, thus enabling sustainable geothermal power.
... Basal reservoirs determined to be at risk of induced seismicity for CCS injection may need brine extraction strategies employed (e.g. Court et al. 2012) in order to control pressure buildup and propagation. Nicholson and Wesson (1990) noted that as the orientation of the stress field moves away from the critically stressed, the value of α increases significantly and much higher pore pressures are needed to cause failure. ...
A series of Mb 3.8-5.5 induced seismic events in the midcontinent region, United States, resulted from injection of fluid either into a basal sedimentary reservoir with no underlying confining unit or directly into the underlying crystalline basement complex. The earthquakes probably occurred along faults that were likely critically stressed within the crystalline basement. These faults were located at a considerable distance (up to 10 km) from the injection wells and head increases at the hypocenters were likely relatively small (∼70-150 m). We present a suite of simulations that use a simple hydrogeologic-geomechanical model to assess what hydrogeologic conditions promote or deter induced seismic events within the crystalline basement across the midcontinent. The presence of a confining unit beneath the injection reservoir horizon had the single largest effect in preventing induced seismicity within the underlying crystalline basement. For a crystalline basement having a permeability of 2 × 10(-17) m(2) and specific storage coefficient of 10(-7) /m, injection at a rate of 5455 m(3) /d into the basal aquifer with no underlying basal seal over 10 years resulted in probable brittle failure to depths of about 0.6 km below the injection reservoir. Including a permeable (kz = 10(-13) m(2) ) Precambrian normal fault, located 20 m from the injection well, increased the depth of the failure region below the reservoir to 3 km. For a large permeability contrast between a Precambrian thrust fault (10(-12) m(2) ) and the surrounding crystalline basement (10(-18) m(2) ), the failure region can extend laterally 10 km away from the injection well.
Carbon capture and sequestration (CCS) is necessary to mitigate global warming caused by anthropogenic (CO2) emissions in the atmosphere. However, due to very high storage cost, it is difficult to sustain the CCS industry. The hot sedimentary and dry rock reservoirs with very high temperature can support both geothermal energy production, and carbon geosequestration economically, provided the CO2 is used as a heat-carrying fluid with proper optimization of injection parameters according to reservoir conditions. In this paper we have reviewed past studies discussing the working mechanisms, pressure management strategies and various advantages of energy extraction from hydrothermal reservoirs by CO2 plume geothermal technology and hot dry rock— enhanced geothermal system (EGS) technology. Past studies highlighted that due to very high thermal expansivity and mobility, supercritical CO2 can produce more heat than water-EGS. For low enthalpy (around 50 degree C and shallow (0.5–1.5 km) reservoirs, CO2 can fetch more heat than water because of higher heat capacity. Other advantages of CCS and EGS are (i) the production of brine or CO2 assisting to manage the reservoir pressure and restrict the fluid interference with neighboring reservoirs, (ii) the fluid loss, which is a significant concern in a water-EGS but for CO2-EGS it is environmentally friendly, and (iii) higher pressure and cold fluid injection induced geological deformation and microseismicity are relatively less for CO2-EGS than water-EGS. In this paper, we have also discussed various challenges of CO2-EGS to enable CCS in hydrothermal reservoir and hot dry rock system.
The use of water production as a pressure mitigation tool in the context of CO2 storage is widely studied but the impact it might have on the migration behaviour of a buoyant CO2 plume is less well reported. To investigate this further two different scenarios were modelled. In the first, a single water production well was used to draw CO2 along the strike of an open aquifer with a regional dip. Large rates of water production (5–10 times the volume of injected CO2) were required to achieve only small displacements of the CO2 plume. The second scenario investigated to what extent an induced hydraulic gradient might spill CO2 already stored in a structural trap. Here the effects were more pronounced with over 90% of the CO2 being spilled at a water cycling rate of 10 Mt per year (corresponding to a hydraulic gradient of 1.28 bar/km). The modelling was tested by the real case at Sleipner where CO2 migration in the Utsira Sand is potentially impacted by water production at the nearby Volve field. Simulations concluded that the CO2 plume at Sleipner should not be materially affected by water production from Volve and this is supported by the time-lapse seismics.
In order for carbon capture and storage (CCS) to have a significant impact on anthropogenic carbon emissions, large volumes of carbon dioxide (CO2) will need to be captured and stored in the subsurface. It is therefore likely that multiple storage operations will access the same storage reservoir, leading to the potential for overlapping pressure responses. Pressure management through brine production is an approach to reduce the pressure response of injection operations, concomitantly reducing the potential for overlap. In this study numerical modeling is used to simulate the basin-wide deployment of CCS in the Illinois Basin, USA to determine the potential impact of brine production on pressure increase at the injection wells and the Areas of Review (the area that the US Environmental Protection agency deems at risk for CO2 and brine leakage; AoR) of the injection operations. The results show that brine production can reduce the combined size of AoRs by about one order of magnitude, if a volume of brine equivalent to the volume of injected CO2 is produced. Sites with low injection rates and/or favorable storage properties (i.e., high permeability and porosity, large thickness and depth) may not need pressure management, if the critical pressure is only exceeded within the CO2 plume. Injection of CO2 at locations with favorable storage properties leads to a combined AoR 30% smaller than if the injection sites are co-located with large stationary sources. However, pipeline networks would need to be developed to transport CO2 from the sources to the injection sites. If the produced brine is to be disposed through reinjection into the subsurface, the reinjection formation needs to be hydraulically isolated from the storage formation, as to not negate the effect of pressure management. The results also show that injectivity does not seem to be a major issue in the Illinois Basin, with only four out of 54 hypothetical CCS sites exceeding the allowable pressure increase set to prevent injection-induced seismicity. Unfortunately, brine production is not an effective strategy to control the maximum pressure increase at the four sites, so that a reduction in injection rates is necessary. If the injections occur at locations more favorable for injection, pressures are well below the maximum allowable levels, while maintaining the same basin-wide injection rates.
Two of the most important challenges facing the global energy sector are to reduce the CO2 intensity and the water intensity of energy production. Because many economies will continue to depend on fossil fuels as primary energy sources, CO2 capture and storage (CCS) must play a major role in curbing CO2 emissions. A large portion of CO2 storage will need to occur in saline reservoirs because these resources are more widely distributed than hydrocarbon resources—where CO2 capture utilization and storage (CCUS) can be deployed for enhanced oil recovery (EOR). CCS deployment can be accelerated with a pressure-management strategy, called pre-injection brine production that proactively manages project risks linked to reservoir pressure. In this approach, a CCS wellfield is deployed sequentially, one well at a time, with each well being used for three stages: (1) monitoring, (2) brine production, and (3) CO2 injection. Using the same well to produce brine before injecting CO2 provides pre-injection reservoir diagnostics needed for proactive planning of wellfield operations. Because pressure drawdown is greatest where CO2 injection will subsequently occur, reservoir pressure is efficiently managed per well, and per unit of removed brine. This approach to managing geologic CO2 storage can (1) identify resources with sufficient CO2 storage capacity and permanence, and provide information needed to effectively manage those resources prior to injecting CO2; (2) increase CO2 storage capacity and efficiency; (3) limit pore-space competition with neighboring subsurface operations; and (4) reduce the duration of post-injection site care and monitoring, while (5) creating the opportunity to generate water, using an emerging CCUS technology called enhanced water recovery (EWR). Although beneficial consumptive use of produced brine may be preferred in water-constrained regions, there may be situations where the brine composition is not economically treatable, which could necessitate reinjecting some or all of the produced brine into a separate reservoir. In this study we consider a range of brine-disposition options, from 100% reinjection in the subsurface to near zero net injection of fluid, which maximizes the water generation benefit per tonne of stored CO2. These options are analyzed for a case where a nearby saline reservoir overlying a CO2 storage reservoir is used to store some or all of the brine removed from the CO2 storage reservoir.
This work presents experimental studies of four candidate fracture-sealing materials with the potential for sealing CO2 leakage pathways during CO2 sequestration, including paraffin wax, polymer-based gel, silica-based gel, and micro-cement. We investigated their ability to effectively seal CO2 injection-induced or natural fractures with widths from 1/4 mm up to 1 mm. All four materials significantly reduced fracture permeabilities. However, the micro-cement was the most effective sealant agent and was the only sealant material that was able to withstand large differential pressures, typical of what might be caused by CO2 injection. Visual inspection of the fracture surfaces revealed that both the gel and the wax-filled fractures had worm-holes which made them less effective as sealant agents. Based on the mechanical experiments conducted, the gels cannot be expected to withstand large pressure differentials in a fracture whereas the micro-cement can. Thus micro-cement is recommended for sealing of fractures if fracture width is above half a millimeter. The long-term chemical stability of polymer-based gel was assessed by exposing it to CO2 for 7 months at 20 degrees C without any apparent sign of degradation. The CO2 exposure does not seem to hinder the use of gel as a sealant material. Given that cement exposed to CO2 has been shown to be susceptible to alteration via carbonatation reactions, a potential injection scenario might be to inject cement first to create a barrier to differential pressures, and then follow with gel as a second injection fluid to create a chemically stable sealing agent to CO2 exposure or the usage of CO2 resistant micro-cements not investigated here. (c) 2013 Elsevier Ltd. All rights reserved.
Pressure buildup limits CO2 injectivity and storage capacity and pressure loss limits the brine production capacity and security, particularly for closed and semi-closed formations. In this study, we conduct a multiwell model to examine the potential advantages of combined exhaustive brine production and complete CO2 storage in deep saline formations in the Jiangling Depression, Jianghan Basin of China. Simulation results show that the simultaneous brine extraction and CO2 storage in saline formation not only effectively regulate near-wellbore and regional pressure of storage formation, but also can significantly enhance brine production capacity and CO2 injectivity as well as storage capacity, thereby achieving maximum utilization of underground space. In addition, the combination of brine production and CO2 injection can effectively mitigate the leakage risk between the geological units. With regard to the scheme of brine production and CO2 injection, constant pressure injection is much superior to constant rate injection thanks to the mutual enhancement effect. The simultaneous brine production of nine wells and CO2 injection of four wells under the constant pressure injection scheme act best in all respects of pressure regulation, brine production efficiency, CO2 injectivity and storage capacity as well as leakage risk mitigation. Several ways to further optimize the combined strategy are investigated and the results show that increasing the injection pressure and adopting fully penetrating production wells can further significantly enhance the combined efficiency; however, there is no obvious promoting effect by shortening the well spacing and changing the well placement. (C) Springer-Verlag Berlin Heidelberg 2014
This review provides a comprehensive reflection of the recent advances in nanomaterials and processes for carbon dioxide (CO2) capture and conversion. It is divided into two sections: carbon capture, and conversion into useful by‐products. The latest developments in nanotechnology‐enabled carbon capture processes along with an overview of the conventional technologies for carbon capture are described. Descriptions of by‐product conversion include conversion into important chemicals, liquid fuels, and hydrocarbon such as carbonate, methane, methanol, and formic acid. Finally, perspectives on the future directions in carbon capture and storage technology are presented. © 2012 Society of Chemical Industry and John Wiley & Sons, Ltd
Analysis of geological sequestration of carbon dioxide (CO2) requires mathematical models of different complexity to answer a range of practical questions. A family of vertically-integrated models of intermediate complexity can be derived by assuming that the strong buoyant drive in the system leads to vertical segregation of the injected CO2 and resident brine on a time scale that is fast enough to model the system as being stratified and in vertical-equilibrium. These models range from vertically-integrated numerical models which include capillary forces via mathematical reconstruction, to analytical models assuming a sharp-interface and homogeneous formation parameters. This paper investigates the limits of numerical vertical-equilibrium models and the more restricted vertical-equilibrium sharp-interface models via direct comparisons with a homogeneous three-dimensional model, exploring the impacts of injection rate, injection time, and formation characteristics. We use the commercial simulator ECLIPSE for the three-dimensional model. Our results demonstrate that the applicability of a vertically-integrated modeling approach to CO2 sequestration depends on the time scale of the vertical brine drainage within the plume, relative to the time scale of the simulation. The validity of the sharp-interface assumption is shown to depend on the spatial scale of the capillary forces, which drive the thickness of the capillary transition zone. A finite-capillary-transition-zone vertically-integrated numerical model with saturation reconstruction closely matches results from the three-dimensional model (ECLIPSE) including capillary pressure as long as the segregation time scales are respected. Overall, our results demonstrate that vertically-integrated and sharp-interface models are useful and accurate when applied within the appropriate length and time scales.
Stabilization of CO2 atmospheric concentrations requires practical strategies to address the challenges posed by the continued use of coal for baseload-electricity production. Over the next two decades, CO2 capture and sequestration (CCS) demonstration projects would need to increase several orders of magnitude across the globe in both size and scale. This task has several potential barriers which will have to be accounted for. These barriers include those that have been known for a number of years including safety of subsurface sequestration, pore-space competition with emerging activities like shale gas production, legal and regulatory frameworks, and public acceptance and technical communication. In addition water management is a new challenge that should be actively and carefully considered across all CCS operations. A review of the new insights gained on these previously and newly identified challenges, since the IPCC special report on CCS, is presented in this paper. While somewhat daunting in scope, some of these challenges can be addressed more easily by recognizing the potential advantageous synergies that can be exploited when these challenges are dealt with in combination. For example, active management of water resources, including brine in deep subsurface formations, can provide the additional cooling-water required by the CO2 capture retrofitting process while simultaneously reducing sequestration leakage risk and furthering efforts toward public acceptance. This comprehensive assessment indicates that water, sequestration, legal, and public acceptance challenges ought to be researched individually, but must also be examined collectively to exploit the promising synergies identified herein. Exploitation of these synergies provides the best possibilities for successful large-scale implementation of CCS.
A significant number of large CO2 emitters are located in central Alberta, Canada, including four coal-fired power plants in the Wabamun Lake area, with cumulative annual emissions in the order of 30 million metric tons CO2. To help industry and regulatory agencies in selecting and permitting sites for CO2 storage, proper
characterization is essential, covering the principal aspects of CO2 storage: capacity, injectivity, and confinement. The sedimentary succession in the Wabamun Lake area southwest of Edmonton was identified as a potential CO2 storage site because it would minimize transportation needs and costs from the large CO2 sources in the vicinity. A wealth of data on stratigraphy and lithology; fluid compositions; rock properties; and geothermal, geomechanical, and pressure regimes were used to create and characterize a comprehensive three-dimensional model of the deep saline aquifers in the area that could be CO2
storage targets. These aquifers have sufficient capacity to accept and store large volumes of supercritical CO2 at the appropriate depth and are overlain by thick confining shale units. Initial calculations and modeling of CO2 injection into the Devonian Nisku carbonate aquifer suggest that dissolution and residual saturation of CO2 limit the lateral CO2 plume spread considerably. Hypothetical injection of 12.5million tonnes/yr ofCO2 for 30 yr would result in a maximumplume spread of less than 15 km(9mi) in diameter.
However, multiple injection wells would be needed to inject this large amount of CO2 to maintain bottomhole injection pressures below the rock-fracturing threshold.
For industrial-scale CO 2 injection in saline formations, pressure increase can be a limiting factor in storage capacity. To address this concern, we introduce Active CO 2 Reservoir Management (ACRM), which combines brine extraction and residual-brine reinjection with CO 2 injection, contrasting it with the conventional approach, which we call Passive CO 2 Reservoir Management. ACRM reduces pressure buildup and CO 2 and brine migration, which increases storage capacity. Also, "push-pull" manipulation of the CO 2 plume can counteract buoyancy, exposing less of the caprock seal to CO 2 and more of the storage formation to CO 2 , with a greater fraction of the formation utilized for trapping mechanisms. If the net extracted volume of brine is equal to the injected CO 2 volume, pressure buildup is minimized, greatly reducing the Area of Review, and the risk of seal degradation, fault activation, and induced seismicity. Moreover, CO 2 and brine migration will be unaffected by neighboring CO 2 operations, which allows planning, assessing, and conducting of each operation to be carried out independently. In addition, ACRM creates a new product, as extracted brine is available as a feedstock for desalination technologies, such as Reverse Osmosis. These benefits can offset brine extraction and treatment costs, streamline permitting, and help gain public acceptance.
When injected in deep saline aquifers, CO2 moves radially away from the injection well and progressively higher in the formation because of buoyancy forces. Analyzes have shown that after the injection period, CO2 will potentially migrate over several kilometers in the horizontal direction but only tens of meters in the vertical direction, limited by the aquifer caprock. Because of the large horizontal plume dimensions, three-dimensional numerical simulations of the plume migration over long periods of time are computationally intensive. Thus, to get results within a reasonable time frame, one is typically forced to use coarse meshes and long time steps which result in inaccurate results because of numerical errors in resolving the plume tip.
Most projected climate change mitigation strategies will require a significant expansion of CO2 Capture and Sequestration (CCS) in the next two decades. Four major categories of challenges are being actively researched: CO2 capture cost, geological sequestration safety, legal and regulatory barriers, and public acceptance. Herein we propose an additional major challenge category across all CCS operations: Water management. For example a coal-fired power plant retrofitted for CCS requires twice as much cooling water as the original plant. This increased demand may be accommodated by brine extraction and treatment, which would concurrently function as large-scale pressure management and a potential source of freshwater. At present the interactions among freshwater extraction, CO2 injection, and brine management are being considered too narrowly -in the case of freshwater almost completely overlooked- in the technical and regulatory CCS community. This paper presents an overview of each of these challenges and potential integration opportunities. Active management of CCS operations through an integrated approach -including brine production, treatment, use for cooling, and partial reinjection- can address challenges simultaneously with several synergistic advantages. The paper also considers the related potential impacts of pore space competition (with future groundwater use, gas storage and shale gas) on CCS expansion. Freshwater and brine must become key decision making inputs throughout CCS operations, building on existing successful industrial-scale integrations.
Through the use of analytical solutions derived from a simplified geologic model, this paper investigates the magnitude of pressure transients in permeable zones overlying CO2 storage reservoirs associated with brine migration through the sealing cap rock. A wide range of geologic settings and injection parameters is evaluated from which a generalized correlation is constructed to relate the hydrologic properties of the storage reservoir and seal to the magnitude of expected pressure buildups associated with brine migration across the seal. This correlation, referred to as the detection factor (DF), provides insight into the feasibility and interpretation of pressure changes measured in zones overlying CO2 storage reservoirs as a means of monitoring and leakage detection.
Analysis of geological storage of CO2 almost always involves some set of computational models that provide a mathematical descri iption of the problem. These models can have many purposes, but ultimate they should be able to answer practical questions about the system. These questions usual involve the spatial extent of the CO2 plume, the spatial extent of pressure perturbations, the spatial and temporal dynamics of leakage out of the injection formation, and the spatial and temporal evolution of different trapping mechanisms. Answers to these questions require models that apply to large spatial and temporal scales while including certain small-scale features like leakage pathways. Development of computationally efficient models that can span the appropriate scales may be achieved by analyzing the length and time scales associated with the important processes in the system, and incorporating those scales into a systematic model development. Such a procedure can be described as multiscale modelling. Beginning with the most complex models, a sequence of simplifying assumptions may be proposed, based in part on scaling arguments for the physical processes involved, to produce a sequenc of successively simpler models. Through this approach, the assumptions in all of the simplified models are made transparent, and the length and time scales appropriate for different models can be identified. In addition, by associating length and time scales to the questions being asked,models can be developed that are consistent with those scales and therefore are appropriate to answer the questions.
Increased reliance on geothermal energy and CO 2 capture and sequestration (CCS) in deep geological formations are both regarded as a promising means of lowering the amount of CO 2 emitted to the atmosphere and thereby mitigate climate change. We investigate an approach to produce geothermal energy and to sequester CO 2 at low cost and risk by integrating geothermal production with CCS in sa-line, sedimentary formations where a significant portion of the U.S. geothermal resource base resides. For industrial-scale CO 2 injection in saline formations, pressure increase can be a limiting factor in storage capacity and security, while geothermal energy production can be limited by pressure depletion. Our approach utilizes Active CO 2 Reservoir Management, which combines brine production with CO 2 injection to enable more cost-effective and secure CO 2 storage. The complementary CCS and geothermal systems are integrated synergistically, with CO 2 injection providing pressure support to maintain productivity of geothermal wells, while brine production provides pressure relief and improved injectivity for CO 2 injectors. A volumetric balance between injected and produced fluids mitigates the environmental and economic risks of reservoir overpressure (CCS concern) or underpressure (geothermal concern), including induced seismicity, insufficient well productivity or injectivity, subsidence, and fluid leakage either to or from overlying formations. We investigate the tradeoff between pressure relief at CO 2 injectors and CO 2 breakthrough time at geothermal brine producers for both vertical and horizontal wells, and address the influence of forma-tion dip and permeability heterogeneity. The combined influence of buoyancy and layered heterogeneity delays CO 2 breakthrough at geothermal production wells, particularly when the permeability contrast is large. Our results indicate adequate pressure relief at CO 2 injectors can be attained, while delaying CO 2 breakthrough at production wells for 30 or more years, thus enabling sustainable geothermal power.
When representative equations for the viscosity of carbon dioxide were published in 1990, it was recognized that, owing to inconsistencies among the available experimental liquid viscosity data which could not be resolved, new measurements were necessary. Since then, two new sets of measurements have been performed and it is appropriate to revise the published equations in order to improve their performance in the liquid region. In the previous work, the excess viscosity was represented by two separate equations, one for the gas phase and the other, a provisional one, for the liquid phase. Both equations were joined by a blending function. In the present work, the excess viscosity for the whole thermodynamic surface is represented by one equation. The resulting overall viscosity representation for carbon dioxide covers the temperature range 200 K⩽T⩽1500 K and densities up to 1400 kg m−3. In terms of pressure, the viscosity representation is valid up to 300 MPa for temperatures below 1000 K, whereas for higher temperatures and owing to the limitation of the equation of state used, the upper pressure limit is restricted to 30 MPa. The uncertainties associated with the proposed representation vary from ±0.3% for the viscosity of the dilute gas near room temperature to ±5.0% at the highest pressures. Tables of viscosity generated by the representative equations are included for easy reference and to assist validation of computer coding.
For industrial-scale CO2 injection in saline formations, pressure buildup can limit storage capacity and security. Active CO2 Reservoir Management (ACRM) combines brine production with CO2 injection to relieve pressure buildup, increase injectivity, manipulate CO2 migration, and constrain brine leakage. By limiting pressure buildup, in magnitude, spatial extent, and duration, ACRM can reduce CO2 and brine leakage, minimize interactions with neighboring subsurface activities, allowing independent assessment and permitting, reduce the Area of Review and required duration of post-injection monitoring, and reduce cost and risk. ACRM provides benefits to reservoir management at the cost of extracting brine. The added cost must be offset by the added benefits to the storage operation and/or by creating new, valuable uses that can reduce the total added cost. Actual net cost is expected to be site specific, requiring detailed analysis that is beyond the scope of this paper, which focuses on the benefits to reservoir management. We investigate operational strategies for achieving an effective tradeoff between pressure relief/improved injectivity and delayed CO2 breakthrough at brine producers. For vertical wells, an injection-only strategy is compared to a pressure-management strategy with brine production from a double-ring 9-spot pattern. Brine production allows injection to be steadily ramped up while staying within the pressure-buildup target, while injection-only requires a gradual ramp-down. Injector/producer horizontal-well pairs were analyzed for a range of well spacings, storage-formation thickness and area, level and dipping formations, and for homogeneous and heterogeneous permeability. When the producer is downdip of the injector, the combined influence of buoyancy and heterogeneity can delay CO2 breakthrough. Both vertical and horizontal wells can achieve pressure relief and improved CO2 injectivity, while delaying CO2 breakthrough. Pressure buildup and CO2 breakthrough are sensitive to storage-formation permeability and insensitive to all other hydrologic parameters except caprock-seal permeability, which only affects pressure buildup for injection-only cases.
We investigate the possibility that brine could be displaced upward into potable water through wells. Because of the large volumes of CO2 to be injected, the influence of the zone of elevated pressure on potential conduits such as well boreholes could extend many kilometers from the injection site—farther than the CO2 plume itself. The traditional approach to address potential brine leakage related to fluid injection is to set an area of fixed radius around the injection well/zone and to examine wells and other potentially open pathways located in the “Area-of-Review” (AoR). This suggests that the AoR needs to be defined in terms of the potential for a given pressure perturbation to drive upward fluid flow in any given system rather than on some arbitrary pressure rise. We present an analysis that focuses on the changes in density/salinity of the fluids in the potentially leaking wellbore.
Large stationary CO2 emitters are located in central Alberta with cumulative annual emissions in the order of 30 Mt CO2. This includes four coal-fired power plants in the Wabamun Lake area, southwest of Edmonton with emissions between 3 to 6 Mt/year each. The study will perform a comprehensive characterization of large-scale CO2 storage opportunities in the Wabamun area and analyze any potential risks. As a benchmark, the project will examine the feasibility of storing 20 Mt- CO2/year for 50 years within 30 km of Wabamun. This gigaton-scale storage assessment project is one to two orders of magnitude larger than the commercial projects now under study. It will fill a gap between Canadian province-wide capacity estimates (which do not involve site specific studies of flow and geomechanics etc.) and the detailed commercial studies of small CO2 storage projects currently underway. Unlike the commercial projects, this project is planned as a public non-confidential project lead by the University of Calgary (U of C).
A prerequisite to the wide deployment of CO2 geological storage at an industrial scale is demonstrating that potential risks can be efficiently managed, which includes deploying an adequate monitoring during the injection phase and having intervention plans ready in case of major irregularity. This paper considers the injection of CO2 into a saline formation linked to a shallower aquifer through a leaky pathway. Brine, possibly followed by CO2, may start migrating up through the leak if sufficient pressure builds-up in the storage reservoir. For some man-made leakages (e.g. abandoned well), and more importantly for most of the natural ones (e.g. faults, fractured zone), acting on the transfer itself (i.e. on the leaky pathway) is hardly feasible. Consequently, the corrective measure hereby investigated aims at countering the main driving force of the CO2 upwards migration which is the pressure build-up under the leak by injecting brine into the shallower aquifer, thus creating a hydraulic barrier. Results show that this can be an efficient way to stop a leakage in less than a year instead of letting it continue for hundreds of years, even with a low and decreasing flow rate. It may also be implemented as a preventive measure, while continuing storing CO2.
Although it is recognized that deep aquifers offer a very large potential storage capacity for CO 2 sequestration it is not clear how to fill the storage with a large volume of CO 2 in a relatively short period of time. The typical benchmark for the rate of CO 2 injection is 1 Mt/year when studying storage performance. This rate is very low compare to the scale necessary for the storage technology to play a significant role in managing global emissions. In this study we perform numerical simulations of a large volume of injection, 20 Mt/year during 50 years of continuous injection resulting in a total sequestration of 1 Gt CO 2 . A sensitivity analysis of the results (plume area and CO 2 storage capacity) is presented within the range of aquifer parameters: thickness (50-100 m); permeability (25-100 mD); rock compressibility (from 910 -10 to 210 -9 (1/Pa)) as well as different injection arrangements. The implementation of this study to a particular case of injection of 1 Gt total over 50 years into the Nisku aquifer located in Wabamun Lake Area, Alberta, Canada [1] is presented. In this area, large CO 2 emitters including four coal-fired power plants with emission between 3 to 6 Mt/year each are present. The Nisku aquifer is believed to be a suitable choice for future sequestration projects. In this case study a few injection scenarios (number of wells and their placement, which control the ability to inject without exceeding the aquifer's fracture pressure) are presented. The evolution of plume size and pressure field in the aquifer for these scenarios is shown. As opposed to the generic sensitivity study, the case study includes the heterogeneity of the aquifer and its dip angle. Both generic and Nisku studies have shown that the capacity of the reservoir in the case of large injection volumes should be evaluated not by available pore volume, but by ability to inject some amount without exceeding fracture pressure of formation.
The assumption of Vertical Equilibrium (VE) and of parallel flow conditions, in general, is often applied to the modeling of flow and displacement in natural porous media. However, the methodology for the development of the various models is rather intuitive, and no rigorous method is currently available. In this paper, we develop an asymptotic theory using as parameter the variable The assumption of Vertical Equilibrium (VE) and of parallel flow conditions, in general, is often applied to the modeling of flow and displacement in natural porous media. However, the methodology for the development of the various models is rather intuitive, and no rigorous method is currently available. In this paper, we develop an asymptotic theory using as parameter the variable
RL = L/HÖ{kV /kH }R_{{L}} = L/H\sqrt {k_{{V}} /k_{{H}} } RL = L/HÖ{kV /kH }R_{{L}} = L/H\sqrt {k_{{V}} /k_{{H}} }
. It is rigorously shown that the VE model is obtained as the leading order term of an asymptotic expansion with respect to 1/R. It is rigorously shown that the VE model is obtained as the leading order term of an asymptotic expansion with respect to 1/R
LL
22
. Although this was numerically suspected, it is the first time that it is theoretically proved. Using this formulation, a series of special cases are subsequently obtained depending on the relative magnitude of gravity and capillary forces. In the absence of strong gravity effects, they generalize previous works by Zapata and Lake (1981), Yokoyama and Lake (1981) and Lake and Hirasaki (1981), on immiscible and miscible displacements. In the limit of gravity-segregated flow, we prove conditions for the fluids to be segregated and derive the Dupuit and Dietz (1953) approximations. Finally, we also discuss effects of capillarity and transverse dispersion.
This paper summarises the results of a benchmark study that compares a number of mathematical and numerical models applied
to specific problems in the context of carbon dioxide (CO2) storage in geologic formations. The processes modelled comprise advective multi-phase flow, compositional effects due to
dissolution of CO2 into the ambient brine and non-isothermal effects due to temperature gradients and the Joule–Thompson effect. The problems
deal with leakage through a leaky well, methane recovery enhanced by CO2 injection and a reservoir-scale injection scenario into a heterogeneous formation. We give a description of the benchmark
problems then briefly introduce the participating codes and finally present and discuss the results of the benchmark study.
Humanity already possesses the fundamental scientific, technical, and industrial know-how to solve the carbon and climate
problem for the next half-century. A portfolio of technologies now exists to meet the world's energy needs over the next 50
years and limit atmospheric CO2 to a trajectory that avoids a doubling of the preindustrial concentration. Every element in this portfolio has passed beyond
the laboratory bench and demonstration project; many are already implemented somewhere at full industrial scale. Although
no element is a credible candidate for doing the entire job (or even half the job) by itself, the portfolio as a whole is
large enough that not every element has to be used.
Publisher Summary Deep aquifers are a particularly important class of geologic storage system because of their ubiquity and large capacity. Two important uncertainties in assessing CO2 storage in aquifers are storage efficiency and security, where efficiency denotes the fraction of total aquifer capacity that can be accessed for storage, and security refers to the possibility that stored CO2 will escape the aquifer system by migrating upwards through natural or artificial weaknesses in the capping formation. It is possible to engineer CO2 storage in aquifers by accelerating the dissolution of CO2 in brines to reduce the long term risk of leakage. Such reservoir engineering includes: optimizing the geometry of injection wells to maximize the rate at which buoyancy-driven flow of CO2 and brines drives dissolution; or use of wells and pumps to transport CO2 or brines within the reservoir to increase contact between CO2 and undersaturated brines accelerating the rate of dissolution and residual gas trapping.
This study presents a computational methodology to estimate the maximum probable leakage of CO2 along old wells in a geological sequestration operation. The methodology quantifies the maximum probable CO2 leakage as a function of the statistical characterization of existing wells. We use a Monte Carlo approach based on a computationally efficient simulator to run many thousands of realizations. Results from the Monte Carlo simulations are used to determine maximum leakage rates at 95% confidence. Uncertainty in the analysis is due to leaky well parameters, which are known to be highly uncertain. We consider a wide range of parameter values, with our focus on assignment of effective well permeability values and the correlation of those values along individual wells. We use a specific location in Alberta, Canada, to demonstrate the methodology using a hypothetical injection and an assumed probability structure for the well permeabilities. We show that for a wide range of parameter values, the amount of leakage is within the bounds suggested as acceptable for climate change mitigation.
Injection of fluid wastes into the fractured Precambrian crystalline bedrock beneath the Rocky Mountain Arsenal near Denver triggered earthquakes in the 1960's. An analysis, based on the assumption that fluid flow in the fractured reservoir can be approximated by flow in a porous medium, is presented. The configuration and hydrologic properties of the reservoir are determined from two lines of evidence: (1) locations of earthquake hypocenters determined by seismic arrays installed at the Arsenal and (2) observed long-term decline in fluid levels in the injection well. Together these two sets of data indicate that a long, narrow reservoir, aligned in the direction N 60°W, exists. The reservoir is 3.35 km in width, extends 30.5 km to the northwest and infinitely to the southeast, and spans a depth interval from 3.7 to 7.0 km below land surface. It has a transmissivity of 1.08×10-5 m2/s and a storage coefficient of 1.0×10-5. Computed pressure buildup along the length of the reservoir is compared with the spatial distribution of earthquake epicenters. The comparison shows that earthquakes are confined to that part of the reservoir where the pressure buildup exceeds 32 bars. This critical value is interpreted as the pressure buildup above which earthquakes occur. The migration of earthquake epicenters away from the injection well, a phenomenon noted by previous investigators, can be accounted for by the outward propagation of the critical pressure buildup. The analysis is extended to examining the effects of rapid flow in fractures opened by high injection pressure. The results show that the effect is confined to a small region within 1 km of the injection well. The existence of a critical pressure buildup above which earthquakes occur is completely consistent with the theory on the role of fluid pressure in fault movement as presented by Hubbert and Rubey.
This paper investigates vertically integrated equilibrium models for CO2 storage. We pay particular attention to the importance of including the effect of fine-scale capillary forces in the integrated equations. This aspect has been neglected in previous work, where the fluids are segregated by a sharp interface. Our results show that the fine-scale capillary forces lead to qualitative and quantitative alterations of the integrated equations. Interestingly, while such forces are dispersive on the fine scale, they lead to self-sharpening of the solution on the integrated scale. We discuss these aspects for injection, leakage, and long-term migration through the application by comparison to common sharp interface models proposed in the literature.
The purpose of the study presented in this manuscript is to describe and make available two equation-of-state (EOS) algorithms assembled for multiphase flow and transport of carbon dioxide (CO2). The algorithms presented here calculate solubility, compressibility factor, density, viscosity, fugacity, and enthalpy of CO2 in gaseous and supercritical phases, and mixtures or solutions of CO2 in water, as functions of pressure and temperature. Several features distinguish the two algorithms, but the primary distinction concerns treatment of supercritical/gas-phase CO2: one EOS we assembled is based on Redlich and Kwong's original algorithm developed in 1949, and the other is based on an algorithm developed by Span and Wagner in 1996. Both were modified for application to sedimentary basin studies of multiphase CO2 flow processes, including carbon sequestration applications. We present a brief comparison of these two EOS algorithms. Source codes for both algorithms are provided, including “stand-alone” Matlab © scripts for the interactive calculation of fluid properties at specified P–T conditions and FORTRAN subroutines for inclusion in existing FORTRAN multiphase fluid simulation packages. These routines are intended for fundamental analyses of CO2 sequestration and the like; more advanced studies, such as brine processes and reactive transport, require more advanced EOS algorithms.
Large-scale implementation of geological CO2 sequestration requires quantification of risk and leakage potential. One potentially important leakage pathway for the injected
CO2 involves existing oil and gas wells. Wells are particularly important in North America, where more than a century of drilling
has created millions of oil and gas wells. Models of CO2 injection and leakage will involve large uncertainties in parameters associated with wells, and therefore a probabilistic
framework is required. These models must be able to capture both the large-scale CO2 plume associated with the injection and the small-scale leakage problem associated with localized flow along wells. Within
a typical simulation domain, many hundreds of wells may exist. One effective modeling strategy combines both numerical and
analytical models with a specific set of simplifying assumptions to produce an efficient numerical–analytical hybrid model.
The model solves a set of governing equations derived by vertical averaging with assumptions of a macroscopic sharp interface
and vertical equilibrium. These equations are solved numerically on a relatively coarse grid, with an analytical model embedded
to solve for wellbore flow occurring at the sub-gridblock scale. This vertical equilibrium with sub-scale analytical method
(VESA) combines the flexibility of a numerical method, allowing for heterogeneous and geologically complex systems, with the
efficiency and accuracy of an analytical method, thereby eliminating expensive grid refinement for sub-scale features. Through
a series of benchmark problems, we show that VESA compares well with traditional numerical simulations and to a semi-analytical
model which applies to appropriately simple systems. We believe that the VESA model provides the necessary accuracy and efficiency
for applications of risk analysis in many CO2 sequestration problems.
Disposal of waste fluids via injection into deep saline aquifers is
practiced in a variety of industries. Injection takes place in
sedimentary basins that often have a history of oil and gas exploration
and production, which means that wells other than those used for waste
disposal may exist in the vicinity of the injection site. These existing
wells provide possible pathways for leakage of waste fluids toward the
shallow subsurface and the land surface. For single-phase flows of
liquids with essentially constant properties, the equations governing
the system are linear, and solutions may be written using the
superposition principle. Because leakage through existing wells produces
a time-varying flux rate, the solution of the governing equations
involves convolution integrals. Previous solutions have addressed the
problem of one injection well, one existing (passive) well, and a simple
geometry of two aquifers separated by an aquitard by use of Laplace
transforms. Even for this simple case, inversion of the transform is
difficult. Solutions involving more than one passive well have not been
developed. Nor have solutions been developed for more than two aquifers
and one aquitard. Realistic injection cases often involve layered
systems with multiple aquifers and aquitards, as well as multiple
passive wells, sometimes numbering in the hundreds. Solutions for the
general case of multiple aquifers and wells may be developed through
introduction of approximations to the well function and appropriate
simplification of the convolution integral. Such a solution is
computationally simple. Comparison to solutions using the full (Laplace
transform) solution indicates that the new solution procedure produces
excellent results. Application of the new solution to a case of multiple
passive wells shows that the cumulative leakage flux in the passive
wells is not a simple sum of the single-well case, owing to
leakage-induced drawdown around the passive wells. In addition,
application to the case of multiple aquifers and aquitards demonstrates
the importance of leakage into intervening aquifers as a mechanism to
mitigate leakage into shallow zones, a process referred to as the
"elevator model." The new analytical solution provides a tool to analyze
practical injection problems and forms a foundation on which more
complex solutions, such as those involving injection of a nonaqueous
fluid into a deep brine formation, may be based.
Sequestration of carbon dioxide in geologic formations, both deep aquifers and depleted petroleum reservoirs, has the potential to signi…cantly reduce the atmospheric emissions of that greenhouse gas. Injection into a deep saline formation diers from injection into a hydrocarbon reservoir in that there is no produced ‡uid from the aquifer and the hydrogeologic characterization of both the receptor formation and the cap or seal is much more uncertain. Hydraulic control may reduce the risks and increase the safety of CO2 sequestration. While the applicability to a particular site is strongly dependent on the local conditions, the injection of brine above the con…ning layer can reduce the vertical migration and enhance the lateral spreading of the carbon dioxide.
Stabilization of CO2 atmospheric concentrations requires practical strategies to address the challenges posed by the continued use of coal for baseload-electricity production. Over the next two decades, CO2 capture and sequestration (CCS) demonstration projects would need to increase several orders of magnitude across the globe in both size and scale. This task has several potential barriers which will have to be accounted for. These barriers include those that have been known for a number of years including safety of subsurface sequestration, pore-space competition with emerging activities like shale gas production, legal and regulatory frameworks, and public acceptance and technical communication. In addition water management is a new challenge that should be actively and carefully considered across all CCS operations. A review of the new insights gained on these previously and newly identified challenges, since the IPCC special report on CCS, is presented in this paper. While somewhat daunting in scope, some of these challenges can be addressed more easily by recognizing the potential advantageous synergies that can be exploited when these challenges are dealt with in combination. For example, active management of water resources, including brine in deep subsurface formations, can provide the additional cooling-water required by the CO2 capture retrofitting process while simultaneously reducing sequestration leakage risk and furthering efforts toward public acceptance. This comprehensive assessment indicates that water, sequestration, legal, and public acceptance challenges ought to be researched individually, but must also be examined collectively to exploit the promising synergies identified herein. Exploitation of these synergies provides the best possibilities for successful large-scale implementation of CCS.
the same mathematical form, regardless of the nature and number of fluid components and phases. MUL- Numerical simulation has become a widely practiced and accepted KOM was a research code that served as a test bed for technique for studying flow and transport processes in the vadose developing much of the approaches and methodology zone and other subsurface flow systems. This article discusses a suite of codes, developed primarily at Lawrence Berkeley National Labora- that were subsequently implemented in TOUGH and tory (LBNL), with the capability to model multiphase flows with TOUGH2. A stripped-down version of MULKOM for phase change. We summarize history and goals in the development two-phase flow of water-air mixtures was released to of the TOUGH codes, and present the governing equations for multi- the public in 1987 under the name TOUGH (Pruess, phase, multicomponent flow. Special emphasis is given to space dis- 1987). The acronym "TOUGH" stands for "transport cretization by means of integral finite differences (IFD). Issues of of unsaturated groundwater and heat," and is also an code implementation and architecture are addressed, as well as code allusion to the tuff formations at Yucca Mountain, which applications, maintenance, and future developments. represented one of the chief application areas of the code at the time. A more comprehensive subset of MULKOM modules was later released under the name
The U.S. Department of Energy, through the Office of Technology Development, has requested the demonstration of remediation technologies for the cleanup of volatile organic compounds and associated radionuclides within the soil and groundwater at arid sites. This demonstration program, called the VOC-Arid Soils Integrated Demonstration Program (Arid-ID), has been initially directed at a volume of unsaturated and saturated soil contaminated with carbon tetrachloride, on the Hanford Site near Richland, Washington. A principal subtask of the Arid-ID program involves the development of an integrated engineering simulator for evaluating the effectiveness and efficiency of various remediation technologies. The engineering simulator`s intended users include scientists and engineers who are investigating soil physics phenomena associated with remediation technologies. Principal design goals for the engineer simulator include broad applicability, verified algorithms, quality assurance controls, and validated simulations against laboratory and field-scale experiments. An important goal for the simulator development subtask involves the ability to scale laboratory and field-scale experiments to full-scale remediation technologies, and to transfer acquired technology to other arid sites. The STOMP (Subsurface Transport Over Multiple Phases) simulator has been developed by the Pacific Northwest National Laboratory for modeling remediation technologies. Information on the use, application, and theoretical basis of the STOMP simulator theory and discussions on the governing equations, constitutive relations, and numerical solution algorithms for the STOMP simulator.
This guide describes the simulator`s governing equations, constitutive functions and numerical solution algorithms of the STOMP (Subsurface Transport Over Multiple Phases) simulator, a scientific tool for analyzing multiple phase subsurface flow and transport. The STOMP simulator`s fundamental purpose is to produce numerical predictions of thermal and hydrologic flow and transport phenomena in variably saturated subsurface environments, which are contaminated with volatile or nonvolatile organic compounds. Auxiliary applications include numerical predictions of solute transport processes including radioactive chain decay processes. In writing these guides for the STOMP simulator, the authors have assumed that the reader comprehends concepts and theories associated with multiple-phase hydrology, heat transfer, thermodynamics, radioactive chain decay, and nonhysteretic relative permeability, saturation-capillary pressure constitutive functions. The authors further assume that the reader is familiar with the computing environment on which they plan to compile and execute the STOMP simulator. The STOMP simulator requires an ANSI FORTRAN 77 compiler to generate an executable code. The memory requirements for executing the simulator are dependent on the complexity of physical system to be modeled and the size and dimensionality of the computational domain. Likewise execution speed depends on the problem complexity, size and dimensionality of the computational domain, and computer performance. One-dimensional problems of moderate complexity can be solved on conventional desktop computers, but multidimensional problems involving complex flow and transport phenomena typically require the power and memory capabilities of workstation or mainframe type computer systems.
Under certain circumstances, the increased pore pressure that results from fluid injection, whether for waste disposal, secondary recovery, geothermal energy, or solution mining, can trigger earthquakes. This book discusses known cases of injection-induced seismicity, how and why earthquakes may be triggered, and conditions under which earthquake triggering is most likely to occur. Criteria are established to assist in regulating well operations so as to minimize the seismic hazard associated with deep well fluid injection.
Industrial-scale injection of CO into saline sedimentary basins will cause large-scale fluid pressurization and migration of native brines, which may affect valuable groundwater resources overlying the deep sequestration reservoirs. In this paper, we discuss how such basin-scale hydrologic impacts can (1) affect regulation of CO storage projects and (2) may reduce current storage capacity estimates. Our assessment arises from a hypothetical future carbon sequestration scenario in the Illinois Basin, which involves twenty individual CO storage projects in a core injection area suitable for long-term storage. Each project is assumed to inject five million tonnes of CO per year for 50 years. A regional-scale three-dimensional simulation model was developed for the Illinois Basin that captures both the local-scale CO-brine flow processes and the large-scale groundwater flow patterns in response to CO storage. The far-field pressure buildup predicted for this selected sequestration scenario suggests that (1) the area that needs to be characterized in a permitting process may comprise a very large region within the basin if reservoir pressurization is considered, and (2) permits cannot be granted on a single-site basis alone because the near- and far-field hydrologic response may be affected by interference between individual sites. Our results also support recent studies in that environmental concerns related to near-field and far-field pressure buildup may be a limiting factor on CO storage capacity. In other words, estimates of storage capacity, if solely based on the effective pore volume available for safe trapping of CO, may have to be revised based on assessments of pressure perturbations and their potential impact on caprock integrity and groundwater resources, respectively. We finally discuss some of the challenges in making reliable predictions of large-scale hydrologic impacts related to CO sequestration projects.
Industrial-scale storage of CO2 in saline sedimentary basins will cause zones of elevated pressure, larger than the CO2 plume itself. If permeable conduits (e.g., leaking wells) exist between the injection reservoir and overlying shallow aquifers, brine could be pushed upwards along these conduits and mix with groundwater resources. This paper discusses the potential for such brine leakage to occur in temperature- and salinity-stratified systems. Using static mass-balance calculations as well as dynamic well flow simulations, we evaluate the minimum reservoir pressure that would generate continuous migration of brine up a leaking wellbore into a freshwater aquifer. Since the brine invading the well is denser than the initial fluid in the wellbore, continuous flow only occurs if the pressure perturbation in the reservoir is large enough to overcome the increased fluid column weight after full invasion of brine into the well. If the threshold pressure is exceeded, brine flow rates are dependent on various hydraulic (and other) properties, in particular the effective permeability of the wellbore and the magnitude of pressure increase. If brine flow occurs outside of the well casing, e.g., in a permeable fracture zone between the well cement and the formation, the fluid/solute transfer between the migrating fluid and the surrounding rock units can strongly retard brine flow. At the same time, the threshold pressure for continuous flow to occur decreases compared to a case with no fluid/solute transfer. Published by Elsevier Ltd.
Fluid injection into the deep subsurface, such as injection of carbon dioxide (CO$_2$) into deep saline aquifers, often involves two-fluid flow in confined geological formations. Similarity solutions may be derived for these problems by assuming that a sharp interface separates the two fluids, by imposing a suitable no-flow condition along both the top and bottom boundaries, and by including an explicit solution for the pressure distribution in both fluids. When the injected fluid is less dense and less viscous than the resident fluid, as is the case for CO$_{2}$ injection into a resident brine, gravity override produces a fluid flow system that is captured well by the similarity solutions. The similarity solutions may be extended to include slight miscibility between the two fluids, as well as compressibility in both of the fluid phases. The solutions provide the location of the interface between the two fluids, as well as drying fronts that develop within the injected fluid. Applications to cases of supercritical CO$_{2}$ injection into deep saline aquifers demonstrate the utility of the solutions, and comparisons to solutions from full numerical simulations show the ability to predict the system behaviour.
One of the important challenges in geological storage of CO2 is predicting, monitoring, and managing the risk of leakage from natural and artificial pathways such as fractures, faults, and abandoned wells. The risk of leakage arises from the buoyancy of free-phase mobile CO2 (gas or supercritical fluid). When CO2 dissolves into formation brine, or is trapped as residual phase, buoyancy forces are negligible and the CO2 may be retained with minimal risk of leakage. Solubility trapping may therefore enable more secure storage in aquifer systems than is possible in dry systems (e.g., depleted gas fields) with comparable geological seals. A crucial question for an aquifer system is, what is the rate of dissolution? In this paper, we address that question by presenting a method for accelerating CO2 dissolution in saline aquifers by injecting brine on top of the injected CO2. We investigate the effects of different aquifer properties and determine the rate of solubility trapping in an idealized aquifer geometry. The acceleration of dissolution by brine injection increases the rate of solubility trapping in saline aquifers and therefore increases the security of storage. We show that, without brine injection, only a small fraction (less than 8%) of the injected CO2 would be trapped by dissolving in formation brine within 200 years. For the particular cases studied, however, more than 50% of the injected CO2 dissolves in the aquifer as induced by brine injection. Since the energy cost for brine injection can be small (<20%) compared to the energy required for CO2 compression for a 5-fold increase in dissolution, such reservoir engineering techniques might be viable and practical for accelerating dissolution of CO2. The environmental benefit would be to decrease the risk of CO2 leakage at reasonably low cost.
Carbon capture and geological storage (CCS) operations will require an environmental risk analysis to determine, among other things, the risk that injected CO2 or displaced brine will leak from the injection formation into other parts of the subsurface or surface environments. Such an analysis requires site characterization including identification of potential leakage pathways. In North America, the century-long legacy of oil and gas exploration and production has left millions of oil and gas wells, many of which are co-located with otherwise good geological storage sites. Potential leakage along existing wells, coupled with layered stratigraphic sequences and highly uncertain parameters, makes quantitative analysis of leakage risk a significant computational challenge. However, new approaches to modeling CO2 injection, migration, and leakage allow for realistic scenarios to be simulated within a probabilistic framework. Using a specific field site in Alberta, Canada, we perform a range of computational studies aimed at risk analysis with a focus on CO2 and brine leakage along old wells. The specific calculations focus on the injection period, when risk of leakage is expected to be largest. Specifically, we simulate 50 years of injection of supercritical CO2 and use a Monte Carlo framework to analyze the overall system behavior. The simulations involve injection, migration, and leakage over the 50-year time horizon for domains of several thousand square kilometers having multiple layers in the sedimentary succession and several thousand old wells within the domain. Because we can perform each simulation in a few minutes of computer time, we can run tens of thousands of simulations and analyze the outputs in a probabilistic framework. We use these kinds of simulations to demonstrate the importance of residual brine saturations, the range of current options to quantify leaky well properties, and the impact of depth of injection and how it relates to leakage risk.
A screening and ranking framework (SRF) has been developed to evaluate potential geologic carbon dioxide (CO2) storage sites on the basis of health, safety, and environmental (HSE) risk arising from CO2 leakage. The approach is based on the assumption that CO2 leakage risk is dependent on three basic characteristics of a geologic CO2 storage site: (1) the potential for primary containment by the target formation; (2) the potential for secondary containment
if the primary formation leaks; and (3) the potential for attenuation and dispersion of leaking CO2 if the primary formation leaks and secondary containment fails. The framework is implemented in a spreadsheet in which users
enter numerical scores representing expert opinions or published information along with estimates of uncertainty. Applications
to three sites in California demonstrate the approach. Refinements and extensions are possible through the use of more detailed
data or model results in place of property proxies.
We have used the TOUGH2-MP/ECO2N code to perform numerical simulation studies of the long-term behavior of CO2 stored in an aquifer with a sloping caprock. This problem is of great practical interest, and is very challenging due to
the importance of multi-scale processes. We find that the mechanism of plume advance is different from what is seen in a forced
immiscible displacement, such as gas injection into a water-saturated medium. Instead of pushing the water forward, the plume
advances because the vertical pressure gradients within the plume are smaller than hydrostatic, causing the groundwater column
to collapse ahead of the plume tip. Increased resistance to vertical flow of aqueous phase in anisotropic media leads to reduced
speed of up-dip plume advancement. Vertical equilibrium models that ignore effects of vertical flow will overpredict the speed
of plume advancement. The CO2 plume becomes thinner as it advances, but the speed of advancement remains constant over the entire simulation period of
up to 400years, with migration distances of more than 80km. Our simulations include dissolution of CO2 into the aqueous phase and associated density increase, and molecular diffusion. However, no convection develops in the aqueous
phase because it is suppressed by the relatively coarse (sub-) horizontal gridding required in a regional-scale model. A first
crude sub-grid-scale model was developed to represent convective enhancement of CO2 dissolution. This process is found to greatly reduce the thickness of the CO2 plume, but, for the parameters used in our simulations, does not affect the speed of plume advancement.
KeywordsCO2 plume–Long-term fate–Sloping aquifer–Numerical simulation–Enhanced dissolution–Capillary effects
Injection of fluids into deep saline aquifers is practiced in several industrial activities, and is being considered as part of a possible mitigation strategy to reduce anthropogenic emissions of carbon dioxide into the atmosphere. Injection of CO2 into deep saline aquifers involves CO2 as a supercritical fluid that is less dense and less viscous than the resident formation water. These fluid properties lead to gravity override and possible viscous fingering. With relatively mild assumptions regarding fluid properties and displacement patterns, an analytical solution may be derived to describe the space–time evolution of the CO2 plume. The solution uses arguments of energy minimization, and reduces to a simple radial form of the Buckley–Leverett solution for conditions of viscous domination. In order to test the applicability of the analytical solution to the CO2 injection problem, we consider a wide range of subsurface conditions, characteristic of sedimentary basins around the world, that are expected to apply to possible CO2 injection scenarios. For comparison, we run numerical simulations with an industry standard simulator, and show that the new analytical solution matches a full numerical solution for the entire range of CO2 injection scenarios considered. The analytical solution provides a tool to estimate practical quantities associated with CO2 injection, including maximum spatial extent of a plume and the shape of the overriding less-dense CO2 front.
This work was motivated by considerations of potential leakage pathways for CO2 injected into deep geological formations for the purpose of carbon sequestration. Because existing wells represent a potentially important leakage pathway, a spatial analysis of wells that penetrate a deep aquifer in the Alberta Basin was performed and various statistical measures to quantify the spatial distribution of these wells were presented. The data indicate spatial clustering of wells, due to oil and gas production activities. The data also indicate that the number of wells that could be impacted by CO2 injection, as defined by the spread of an injected CO2 plume, varies from several hundred in high well-density areas to about 20 in low-density areas. These results may be applied to other mature continental sedimentary basins in North America and elsewhere, where detailed information on well location and status may not be available.
Large volumes of CO2 captured from carbon emitters (such as coal-fired power plants) may be stored in deep saline aquifers as a means of mitigating climate change. Storing these additional fluids may cause pressure changes and displacement of native brines, affecting subsurface volumes that can be significantly larger than the CO2 plume itself. This study aimed at determining the three-dimensional region of influence during/after injection of CO2 and evaluating the possible implications for shallow groundwater resources, with particular focus on the effects of interlayer communication through low-permeability seals. To address these issues quantitatively, we conducted numerical simulations that provide a basic understanding of the large-scale flow and pressure conditions in response to industrial-scale CO2 injection into a laterally open saline aquifer. The model domain included an idealized multilayered groundwater system, with a sequence of aquifers and aquitards (sealing units) extending from the deep saline storage formation to the uppermost freshwater aquifer. Both the local CO2-brine flow around the single injection site and the single-phase water flow (with salinity changes) in the region away from the CO2 plume were simulated. Our simulation results indicate considerable pressure buildup in the storage formation more than 100 km away from the injection zone, whereas the lateral distance migration of brine is rather small. In the vertical direction, the pressure perturbation from CO2 storage may reach shallow groundwater resources only if the deep storage formation communicates with the shallow aquifers through sealing units of relatively high permeabilities (higher than 10−18 m2). Vertical brine migration through a sequence of layers into shallow groundwater bodies is extremely unlikely. Overall, large-scale pressure changes appear to be of more concern to groundwater resources than changes in water quality caused by the migration of displaced saline water.
This paper demonstrates the use of coupled fluid flow and geomechanical fault slip (fault reactivation) analysis to estimate the maximum sustainable injection pressure during geological sequestration of CO2. Two numerical modeling approaches for analyzing fault-slip are applied, one using continuum stress–strain analysis and the other using discrete fault analysis. The results of these two approaches to numerical fault-slip analyses are compared to the results of a more conventional analytical fault-slip analysis that assumes simplified reservoir geometry. It is shown that the simplified analytical fault-slip analysis may lead to either overestimation or underestimation of the maximum sustainable injection pressure because it cannot resolve important geometrical factors associated with the injection-induced spatial evolution of fluid pressure and stress. We conclude that a fully coupled numerical analysis can more accurately account for the spatial evolution of both in situ stresses and fluid pressure, and therefore results in a more accurate estimation of the maximum sustainable CO2 injection pressure.
Saline aquifers of high permeability bounded by overlying/underlying seals may be surrounded laterally by low-permeability zones, possibly caused by natural heterogeneity and/or faulting. Carbon dioxide (CO2) injection into and storage in such “closed” systems with impervious seals, or “semi-closed” systems with non-ideal (low permeability) seals, is different from that in “open” systems, from which the displaced brine can easily escape laterally. In closed or semi-closed systems, the pressure buildup caused by continuous industrial-scale CO2 injection may have a limiting effect on CO2 storage capacity, because geomechanical damage caused by overpressure needs to be avoided. In this research, a simple analytical method was developed for the quick assessment of the CO2 storage capacity in such closed and semi-closed systems. This quick-assessment method is based on the fact that native brine (of an equivalent volume) displaced by the cumulative injected CO2 occupies additional pore volume within the storage formation and the seals, provided by pore and brine compressibility in response to pressure buildup. With non-ideal seals, brine may also leak through the seals into overlying/underlying formations. The quick-assessment method calculates these brine displacement contributions in response to an estimated average pressure buildup in the storage reservoir. The CO2 storage capacity and the transient domain-averaged pressure buildup estimated through the quick-assessment method were compared with the “true” values obtained using detailed numerical simulations of CO2 and brine transport in a two-dimensional radial system. The good agreement indicates that the proposed method can produce reasonable approximations for storage–formation–seal systems of various geometric and hydrogeological properties.
Integrated modeling of basin- and plume-scale processes induced by full-scale deployment of CO(2) storage was applied to the Mt. Simon Aquifer in the Illinois Basin. A three-dimensional mesh was generated with local refinement around 20 injection sites, with approximately 30 km spacing. A total annual injection rate of 100 Mt CO(2) over 50 years was used. The CO(2)-brine flow at the plume scale and the single-phase flow at the basin scale were simulated. Simulation results show the overall shape of a CO(2) plume consisting of a typical gravity-override subplume in the bottom injection zone of high injectivity and a pyramid-shaped subplume in the overlying multilayered Mt. Simon, indicating the important role of a secondary seal with relatively low-permeability and high-entry capillary pressure. The secondary-seal effect is manifested by retarded upward CO(2) migration as a result of multiple secondary seals, coupled with lateral preferential CO(2) viscous fingering through high-permeability layers. The plume width varies from 9.0 to 13.5 km at 200 years, indicating the slow CO(2) migration and no plume interference between storage sites. On the basin scale, pressure perturbations propagate quickly away from injection centers, interfere after less than 1 year, and eventually reach basin margins. The simulated pressure buildup of 35 bar in the injection area is not expected to affect caprock geomechanical integrity. Moderate pressure buildup is observed in Mt. Simon in northern Illinois. However, its impact on groundwater resources is less than the hydraulic drawdown induced by long-term extensive pumping from overlying freshwater aquifers.
Shear viscosities of supercritical carbon dioxide have been measured to 673 K and 8 GPa (80 kbar). Measurements were made in a diamond-anvil cell with a rolling-ball technique. Individual isotherms are well fit by a modified free-volume equation. The data demonstrate a close relation between viscosity and residual entropy.
The relentless increase of anthropogenic carbon dioxide emissions and the associated concerns about climate change have motivated new ideas about carbon-constrained energy production. One technological approach to control carbon dioxide emissions is carbon capture and storage, or CCS. The underlying idea of CCS is to capture the carbon before it emitted to the atmosphere and store it somewhere other than the atmosphere. Currently, the most attractive option for large-scale storage is in deep geological formations, including deep saline aquifers. Many physical and chemical processes can affect the fate of the injected CO2, with the overall mathematical description of the complete system becoming very complex. Our approach to the problem has been to reduce complexity as much as possible, so that we can focus on the few truly important questions about the injected CO2, most of which involve leakage out of the injection formation. Toward this end, we have established a set of simplifying assumptions that allow us to derive simplified models, which can be solved numerically or, for the most simplified cases, analytically. These simplified models allow calculation of solutions to large-scale injection and leakage problems in ways that traditional multicomponent multiphase simulators cannot. Such simplified models provide important tools for system analysis, screening calculations, and overall risk-assessment calculations. We believe this is a practical and important approach to model geological storage of carbon dioxide. It also serves as an example of how complex systems can be simplified while retaining the essential physics of the problem.
Capture and subsequent injection of carbon dioxide into deep geological formations is being considered as a means to reduce anthropogenic emissions of CO2 to the atmosphere. If such a strategy is to be successful, the injected CO2 must remain within the injection formation for long periods of time, at least several hundred years. Because mature continental sedimentary basins have a century-long history of oil and gas exploration and production, they are characterized by large numbers of existing oil and gas wells. For example, more than 1 million such wells have been drilled in the state of Texas in the United States. These existing wells represent potential leakage pathways for injected CO2. To analyze leakage potential, modeling tools are needed that predict leakage rates and patterns in systems with injection and potentially leaky wells. A new semianalytical solution framework allows simple and efficient prediction of leakage rates for the case of injection of supercritical CO2 into a brine-saturated deep aquifer. The solution predicts the extent of the injected CO2 plume, provides leakage rates through an abandoned well located at an arbitrary distance from the injection well, and estimates the CO2 plume extent in the overlying aquifer into which the fluid leaks. Comparison to results from a numerical multiphase flow simulator show excellent agreement. Example calculations show the importance of outer boundary conditions, the influence of both density and viscosity contrasts in the resulting solutions, and the potential importance of local upconing around the leaky well. While several important limiting assumptions are required, the new semianalytical solution provides a simple and efficient procedure for estimation of CO2 leakage for problems involving one injection well, one leaky well, and multiple aquifers separated by impermeable aquitards.
Climate scientists in the US are seeing the risks due to the carbon dioxide and greenhouse gas emissions and are taking appropriate measures to curb the emissions. To make the problem manageable, the required reduction in emissions can be broken down into wedges, an incremental reduction of a size that matches available technology. Achieving nearly every one of the wedges requires new science and engineering to cut down costs and address the problems that accompany widespread deployment of new technologies. Cutting the electricity use to half in buildings could lead to two wedges and another wedge could be achieved if the industry finds additional ways to use electricity more efficiently. The extra carbon emissions produced during the delivery of electricity and modern cooking fuel can be compensated for by one fifth of a wedge of emission reductions elsewhere. Strong international enforcement mechanisms will have to come into being and economic growth will have to be maintained.
Impact of the capillary fringe in vertically inte-grated models for CO2 storage Screening and ranking framework for geologic CO2 storage site selection on the basis of health, safety, and environmental risk
- J M Nordbotten
- H K Dahle
Nordbotten, J.M., Dahle, H.K., 2011. Impact of the capillary fringe in vertically inte-grated models for CO2 storage. Water Resour. Res. 47 (2), W02537. Oldenburg, C.M., 2008. Screening and ranking framework for geologic CO2 storage site selection on the basis of health, safety, and environmental risk. Environ. Geol. 54 (8), 1687–1694.