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In the context of global climate change, carbon capture and storage (CCS) has become a direct and effective measure for reducing greenhouse gases emission. However, injecting CO2 into the subsurface reservoirs may pose risks related to geological hazards. Therefore, monitoring the variations in underground temperature fields, strain fields, and vibration fields induced by CO2 injection is essential for predicting and controlling geological hazards. Distributed fiber optic sensing (DFOS) technology, with its unique features, enables real‐time monitoring of temperature, strain, and vibration. By deploying fiber optic (FO) cables inside wellbores, a DFOS can be used to effectively capture multiple underground response parameters. This paper reviews the applications of DFOS technology in CO2 geological sequestration. The chapter covers aspects such as the literature review, principles and applications of fiber optics, and representative monitoring projects. Finally, the paper discusses the challenges and proposed solutions for DFOS technology in this context. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Carbon capture and storage (CCS) plays an important role in promoting developing countries to reduce carbon emission and meet the requirement for carbon reduction under carbon neutral and carbon peak targets. To evaluate the incentive effect of subsidization mechanisms on CCS investment, the paper incorporates two incentives into the model, considers the effects of the carbon trading price, electricity price, and other uncertain factors on the investment behaviors for CCS projects under uncertainty and explores incentive intensity of two policies on investment based on the real option method. The results show that even in the case of full operating cost subsidies and double electricity price subsidies, the power plant still delays CCS investment due to the imperfection of carbon market. The most appropriate policies for supporting immediate investment in CCS project are identified in the paper by considering the critical carbon price and electricity price in different scenarios. Additionally, the findings show that it is more efficient for the electricity price subsidy than cost subsidy with same subsidy proportion under single policy condition, while the minimum subsidy amount required to invest immediately is 32.86 million CNY in the combination of the two policies. This provides environmental policymakers with valuable insights on promoting CCS deployment under the context of carbon reduction. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

This paper addresses the urgent challenge of CO2 emissions and the need for sustainable energy sources. It emphasizes CO2 hydrogenation as a promising solution for large‐scale long‐term energy storage, converting CO2 into valuable fuels using green hydrogen generated from renewable sources. The study concentrates on exploring pathways leading to oxygenated compounds, such as alcohols or ethers, for their utilization as sustainable fuels. The investigation encompasses methanol, dimethyl ether, ethanol, and higher alcohols. The paper investigates catalysts for CO2 hydrogenation, ranging from traditional metal‐based to advanced materials, aiming to identify efficient and stable catalysts for synthesizing oxygenated compounds. Catalysts are indispensable in CO2 hydrogenation for the synthesis of oxygenated compounds, contributing to improved reaction kinetics, selectivity, economic viability, reduced environmental impact, and the overall sustainability of the process. The goal is to contribute to a fully renewable, carbon‐neutral system powered by excess solar and wind electricity, where recycled CO2 and green hydrogen are used to produce fuels, to be stored and then used to produce energy, electricity, heat, or mechanical energy, on demand, with the capture of the CO2, in a system which is overall carbon neutral. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Geological sequestration of carbon dioxide (CO2) is an effective method to reduce greenhouse gases and an important technology for carbon neutralization. Among all geological sequestration sites, coal reservoirs are potentially effective and practicable. The Xiangzhong Depression of Hunan Province of China is selected as the research area, and the coal seam of Longtan Formation is the target reservoir in this paper. CO2‐enhanced coalbed methane (CO2‐ECBM) and CO2 sequestration capacity are both simulated according to the laboratory experiments on reservoir parameters. During simulation, four production wells and one injection well were designed, and the simulation process can be divided into two stages: CO2‐ECBM and CO2 geological storage. The CO2‐ECBM stage refers to CO2 injection for increasing methane production, and the CO2 geological storage stage aims to predict the CO2 sequestration capacity. After that, sensitivity analyses of sequestration effect are carried out. During the simulation, when maintaining a constant pressure injection of CO2 under the original conditions of 0.01 mD permeability, 9% porosity, and 1.47 MPa reservoir methane pressure, the total storage amount is only 0.14 × 106 m3. However, the storage amount increases significantly to 6.62 × 106 m3 if the permeability increases to 1.5 mD. Orthogonal simulation indicates that permeability has the greatest impact on CO2 sequestration. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The requirement to pre‐treat flue gas prior to the CO2 capture step is an economic challenge when using aqueous amine absorbents for capturing CO2 from coal‐fired power station flue gases. A potentially lower cost alternative is to combine the capture of both CO2 and SO2 from the flue gas into a single process, removing the requirement for the desulfurization pre‐treatment step. The CSIRO's CS‐Cap process uses a single aqueous amine absorbent to capture both of these acid gases from flue gas streams. This paper covers the initial simulation of this process applied to both brown and black coal flue gases. Removal of absorbed SO2 is achieved via reactive crystallization. This is simulated here using a 'black box' process, resulting in a K2SO4 product. Different operating conditions have been evaluated that increase the sulfate concentration of the absorbent in the SO2 capture section of the process, which is expected to increase the efficiency of the reactive crystallization step. This paper provides information on the absorption of SO2 into the amine solution, and heat and mass balances for the wider process. This information will be required for further detailed simulation of the reactive crystallization step, and economic evaluation of the CS‐Cap process. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

CO2 capture by absorption and stripping with aqueous amine is a well‐understood and widely used technology. However, drawbacks still exist in the practical applications, such as high energy consumption and easy degradation of the absorbents during the desorption process. In this paper, a novel NE‐1 absorbent was developed, and its suitable operating conditions were determined: concentration (45 wt.%), absorption temperature (40 °C), and desorption temperature (100 °C). The NE‐1 absorbent exhibits a high CO2 absorption capacity of 3.73 mol/kg, 1.33 times that of 30% monoethanolamine (MEA). After optimizing with carbamide as a corrosion inhibitor, 45% NE‐1a1 may attain an effective CO2 capacity of 2.5 mol/kg and over 70% desorption rate in five cycles, demonstrating excellent cycling stability performance. The research results have significant implications for developing an efficient and stable commercial carbon capture solvent and promoting the development of carbon reduction technologies. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Biomass conversion with carbon capture and storage (Bio‐Energy CCS; BECCS) is one of the options considered for mitigating climate change. In this paper, the carbon capture technology chemical‐looping combustion (CLC) is examined in which the CO2 is produced in a stream separate from the combustion air. A central research topic for CLC is oxygen carriers; solid metal oxides that provide oxygen for the conversion process. Biomass and waste‐derived fuels contain reactive ash compounds, such as potassium, and interactions between the oxygen carrier and the ash species are critical for the lifetime and performance of the oxygen carrier. This work develops and demonstrates an improved method for studying the interactions between ash species and oxygen carriers. The method uses a lab‐scale reactor operating under fluidized conditions, simulating CLC batch‐wise by switching between feed gas. The novelty of the setup is the integrated system for feeding solid particles of ash model compounds, enabling the simulation of ash species accumulating in the bed. Ilmenite is a benchmark oxygen carrier for solid fuel conversion and was used in this study to evaluate the method using K2CO3 as a model ash compound. Experiments were done at 850 and 950°C. Methane conversion in CLC cycles and fluidization was evaluated with gas analysis and pressure drop measurements. Scanning electron microscopy and energy dispersive X‐ray spectroscopy (SEM‐EDS) and X‐ray diffraction (XRD) analysis of bed particles were done after the experiments to establish changes in the morphology and composition of the ilmenite. The method for feeding the ash model compound was concluded to be satisfactory. At 950°C, K accumulated in the particles forming K‐titanates and agglomeration was enhanced with K2CO3 addition. The agglomeration mechanism was solid‐state sintering between the Fe‐oxides forming on the particle surfaces. The bed defluidized at 950°C, but no such effect was seen at 850°C. The method is suitable for studying the Fe‐Ti‐K system with ilmenite and potassium without the influence of other ash species. © 2023 The Authors. Greenhouse Gases: Science and Technology published by Society of Chemical Industry and John Wiley & Sons Ltd. [ABSTRACT FROM AUTHOR]

In this work, the research project IBUMECO2 is presented for the first time. This project rises as a need to implement negative emissions technologies and circular economy approaches in our current energy production system. The overall goal of the project is the integration of CO2 capture and utilization in biogas upgrading plants in combination with membrane technology for solvent regeneration. The integration of CO2 capture and utilization in biogas upgrading plants is pivotal for two main reasons: (1) it allows to obtain biomethane, a potential substitute of natural gas; (2) the utilization of the CO2 contained in biogas makes the idea a negative emission technology. The implementation of membrane technology for solvent regeneration makes the process affordable and includes it in a circular economy framework. In this paper, the project and the process are deeply described, including potential technological improvements identified by a state‐of‐the‐art, the methodology and goals expected. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The Spanish CO SB 2 sb Technology Platform Association (PTECO2) was founded in 2006 by Spain's industrial sector, research and technology centres, and universities. Acknowledging the opportunity given by I Greenhouse Gases: Science and Technology i , this special issue gathers nine interesting papers featuring the activities of some of the members of PTECO2. Acknowledging the opportunity given by I Greenhouse Gases: Science and Technology i , this special issue gathers nine interesting papers featuring the activities of some of the members of PTECO2. [Extracted from the article]

In this paper, the mechanisms of long‐term CO2 sequestration and the effects of injection modes (including injection temperature, injection rate and injection cycle) in Zhujiang Formation characterized by high porosity and permeability were investigated using the numerical simulation method. Simulation results showed that more than 88% of the injected CO2 would exist in a supercritical state during the injection period and more than 79% of CO2 would be sequestrated in the reservoir by mineral trapping after 5,000 years. Eventually, the distribution shape of SC‐CO2 was a quarter funnel near the injection well, while the distribution shapes of dissolved and mineralized CO2 were both one quarter rotunda. During the long‐term CO2 sequestration in Zhujiang Formation, the dissolved minerals were anorthite, chlorite and smectite in turn, while the top three main precipitated minerals were calcite, dawsonite and albite. Moreover, higher injection temperature leads to a higher mineral tapping and more dissolved/precipitated minerals. While higher injection rate reduces the mineral tapping and total amount of dissolved/precipitated mineral. Compared to injection temperature and injection rate, the injection cycle has little effect on the CO2 phase evolution and mineral dissolution/precipitation process. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Carbon dioxide (CO2) geological sequestration technology is an attractive means of reducing greenhouse gas emissions. This work aims to seek the transport mechanism of CO2 in fractured porous media. A two‐phase flow extended finite element model is developed in this paper. The two‐phase flow in the fracture and porous matrix are all considered in the model development. We present numerical simulations under 2D linear flow conditions with specific and sensitivity analysis about fracture properties, capillary pressure, relative permeability, reservoir heterogeneity, and properties. It is found that fracture will dominate the CO2 transport when the intersection angle of fracture orientation and injection direction is less than 90°, and CO2 flows into deeper regions along the fracture. It is significant to find a suitable capillary pressure and relative permeability model which matches the microscopic pore structure when simulating CO2 geological sequestration in fractured media. Using the Brooks–Corey equation for capillary pressure and relative permeability, the CO2 transport efficiency would increase by around 16% compared to the Van Gneuchten equation. Besides, the CO2 phase and properties evolution during CO2 geological sequestration has a great influence on CO2 transport efficiency., CO2 transport efficiency is reduced by around 18% due to an increase in CO2 density and viscosity when considering CO2 properties evolution. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The characteristics of each carbonate reservoir are greatly different, and current databases are insufficient to support engineering scheme design and optimization of carbon dioxide (CO2) sequestration and enhanced oil recovery. In this paper, the behavior of CO2‐brine‐rock interactions was investigated under supercritical CO2 (50°C and 8.5 MPa) conditions. Five experiments were carried out, including CO2 solubility in brine, mass loss analysis by static reaction of CO2–brine–rock, mineralogical composition analysis by X‐ray diffraction (XRD), core surface morphology analysis by scanning electron microscopy (SEM), and wettability alteration by contact angle analysis. The experimental results showed that: (a) the CO2 solubility in brine increases with increasing pressure, but it increases slowly and gradually reaches equilibrium; (b) the mass loss of carbonate increases with reaction time, but its increments decrease with reaction time; (c) the calcite content gradually decreases and the quartz content slightly increases with reaction time, as evidenced by XRD analysis; (d) based on SEM image analysis, calcite was dissolved into brine by carbonic acid to make the pores larger, and then subsequent precipitation made the pores smaller; and (e) the carbonate rock surface became more water‐wet after CO2–brine–rock interaction experiments due to surface corrosion and increased quartz content. Using the experimental results, a mathematical model was developed to predict CO2 sequestration capacity under reservoir conditions. The results suggest that CO2 solubility in brine was the main aspect compared with mineral trapping in carbonate reservoirs, and CO2 sequestration capacity increased with increasing temperature and pressure. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

CO2 capture and storage (CCS) can be an important feature of a decarbonization strategy involving electricity generation. According to the recently revised Section 45Q tax credits, said credits will be provided for implementing CCS, which is motivating some United States (US) electricity generation companies to revisit their business strategies for CCS. This paper discusses alternative business models being considered by companies for undertaking CCS, including providing a 'template' for evaluating the cost‐effectiveness of CCS with Section 45Q tax credits and storage in saline reservoirs. Using stylized illustrative examples, the paper indicates how use of Section 45Q tax credits should be expected to change dispatch at an electricity generating unit. For situations similar to the examples, the paper suggests that Section 45Q tax credits may need to be modified to achieve its intended impact. Modifications can include extending the time period of tax credit availability beyond the current 12 years. In addition, continued R&D investments in CCS and specific support for first‐of‐a‐kind CCS demonstrations would be valuable complements for the deployment of the Section 45Q tax credit. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The generation of heat‐stable salts (HSSs) in alkanolamine solutions for CO2 capture processes, which is adapted for power plant technologies, exists irrespective of the class of amine solution used for the capture process. Their presence do not only trigger decrements in the CO2 absorption capacities of the solvents and contribute to further alkanolamine degradation, but also result in foaming and loss of solvents, which impacts system economics and threatens the environment. HSSs also promote the corrosiveness of the metallic structures of capture systems by lowering the pH and increasing the conductivity of the absorbent solutions. Overall, these effects substantially subvert the reliability and integrity of CO2 capture units. This survey affords sufficient background on the existence of HSSs by unraveling the flow process in a typical alkanolamine‐based CO2 capture unit with respect to their formation points and potential threats. Furthermore, the major HSSs removal and alkanolamine reclamation methodologies (electrodialysis, distillation, ion exchange, electromagnetic separation, and solvent extraction) were comprehensively explored. We believe that this review paper will benefit researchers across disciplines as we continue to explore new and complex solvent formulations to minimize the cost of CO2 capture while maximizing efficiency. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

As an essential greenhouse gas, CO2 is the leading cause of global warming and environmental problems. An efficient strategy to lower CO2 emissions is the hydrate‐based method of CO2 geological storage. The stability and formation process of hydrate is the premise and foundation of the hydrate method of CO2 geological storage. However, the formation rule of CO2 hydrate has a significant impact on the formation characteristics of CO2 hydrate. This paper thoroughly examines the formation properties of CO2 hydrate in porous media systems. The quantitative impacts and laws of many parameters on the CO2 hydrate production process are thoroughly examined. On this basis, the internal mechanism of particle size, pore distribution, and critical size of particles in porous media systems on the kinetics of CO2 hydrate formation are detailed. Finally, the shortcomings of the studies on CO2 hydrate formation kinetics in porous media systems and the main directions in the future are pointed out. The influence of pore distribution in porous media on the CO2 hydrate formation process still needs further study. The relative results will be useful in the future for CO2 capture and sequestration in sediments. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Carbon capture technologies have been recognized as a potential alternative to alleviate global warming. Carbon capture and storage (CCS) is preferred over carbon conversion and utilization (CCU) due to its lower operating costs and higher CO2 reduction capability. Nevertheless, CO2 utilization has the potential to be more economical if value‐added products are produced. This highlights the importance of assessing CO2 utilization routes and alternatives in carbon management. This review paper aims to evaluate the carbon utilization potential of major CO2‐capturing absorbents including amine, hydroxide, ionic liquid, amino acids and carbonate absorbents. All absorbents show potential application for CO2 utilization except for ionic liquids (ILs) due to their unclear CO2 capture mechanisms. Absorbents that require a desorption process for CO2 utilization include MEA, MDEA, K2CO3 and Na2CO3 due to their high absorption capacity. Industries have utilized the desorbed CO2 as chemical feedstocks, enhanced oil recovery (EOR) and mineral carbonation. For hydroxide absorbents and CaCO3, desorption of CO2 is unnecessary as the absorbed CO2 can be directly utilized to produce construction materials. Apart from that, the incorporation of advanced technologies and business models introduced by the fourth industrial revolution are plausible considerations to accelerate the development of carbon capture technologies. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

This paper presents an investigation on simultaneous freshwater production and CO2 capture using the flue gases of a 500 MWe coal‐fired power plant. Generally, a fan/cooler is used to reduce the temperature of flue gas before flowing into the absorber column of a CO2 capture unit. It has been replaced with a heat exchanger in this study. Seawater and flue gas were passed through the heat exchanger to raise the temperature of seawater and reduce the temperature of flue gas. The high‐temperature seawater was subsequently fed into a membrane distillation (MD) unit for freshwater production. The cold flue gas was directed to the CO2 capture unit. The heat exchanger and CO2 capture unit were modeled with Aspen Plus software. Whereas MATLAB software was used to develop and solve the MD mathematical model software for freshwater production. The seawater flow rate was varied from 4000 L/min to 7000 L/min in the heat exchanger. As a result, the flue gas (flow rate 781.6 t/h) and the outlet seawater temperatures were reduced from 27.498 to 22.360°C and 73.384 to 52.670°C, respectively. However, higher inlet seawater temperature in the MD unit produced more freshwater. An increase in inlet seawater feed temperature in the MD unit from 52.670 to 73.384°C increased the freshwater production from 211,956.5 to 299,244 L/day. Furthermore, the CO2 capture process has been analyzed by varying the methyldiethanolamine (MDEA) and piperazine (PZ) concentrations in weight% (45 and 5, 40 and 10, 35 and 15, and 30 and 20, respectively). It was observed that the energy requirement reduced from 3.55 to 3.26 MJ/kg CO2 by increasing the PZ content from 5 to 20 wt.%. At 15 and 20 wt.% of PZ content in the blended solution of MDEA/PZ, the energy required to regenerate the solvent was 3.31 and 3.26 MJ/kg CO2, respectively. PZ emissions from the absorber were also increased with the raising of PZ content in the blended solution. The energy requirement was not much higher at 15 wt.% than 20 wt.%. Therefore, MDEA/PZ solution (15/35 wt.%) was considered an optimal concentration. The reboiler duty was reduced up to 3.25 MJ/kg CO2 at 15/35 wt.% concentration with stripper pressure of 2.3 bar. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The abandonment process is a highly important part of project management for CO2 capture and storage (CCS) projects. For the first full procedure of a CO2 geological storage demonstration project in a deep saline aquifer in China, this paper describes the abandonment process of a CO2 operating well. The key idea that we advance is that wellbore integrity tests should be conducted before the abandonment, and consideration must be given to the CO2 corrosion resistance materials, the design method of sealing the plugs, monitoring tests (such as pressure tests), and the use of a long-term monitoring system (such as the original pressure test and a packer isolation test every year). According to Chinese regulations and related experience in the oil and gas industry, the factors chosen are the pressure factor, cap rock, potable water layer, unexploited resource layer, suspected leak path, perforated zone, productive hydrocarbon zone without perforation, and water-injection and waste-water treatment layers. We intuitively evaluate and quantify the plugged zones using the modified analytical hierarchy process (M-AHP) method to determine the positions of the plugs. Next, referring to the Chinese regulations on Well abandonment and inactive well practices, the last plug located in the Quaternary strata is compulsorily ensured, and the length of all plugs is also determined. Finally, the paper summarizes the methodology and presents suggestions for the abandonment process of the Shenhua CCS project. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Mitigation of carbon dioxide (CO2) from various sources is a major challenge in the world today. Apart from attempts to control CO2 emissions from large CO2 emitting sources such as coal‐fired power plants and significant fossil fuel‐consuming industries, there have also been attempts made to control CO2 in internal combustion (IC) engines. Compression ignition (CI) engines find their applications mainly in automotive vehicles, decentralized power generation units, standby power requirements in hospitals and educational institutions. In recent years, there has been a great interest in developing eco‐friendly and low‐cost adsorbents for CO2 capture via the adsorption method. This investigation explores the possibility of using activated carbon obtained from coconut shell for capturing CO2 in a CI engine exhaust. Surface texture characteristics and physicochemical properties of the coconut shell‐based activated carbon are determined for their suitability as a potential adsorbent for CO2 adsorption. Furthermore, an attempt is made to combine a postcombustion carbon capture device in a CI engine. For this purpose, an in‐house fabricated adsorption chamber is packed with activated carbon and attached to a single‐cylinder, four‐stroke, naturally aspirated, direct injection (DI) diesel engine exhaust. The test engine is operated on two different fuels; (i) diesel (D100) and (ii) biodiesel‐diesel blend comprising 20% of Jatropha methyl ester (JME) and 80% of diesel (JME20). The engine performance and CO2 emission without and with the adsorption chamber are evaluated for D100 and JME20 operations. Further, the performance parameters of the adsorption chamber packed with activated carbon are also evaluated in both fuel operations. The results are analyzed, discussed, and presented in this paper. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

As part of the Integrated Midcontinent Stacked Carbon Storage Hub (IMSCS‐Hub) project led by Battelle Memorial Institute, a study was conducted to determine the feasibility of storing carbon dioxide (CO2) in the stacked saline rock formations of the Sleepy Hollow Field (SHF), located in Red Willow County, southern Nebraska. A series of CO2 injection simulation scenarios, with and without active reservoir management (ARM; brine extraction), were evaluated to investigate the feasibility of storing 50+ million tonnes (Mt) of CO2. The results indicated CO2 injection combined with ARM may enable permanent storage of 50+ Mt of CO2. The area of review (AOR), the area in which underground sources of drinking water (USDWs) might be endangered during CO2 injection, was assessed for the simulation scenarios. In comparison to a case without ARM, brine extraction resulted in a much smaller AOR, covering an area of 42 square miles (108.8 km2), roughly one‐fourth the size of an AOR resulting from CO2 injection without ARM. The findings presented in this paper indicate that CO2 injection with ARM can improve the CO2 storage capacity of a geologic storage complex up to 100% while also reduce the rate of pressure buildup in the subsurface, resulting in a 75% reduction in AOR. This may help in lowering carbon capture and storage project costs, risks, and effort needed to meet monitoring requirements for a storage project. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The continued rise in anthropogenic carbon dioxide (CO2) emissions and increase in atmospheric CO2 concentration has led to calls from experts, including the Intergovernmental Panel on Climate Change that has estimated that global warming needs to be limited to 1.5 °C above preindustrial levels to avoid the worst effects of climate change, and that carbon neutrality would need to be achieved globally by 2050 to meet this target. Achieving carbon neutrality by mid‐century will rely on successful implementation and widespread adoption of technologies for reducing emissions from large point sources of CO2, direct CO2 capture from the air, as well as storage and utilization technologies that would convert CO2 to a form that would ensure safety and permanency of storage. In this paper, engineering solutions for CO2 capture, utilization, and storage are reviewed with a focus on technology readiness level, and cost. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The utilization of various conventional and emerging solid adsorbents is an attractive carbon capture method for post‐combustion and direct air capture (DAC). This review aims to identify adsorbents with the highest CO2 adsorption performance at various CO2 capture conditions inclusive of pre‐combustion, post‐combustion, and DAC to aid the selection of adsorbents. It presents the various adsorbents' physical and chemical properties, their synthesis methods, CO2 adsorption performance, and their advantages as CO2 adsorbents. Findings of the review show that NaX@NaA core‐shell microspheres possess the highest CO2 adsorption capacity at 5.60 mmol g−1 for adsorption at DAC conditions. MOF‐177‐TEPA exhibited the highest post‐combustion condition CO2 adsorption capacity at 4.60 mmol g−1 given tetraethylenepentamine properties leading to low diffusion resistance for CO2 and easy access to active sites. Approximation of these adsorbents' adsorption capacity within pre‐combustion capture temperature at 1 bar for oxy‐combustion process was 0.0000026–48.71 mmol g−1. It is crucial to understand and evaluate these adsorbents' characteristics for application in the appropriate adsorption conditions. This considers their usage limitations on pilot‐scale CO2 capture because of low productivity, poor durability, and stability for prolonged cyclic adsorption–desorption, expensive adsorption system, high gas flow rate, high adsorbate accommodation requirement, longer flow switching time, and low tolerance towards water and impurities present in flue gas. This paper hence presents future enhancements in overcoming their limitations to accommodate pilot scale carbon capture. These are beneficial in providing insights for capturing CO2 from flue gases emitted in industries. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Carbon capture and utilization technology is one of the medium‐term technology options to reduce CO2 emissions while producing value‐added fuels and chemical products. The integrated CO2 capture and hydrogenation process is an encouraging replacement to the conventional decoupled CO2 capture and hydrogenation process, which allows direct utilization of captured CO2 thus eliminating the energy‐intensive CO2 desorption and compression steps in the typical carbon capture and storage (CCS) process. The hydrogenation of captured CO2 in amine/alkali hydroxide solvents is the key step to attain the integrated CO2 capture and hydrogenation process. Considering the lack of timely review on the topic of hydrogenation of amine/alkali hydroxide solvent captured CO2 to formate in the presence of heterogeneous catalysts, a summary of such process with different capturing solvents and heterogeneous catalyst were critically summarized and briefly reviewed in the current paper. The main goal of this review is to provide fundamental insights and guidance for the future design of heterogeneous catalysts for the hydrogenation of captured CO2 in amine/alkali metal hydroxide‐based solvents. Future research directions to advance the process of hydrogenation of captured CO2 were also recommended. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The goal of reducing energy consumption of the CO2 removal process from flue gas may be pursued by developing new solvents as well as by modifying the technological process itself. This paper provides a discussion of the experimental results obtained from a process development unit (PDU) using an aqueous 2-amino-2-methyl-1-propanol (AMP) solution activated with piperazine (PZ) for post-combustion carbon capture located at the Clean Coal Technologies Centre in Poland. The results are compared for two distinct process setups, namely one with the lean amine stream being split - a solution referred to as split flow, and a system with standard configuration. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

In 2018, the International CCS Knowledge Centre (CCS Knowledge Centre) conducted a feasibility study with SaskPower to determine if a business case could be made for a postcombustion, carbon capture retrofit of SaskPower's Shand Power station, a 305‐MW, single‐unit, lignite coal‐fired power station located near Estevan, Saskatchewan. Specifically, Mitsubishi heavy industries' KM CDR technology was evaluated for this study. While no decision has been made, should SaskPower decide to proceed, the Shand carbon capture and storage (CCS) project would produce the second, full‐scale capture facility in Saskatchewan with a nominal capacity of 2 million tonnes of CO2 (Mt) per year. This paper summarizes the key technical and economic findings of this study. Notably this study found that the capital costs of the potential Shand CCS facility are decreased by 67% on a per tonne of CO2 captured basis when compared to the CCS retrofit of Unit 3 at the Boundary Dam Power Station (the world's first industrial scale CCS installation on a coal fired power station). The proposed capture facility would also have a load following operational profile, reduction in parasitic loses by employing heat integration strategies, and need no additional water draw to provide the required increase in cooling duty. © 2020 The Authors. Greenhouse Gases: Science and Technology published by Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The increase of fluid injection projects with large burial depths, such as CO2 geological storage, poses a new challenge for the change law of pressure in reservoirs. To obtain the pressure of anywhere at anytime conveniently and then evaluate the injectivity and safety of reservoirs, a Darcy formulation suited for two-phase flow of displacement is put forward in this paper. A convenient and practical explicit integral (analytical) solution of pressure build-up for two-phase flow under a constant injection rate of CO2, based on an infinite reservoir with a constant pressure boundary whose location is a function of time is then derived. Subsequently, this work compared the results of the explicit integral solution with the results of Nordbotten's approximate solution and the simulated results of TOUGH2/ECO2N for an analysis case of CO2 injection, which demonstrated a good consistency, verifying the correctness and the reliability of the explicit integral solution. Furthermore, the sensitivity analysis of Slc (the saturation of brine in the CO2 domain) and Slw1 (the saturation of brine in the brine domain 1) showed that they both have a great impact on the pressure profiles in reservoirs, and the pressure is more sensitive to Slw1 than Slc. Therefore, the determination of Slc and Slw1 should be careful and based on the actual project in applications. Generally speaking, the explicit integral solution is simple, convenient, and practical compared with numerical simulators and other analytical solutions with similar assumptions. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd [ABSTRACT FROM AUTHOR]

It has been proposed that a considerable amount of CO2 can be safely sequestered from the atmosphere in geological formations such as coalbeds. In spite of promising evidence of the economic and technical viability of CO2 sequestration in coal seams, many of its hydro-geomechanical aspects are not fully understood. This paper presents a coupled hydro-mechanical model that is used to assess the reservoir performance of a coalbed and the induced surface and subsurface deformations. A series of numerical simulations has been performed to study the effects of different parameters on the reservoir and geomechanical behaviors associated with CO2 injection. A single-phase dual-porosity model is coupled to a one-dimensional poroelastic model and an analytical model for the ground surface movements. Through these simulations, the role of three sets of parameters at different scales is investigated: fracture characteristics, matrix characteristics, and geomechanical/geometrical characteristics. The comparative impacts of these parameters on reservoir permeability, volume of the stored CO2, and deformations of the coalbed and the ground surface, are quantitatively assessed, in order to identify the most important parameters influencing the hydro-mechanical response of the ground. [ABSTRACT FROM AUTHOR]

The environmental problems caused by global warming have attracted close attention of governments and scientists all over the world. As the source and sink of atmospheric carbon dioxide, cropland soil plays an important role in the global carbon cycle. Paddy soil is a major component of global cropland, and there is growing research on its carbon sequestration potential. Based on the dynamic characteristics of soil carbon sequestration in cropland, this paper reviews and synthesizes the process and mechanism of soil carbon sequestration in cropland, discusses the driving factors of soil carbon sequestration in cropland from the perspective of crop management practices, and emphatically discusses the knowledge of soil carbon sequestration potential in paddy fields in China. The main conclusions are as follows: (1) The organic carbon content of cropland soil in China is obviously lower than the global average, and the current sequestration rate of paddy soil in China is obviously lower than the potential sequestration rate, which has great potential for carbon sequestration. Since the mid‐1980s, China's agricultural soil organic carbon (SOC) has been gradually increasing, especially the carbon sink effect of rice soil in southern China. (2) Soil and crop management practices such as conservation agriculture, irrigation, integrated nutrition management, straw returning, and crop rotation can improve input efficiency, increase SOC content in the soil carbon pool, and reduce greenhouse gas emissions. (3) The research on SOC fixation mechanism has entered the micro level of soil particles. The chemical protection mechanism of clay, the physical protection mechanism of aggregates, and the biological mechanism interact and influence each other. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Oxy‐fuel combustion in coal‐fired plants has become one of the most promising technologies for carbon capture and storage (CCS). Because of the obvious difference between the oxy‐fuel combustion medium (O2/CO2) and air in the atmosphere (O2/N2), the characteristics of combustion, heat transfer, etc., under oxy‐fuel combustion have changed greatly from those under air combustion. In this paper, computational fluid dynamics (CFD) simulation was used to investigate pulverized coal combustion in a 200 MWe tangentially fired oxy‐fuel combustion boiler. Improved models for the gas radiative properties and chemical reaction mechanisms were incorporated into the CFD code. Both conventional air‐fired and oxy‐fuel combustion were operated. Different flue gas recycling patterns (dry recycling and wet recycling) were also investigated. The temperature distribution in the furnace, the temperature field, and the CO concentration field in each scheme were analyzed, this being relevant to the design of oxy‐fuel combustion boilers. It was found that combustion could form a good tangential circle and stable temperature field in the furnace either under air‐fired or oxy‐fule combustion conditions. The temperature under oxy‐fuel combustion was lower than with air combustion. The burnout rate under the air condition was lower than that with the oxy‐fuel combustion condition. With oxy‐fuel combustion, it is necessary to pay special attention to the slagging tendency of the primary combustion zone in the furnace. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Salt caverns have been identified as one of the best options for the underground storage of gases due to salt rock's excellent sealing capabilities and interesting mechanical properties, such as self‐healing when damaged or cracked. It is feasible to build salt caverns in the Brazilian pre‐salt ultra‐deep water environment for gas storage. However, the peculiar geology of the Brazilian province considered here is characterized by the stratification of thick layers of halite with intercalations of carnallite and tachyhydrite salt rock, whose creep strain rate is almost two orders of magnitude higher than halite's creep strain rate under the same conditions of temperature and pressure. Computational mechanics is being used for the design of offshore salt caverns opened by dissolution mining for the storage of natural gas. The challenge presented in this paper requires the storage of natural gas with high CO2 content offshore in ultra‐deep water (2140 m) in salt caverns. If the economics proves feasible, this offshore gas storage station will be the first of its kind in the world. A technical feasibility rock mechanics study of giant salt caverns, 450 m high by 150 m in diameter, has shown that one cavern can store 4 billion Sm3 or 7.2 million tons of CO2. The salt dome studied can accommodate the construction of 15 caverns, thus providing the confinement of approximately 108 million tons of gas. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Global climate change resulting from substantial CO2 emissions is increasingly attracting attention, and coal‐fired power plants are a major source of CO2 emission, so it is necessary to control and reduce CO2 emissions from power plants. Using alkali‐based solutions for CO2 capture is thought to be an effective method to achieve this but poor CO2 sorption/desorption kinetics inhibit its development. The use of nanofluids, prepared by adding nanoparticles to an alkali‐based solution, is a promising way to improve CO2 sorption/desorption reactivity because the addition of nanoparticles not only improves the gas‐liquid mass/heat transfer but also enhances the reaction kinetics. In this paper, a nanostructured Cu/TiO(OH)2 was prepared and used to accelerate the CO2 sorption/desorption performance of a potassium‐based solution. The CO2 sorption/desorption reaction rates increased with the thermal conductivity of the nanofluid but the inclusion of more nanoparticles resulted in particle sedimentation. The potassium‐based solution containing 0.014 vol% of the nanostructured Cu/TiO(OH)2 was therefore the targeted nanofluid that gave the best CO2 sorption/desorption performance and cyclic stability. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

A system incorporating spent bleaching clay (SBC) into the calcium looping (CaL) process has been proposed. In this paper, prepared sorbents doped with regenerated SBC and cement were tested in a bubbling fluidized bed (BFB) to examine in detail their cyclic CO2 capture capacity and attrition properties. The results revealed that the cyclic CO2 capture capacity of pellets modified by pyrolyzed SBC and/or cement showed significantly better performance than limestone, which is consistent with the thermogravimetric analyzer (TGA) results. This is due to the improvement of pore structure and enhanced sintering resistance created by adding support materials to the sorbent. The elutriation rates of the composites prepared with pyrolyzed SBC and/or cement were consistently lower than for crushed limestone. Scanning electron microscopy (SEM) images indicated that the pellets possessed higher sphericity than limestone particles, thus reducing surface abrasion. Limestone exhibited a high attrition rate (diameter reduction rate) of 10.7 μm/cycle, which could be eliminated effectively by adding regenerated SBC and/or cement. 'L‐5PC‐10CA' (85% lime/5% pyrolyzed SBC/10% cement) exhibited an attrition rate of only 7.9 μm/cycle. Based on the analysis of breakage and probability density function (PDF) for particle size distribution, it appeared that pellets without cement experienced breakage (mostly chipping and disintegration) and surface abrasion, whereas 'L‐10CA' (90% lime/10% cement) and 'L‐5PC‐10CA' mainly suffered surface abrasion, combined with some chipping. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Calcium‐based sorbents have been regarded as effective agents for capturing CO2 from industrial flue gas. Recent studies have shown that steam can enhance the carbonation performance of calcium‐based sorbents. In this paper, a CaO (001) surface was made to investigate the micro‐level mechanism of steam‐enhanced carbonation based on first principles calculations. Charge transfer and bond population were calculated to evaluate an interaction effect between adsorbates and the CaO (001) surface. Individual adsorption of CO2 and H2O was compared with binary adsorption and co‐adsorption of the two molecules on the CaO (001) surface, based on dispersion‐corrected density functional theory (DFT‐D) calculations. First, the predicted adsorption energies suggest the O‐top site is the best site. It forms carbonate‐like structure and hydroxyl‐like structure for the individual adsorption of CO2 and H2O. Binary adsorption calculations indicate that H2O is more easily adsorbed by the CaO (001) surface than CO2. The adsorption of H2O and CO2 adsorption are promoted in comparison with their individual adsorption on the CaO (001) surface. Moreover, the analysis of adsorption energies and partial density of states (PDOS) suggests that a H2O‐CaO (001) surface (CaO (001) surface that has already adsorbed H2O) is more reactive than the clean CaO (001) surface for CO2 adsorption, which further supports the idea that the steam‐enhanced mechanism is an Eley–Rideal (E–R) mechanism, which means H2O is adsorbed on the CaO surface, and then CO2 is adsorbed. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Capturing carbon dioxide (CO2) from large point sources and depositing it in a geological formation is an efficient way of decreasing CO2 concentration in the atmosphere. A comprehensive study is required to perform a safe and efficient CO2 capture and storage (CCS) project. The study includes different steps, such as selecting proper underground storage and keeping track of CO2 behavior in the storage environment. Numerical reservoir simulators are the conventional tools used to implement such an analysis. The intricacy of simulating multiphase flow, having a large number of time steps required to study injection and post-injection periods of CO2 sequestration, a highly heterogeneous reservoir, a large number of wells, etc., will lead to a complicated reservoir model. A single realization for such a reservoir takes hours to run. Additionally, a thorough understanding of the CO2 sequestration process requires multiple realizations of the reservoir model. Consequently, using a conventional numerical simulator makes the computational cost of the analysis too high to be practical. In this paper, we examine the application of a relatively new technology, the Surrogate Reservoir Model (SRM), as an alternative tool to solve the aforementioned problems. SRM is a replica of full-field reservoir simulation models. It can generate outputs in a very short time with reasonable accuracy. These characteristics make SRM a unique tool in CO2 sequestration modeling. This paper proposes developing an SRM for a CO2 sequestration project ongoing in the SACROC unit to model pressure behavior and phase saturation distributions during different time steps of the CO2 storage process. [ABSTRACT FROM AUTHOR]

Abstract: The Pearl River Mouth Basin (PRMB) is the largest petroliferous sedimentary basin in the northern South China Sea. It is near the coastal economic zone of Guangdong province where a large number of CO2 emission sources are located. Carbon dioxide enhanced oil recovery (EOR) represents an opportunity to promote offshore carbon capture, utilization and storage (CCUS) deployment because CO2 flooding offers a method to recover additional oil while simultaneously sequestering anthropogenic CO2. In this paper, a comprehensive multiparameter ‘quick look’ and potential evaluation method was proposed to screen and assess offshore CO2 EOR potential. A screening scheme for the CO2 EOR potential of reservoirs of the PRMB was also proposed using additional parameters, including reservoir properties and engineering design incorporating a dimensionless screen model and calculations. The results show that the suitability of reservoirs for CO2 EOR and storage varies and could be categorized into four priority grades. Approximately 30 of the oil reservoirs from 10 oilfields were preferentially identified by applying the screening method for reservoirs with predicted higher ultimate recovery potentials. It was predicted that 3227 × 104 t of additional oil could be produced from these reservoirs and that 3617 × 104 t of CO2 could be simultaneously stored. The sensitivity analysis shows that injection pressure (Pinj) would be more sensitive than production pressure (Pp) and well distance (L) on the CO2 EOR and storage efficiency, indicating that EOR operations with higher Pinj may improve oil production. The prospective reservoirs include those candidates with suitability grades of I and II from the Lufeng (LF) and Huizhou (HZ) oilfield clusters, where 1164 × 104 t of additional oil could be produced and 1464 × 104 t of CO2 stored with CO2 EOR. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Abstract: In this paper, the optimal investment timing decision in carbon capture and storage (CCS) is studied under different business modes. Two analytical models of the optimal CCS investment threshold are presented: one is the ‘single mode,’ meaning that CCS investment is performed only by the power producer; the other is the ‘cooperation mode,’ referring to CCS investment can be conducted by cooperation between the power producer and the CCS operator. In the single mode, this study pictures the investment decision for a CCS project based on real options theory considering uncertainties in carbon prices, government incentives, and CCS investment costs. On this basis, a model for the cooperation mode is proposed by integrating real options theory and game theory to analyze the CCS investment threshold. The results of a numerical example show that CCS investment in cooperation mode requires a much larger threshold than in single mode. Moreover, the CCS investment threshold is positively affected by carbon price volatility and the transfer payments coefficients, but negatively affected by government incentives and learning effects. These conclusions provide a theoretical foundation for decision making regarding CCS investment and related policy making. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Abstract: In this paper we aim to develop a validated device‐scale CFD model that can predict quantitatively both hydrodynamics and CO2 capture efficiency for an amine‐based solvent absorber column with random Pall ring packing. A Eulerian porous‐media approach and a two‐fluid model were employed, in which the momentum and mass transfer equations were closed by literature‐based empirical closure models. We proposed a hierarchical approach for calibrating the parameters in the closure models to make them accurate for the packed column. Specifically, a parameter for momentum transfer in the closure was first calibrated based on data from a single experiment. With this calibrated parameter, a parameter in the closure for mass transfer was next calibrated under a single operating condition. Last, the closure of the wetting area was calibrated for each gas velocity at three different liquid flow rates. For each calibration, cross validations were pursued using the experimental data under operating conditions different from those used for calibrations. This hierarchical approach can be generally applied to develop validated device‐scale CFD models for different absorption columns. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Abstract: This paper presents a materials design for tuning the CO2‐capture capability of mixed‐metal‐organic framework mmen‐(ZnxMg1‐x)2(dobpdc) using density functional theory. The structural stability of a mixed‐metal structure with respect to its parent single‐metal species was investigated via energy of mixing (ΔEmix). We found that the ΔEmix of all mixed‐metal structures are negative, signifying exothermic mixing. This then indicates that mixed‐metal structures are energetically preferable compared with their non‐interacting single‐metal species. Moreover, the magnitudes of ΔEmix of all mixed‐metal structures are lower than 1 kJ/mol, implying an ‘ideal mixing’. Density‐of‐state analysis also reveals that the electronic structures of both Mg and Zn in mixed‐metal structures are not significantly different from those in parent single‐metal species, suggesting weak chemical interaction between Mg and Zn in mixed‐metal structures. For CO2‐adsorbed mmen‐(ZnxMg1‐x)2(dobpdc), we found that the adsorption energy (Eads) is a linear function of mixing ratio (x), and does not depend on how Mg and Zn atoms are arranged in forming different mixed‐metal structures. This can be described by the weak chemical interaction between Mg and Zn in a mixed‐metal structure. Consequently, Eads can then be predicted conveniently from the mixing ratio, while the adsorption properties of parent single‐metal species can be tuned with the proposed mixed‐metal method. We then expect that the knowledge of materials design using a mixed‐metal approach presented in this work would benefit the community in providing the ability to tune CO2 capture capability efficiently in the materials studied. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Abstract: In oxy‐fuel combustion, fuel is burned using oxygen together with recycled flue gas, which is needed to control the combustion temperature. This leads to higher concentrations of sulfur dioxide and sulfur trioxide in the recycled gas, which can result in the formation of sulfuric acid and enhanced corrosion. Current experimental data on SO3 formation, reaction mechanisms, and mathematical modelling have indicated significant differences in SO3 formation between air‐ and oxy‐fuel combustion for both the wet and dry flue gas recycle options. This paper provides an extensive review of sulfur trioxide formation in air‐ and oxy‐fuel combustion environments, with an emphasis on coal‐fired systems. The first part summarizes recent findings on oxy‐fuel combustion experiments, as they affect sulfur trioxide formation. In the second part, the review focuses on sulfur trioxide formation mechanisms, and the influence of catalysis on sulfur trioxide formation. Finally, the current methods for measuring sulfur trioxide concentration are also reviewed along with the major difficulties associated with those measurements using data available from both bench‐ and pilot‐scale units. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Abstract: Part 1 of this paper presents a numerical model for non‐reactive physical mass transfer across a wetted wall column (WWC). In Part 2, we improved the existing computational fluid dynamics (CFD) model to simulate chemical absorption occurring in a WWC as a bench‐scale study of solvent‐based carbon dioxide (CO2) capture. To generate data for WWC model validation, CO2 mass transfer across a monoethanolamine (MEA) solvent was first measured on a WWC experimental apparatus. The numerical model developed in this work can account for both chemical absorption and desorption of CO2 in MEA. In addition, the overall mass transfer coefficient predicted using traditional/empirical correlations is conducted and compared with CFD prediction results for both steady and wavy falling films. A Bayesian statistical calibration algorithm is adopted to calibrate the reaction rate constants in chemical absorption/desorption of CO2 across a falling film of MEA. The posterior distributions of the two transport properties, i.e., Henry's constant and gas diffusivity in the non‐reacting nitrous oxide (N2O)/MEA system obtained from Part 1 of this study, serves as priors for the calibration of CO2 reaction rate constants after using the N2O/CO2 analogy method. The calibrated model can be used to predict the CO2 mass transfer in a WWC for a wider range of operating conditions. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The National Risk Assessment Partnership (NRAP) has developed a suite of tools to assess and manage risk at CO2 sequestration sites. The NRAP tool suite includes the Aquifer Impact Model (AIM), which evaluates the potential for groundwater impacts from leaks of CO2 and brine through abandoned wellbores. There are two aquifer reduced-order models (ROMs) included with the AIM tool, a confined alluvium aquifer, and an unconfined carbonate aquifer. The models accept aquifer parameters as a range of variable inputs so they may have broad applicability. The generic aquifer models may be used at the early stages of site selection, when site-specific data is not available. Guidelines have been developed for determining when the generic ROMs might be applicable to a new site. This paper considers the application of the AIM to predicting the impact of CO2 or brine leakage were it to occur at the Illinois Basin Decatur Project (IBDP). Results of the model sensitivity analysis can help guide characterization efforts; the hydraulic parameters and leakage source term magnitude are more sensitive than clay fraction or cation exchange capacity. Sand permeability was the only hydraulic parameter measured at the IBDP site. More information on the other hydraulic parameters could reduce uncertainty in risk estimates. Some non-adjustable parameters are significantly different for the ROM than for the observations at the IBDP site. The generic ROMs could be made more useful to a wider range of sites if the initial conditions and no-impact threshold values were adjustable parameters. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

CO2 leakage is a major concern in a geological carbon sequestration projects due to adverse environmental consequences, where the main leakage risk is identified to be along existing wells through a thick, low-permeable cap rock. To pursue robust and cost effective real-time downhole monitoring technology for CO2 sequestration wellbore integrity, a permanently deployed coaxial cable casing imager is developed and evaluated in laboratory in this paper. The prototype of the casing imager consists of evenly distributed coaxial cable strain sensors helically wrapped around the pipe. The system is deployed on both PVC pipe and steel pipe to test its performance in casing deformation monitoring, including axial compression, radial expansion, bending, and ovalization. The strain sensors are pre-stressed and then helically wrapped onto the pipe with high strength epoxy. Multiple linear variable differential transformers (LVDTs) or strain gauges are used as an independent measurement of the actual pipe deformation in comparison to the casing imager measured pipe deformation. The test results demonstrated the ability of the lab-scale casing imager prototype in real-time casing deformation monitoring, including axial compression, radial expansion, bending, and ovalization, which would prove of great value in evaluating wellbore integrity state and providing early warnings of leakage risk that will contaminate the groundwater during CO2 injection. The low cost and high robustness of the distributed coaxial cable sensors will greatly lower the downhole monitoring cost and increase the system longevity. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

An import factor for long-term storage is the integrity of wells penetrating the carbon storage reservoir. Well integrity will play a crucial role in establishing leakage risk in areas where there is a high density of existing (legacy) wells that could intersect operations including depleted petroleum fields where enhanced oil recovery or carbon storage will occur. The objective of this study was to develop methods that establish the baseline flow parameters from individual measurements in five wells in Wyoming. This paper describes the methods used to collect and analyze the data. The methods included isolation logging tools, in situ point and average permeability measurements, and laboratory tests on samples collected in the wells. The log results collected in the wells, considered in conjunction with the core measurements, indicate that interfaces and/or problems with cement placement related to eccentering provide preferential pathways for fluids, which increase the effective permeability of the barrier several orders of magnitude above that of intact cement. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Carbon capture and storage (CCS) is a technology that has been proposed to reduce what are perceived to be excessive concentrations of carbon dioxide (CO2) in the atmosphere. CCS will require the transportation of CO2 from the capture locations to the storage sites via pipelines. To ensure safety, an accurate prediction of CO2 decompression following pipeline fracture is crucial for the design and operation for these projects. A multi-phase CO2 pipeline decompression model using computational fluid dynamics (CFD) techniques is presented in this paper. The GERG-2008 equation of state (EOS) is employed to describe the properties of vaporand liquid phases. A phase change model using a mass transfer coefficient to control the inter-phase mass transfer rateis implemented into the CFD code. By varying the mass transfer coefficient, the effect of delayed nucleation on the decompression wave speed can be investigated. The proposed multi-phase CFD decompression modelis validated against the experimental data from a shock tube test. The performance of the proposed model is also compared with that of the Homogeneous Equilibrium Model (HEM). In addition, the influence of delayed nucleation on CO2 decompression characteristics is discussed and an optimum mass transfer coefficient for CO2 depressurization is obtained. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

A hierarchical model calibration and validation are proposed for quantifying the confidence level of mass transfer prediction using a computational fluid dynamics (CFD) model, where the solvent-based carbon dioxide (CO2) capture is simulated and the predicted results are compared to the corresponding bench-scale experimental data. Two unit problems with an increasing level of complexity are proposed to break down the complex physical/chemical processes of solvent-based CO2 capture into relatively simpler problems to separate the effects of physical transport and chemical reaction. This paper focuses on the calibration and validation of the first unit problem, i.e., the CO2 mass transfer across a falling ethanolamine (MEA) film in the absence of chemical reaction. This problem is investigated both experimentally and numerically using non-reactive nitrous oxide (N2O) as a surrogate for CO2. To capture motion of the gas-liquid interface, a volume of fluid method is employed with a one-fluid formulation to compute the mass transfer between the two phases. Parallel bench-scale experiments are designed and conducted to validate and calibrate the CFD models using a general Bayesian calibration approach. Two important transport parameters, Henry's constant and gas diffusivity, are calibrated to produce the posterior distributions, which will be used as input for the second unit problem to address the chemical absorption of CO2 across the MEA falling film, where both mass transfer and chemical reaction are involved. Mass transfer coefficients predicted by CFD are also compared with those predicted by the traditional/empirical correlations under both steady and wavy falling film conditions. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The ever-increasing demand for nanostructured composite materials and sustainable processes for next generation CO2 capture technologies has necessitated the need to develop novel and cost-effective synthetic routes for CO2 adsorbents based on amine and ionic liquid functionalized porous adsorbent materials with improved physico-chemical properties. The most obvious option is modification of the synthesized porous adsorbent materials by the incorporation of organic functional molecules into the pore structures of support materials, giving place to hybrid materials that combine the properties of both composites. These hybrid materials will be of great potential for practical applications, especially for post-combustion CO2 capture, owing to the increase in CO2 capturing ability and selectivity to CO2 compared to other gases in the flue gas stream. This paper reviews the diverse synthesis routes of bare porous materials and rich functionalities of porous adsorbent materials which will allow further post-modification to improve their performance in CO2 capture and increase their CO2/N2 and CO2/CH4 selectivity ratios. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Carbon dioxide (CO2) emissions from power stations and industrial plants are seen as major contributors to what is known as the greenhouse gas (GHG) effect. Carbon dioxide capture and storage (CCS) is one technology which may reduce the quantity of CO2 released into the atmosphere but development of CCS has slowed due to the absence of a viable financial model. Metering technology is a prerequisite in enabling realistic financial decisions to be taken; however, there is currently a paucity of research into the types of flowmeters which would be suitable for incorporating into CCS transportation chains. This paper reviews and summarizes existing metering technologies with a view to establishing their suitability for measuring high mass flowrate, supercritical CO2. Open channel, differential pressure, velocity measurement, direct mass measurement, and electrical, magnetic, thermal, sonic, and radiation technologies are all considered. The challenges associated with each generic group are described, and recommendations made regarding the practicalities of using particular types of meter for CO2 transport in CCS applications. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The Area of Review (AoR) under the US Environmental Protection Agency's (EPA) Class VI CO2 injection permit is defined as the region surrounding the geologic carbon sequestration (GCS) project where underground sources of drinking water (USDWs) may be endangered. Estimation of the AoR is based on the calculated reservoir pressurization due to CO2 injection and the associated potential to lift saline water into potable groundwater aquifers through open flow paths (e.g. wells) assuming the system is hydrostatic. In cases where the storage reservoirs are not initially hydrostatic, and in particular where they are overpressured, AoR estimation methods need to be altered. In this paper, we present and apply an approach to evaluating potential endangerment of USDW based on comparing brine leakage through a hypothetical open flow path in a no-injection scenario and brine leakage in a CO2-injection scenario. We present six possible ways to normalize injection-related leakage relative to no-injection leakage. We calculate leakage using semi-analytical solutions for single-phase flow and model reservoir pressurization and flow up (single) leaky wells located progressively farther from the injection well. For an example case of relative overpressure and using an injection-rate-based approach, results show 50-60% larger open-well-leakage rates for wells located at 2 km and 10% increase for wells located at 10 km from the injection well relative to the no-injection case. If total brine leakage is considered, the results depend strongly on the assumed pre-injection to post-injection time frames and on the methods of normalization used to calculate incremental leakage. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd [ABSTRACT FROM AUTHOR]

CO2 geo-sequestration into saline aquifers and an enhanced geothermal system (EGS) are two of the most effective solutions to reduce CO2 emissions into the atmosphere. The significance of thermal-hydrological-mechanical-chemical (THMC) interactions is well identified in these two processes: fluid and heat flow, solute transport within a three-phase mixture; stresses and displacements related to geomechanical effects; non-isothermal effects on fluid properties and reaction processes; and equilibrium and kinetics of fluid-rock and gas-rock chemical interactions. In this paper, a novel numerical model is developed to describe the THMC processes mathematically. One mean stress formulation, which is simplified from the geomechanical equations with full stress tensor, is employed to solve mean stresses and displacements. Chemical equilibrium and kinetics are considered to quantitatively simulate geochemical reaction associated with solute transport. A sequentially coupled computational framework is proposed and used to solve reactive transport of water, gas components, and chemical species in subsurface formation with geomechanics. It is designed to keep a generalized computational structure for different THMC processes. A practical case with complex chemical compositions is presented to analyze the THMC processes quantitatively on the coupled effects of geochemistry and geomechanics during CO2 geo-sequestration. In addition, a practical EGS case is presented to address the mutual effects of each THMC process quantitatively, especially the mutual effects of stress and chemical reaction. Heat transfer affects mean stress and geochemical reactions; mean stress impacts the solute transport and successive chemical reactions; and geochemical reactions are shown to have significant impact on the mean stress, pressure, or temperature. [ABSTRACT FROM AUTHOR]