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Direct air capture (DAC) offers a potential solution for capturing carbon dioxide directly from the atmosphere, making it a promising technology in the field of negative carbon solutions. However, its current stage is characterized by high costs and a lack of maturity, placing it in the early phases of commercial application. To address these challenges, this paper introduces a novel cost-sharing mechanism specifically designed for DAC equipment within the context of carbon emission management in power systems. The aim is to facilitate both DAC capacity configuration and cost allocation. We begin by dissecting the operational principles of DAC and reviewing ongoing demonstration projects. We then pioneeringly devises a unified operational model (UOM) for DAC, which integrates electricity and carbon considerations seamlessly. Following this, we introduce an enhanced version of the carbon emission flow (CEF) theory, customized for DAC deployment. This sets the stage for the design of a DAC-specific carbon capture cost-sharing mechanism. Building on these foundations, we develop a meticulous DAC capacity planning model. This is accompanied by a cost allocation methodology based on the Shapley value framework. The ultimate goal is equitable cost allocation among stakeholders and optimized DAC capacity planning. Case studies validate the efficacy of both the proposed model and the cost allocation methodology. The insights from this study contribute to advancing theoretical frameworks for carbon capture technologies and have practical implications for engineering designs in real-world implementation. • A novel cost-sharing mechanism is designed for DAC deployment. • A unified operational model (UOM) is developed for DAC. • Liquid solvent DAC is utilized for large-scale applications. [ABSTRACT FROM AUTHOR]

Green hydrogen produced by the power-to-gas facilities can be blended into the natural gas system, which is a promising way toward a low-carbon energy system. This paper proposes a laddered carbon trading-based operation model for integrated electricity–gas system with hydrogen injection considering the complex combustion properties of hydrogen mixed gas turbine (HMGT). The power-to-hydrogen, hydrogen methanation, and carbon emission processes are combined with the methane reactor and the flexible carbon capture, utilization and storage facility. Then, a HMGT combustion model based on the system thermodynamics and chemical reaction kinetics is introduced. The piecewise linearization technique is adopted to describe the varying hydrogen production efficiency of electrolysis system. Moreover, an energy balance based quasi-steady-state model to deal with the calorific value problem of the gas mixture is proposed and solved by an advanced sequential cone programming algorithm. Case studies are carried on a 30-bus-20-node system and a 197-bus-171-node practical system in Northwest China to illustrate the effectiveness of the proposed model. • Proposing a laddered carbon trading-based operation model for IEGS with hydrogen injection. • Proposing a simplified HMGT operation model based on the system thermodynamics and chemical reaction kinetics. • Proposing an energy balance-based quasi-steady-state model and solved by an iterative sequential convex programming algorithm. [ABSTRACT FROM AUTHOR]

The advance of air-conditioning systems has become a popular topic, due to its huge energy consumption and the increasing demand of improving indoor air quality. Although various approaches have been proposed for humidity, temperature and CO 2 control, their coordination has not yet been studied. In this study, the technologies of desiccant dehumidification, indirect evaporative cooling and direct CO 2 capture are innovatively integrated in an air-conditioning system, by which their respective advantages can be exerted and limitations can be compensated. Under a base working condition with ambient temperature of 35 °C and relative humidity of 80%, the overall coefficient of performance of the integrated system reaches 0.93, with an improvement of 53.3% against a conventional scheme. The integrated system is more efficient at higher crowdedness. With occupant number from 2 to 22 in a room, the advantage of the integrated system ranges from 50.7% to 85.6%. Parametric studies on different indoor and outdoor conditions are conducted, indicating that the energy efficiency advantage is more outstanding at higher indoor temperature, lower ambient temperature and lower ambient humidity. The factors of economic, environment and health are discussed, where the integrated system exhibits superiority against conventional systems and existing studies as well. Approaches are raised to improve the performance and promote future studies. The results in this paper contribute to providing a scheme for the integration of different technologies and enlightening insights for the advance of air-conditioning systems for the sake of air quality improvement, energy saving and emission reduction. • An integrated air-conditioning system is proposed for improving energy efficiency. • Different technologies for temperature, humidity and CO 2 control are coordinated. • 53.3% improvement on energy efficiency is obtained for base working condition. • Parametric analyses indicate advantage for the integrated system at most cases. • Economic and environmental issues are discussed compared with existing studies. [ABSTRACT FROM AUTHOR]

• A full-scale CO 2 pipeline burst test to generate model validation data. • Validated CFD models for CO 2 dispersion simulations. • Comprehensive studies of CO 2 dispersion due to pipeline fracture. • Determination of consequence distances due to full-scale pipeline fracture. Transportation of Carbon Dioxide (CO 2) via high-pressure pipelines from source to storage site forms an important link in the Carbon Capture and Storage (CCS) chain. To ensure the safety of the operation, it is necessary to develop a comprehensive understanding of the consequences of possible pipeline failure. CO 2 is a hazardous substance and an accidental release may lead to catastrophic damage. This paper describes an experimental investigation of the dispersion of CO 2 in the atmosphere in a full-scale burst test of a pipeline containing high-pressure dense phase CO 2. The experiment was carried out to simulate a CO 2 pipeline failure in the real world. The test rig consisted of a buried 85 m long, 610 mm diameter pipeline test section connected at either end to 116 m long reservoirs. An explosive charge detonated at test section half-length initiated a rupture in the pipe wall top surface, releasing the high-pressure contents. The atmospheric dispersion of the CO 2 following the explosive release was measured. The paper also describes Computational Fluid Dynamics (CFD) simulations of the dispersion of CO 2 following the release. The CFD models were validated against the experimental data. The models were then extended to estimate the consequence distances related to CO 2 dispersion following failure of longer pipelines of various diameters under different wind speeds and directions. Comparison of the results with prior studies was carried out. [ABSTRACT FROM AUTHOR]

This paper investigates the viability of CO 2 storage in geological formations, including depleted hydrocarbon reservoirs applying 3-dimensional seismic and well data of the Niger Delta region as a case study for CO 2 sequestration, which represents an essential initiative for the reduction of greenhouse gas emissions. Different theoretical and experimental studies from literature on CO 2 sequestration in geological formations across the world, including the Niger Delta, are reviewed. The Niger Delta basin has a high potential for CO 2 sequestration, and this indication is shown through the review of research papers undertaken outside and within the basin, which reveal the presence of massive hydrocarbon fields, lateral continuity of reservoir, reservoir-seal pairs, faults, and traps, developed hydrocarbon fields, appropriate reservoir depth. The gaps identified from the review of various research studies are analyzed to form the basis of a future research investigation for capturing, removing, and storing CO 2 in depleted hydrocarbon reservoirs and other geological formations. The authors deduced that accurate injection pressure, rate, and depth estimation are critical factors for CO 2 sequestration and need to be thoroughly investigated. • Niger Delta depleted oil/gas reservoir CO 2 capture, utilization & storage reviewed • Potential issues relating to CO 2 sequestration and modeling in Niger Delta noted • Appropriate CFD solution should combine static and dynamic model. • Research gaps identified and future directions recommended. [ABSTRACT FROM AUTHOR]

This paper assesses the separation of CO 2 from ambient air from a technical and economic standpoint. Reducing CO 2 emissions and their sequestration from the atmosphere is vital to counteract ongoing climate change. The most promising technological options for CO 2 separation are first identified by reviewing the literature and comparing the most important technical and economic parameters. The results point to amines/imines as adsorbing agents to separate CO 2 from ambient air. A system layout is then designed and a technical analysis conducted by solving mass and energy balances for each component. An economic analysis is then performed by applying a specifically-developed model. The total energy demand of the system discussed here is calculated as 3.65 GJ/t CO2 . This high energy demand mainly derives from the system-specific implementation of two compressors that compress air/CO 2 and overcome the pressure losses. The second-law efficiency calculated ranges of 7.52–11.83 %, depending on the option of heat integration. The costs of avoiding CO 2 emissions vary between $ 824 and 1333/t CO2 , depending on the energy source applied. The results of this work present higher values for energy demand and costs compared to other values stated in literature. The reasons for this deviation are often insufficient and overoptimistic assumptions in other literature on the one hand, but also relate to the specific system design investigated in this paper on the other. Further case studies reveal that enormous land requirements and investments would be needed to reduce potential CO 2 quantities in the atmosphere to contemporary levels. A comparison between CO 2 removal from the atmosphere and carbon capture and storage technology for coal power plants shows that this technology is not yet able to economically compete with carbon capture and storage. Furthermore, the impact of CO 2 separation on the production costs of industrial commodities like cement and steel demonstrates that CO 2 removal from the atmosphere is not yet a viable alternative to solving the climate change problem. In the long-term, CO 2 separation from ambient air may still play an important role in the sequestration of CO 2 from diluted and dispersed sources, as the technology has the potential for significant further development and optimization. [ABSTRACT FROM AUTHOR]

Methanol is a rational candidate for long-term energy storage in renewable energy systems, and efficient energy conversion as well as carbon cycling are the keys to its successful application. The use of oxy-fuel combustion in methanol engine is promising to achieve high thermal efficiency and carbon recovery. Large proportion of carbon dioxide (CO 2) dilution is usually used in oxy-fuel combustion to accommodate the thermal load, but it also brings challenges in thermal efficiency improvement. In this paper, the effects of CO 2 dilution on the performance of methanol spark ignition (SI) engines are investigated using one-dimensional thermodynamics simulations and chemical kinetics calculations. It is demonstrated that the net indicated thermal efficiency (ITE net) decreases from 40.5% to 31% under 0.16 oxygen fraction compared to the traditional air operation. Increasing the oxygen fraction can alleviate the temperature drop in the cylinder due to the high specific heat capacity of CO 2 meanwhile it also reduces the exhaust energy. Based on thermodynamics process analysis of internal combustion engine(ICE), the energy taken away by the exhaust gas accounts for about 55% and the recovery of exhaust gas energy is crucial to improving the engine thermal efficiency. Therefore, reforming methanol with waste heat and high compression ratio (CR) are adopted. Under the constraint of 150 bar peak combustion pressure, the maximum net indicated thermal efficiency with reforming (ITE net , r) of the oxy-fuel methanol engine is 38.6%, which is only 1.9% lower than that of the baseline condition but allows cost-effective CO 2 capture since the exhaust only consists of CO 2 and water (H 2 O). Fig. 1 zero‑carbon renewable energy storage and utilization system based on CO 2 cycle and methanol fuel. [Display omitted] • ITE with CO2 dilution is ∼9% lower than air operation. • >50% energy is exhausted for oxy-fuel engine. • Fuel reforming with exhaust heat can effectively improve ITE. • With fuel reforming and high CR, the ITE can be recovered to the air operation level. [ABSTRACT FROM AUTHOR]

This paper examines the potential for synergistic benefits of co-utilizing three waste streams of pinewood, spent fluid catalytic cracking (sFCC) catalyst, and waste CO 2 via thermochemical conversion. For this, a lab-scale fixed-bed semi-batch scale reactor facility is utilized to investigate the impact of using sFCC catalyst and its reusability on the syngas output, quality, and energy during pyrolysis and CO 2 -assisted gasification of pinewood 800–900 °C. Results are reported on the pyrolysis and CO 2 -assisted gasification of pinewood, as well as the impact of using sFCC catalyst and its reusability on syngas output, quality, and energy. Incorporating the catalyst without direct contact with the solid feedstock resulted in syngas enhancement and reusing this catalyst led to <5 wt% char formation from the gasification at 900 °C. The addition of FCC catalyst improved the total CO yield and its rate with an increase in temperature due to improved cracking of volatiles and their simultaneous reforming using CO 2. In addition, the syngas and energy yields decreased when the catalyst was in direct contact with the solid biomass which also acted as a barrier between the feedstock and gasifying agent, leading to lower CO production. Catalytic gasification at 900 °C using CO 2 provided combustible gas output that was 1.4 times higher than the feedstock mass which suggests that at least 0.4 g of CO 2 consumption for combustible gases, such as H 2 and CO. This points to the synergistic potential in co-utilization of waste streams of biomass, spent FCC catalyst, and CO 2 that provided not only waste management and energy recovery but also energy efficient carbon sequestration. Temperature programmed oxidation of the char residue left from the pyrolysis and gasification tests and coke that forms on the sFCC catalyst revealed conversion of about 0.1 g of the feedstock to coke that was significantly more resistant to oxidation than the char formed. • Investigated synergistic utilization of pinewood, CO 2 and spent FCC catalysts. • Examined pyrolysis and CO 2 -assisted gasification of pinewood and sFCCs at 800–900 °C. • Avoiding catalyst feedstock contact resulted in syngas enhancement. • CO 2 consumption of at least 0.4 g/g feedstock was converted into combustible syngas. • Reusing sFCCs for gasification resulted in coke deposition led reduction in activity. [ABSTRACT FROM AUTHOR]

The escalating CO 2 emissions in recent years underlined the need for advanced Carbon Capture and Utilization (CCU) technologies. This context has spurred the exploration of novel materials for promoting CCU efficiency, among which electrospun nanofibers have emerged as a promising candidate. Electrospinning coupled with various post-treatment (such as heat-treating, in-situ growth, selective removal, etc.) offers a versatile approach to fabricate diverse nanofibers, including polymeric, carbonaceous, metallic, and composite fibers, with tunable surface morphologies and chemical properties. This paper provides a comprehensive review of electrospun nanofibers in CCU processes, including adsorption, membrane separation and absorption, electrochemical and photo-electrochemical reduction, thermal catalytic hydrogenation, and more. Each CCU technology is examined in depth to cover the recent research achievements with a specific focus on the contributions of electrospun nanofibers. Lastly, a critical discussion and a list of potential future research directions for this evolving field are provided. • Latest electrospun nanofiber-based CCU technologies are thoroughly reviewed. • Electrospinning enables creating various nanofibers, aiding multiple CCU technologies. • Provide critical discussion and future directions for this evolving research field. [ABSTRACT FROM AUTHOR]

Deploying negative emission technologies has become crucial for limiting the global temperature rise to approximately 1.5 °C above preindustrial levels. DAC technologies are being explored as one of the prospective options. These technologies have been thoroughly investigated as a potential project to capture CO 2 emissions and provide purified air, natural gas, or fuel oil. An applied approach, on the other hand, was not taken into consideration while evaluating the influence that this technology has on emissions. For this reason, British Columbia provides a substantial chance to examine emissions that were produced after the DAC actions were put into place in 2015. In this study, the difference-in-differences methodology is employed for the very first time to compare the emissions that are produced by the transport sectors in British Columbia with those emitted by other provinces in Canada. The role that GDP and population play in the release of emissions is also taken into consideration in this paper. Based on the research results, it can be observed that the implementation of DAC initiatives has yielded notable effects. Evidence shows that the DAC effort has led to an average reduction of 0.08 in logarithmic CO 2 emissions in the transport sector. By accounting for GDP and population, the empirical results indicate that DAC technology reduced CO 2 emissions in British Columbia compared to provinces without DAC facilities. DAC initiatives are expected to become increasingly prevalent between the mid-2030s and 2040s. Overall policy implications suggest that there is a need for DAC technologies to collaborate with alternative mitigation technologies, or alternative technologies should collaborate with DAC technologies that are more efficient to achieve the targeted goals in a short time. • The study offers empirical evidence of DAC technology's impact, providing insights beyond theoretical conjectures. • Based on the research results, it can be seen that the implementation of DAC facilities has yielded notable effects. • DAC technology in British Columbia has led to a significant and negative impact on CO 2 emissions compared to other provinces without DAC facilities. • The study highlights the differential effectiveness of DAC across transport sectors, pointing toward a need for tailored implementation strategies. [ABSTRACT FROM AUTHOR]

this work addresses the methodological challenges of undertaking techno-economic assessments of very early stage (technology readiness level 3–4) CO 2 capture technologies. It draws lessons from a case study on CO 2 capture from a natural gas combined cycle with exhaust gas recycle and electric swing adsorption technology. The paper shows that also for very early stage technologies it is possible to conduct techno-economic studies that give a sound first indication of feasibility, providing certain conditions are met. These conditions include the availability of initial estimates for the energy use of the capture technology, either from bench scale measurements, or from rigorous process models, and the possibility to draw up a generic (high level) equipment list. The paper shows that for meaningful comparison with incumbent technologies, the performance of very early stage technologies needs to be projected to a future, commercial state. To this end, the state of the art methods have to be adapted to control for the development and improvements that these technologies will undergo during the R&D cycle. We call this a hybrid approach. The paper also shows that CO 2 capture technologies always need to be assessed in sympathy with the CO 2 source (e.g. power plant) and compression plant, because otherwise unreliable conclusions could be drawn on their feasibility. For the case study, it is concluded that electric swing adsorption is unlikely to become economically competitive with current technologies, even in a highly optimised future state, where 50% of the regeneration duty is provided by LP steam and 50% by electricity: the net efficiency of an NGCC with EGR and optimised ESA (49.3% LHV ; min–max 45.8–50.4% LHV ) is lower than that of an NGCC with EGR and standard MEA (50.4% LHV ). Also, investment and operational costs are higher than MEA, which together with ESA’s lower efficiency leads to an unfavourable levelised cost of electricity: 103 €/MWh (min–max 93.89–117.31 €/MWh) for NGCC with ESA, versus 91 €/MWh for NGCC with MEA. [ABSTRACT FROM AUTHOR]

National Development and Reform Commission and National Energy Administration have launched a series of policies on closing down small coal-power units, in order to reduce energy consumption and pollutant emissions. However, it is hard to change current situation in the short term since coal is still the domain source of power generation in China. Aiming at efficiently closing down the small power units, to create a power generation planning model with minimized costs needs to take both economic and technical aspects into account. In this paper, eight types of coal-fired generators are classified into three categories: Inefficient units; Efficient units; and Low-carbon units. This paper has developed a power generation planning model under multiple constraint conditions such as coal-power demand, total installed capacity, and carbon capture etc. Also, the model involves variable costs of CCS technology and contingency payments at the same time. This paper has applied the power generation planning model into China’s coal-fired power industry research during the period from 2016 to 2030. The results show that because the coal-power demand ends up with a drop following a rise, the total costs thereby shows a same trend. During the planning period, the fuel costs and the operation and maintenance costs decrease most obviously. Given the installed capacity, compared with the increase in the number of efficient units, the number of inefficient units shows a gradual decrease. The number of low-carbon units displays a slight increase. Since low-carbon units can capture and store 90% of their carbon emissions, the total carbon emissions from coal-fired power industry have significantly been reduced in their operation year. Thus, it is imperative to develop high efficiency and low-carbon units as they will be the major contributors to the sustainable development of the coal-fired power industry. [ABSTRACT FROM AUTHOR]

To achieve the targets in the Paris Climate Change Agreement, carbon capture, utilization and storage (CCUS) will be one of the critical carbon mitigation technologies. For China, the biggest carbon emitter with coal-dominated energy structure, CCUS is expected to play more and more important roles for carbon emissions reduction. This paper looks at a method for designing a pipeline network system for large-scale CO2 capture, utilization, and storage (CCUS) in China. On the basis of performing a moderately significant literature review of past papers and models dating back to the early 2000’s, a updated multi-stage mixed integer programming (MIP) model for carbon source and sink matching (SSM) in ChinaCCUS DSS (Decision Support System) is developed. The Jing-Jin-Ji (Beijing–Tianjin–Hebei) region suffering from increasingly serious air pollution is chose as a case study to address the SSM issue with application of the updated model. The modeling results show that around 2200 km pipeline with investment of around $1.6 billion needed to be built to transport the cumulative sequestrated emissions of 1620 Mt CO 2 in the planning period of 2020–2050. Compared to the single-stage programming, the multi-stage programming could result to better pipeline connectivity. [ABSTRACT FROM AUTHOR]

Achieving carbon neutrality is probably one of the most important challenges of the 21st century for our societies. Part of the solution to this challenge is to leverage renewable energies. However, these energy sources are often located far away from places that need the energy, and their availability is intermittent, which makes them challenging to work with. In this paper, we build upon the concept of Remote Renewable Energy Hubs (RREHs), which are hubs located at remote places with abundant renewable energy sources whose purpose is to produce carbon-neutral synthetic fuels. More precisely, we model and study the Energy Supply Chain (ESC) that would be required to provide a constant source of carbon-neutral synthetic methane, also called e-NG (electric Natural Gas) or e-methane (electric methane), in Belgium from an RREH located in Morocco. To be carbon neutral, a synthetic fuel has to be produced from existing carbon dioxide (CO 2) that needs to be captured using either Direct Air Capture (DAC) or Post Combustion Carbon Capture (PCCC). In this work, we detail the impact of three different carbon sourcing configurations on the price of the e-methane delivered in Belgium. Our results show that sourcing CO 2 through a combination of DAC and PCCC is more cost-effective, resulting in a cost of 146 €/MWh for e-methane delivered in Belgium, as opposed to relying solely on DAC, which leads to a cost of 158 €/MWh. Moreover, these scenarios are compared to a scenario where CO 2 is captured in Morocco from a CO 2 emitting asset that allow to deliver e-methane for a cost of 136 €/MWh. • Model energy supply chain from Morocco to Belgium for electric methane; • Explore three CO2 sources for electric methane synthesis; • Analyse the pros and cons of each CO2 source on price and energy efficiency. [ABSTRACT FROM AUTHOR]

Direct air carbon capture (DAC) is a promising negative carbon technology to balance unavoidable carbon emissions from distributed sources. Deploying DAC into the integrated renewable energy system provides an effective way to achieve regional carbon neutrality. Developing a reasonable configuration approach for the DAC-based integrated energy system (IES) is the premise to ensure the stable, flexible, economic and net-zero carbon operation. However, DAC system captures CO 2 from the air through adsorption and desorption with a much lower respond speed than other energy generation, conversion and storage equipment in the IES. Meanwhile, the CO 2 adsorption/desorption rate varies significantly with time, making the energy consumption of DAC does not fully correspond to the amount of CO 2 being captured. Conventional steady-state IES configuration methods fail to reflect such characteristics of the DAC, which may lead to non-optimal or even infeasible configurations. To this end, this paper develops a configuration-oriented dynamic model for the DAC process to correctly reflect the energy consumption characteristics under given internal operating conditions and the variations of the CO 2 adsorption/desorption rate over time. The DAC model is embedded into the configuration framework of the DAC-based IES, formulating a novel configuration approach that optimizes the investment, operation and maintenance, carbon reduction and renewables utilization performance. The optimal capacity of DAC and the corresponding time periods for adsorption, desorption and shutdown operation in typical scenario are determined, revealing the coordinated manner of DAC system with other devices within the IES. Case studies demonstrate the effectiveness of the proposed configuration approach, which can meet the carbon neutral target with the lowest economic cost. Further comparisons also verify the advantages of flexible operation of the DAC system to achieve better coordination with renewable generations and more efficient CO 2 capture. [Display omitted] • Configuration-oriented dynamic model is developed for the S-TVSC based DAC process. • Configuration approach is proposed for DAC-IES considering dynamic behavior of DAC. • Differences in characteristics during CO 2 adsorption and desorption are considered. • The proposed approach achieves carbon neutral target with the lowest economic cost. • Flexible operation of DAC promotes renewable integration and CO 2 capture efficiency. [ABSTRACT FROM AUTHOR]

The production of precipitated calcium carbonate (PCC) from steel slag has been proposed as a potential method of simultaneously reducing the CO 2 emissions from the steelmaking process and turning its waste stream into a valuable product. On average the production of one ton of steel results in two tons of CO 2 emissions and 600 kg of slag. Globally, more than 400 Mt of steel slag are produced annually. If all the slag were used for the production of PCC, 64 Mt CO 2 could be utilized and 145 Mt of calcium carbonate would be produced. In 2014 the research group Energy Engineering and Environmental Protection at Aalto University in Finland has designed, constructed and tested the world’s first mineral carbonation pilot plant test facility that converts steel slag and CO 2 into PCC. In batch mode the pilot plant can handle up to 20 kg of solid steel slag and 190 L of liquid solvent, and it can produce about 10 kg of calcium carbonate. The solvent can be regenerated and reused in the calcium extraction stage, which makes the process economically more feasible. Almost 80% of the calcium in the slag was extracted, while more than 70% of the CO 2 was utilized and converted into PCC. In high temperature carbonation tests, ammonia gas was detected from the flue gases. At 60 °C more than 2 vol.% of NH 3 was detected in the flue gas, and at 50 °C it was 0.65 vol.%, while at 45 °C the NH 3 concentration in the flue gas was only 0.11 vol.%. To avoid ammonia evaporation, aragonite PCC can be produced at 45 °C by optimizing the CO 2 flow rate. The paper presents the process design as well as the early results achieved from the pilot plant. The paper also presents technical challenges that occurred during the scale-up work and experiments. [ABSTRACT FROM AUTHOR]

Around 21% of the world’s power production is based on natural gas. Energy production is considered to be the significant sources of carbon dioxide (CO 2 ) emissions. This has a significant effect on the global warming. Improving power plant efficiency and adding a CO 2 capture unit into power plants, have been suggested to be a promising countermeasure against global warming. This paper presents a new insight to the application of energy efficient technologies in retrofitting natural gas combined cycle (NGCC) power plants with CO 2 capture. High fidelity models of a 420 MW NGCC power plant and a CO 2 capture plant with CO 2 compression train have been built and integrated for 90% capture level. These models have been then validated by comparisons with practical operating data and literature results. The novelty of the paper is to propose optimal retrofitting strategies to minimize the efficiency penalty caused by integrating carbon capture units into the power plant, including (1) implementing heat transfer intensification techniques to increase energy saving in the heat recovery steam generator (HRSG) of the power plant; (2) extracting suitable steam from the HRSG to supply the heat required by the capture process, thus on external heat is purchased; (3) employing exhaust gas recirculation (EGR) to increase the overall energy efficiency of the integrated process, which can benefit both power plant (e.g. increasing power plant efficiency) and capture process (e.g. reducing heat demands). Compared with the base case without using any integrating and retrofitting strategies, the optimal solution based on the proposed approaches can provide sufficient heat to CO 2 capture process, and keep the same power generation. The optimal solution shows that, the flue gas flow-rate is reduced 33% in the inlet of CO 2 capture process, heat demand in CO 2 capture decreases 4.3%, heat output from the power plant increases from 0 MW to 133 MW, and more than 22% of profit is obtained in the integrated system. This demonstrates the validity and efficiency of the proposed approaches in retrofitting existing NGCC power plants with CO 2 capture. [ABSTRACT FROM AUTHOR]

• Net primary productivity is introduced to build carbon footprint pressure index. • Discussing driving factors of carbon footprint pressure in 60 sample countries. • Technological progress restricts the increase of global carbon footprint pressure. • Optimizing the IPAT decoupling approach. • Carbon footprint pressure in non-OECD countries is rising rapidly. Carbon sequestration capacity of vegetation plays an important role in global carbon emission reduction. Based on vegetation carbon sequestration, this paper establishes a carbon footprint pressure index to evaluate the carbon footprint pressure in 60 sample countries, and discusses the driving factors that influence carbon footprint pressure in various countries through IPAT equation and Logarithmic Mean Divisia Index decomposition approach. The results indicate that the global carbon footprint pressure shows an upward trend from 2000 to 2015, mainly owing to population growth and rapid socioeconomic development; technological progress has a certain inhibitory effect on the rise of carbon footprint pressure. Furthermore, the overall carbon footprint pressure in the Organisation for Economic Co-operation and Development (OECD) countries shows a downward trend, while the carbon footprint pressure in non-OECD countries is rising, even exceeding the economic growth rate, which is probably related to the transfer of a large number of implied carbon emissions from OECD countries to non-OECD countries. [ABSTRACT FROM AUTHOR]

This paper aims at evaluating the best allocation of potential biomethane generation for the decarbonization of the transport system, presenting a case study in Italy. The country has some peculiar features, such as several operating biogas plants, additional potential feedstock for biogas/biomethane generation, a well-developed natural gas network and established relevant natural gas uses in different final sectors, including transport. Based on current estimates for sustainable biomethane potential by 2030, ranging from 2.3 to 7.6 billion cubic meters depending on the scenario, the analysis compares technologies for the generation, distribution and final use of biomethane. The results of the analysis confirm the potential interesting contribution of biomethane in decarbonizing the Italian transport system: a billion cubic meters of biomethane can lead to 2.33–4.37 Mt CO 2 e savings, depending on the feedstock mix and the application. On a national basis, annual climate emission savings in 2030 range from 10.0 to 26.7 Mt CO 2 e , depending on the scenario. Additional 3.1–8.1 Mt CO 2 of emissions can be avoided if the CO 2 captured during the biomethane upgrading can be stored or reused. The proposed methodology could be used to extend the analysis to other countries, and to the European context. • We analyze the climate emissions of biomethane for different supply chains. • We evaluate the effects of feedstock, distribution strategy and electricity mix. • The results confirm the important role of biomethane for transport decarbonization. • We discuss the best allocation in transport segments based on emissions savings. • We compare alternative biomethane scenarios for Italy in 2030. [ABSTRACT FROM AUTHOR]

With the transition towards a decarbonized society, energy system integration is becoming ever more essential. In this transition, the energy vector hydrogen is expected to play a key role as it can be produced from (renewable) power and natural gas with carbon capture and storage and utilized in a plethora of applications and processes across sectors. Despite global hydrogen demand reaching 94 million tonnes in 2021, still less than 0.7% of it is supplied by low-emission hydrogen. Moreover, to date hydrogen production is mostly located in close proximity to where it is used. In order to link future production and demand sites, it is planned to re-purpose existing natural gas and expand dedicated hydrogen pipelines. During the early stages of ramping up the hydrogen sector (2020s and early 2030s), however, blending natural gas with hydrogen for joint pipeline transmission has been suggested. Against this background, this paper studies hydrogen blending from a modeling perspective, both in terms of the implications of considering (or omitting) technical modeling details and in terms of the potential impact on the ramp-up of the hydrogen sector. To this end, we present a highly modular and flexible integrated sector-coupled energy system optimization model of the power, natural gas, and hydrogen sectors with a novel gas flow formulation for modeling blending in the context of steady-state gas flows. A stylized case study illustrates that hydrogen blending has the potential to initiate and to facilitate the ramp-up of the hydrogen sector under certain assumptions, while omitting the technical realities of gas flows – particularly in the context of blending – can result in suboptimal expansion planning not only in the hydrogen, but also in the power sector, as well as in an operationally infeasible system. • Integrated sector-coupled energy system model for power, natural gas, and hydrogen. • Natural gas and hydrogen blending in the context of steady-state gas flows. • Transmission expansion planning and operation requires steady-state gas flows. • Blending can facilitate the initial ramp-up of the hydrogen sector. • Level of energy system integration impacts utilization of electrolyzers. [ABSTRACT FROM AUTHOR]

The transition to a deeply decarbonized energy system requires coordinated planning of infrastructure investments and operations serving multiple end-uses while considering technology and policy-enabled interactions across sectors. Electricity and natural gas (NG), which are vital vectors of today's energy system, are likely to be coupled in different ways in the future, resulting from increasing electrification, adoption of variable renewable energy (VRE) generation in the power sector and policy factors such as cross-sectoral emissions trading. This paper develops a least-cost investment and operations model for joint planning of electricity and NG infrastructures that considers a wide range of available and emerging technology options across the two vectors, including carbon capture and storage (CCS) equipped power generation, low-carbon drop-in fuels (LCDF) as well as long-duration energy storage (LDES). The model incorporates the main operational constraints of both systems and allows each system to operate under different temporal resolutions consistent with their typical scheduling timescales. We apply our modeling framework to evaluate power-NG system outcomes for the U.S. New England region under different technology, decarbonization goals, and demand scenarios. Under a global emissions constraint, ranging between 80%–95% emissions reduction compared to 1990 levels, the least-cost solution relies significantly on using the available emissions budget to serve non-power NG demand, with power sector using only 14%–23% of the emissions budget. Increasing electrification of heating in the buildings sector results in greater reliance on wind and NG-fired plants with CCS and results in similar or slightly lower total system costs as compared to the business-as-usual demand scenario with lower electrification of end-uses. Interestingly, although electrification reduces non-power NG demand, it leads to up to 24% increase in overall NG consumption (both power and non-power) compared to the business-as-usual scenarios, resulting from the increased role for CCS in the power sector. The availability of low-cost LDES systems reduces the extent of coupling of electricity and NG systems by significantly reducing fuel (both NG and LCDF) consumption in the power system compared to scenarios without LDES, while also reducing total systems costs by up to 4.6% for the evaluated set of scenarios. • A decarbonized joint electric power and natural gas model is developed. • Impact of electrification, coupling constraints, and new technologies are analyzed. • Joint planning with cross-sectoral emission limit is the most cost-effective pathway. • Increased use of carbon capture technologies can increase overall NG consumption. [ABSTRACT FROM AUTHOR]

Electric vehicles (EVs) are widely recognized as promising solutions to reduce carbon emissions from the transportation sector. The rapid proliferation of EVs intensifies the interdependency between the power distribution system (PDS) and transportation system (TS). This paper proposes a distributed low-carbon economic dispatch scheme for the integrated power and transportation system (IPTS). Carbon emissions from the TS are quantified by a carbon dioxide calculation model, and the emissions from the PDS are determined by the electricity generation of fossil-fueled generators and the carbon reduction of carbon capture and storage (CCS) devices. An integrated model reformulation method is employed to transform the original non-convex model into a tractable one. Then a distributed solution method based on the spectral penalty parameter based adaptive alternating direction method of multipliers (SPPA-ADMM) is developed to protect the privacy of the PDS and TS. The reformulated model is solved iteratively, and the penalty parameter of the SPPA-ADMM is adjusted adaptively to improve the convergence performance of the method. Numerical results on three test systems demonstrate the effectiveness of the proposed scheme in achieving low-carbon economic dispatch of IPTS. Moreover, case studies validate the superiority of the SPPA-ADMM based distributed solution method in computation performance. • A low-carbon economic dispatch scheme for integrated power and transportation system is proposed. • An integrated model reformulation method is designed to transform the non-convex model into a tractable one. • The SPPA-ADMM based distributed solution method is used to protect the privacy and improve computation efficiency. • Effects of the proliferation of EVs on costs and carbon emissions are discussed in sensitivity analysis. [ABSTRACT FROM AUTHOR]

As the world's largest producer and consumer of coal, coal phaseout is critical for China to achieve carbon neutrality and contribute to global decarbonization. Here, utilizing the Global Change Assessment Model, this paper simulates China's coal phaseout pathways at the sectoral level between 2015 and 2060, considering the deployment of carbon capture and storage (CCS). The results show that China's coal consumption peaks at 96.4 Exajoules (EJ) in approximately 2020 and needs to decrease to 10.9 EJ by 2060 to achieve carbon neutrality. Specifically, the power sector bears the most significant proportion of responsibility, as its coal consumption must fall to 1.4 EJ by 2060, which is approximately 97.2% lower than the peak in 2020. The industrial sector is next and needs to decrease consumption to 9.2 EJ of coal in 2060, which is a reduction of 32.3 EJ below the 2020 level. Electricity will replace coal as the dominant energy source in the industrial sector after 2040. However, a portion of feed coal will remain in the industry for a long time. Among the industrial subsectors, the steel sector needs to put significant pressure on efforts to phase out coal, followed by the cement and nitrogen fertilizer sectors. In 2060, these three sectors will consume 5.7 EJ of coal, accounting for 64.1% of the total coal consumption in the industrial sector. The deployment of coal-CCS is one of the alternatives to achieve carbon neutrality and ensure smooth coal phaseout. Under the carbon neutrality scenario, the annual deployment of coal-CCS needs to exceed 0.13 EJ from 2025 to 2045, with a peak at 3.3 EJ in 2045. • China's coal phaseout pathway is assessed in the carbon neutrality scenario (CNS). • Coal consumption needs to drop to 10.9 EJ in 2060 to achieve carbon neutrality. • The power sector's coal will decrease to 97.2% below the peak by 2060 in the CNS. • The industry will pass the power sector as the top coal consumer by 2045 in the CNS. • The deployment of coal-CCS will peak at 3.3 EJ after 2045 in the CNS. [ABSTRACT FROM AUTHOR]

Under the high attention of the international community to CO 2 emissions, the capture utilization and storage (CCUS) and the CO 2 hydrogenation fuel production have become two popular directions, especially for the combination of the two processes. In this paper, the production of liquid fuels via the methanol synthesis pathway in an integrated CCUS system based on Aspen Plus models was studied. The NH 3 -CO 2 -H 2 O absorption was used to capture CO 2 and hydrogen was provided by water electrolysis using renewable energy sources. A two-stage reactor with a recirculating stream was specified for the process of CO 2 hydrogenation to synthesize methanol, and the liquid fuel dimethyl ether (DME) was reproduced by dehydrating methanol (Power-to-Liquid). The amount of absorbent used for the carbon capture process was determined and the yield differences due to the number of cycles in the intermediate methanol synthesis reaction were analyzed. It is possible to convert 4.15 t of CO 2 per tonne of DME produced at the mass material balance of the process. The optimization of the heat exchange network and the energy requirements for the total process were evaluated. It is calculated that the energy involved in producing 1 ton of DME in the process model is 176 GJ. The analysis of the overall process and the evaluation of models could provide options for the possibility of CCUS engineering application. [Display omitted] • An integral process model converts CO 2 to liquid fuels by methanol synthesis. • Treatment options are proposed for emissions that accumulate in the cycle of the process. • The model offers energy requirement assessment for possible engineering applications. [ABSTRACT FROM AUTHOR]

• Lab synthesis of various adsorbents for adsorption-based PCC. • Bench and pilot-scale experimental studies of adsorption-based PCC. • Molecular simulation of adsorbents for post-combustion carbon capture. • Process modelling\simulation and techno-economic analysis of adsorption-based PCC. • Achievements, challenges and future prospect in adsorption-based PCC. Adsorption-based post-combustion carbon capture is a promising emerging technology for capturing CO 2 emissions from fossil-fueled power plants due to the ease of adsorbent regeneration in comparison with solvent-based technologies. To increase its competitiveness, research efforts have focused on the development of new adsorbent materials and processes. This paper presents a state-of-the-art review of such efforts, focusing on lab synthesis and characterization of adsorbent materials, (carbon capture) experimental studies, molecular simulation, process modelling\simulation and techno-economic analysis. Most experimental studies on adsorption-based post-combustion capture are at bench scale. Just a few experimental studies are at pilot scale. There are currently no commercial deployment of adsorption-based post-combustion capture technology. This review paper points out challenges encountered in these experimental investigations utilizing different adsorbent materials, limiting its commercial deployment. These gaps in experimental investigations need further research especially in the chemical modification of the adsorbent materials to increase the adsorption capacity. Molecular simulation of adsorbents and process modelling\simulation of carbon capture processes are cost-effective and time efficient approaches for the assessment of adsorbents' CO 2 capture performance. The review also highlighted the need for more research in the model development of adsorbent materials at molecular scale and the model development of adsorption-based post-combustion process adopting new reactor configurations to further reduce the cost of CO 2 capture. [ABSTRACT FROM AUTHOR]

This paper estimated the cost curve of energy saving and CO 2 emissions reduction in China's iron and steel sector. Forty-one energy saving technologies which are widely used or popularized are selected, their investments, operation costs, energy savings and CO 2 abatement are collected and the data in 2010 are taken as a baseline. Then energy conservation supply curve and CO 2 conservation supply curve under two different discount rates are calculated in the paper. These 41 technologies result in a saving contribution of 4.63 GJ/t and a CO 2 abatement contribution of 443.21 kg/t. Cost-effectiveness of technologies was analyzed based on the fuel price and an estimated CO 2 price. When comparing the result with the promoted technologies during the 12 th five-year-plan, we found that some promoted technologies are not cost-effective in current situation. Three scenarios are set through changing the diffusion rate of technologies and the share of BOF and EAF, based on this energy saving potentials of technologies in 2020 and 2030 are forecasted. At the same time, we compared the change of the CSC depending on the year and the energy saving potentials in three scenarios of 2020 and 2030, respectively. [ABSTRACT FROM AUTHOR]

Abstract: In densely populated countries there is a growing and compelling need to use underground for different and possibly coexisting technologies to produce “low carbon” energy. These technologies include (i) clean coal combustion merged with CO2 Capture and Storage (CCS); (ii) last-generation nuclear power or, in any case, safe nuclear wastes disposal, both “temporary” and “geological” somewhere in Europe (at least in one site): Nuclear wastes are not necessarily associated to nuclear power plants; (iii) safe natural gas (CH4) reserves to allow consumption also when the foreign pipelines are less available or not available for geopolitical reasons and (iv) “low-space-consuming” renewables in terms of Energy Density Potential in Land (EDPL measured in [GWh/ha/year]) as geothermics. When geothermics is exploited as low enthalpy technology, the heat/cool production could be associated, where possible, to increased measures of “building efficiency”, low seismic risks building reworking and low-enthalpy heat managing. This is undispensable to build up “smart cities”. In any case the underground geological knowledge is prerequisite. All these technologies have been already proposed and defined by the International Energy Agency (IEA) Road Map 2009 as priorities for worldwide security: all need to use underground in a rational and safe manner. The underground is not renewable in most of case histories [10,11]. IEA recently matched and compared different technologies in a unique “Clean Energy Economy” improved document (Paris, November 16–17, 2011), by the contribution of this vision too (see reference). In concert with “energy efficiency” improvement both for plants and buildings, in the frame of the “smart cities” scenarios, and the upstanding use of “energy savings”, the energetic planning on regional scale where these cities are located, are strategic for the year 2050: this planning is strongly depending by the underground availability and typology. Therefore, if both literature and European Policy are going fast to improve the concept of “smart cities” this paper stresses the concept of “smart regions”, more strategic than “smart cities”, passing throughout a discussion on the synergic and conflicting use of underground to produce energy for the “smart regions” as a whole. The paper highlights the research lines which are urgent to plan the soundest energy mix for each region by considering the underground performances case by case: a worldwide mapping, by GIS tools of this kind of information could be strategic for all the “world energy management” authorities, up to ONU, with its Intergovernmental Panel on Climate Change (IPCC), the G20, the Carbon Sequestration Leadership Forum (CSLF) and the European Platforms such as the “Zero Emissions Fossil Fuel Power Plants” (EU-ZEP Platform), the Steel Platform, the Biomass Platform too. All of these organizations agree on the need for synergistic and coexistent uses of underground for geological storage of CO2, CH4, nuclear waste and geothermic exploitation. The paper is therefore a discussion of the tools, methods and approaches to these underground affecting technologies, after a gross view of the different uses of underground to produce energy for each use, with their main critical issues (i.e. public acceptance in different cases). The paper gives some gross evaluation for the Lazio Region and some hints from the Campania Region, located in Central Italy. Energy Density Potential in Land (EDPL), is calculated for each renewable energy technology (solar, wind, geothermal) highlighting the potentiality of the last. Why the Italian case history among the densely populated countries? on the Italian territory is hard to find suitable areas (mostly if greenfields) to use the own underground, with respect to other European countries, due to the presence of seismotectonic activity and many faulted areas characterized by Diffuse Degassing Structures (DDSs, which are rich in CO2 and CH4). In this cases, public acceptance must be facilitated by the concerted efforts of researchers, universities, NGOs and policy-makers. [Copyright &y& Elsevier]

Abstract: Cement industry is one of the largest carbon emitting industrial sectors. It is responsible for about 5% of anthropogenic CO2 in the world. Therefore, it is a relevant industrial sector for CO2 emission regulation strategies. Bearing in mind the importance of cement industry in Croatia, and because of the fact that Croatia will soon become an EU member state, the present paper analyses the potential to reduce CO2 emission in the Croatian cement industry. There are several measures that can reduce CO2 emissions from the cement manufacturing process: the use of waste heat as an alternative source of energy; CO2 capture and storage technologies; reduction of clinker to cement ratio; the use of alternative and biomass fuels; the use of alternative raw materials; an energy efficient combustion process. The most energy efficient technology for cement manufacturing today is the use of a rotary kiln together with a multi-stage preheater and a calciner. Since the use of cement calciners is a relatively new technology, further improvement of their operating conditions is still needed. This paper also highlights the results of research in the field of computational fluid dynamic (CFD) simulations that are used for the investigation of process and combustion emissions. The above mentioned measures together with numerical investigations can reduce the effect of cement manufacturing in Croatia on the environment and can make it more competitive with cement manufacturers from the EU. [Copyright &y& Elsevier]

Abstract: The application of Carbon Capture and Storage (CCS) technology to energy-intensive processes is starting to attract attention, presenting an opportunity for developing multi-user CO2 transportation networks. Recognising that most industrial facilities have not been designed with CCS in mind, this paper begins by looking at the practical issues associated with retrofitting CCS to industrial facilities. It then explores the technical and legal issues associated with building a CO2 network. This is followed by an analysis of the costs involved. Having identified the key issues, a case study from North East England is presented as an example of what is possible in an area of high CO2 emissions. The paper concludes by considering the issues involved in sizing a CO2 network which can evolve to meet future needs and linking that to the development of policy. [Copyright &y& Elsevier]

• Proposed the concept of negative emission hybrid renewable energy system (NEHRES). • Developed the decision-support framework for the optimal design of the NEHRES. • Integrated first-principle and data-driven methods for the system modeling. • Conducted a case study on the design of the system for a standalone rural island. • Validated the economic and carbon sequestration feasibilities of the NEHRES. To tackle the increasing global energy demand the climate change problem, the integration of renewable energy and negative emission technologies is a promising solution. In this work, a novel concept called "negative emission hybrid renewable energy system" is proposed for the first time. It is a hybrid solar-wind-biomass renewable energy system with biochar production, which could potentially provide energy generation, carbon sequestration, and waste treatment services within one system. The optimization and the conflicting economic and environmental trade-off of such system has not yet been fully investigated in the literature. To fill the research gap, this paper aims to propose a stochastic multi-objective decision-support framework to identify optimal design of the energy mix and discuss the economic and environmental feasibilities of a negative emission hybrid renewable energy system. This approach maximizes energy output and minimizes greenhouse gas emissions by the optimal sizing of the solar, wind, combustion, gasification, pyrolysis, and energy storage components in the system. A case study on Carabao Island in the Philippines, which is representative of an island-mode energy system, is conducted based on the aim of achieving net-zero emission for the whole island. For the island with a population of 10,881 people and an area of 22.05 km2, the proposed optimal system have significant negative emission capability and promising profitability with a carbon sequestration potential of 2795 kg CO 2-eq /day and a predicted daily profit of 455 US$/day. [ABSTRACT FROM AUTHOR]

• CO 2 dilution produces lowest temperature increase under MILD combustion mainly due to chemical effect. • Negative heat release region disappears under MILD combustion in regardless of diluents. • CO 2 is preferable than both N 2 and H 2 O for establishing MILD combustion regime. • CO formation increases in CO 2 -diluted MILD combustion from CO 2 + CH 2 (S) ↔ CH 2 O + CO. • C 2 H 2 formation is extremely low under MILD combustion, suggesting low sooting tendency. To deepen the understanding of combining moderate or intense low-oxygen dilution (MILD) combustion with oxy-fuel combustion for enhancing flame stability while realizing carbon capturing and storage, this paper presents a numerical study of methane MILD combustion in three atmospheres, i.e.: O 2 /N 2 , O 2 /CO 2 and O 2 /H 2 O, with both computational fluid dynamics (CFD) and kinetic calculation approaches. Firstly, CFD predictions for the three conditions were performed following a systematic validation of the numerical method against experimental measurement from methane/air MILD combustion in a laboratory-scale closed furnace. Subsequently, kinetic calculations with a well-stirred reactor model was used to quantitatively identify the operating ranges of MILD combustion in the three atmospheres for methane. Moreover, the kinetic calculation provided additional insight into the fuel oxidation pathway. The results reveal that replacing N 2 with either CO 2 or H 2 O would help to establish MILD combustion mode from the viewpoint of lower temperature increase, due to both physical and chemical property discrepancies among the diluents. Specifically, the chemical effect and physical effect are responsible to the lower temperature rise for CO 2 -diluted case and H 2 O-diluted case, respectively. Inside the MILD combustion furnace, the negative heat release region disappears in regardless of atmospheres, indicating the eliminated fuel pyrolysis process under MILD combustion mode. Detailed analysis of the flame structure suggests that the combustion regimes inside the furnace in the three atmospheres are all in well-stirred combustion regime, and CO 2 -diluted case has the most extended reaction zone. Kinetic calculation indicates that CO 2 or H 2 O dilution would result in a wider MILD combustion operating range compared to N 2 dilution, while it is more pronounced for CO 2. These observations all imply that MILD combustion will be more easily established with CO 2 dilution than N 2 or H 2 O dilution. However, higher CO formation is obtained in O 2 /CO 2 , forcing more attention to be paid on CO emission under CO 2 -diluted MILD combustion. Furthermore, the hydrocarbon recombination route is negligible under MILD combustion in spite of the atmospheres, implying lower sooting tendency as compared with conventional combustion. [ABSTRACT FROM AUTHOR]

Highlights • Both liquid–solid and liquid–liquid phase change solvents critically reviewed. • Various mechanisms triggering phase separations in solvents elucidated in detail. • Advantages and challenges of phase change processes for CO 2 capture assessed. • Gaps between state-of-the-art and ideal solvents analyzed. • Insights into research needs regarding solvents and desired properties provided. Abstract Carbon Capture and Storage is regarded as an important component in a portfolio of low-carbon energy technologies for mitigating climate change. Absorption technologies are presently the most available and effective approach for post-combustion CO 2 capture. However, state-of-the-art amine-based absorption technologies incur intensive energy use, as high as 3 times the thermodynamic minimum, thus resulting in prohibitively high costs. Solvents are key to the performance of absorption technologies. Recently, a new class of solvents, phase change solvents, have attracted growing interest due to their potential to substantially reduce energy use for CO 2 capture. Phase change solvents are homogeneous (single-phase) solvents under normal conditions, but undergo a phase transition into a heterogenic (two-phase) system, triggered by changes in polarity, hydrophilicity, ionic strength, or hydrogen bond strength to form a CO 2 -lean liquid phase and a CO 2 -enriched liquid or solid phase. This review paper first examines different mechanisms that trigger phase separations in solvents. A comprehensive list of phase change solvents reported in the recent literature, including those subject to chemically or thermally triggered phase changes, non-aqueous or aqueous systems, and those forming either a CO 2 -enriched solid or a liquid phase are provided and their physiochemical properties for CO 2 capture are discussed. Enabled by phase change solvents, different variants of CO 2 absorption processes have been developed and tested in laboratory or pilot scales over the past ten years. The status of such emerging processes is summarized and their advantages and challenges for post-combustion CO 2 capture are reviewed and commented. Solvent properties such as CO 2 loading capacity, lean- and rich-phase partition, desorption pressure, absorption kinetics, viscosity, stability, and volatility are critical for both CO 2 capture performance and scalability. Gaps between state-of-the-art and ideal solvents are analyzed, and insights into the research needs such as solvent structure–property–performance relations, computational solvent design, ideal vapor-liquid equilibrium behavior, and integration of capture processes with post-combustion emission sources are provided. [ABSTRACT FROM AUTHOR]

Highlights • A Bayesian network model is used to generate scenarios for a new energy technology. • Scenarios consider technical and sociopolitical factors and their interactions. • Application to CCS predicts that improvements in both sets of factors are necessary. Abstract The formulation and use of scenarios is now a fundamental part of national and global efforts to assess and plan for climate change. While scenario development initially focused on the technical dimensions of energy, emissions and climate response, in recent years parallel sets of shared socio-economic pathways have been developed to portray the values, motivations, and sociopolitical and institutional dimensions of these systems. However, integrating the technical and social aspects of evolving energy systems is difficult, with transitions dependent on highly uncertain technological advances, social preferences, political governance, climate urgency, and the interaction of these elements to maintain or overcome systemic inertia. A broad range of interdisciplinary knowledge is needed to structure and evaluate these processes, many of which involve a mix of qualitative and quantitative factors. To structure and facilitate the necessary linkages this paper presents an approach for generating a plausible range of scenarios for an emerging energy technology. The method considers influences among technical and social factors that can encourage or impede necessary improvements in the performance and cost of the technology, as well the processes affecting public acceptance and the establishment of governance structures necessary to support effective planning and implementation. A Bayesian network is used to capture relationships among the technological and socioeconomic factors likely to affect the probability that the technology will achieve significant penetration and adoption. The method is demonstrated for carbon capture and storage (CCS): a potential technology on the pathway to deep decarbonization. A preliminary set of expert elicitations is conducted to illustrate how relationships between these factors can be estimated. This establishes a prior or baseline network that can be subsequently analyzed by choosing either optimistic or pessimistic assumptions for respective groups of technical and social variables, identifying sets of key factors that limit or encourage successful deployment. [ABSTRACT FROM AUTHOR]

Graphical abstract Highlights • Dynamic simulation of entire CFPP-PCC process. • Dynamic behavior analysis for the integrated CFPP-PCC process. • Coordinated predictive control design for the integrated CFPP-PCC system. • Interactions between CFPP and PCC systems taken into account in control design. • Three operating modes proposed for the CFPP-PCC unit. Abstract Solvent-based post-combustion CO 2 capture (PCC) provides a promising technology for the CO 2 removal of coal-fired power plant (CFPP). However, there are strong interactions between the CFPP and the PCC system, which makes it challenging to attain a good control for the integrated plant. The PCC system requires extraction of large amounts of steam from the intermediate/low pressure steam turbine to provide heat for solvent regeneration, which will reduce power generation. Wide-range load variation of power plant will cause strong fluctuation of the flue gas flow and brings in a significant impact on the PCC system. To overcome these issues, this paper presents a reinforced coordinated control scheme for the integrated CFPP-PCC system based on the investigation of the overall plant dynamic behavior. Two model predictive controllers are developed for the CFPP and PCC plants respectively, in which the steam flow rate to re-boiler and the flue-gas flow rate are considered as feed-forward signals to link the two systems together. Three operating modes are considered for designing the coordinated control system, which are: (1) normal operating mode; (2) rapid power load change mode; and (3) strict carbon capture mode. The proposed coordinated controller can enhance the overall performance of the CFPP-PCC plant and achieve a flexible trade-off between power generation and CO 2 reduction. Simulation results on a small-scale subcritical CFPP-PCC plant developed on gCCS demonstrates the effectiveness of the proposed controller. [ABSTRACT FROM AUTHOR]

Highlights • Local CO 2 emission factors of China's coal chemical products are published. • The total CO 2 emission from China's coal chemical industry was 607 Mt in 2015. • The spatial disparity of CO 2 emission from China's coal chemical industry is great. • CO 2 emission from modern coal chemical industry is predicted to be 417 Mt in 2020. • Carbon capture, utilization, and storage has great potential to reduce its emission. Abstract As the largest producer of coal chemical products in the world, China faces tremendous pressure to reduce its carbon emission. An accurate quantification of the carbon dioxide (CO 2) emission of coal chemical industry in China is therefore necessary. However, due to the variety of coal chemical products and limitations of CO 2 emission factors, the total CO 2 emission of coal chemical industry has yet to be determined. In this study, local CO 2 emission factors of coal chemical products in China are published based on first hand data from twenty-three coal chemical enterprises and the total CO 2 emission of China's coal chemical industry is extrapolated. The provincial-level spatial distribution of the CO 2 emission of coal chemical industry is presented to assist the government in identifying key emission reduction areas. Additionally, scenario analysis of CO 2 emission for China's modern coal chemical industry in 2020 is conducted to determine whether the development of the modern coal chemical industry will have a significant impact on future CO 2 emission, as well as the effect of carbon capture, utilization and storage technologies on the reduction in carbon emission. The estimate shows that the total CO 2 emission of the coal chemical industry in 2015 was 607 million tonnes (Mt), accounting for approximately 5.71% of China's total CO 2 emission. The figure is higher than the total annual CO 2 emission of a country such as Canada (555 Mt) or Brazil (486 Mt). Quantifying the emission of the coal chemical industry is therefore critical to understand the global carbon budget. The spatial distribution shows that Shandong, Inner Mongolia and Shanxi release one-third of the coal chemical industry's total CO 2 emission. Considering the development of the modern coal chemical industry, its CO 2 emission is predicted to be as high as 416.52 million tonnes in 2020. However, the CO 2 emission could be reduced by 317.98 million tonnes when carbon capture, utilization and storage are applied to process and energy systems simultaneously. This paper quantifies the CO 2 emission of the coal chemical industry in China for the first time, identifies key chemical products and the provinces in which they are produced, explores the carbon reduction potential by scenario analysis, and provides specific data to support the assessment of effective CO 2 reduction policy. [ABSTRACT FROM AUTHOR]

Graphical abstract Figure X: Micro-encapsulated sorbent (MECS) consist of a CO 2 -absorbing material inside a polymer capsule shell (shown in bottom left). A model is developed in this paper in order to extrapolate lab-scale experimental results on MECS to predict absorber sizes. First, a model for CO 2 absorption in an individual capsule is fitted to experimental loading curves collected on 0.1-gram samples of MECS exposed to CO 2 (shown on left). Next, the capsule model is validated against data collected on 25 g of capsules fluidized in an absorber column (shown bottom center). The model is then optimized for a 1 MWe coal testing facility (fluidized bed design shown on top). Finally, the model is used to size an absorber for a 500 MWe coal plant (modular packed bed design shown bottom right). Highlights • Model is developed for micro-encapsulated sodium carbonate solution in absorber beds. • Modeled absorbers are similar in size to state-of-the-art amine absorbers for coal plant. • Energy penalty of sodium carbonate capsule absorber is as low as 11.8% of plant power. Abstract Micro-Encapsulated CO 2 Sorbents (MECS) are a promising technology for post-combustion carbon capture because they enable slow-reacting solvents like carbonate solution to compete with traditional amine solvents. Before scaling up MECS for pilot testing, modeling is needed to design a MECS absorber and quantify its size and energy penalty. To that end, a multi-scale model for MECS- that ranges from a single capsule to a 500 MWe power plant absorber- is developed and presented here. First, the individual capsule model is developed and fitted to experimental CO 2 absorption data collected on a 0.1 g sample of capsules filled with sodium carbonate solution. This capsule model is then validated against data collected on a 25 g batch of capsules exposed to flue gas conditions in a fluidized column. This model is then scaled up to represent two absorber designs: a multi-stage, counter-flow fluidized bed and a hollow, cylindrical packed bed with radial gas flow. These two absorber bed models are first optimized for a 1 MWe pilot-scale absorber, and then optimized for a 500 MWe coal plant. This model predicts absorbers of similar dimensions and smaller energy penalties than previously modeled absorbers filled with amine solvent capsules. Furthermore, it is demonstrated here that a few reasonable improvements to capsule design would result in absorber sizes and energy penalties lower than those of a benchmark amine solvent tower. These results demonstrate that micro-encapsulated carbonate solution can compete with faster-acting amine solvents for post-combustion carbon capture. [ABSTRACT FROM AUTHOR]

Highlights • A calcium looping process with energy storage for peak shaving in a coal-fired power plant was proposed and assessed. • The boiler always operates at MCR to ensure the highest boiler efficiency is achieved. • The proposed system can reduce the net efficiency penalty from 6.96% LHV to 5.98% LHV. • The proposed system with cryogenic O 2 storage has a wide peaking capability. Abstract CO 2 capture and peak shaving are two of the main challenges for coal-fired power plants in China. This paper proposed a calcium looping (CaL) combustion system with cryogenic O 2 storage for simultaneous flue gas decarbonization and peak shaving for a 1000 MW e coal-fired power plant. The philosophy of this concept is that: (1) the boiler always operates at maximum continuous rating (MCR) to ensure the highest boiler efficiency; (2) during off-peak times, the excess energy output from coal combustion is used to provide heat for the calciner and produce pure oxygen for energy storage; (3) at peak times, the O 2 produced is used to capture CO 2 in the flue gas via the CaL process and reduce the CO 2 abatement penalty; and (4) any excess O 2 is treated as a by-product for commercial utilization. The whole system was simulated in Aspen Plus® which shows that the net electric efficiency of the proposed system without cryogenic O 2 storage system is 35.52% LHV (LHV, low heating value), while that of the conventional CaL system is 34.54% LHV. The proposed system can reduce the methane consumption rate by 38.5 t/h when methane is used as fuel in the calciner. Including the cryogenic O 2 storage system, the peaking capability of the proposed system can range from 534.6 MW e to 1041 MW e. Correspondingly, the net electric efficiency is improved from 18.98% LHV to 36.97% LHV. Increasing the rate of oxygen production can reduce the minimum net power output to lower than 534.6 MW e. The peaking capability can be regulated by the rate of oxygen production where excess oxygen serves as a byproduct. [ABSTRACT FROM AUTHOR]

Highlights • Carbon capture utilization storage (CCUS) supply chain problem is studied. • All stages for carbon capture, transport and storage are taken into account. • The model is applied to a realistic case study of Northeast China. • Scenarios assessing toward different CO 2 reduction level are implemented. • The intermediate sites for CCUS supply chain lessen transportation and total costs. Abstract In recent years, several strategies have been developed and adopted in a bid to diminish the carbon dioxide (CO 2) released into the atmosphere. Carbon capture, utilization and storage (CCUS) system is one of the options. In this paper, we develop a CCUS supply chain superstructure by introducing more comprehensive transportation routes as well as the resultant system deployment schemes. A mixed integer linear programming (MILP) model is proposed to optimize the strategic CCUS deployment in Northeast China by making simultaneous selection of emission sources, capture facilitates, CO 2 pipeline, intermediate transportation sites, utilization and storage sites. The CCUS cost includes the cost of flue gas dehydration, CO 2 capture, transportation and injection, and revenue from CO 2 utilization through enhanced oil recovery (CO 2 -EOR). The overall network is economically optimized over a 20 years' life span to provide the geographic distribution and scale of capture, utilization and sequestration sites as well as the transportation routes for different scenarios. The results suggest that it is economic feasible to reduce 50% of the current CO 2 emissions from the stationary sources at a total annual cost $2.30 billion accompanied with $0.77 billion of revenue generated annually through CO 2 -EOR. Overall, the optimal CCUS supply chain network correspond to a net cost of $23.53 per ton of CO 2. The results are compared with source-sink model and it can be observed that the total annualized net cost is reduced from $1.62 billion to $1.53 billion and the transportation cost are reduced from $0.27 billion to $0.19 billion. [ABSTRACT FROM AUTHOR]

[Display omitted] • Simulations provide reliable hydrogen production data for estimation of key indicators. • Hydrogen produced by electrolysis has larger EROEI than natural gas-based routes. • Green hydrogen appears the best solution in terms of LCOH for small-scale local production. • Green hydrogen performs better in terms of GWP, while other impacts should be improved. • TCO of hydrogen-fuelled vehicles is larger than diesel ones mainly due to purchase cost. Hydrogen is a versatile energy carrier and storage medium that may be employed in a variety of applications. According to the industrial processes used for its production, hydrogen may be labelled using different colours: (i) grey hydrogen, produced from natural gas using steam methane reforming (SMR), (ii) blue hydrogen, like the grey one, but with carbon capture and storage (CCS), (iii) green hydrogen, produced by water electrolysis using electricity from renewable sources only, (iv) "grid" hydrogen, produced by electrolysis using grid electricity. In this study, process simulation is used to solve material and energy balances, as well as to estimate capital and maintenance costs for each technology investigated. Then, process simulation outcomes are used to estimate three key performance indicators focusing on sustainability issues: the Energy Return on Energy Invested (EROEI), the Levelized Cost of Hydrogen (LCOH) and the Life Cycle Assessment (LCA). With reference to the case study of the Trieste port in Italy, the potential of synthesizing and utilizing hydrogen to fuel transportation activities within a port is examined. Based on the daily hydrogen consumption in fuel cells installed on locomotors and trucks, the design of the different processes considered is carried out, as well as their comparison in terms of EROEI, LCOH, and LCA. Furthermore, LCA and Total Cost of Ownership (TCO) evaluations for various hydrogen-fueled vehicles within the port are presented and compared to diesel-fueled ones to determine the impact of fuel-cell vehicles during operations. Results show that EROEI of hydrogen produced by electrolysis is larger than that produced by SMR with or without CCS. The LCOH for grey hydrogen is of the same order of magnitude of that of green or grid ones. The hydrogen compression step to 300 bar impacts on both energetic and economic performances. LCA indicates that the Global Warming Potential (GWP) of green hydrogen is at least half with respect to blue hydrogen, however other impact categories are less favourable. On the other hand, the TCO of hydrogen-fueled vehicles is higher than that of diesel-fueled ones, mainly because of the higher purchase costs. It is concluded that the methodology proposed in this paper, based on the evaluation of indicators at the design stage, is suitable for comparing hydrogen production processes. In addition, it is a powerful tool for policy decision-makers in defining the strategies for the development of hydrogen-based transport systems in port operations. [ABSTRACT FROM AUTHOR]

Highlights • Multi-phase CFD model for decompression simulation of CO 2 mixtures. • Incorporation of GERG-2008 EOS into CFD code for decompression modelling. • Predicted decompression wave speed validated by measurements in shock tube experiments. • Investigation of effects of delayed bubble formation on the decompression wave speed. Abstract Carbon Capture and Storage (CCS) is widely seen as an effective technique to reduce what is perceived as excessive CO 2 concentration in the atmosphere. This technique includes transporting CO 2 from source point to the storage site, usually through high-pressure pipelines. In order to ensure safe transport (i.e. to prevent the contents from being released into the atmosphere), it is important to estimate the required pipe toughness in the design stage. This requires an accurate prediction of the speed of the ‘decompression wave’ in the fluid, which is created when the high-pressure fluid escapes into the ambient. In this paper, a multi-phase Computational Fluid Dynamics (CFD) model is presented to simulate the decompression of high-pressure pipelines carrying CO 2 mixtures. A ‘real gas’ Equation of State (EOS), the GERG-2008 EOS, is incorporated into the CFD code to model the thermodynamic properties of the fluid in both liquid and vapour states. The non-equilibrium liquid/vapour transition is modelled by introducing ‘source terms’ for mass transfer and latent heat. The model is validated through simulation of a ‘shock tube’ test. A ‘time relaxation factor’ is used to control the inter-phase mass transfer rate. The measured decompression wave speed is compared with that predicted using different values of the time relaxation factor. It is found that the non-equilibrium phase transition has a significant influence on the decompression wave speed. Also, the effects of delayed bubble formation and of various impurities on the decompression wave speed are investigated. [ABSTRACT FROM AUTHOR]

This paper provides pathways of the carbon content of electricity extracted from the Intergovernmental Panel on Climate Change’s fifth Assessment Report scenarios database. It demonstrates three policy-relevant aspects of the carbon content of electricity that are implicit in most integrated assessment model results but under-discussed in academia and the policy debate. First, climate stabilization at any level from 1.5 °C to 3 °C requires the carbon content of electricity to decrease quickly and become almost carbon-free before the end of the century. As such, the question for policy makers is not whether to decarbonize electricity but when and how to do so. Second, decarbonization of electricity is still possible and required if some of the key zero-carbon technologies—such as nuclear power or carbon capture and storage—turn out to be unavailable. Third, progressive decarbonization of electricity is part of every country’s cost-effective means of contributing to climate stabilization. The pathways of the carbon content of electricity reported here can be used to benchmark existing decarbonization targets, such as those set by the European Energy Roadmap or inform new policies in other countries. They can also be used to assess the desirable uptake rates of electric and plug-in hybrid vehicles, electric stoves and heat pumps, industrial electric furnaces, or other electrification technologies. [ABSTRACT FROM AUTHOR]

Rotating packed beds (RPBs) are a compact and potentially more cost-effective alternative to packed beds for application in solvent-based carbon capture process. However, with concentrated monoethanolamine (MEA) (up to 70–80 wt%) as the solvent, there is a question as to whether intercooler is needed for the RPB absorbers and how to design and operate them. This study indicates that the liquid phase temperature could rise significantly and this makes it essential for RPB absorber to have intercoolers. This is further assessed using a validated RPB absorber model implemented in gPROMS ModelBuilder® by evaluating the impact of temperature on absorption performance. Different design options for RPB absorber intercoolers (stationary vs rotary) were introduced and their potential sizes and associated pressure drop were evaluated based on a large scale flue gas benchmark of a 250 MWe Natural Gas Combined Cycle Power Plant. This paper addresses a fundamental question about intercooling in RPB absorber and introduces strategies for the intercooler design. [ABSTRACT FROM AUTHOR]

The carbon capture by adsorption (CCA) is regarded as an available engineering technology because of its low energy-consumption, easy to control, and possible integration with renewable energy. The recent advances in CCA research comprises mainly about the performance improvement of adsorbents, design and optimization of engineering process. However, considering the time-consuming and intensive funding required for experimental investigation, the numerical simulation has been widely applied in CCA. In numerical simulation field of CCA, the adsorption process is commonly simplified into mathematical models group comprised of adsorption kinetics model, the adsorption equilibrium model, pressure drop model and heat transfer model. However, few studies’ focus is to provide a detailed review of the research methodology of mathematical modeling in CCA simulation. This paper presents a pathway map on CCA mathematical modeling through literature review and case study. An overview of model screening and modeling method of CCA is provided in the review part. This part also provides a short guided tour on how to combine the fundamental models about heat and mass transfer together to form a model group for various application scenarios in CCA. Then the pathway map on CCA modeling, which is summarized based on the review, is applied to a case study. In this part, the adsorption of CO 2 /N 2 mixtures on activated carbon under the conditions of high temperature and low pressure is numerically investigated based on the established models. The performance indicators comprise gas temperature, mole fraction, and adsorbate amount of the fixed bed, are applied in the evaluation performance of CCA. Based on the proposed methodology, the CCA modeling demonstrates a more fluent design process relative to the real physical scenario, with a possible access to further optimization. Particularly, the simulation results showed that the optimized dimensionless velocity for the highest utilization efficiency of the fixed bed can be obtained and thus is proposed as 1.2–1.4 for the most suitable feed velocity to fit different size of fixed bed and different types of adsorbents for the engineering design. [ABSTRACT FROM AUTHOR]

Understanding the thermophysical properties for mixtures of CO 2 and hydrocarbons at reservoir conditions is very important for the correct design and optimization of CO 2 -enhanced oil recovery and carbon storage in depleted oil or gas fields. In this paper, we present a comprehensive thermodynamic study of the prototype system (CO 2  + n-heptane) comprising highly-accurate measurements of the saturated-phase densities, compressed-fluid densities, and bubble and dew points at temperatures from 283 K to 473 K and pressures up to 68 MPa over the full range of composition. We use these results to examine the predictive capability of two leading thermodynamic models: the Predictive Peng-Robinson (PPR-78) equation of state and a version of the Statistical Associating Fluid Theory for potentials of the Mie form, known as SAFT-γ Mie. Both of these models use group contribution approaches to estimate interaction parameters and can be applied to complex multi-component systems. The comparison shows that both approaches are reliable for the phase behavior. Neither model is entirely satisfactory for density, with each exhibiting absolute average relative deviations (AARD) from the experimental data of about 4% for the saturated-phase densities and 2% for the compressed-fluid densities; however, SAFT-γ Mie is found to be much more accurate than PPR-78 for the compressibility, with an overall AARD of 6% compared with 18% for PPR-78. [ABSTRACT FROM AUTHOR]

Biogas upgraded to biomethane can provide a renewable gaseous transport fuel and is one of the proposed solutions in meeting the renewable energy supply in transport targets set under the EU Renewable Energy Directive. The upgrading process for biogas involves the removal of CO 2 . Amine scrubbing is one traditional method of upgrading that is applied due to its low methane slippage and its capability to provide a high purity renewable methane product. However, new technologies such as power to gas (P2G) can also upgrade biogas through biological methanation by combining the CO 2 in biogas with H 2 to produce renewable methane. The H 2 for P2G can be produced through electrolysis of renewable electricity. Through simulation software – SuperPro Designer, the economics of different pathways for upgrading biogas from a grass silage and slurry fed digester are analysed and compared in this paper. Three scenarios were investigated: biogas upgrading through amine scrubbing (scenario 1); biogas upgrading through amine scrubbing with CO 2 directed to ex-situ biological methanation (scenario 2) and biogas upgrading through ex-situ biological methanation only (scenario 3). The results show that at a net present value of zero, the minimum selling price (MSP) per m 3 of renewable methane for scenario 1, 2 and 3 is €0.76; €1.50 and €1.43, respectively (with an electricity price to produce H 2 of €0.10/kWh and a grass silage production cost of €27/t). The electricity price has a significant effect on the cost of renewable methane in both scenarios 2 and 3. The MSP reduces to €1.09 and €1.00 per m 3 of renewable methane, respectively for scenarios 2 and 3, if the electricity price is reduced to €0.05/kWh. Since the renewable methane MSP from scenario 2 is higher than scenario 3, it is suggested that direct biogas injection to the methanation reactor is financially more attractive than capturing CO 2 from biogas and feeding it to the methanation step. The MSP of renewable methane from both scenarios 2 and 3 are significantly higher than that of scenario 1. However, when considering climate change mitigation, balancing of the electricity network and storage of surplus electricity, utilising P2G can offset some of these costs. The cost of H 2 is a significant factor in determining the cost of renewable methane. [ABSTRACT FROM AUTHOR]

A transformation of the electricity generation system is required to drastically reduce the associated CO 2 emissions. In future systems, variable renewable energy sources (wind and solar) are expected to provide a significant fraction of the electricity supply, increasing the requirement for variation management compared with today’s situation. This paper investigates the impacts of measures designed to increase the competitiveness of coal-fired power plants in future energy systems, which are facing restrictions related to CO 2 emissions and variable operation as a consequence of high penetration levels of wind and solar power. We investigate the cost-optimal compositions of three regional electricity generation systems with different conditions for generation using renewables with a linear cost-minimizing investment model. The model is applied in two energy policy scenarios: one with a tight cap on CO 2 emissions, and one with a stringent requirement for generation from renewables. In a system with a stringent requirement for electricity generation from renewables but without a CO 2 cap, coal-based technologies with improved cycling properties provide variation management, given that the development of measures for ensuring improved flexibility continues and reaches full-scale implementation at moderate cost. The effects of improved cycling properties on the system composition are especially relevant for regions with moderate potential for wind and solar generation, in that they reduce wind curtailment and improve the underlying conditions for investments in solar power. In the system with a tight CO 2 cap, only coal-based technologies with Carbon Capture and Storage (CCS) and co-firing of biomass are feasible. Increasing the share of biomass in co-firing technologies to achieve negative CO 2 emissions increases the competitiveness of these technologies to a greater extent than if simply the cycling properties are improved. A larger co-firing fraction reduces the total system costs, since it facilitates the provision of low-cost flexibility by Natural Gas Combined Cycle (NGCC) plants, and it is especially important in regions where nuclear power is otherwise cost-competitive, as low-cost flexibility stimulates investments in wind and solar power at the expense of nuclear power. [ABSTRACT FROM AUTHOR]

Carbon capture and storage (CCS) has been identified as an urgent, strategic and essential approach to reduce anthropogenic CO 2 emissions, and mitigate the severe consequences of climate change. CO 2 storage is the last step in the CCS chain and can be implemented mainly through oceanic and underground geological sequestration, and mineral carbonation. This review paper aims to provide state-of-the-art developments in CO 2 storage. The review initially discussed the potential options for CO 2 storage by highlighting the present status, current challenges and uncertainties associated with further deployment of established approaches (such as storage in saline aquifers and depleted oil and gas reservoirs) and feasibility demonstration of relatively newer storage concepts (such as hydrate storage and CO 2 -based enhanced geothermal systems). The second part of the review outlined the critical criteria that are necessary for storage site selection, including geological, geothermal, geohazards, hydrodynamic, basin maturity, and economic, societal and environmental factors. In the third section, the focus was on identification of CO 2 behaviour within the reservoir during and after injection, namely injection-induced seismicity, potential leakage pathways, and long-term containment complexities associated with CO 2 -brine-rock interaction. In addition, a detailed review on storage capacity estimation methods based on different geological media and trapping mechanisms was provided. Finally, an overview of major CO 2 storage projects, including their overall outcomes, were outlined. This review indicates that although CO 2 storage is a technically proven strategy, the discussed challenges need to be addressed in order to accelerate the deployment of the technology. In addition, beside the necessity of techno-economic aspects, public acceptance of CO 2 storage plays a central role in technology deployment, and the current ethical mechanisms need to be further improved. [ABSTRACT FROM AUTHOR]

• A novel decarbonization concept applied to offshore natural gas wells benefiting CCUS technology. • A comprehensive CFD model considers real gas EOS and the behaviours of gas, droplets, liquid film. • Compatible with pure CO 2 and CH 4 -CO 2 models to study condensation and separation characteristics. • The maximum CO 2 condensation amount under high pressure and low temperature is 10.33 ton/h. • The maximum CO 2 capture capacity is 4.43 ton/h with high heterogeneous droplet mass concentration. Carbon capture, utilisation and storage (CCUS) is of unique significance for building a green and resilient energy system, and it is also a key solution to tackle the climate challenge. The concept of supersonic decarburization, a joint product of non-equilibrium condensation and swirling separation, can contribute to CCUS technology in a clean way. In this paper, a numerical model is established and validated to investigate the complex physical phenomena of supersonic decarbonization in a high-pressure environment based on the real gas equation of state. The model is compatible with the pure CO 2 model and CH 4 -CO 2 model. Through the simulation of the supersonic nozzle and supersonic separator, the condensation and separation performance of supersonic decarbonization technology was evaluated. For the condensation performance of carbon dioxide, the results show that higher pressure makes it much easier to achieve the condensation process. When the pressure is supercritical, the decrease of inlet temperature or the increase of inlet mole fraction of CO 2 leads to a higher liquid fraction. For separation performance, when the mass concentration of inlet heterogeneous droplets increases from 0.1 kg/m3 to 7.5 kg/m3, the carbon separation amount increases from 3.33 ton/h to 4.43 ton/h, while the exergy loss of condensed CO 2 drops from 436.57 kJ/kg to 329.56 kJ/kg. It demonstrates that the decarburization process is easier, and exergy required for condensation decreases when the concentration of the foreign core is larger. This new concept is beneficial to CCUS technology and can be applied to carbon capture in offshore natural gas processing. [ABSTRACT FROM AUTHOR]

This paper discusses the economic impacts of climate change, including those on ecosystems, and whether a new backstop technology should be used under conditions of strict temperature targets. Using the dynamic integrated climate-economy (DICE) model, we developed a new model to calculate the optimal path by considering new backstop technologies, such as CO 2 capture and storage (CCS). We identify the effects of parameter changes based on the resulting differences in CO 2 leakage and sites, and we analyse the feasibility of CCS. In addition, we focus on ocean acidification and consider the impact on economic activity. As a result, when CCS is assumed to carry a risk of CO 2 leakage and acidification is considered to result in a decrease in utility, we find that CCS can only delay the effects of climate change, but its use is necessary to achieve strict targets, such as a 1.5 °C limit. This observation suggests that if the target temperature is too tight, we might end up employing a technology that sacrifices the ecosystem too greatly. [ABSTRACT FROM AUTHOR]