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The cost of CO2 capture and storage
Abstract
The objective of this paper is to assess the current costs of CO2 capture and storage (CCS) for new fossil fuel power plants and to compare those results to the costs reported a decade ago in the IPCC Special Report on Carbon Dioxide Capture and Storage (SRCCS). Toward that end, we employed a similar methodology based on review and analysis of recent cost studies for the major CCS options identified in the SRCCS, namely, post-combustion CO2 capture at supercritical pulverized coal (SCPC) and natural gas combined cycle (NGCC) power plants, plus pre-combustion capture at coal-based integrated gasification combined cycle (IGCC) power plants. We also report current costs for SCPC plants employing oxy-combustion for CO2 capture—an option that was still in the early stages of development at the time of the SRCCS. To compare current CCS cost estimates to those in the SRCCS, we adjust all costs to constant 2013 US dollars using cost indices for power plant capital costs, fuel costs and other O&M costs. On this basis, we report changes in capital cost, levelized cost of electricity, and mitigation costs for each power plant system with and without CCS. We also discuss the outlook for future CCS costs.
... Die Kosten der Abscheidung von Energiewandlern wie Kohle-und Erdgaskraftwerken liegen höher als die Kosten von Transport und Speicher (Rubin et al. 2015, Basis 2013Schmelz et al. 2020, Basis 2018 in USD) (Abb. 8). ...
... 1.9-2.4 USD/t CO 2 offshore (Rubin et al. 2015). Während Pipelines mit einem höherem CAPEX (capital expenditure) einhergehen, ist der Transport per Schiff oder Bahn mit einem höherem OPEX (operational expenditure) behaftet. ...
... Costs of CCS for capture, transport and storage in USD/t after (1)Rubin et al. (2015) and(2)Schmelz et al. (2020). ...
... The simulation results were used to analyze the cost of injecting and storing CO 2 in order to determine the economics of the project. The costs associated with drilling and completing the well, as well as the annual operating expenses, were estimated based on previous economic studies conducted by energy industries [21][22][23][24][25]. A CO 2 injection well lifespan of 25 years and a discounted rate of 15% were used to calculate the net present value (NPV) of the project [21]. ...
... The annual operating costs of the injection project calculated from the operating premises are shown in Table 4, and the results from the economic analysis in terms of project economic components, including CAPEX, annual OPEX, annual sale, and revenue, are shown in Figure 5. According to the analysis, the total annual OPEX per well is around USD 2.03 million per year, including the cost of CO 2 capture and transport of around USD 1.58 million per year, or approximately USD 53 per ton of CO 2 [23,24]. Thus, the minimum sale unit price, in the term of carbon credit cost of USD 72.50 per ton of CO 2 e is required to reach the breakeven for this project, which results in an annual revenue of USD 117,000 year per well. ...
... nue, are shown in Figure 5. According to the analysis, the total annual OPEX per well is around USD 2.03 million per year, including the cost of CO2 capture and transport of around USD 1.58 million per year, or approximately USD 53 per ton of CO2 [23,24]. Thus, the minimum sale unit price, in the term of carbon credit cost of USD 72.50 per ton of CO2e is required to reach the breakeven for this project, which results in an annual revenue of USD 117,000 year per well. ...
Carbon geological storage (CGS) is one of the key processes in carbon capture and storage (CCS) technologies, which are used to reduce CO2 emissions and achieve carbon-neutrality and net-zero emissions in developing countries. In Thailand, the Mae Moh basin is a potential site for implementing CGS due to the presence of a structural trap that can seal the CO2 storage formation. However, the cost of CGS projects needs to be subsidized by selling carbon credits in order to reach the project breakeven. Therefore, this paper estimates the economic components of a CGS project in the Mae Moh basin by designing the well completion and operating parameters for CO2 injection. The capital costs and operating costs of the process components were calculated, and the minimum carbon credit cost required to cover the total costs of the CGS project was determined. The results indicate that the designed system proposes an operating gas injection rate of 1.454 MMscf/day, which is equivalent to 29,530 tCO2e per year per well. Additionally, the minimum carbon credit cost was estimated to be USD 70.77 per tCO2e in order to achieve breakeven for the best case CGS project, which was found to be much higher than the current market price of carbon credit in Thailand, at around USD 3.5 per tCO2e. To enhance the economic prospects of this area, it is imperative to promote a policy of improving the cost of carbon credit for CGS projects in Thailand.
... Furthermore, a study by Smith (2011) focused on examining the spectrum of expenses associated with the transportation and storage of CO 2 while also assessing how these costs influence the outcomes of economy-wide models for decarbonization strategies; while there has been substantial analysis of the cost and efficacy of different CO 2 capture technologies, there has been comparatively less emphasis on assessing the expenses linked to CO 2 transport and storage. On the other hand, Mccoy and Rubin (2008) (Mccoy and Rubin 2008;Smith et al. 2021;Schmelz et al. 2020;Rubin et al. (2015); Lanyu et al. 2011;Knoope et al. 2014). ...
... Additionally, offshore storage is found to be more costly than onshore storage. In a separate study, Rubin et al. (2015) assessed the current cost of CCS for three significant power plants, comparing the results with those from a decade ago. Adhering to the methodology outlined in the Special Report on Carbon and Dioxide Capture and Storage, the outcomes indicate a significant rise in capital costs, both with and without CCS. ...
... These studies primarily focused on the impact of CO 2 transportation costs based on its physical aspects. To gain a comprehensive understanding of the variations in scope and key findings among relevant studies, an analysis of research conducted by Mccoy and Rubin (2008), Rubin et al. (2015), Schmelz et al. (2020), Smith et al. (2021), Lanyu et al. (2011), Knoope et al. (2014), and this paper is presented in Table 1. ...
Carbon dioxide (CO2) occupies the leading position among greenhouse gas (GHG) emissions that adversely impact the environment. A way to remedy the growing emission of CO2 is by using carbon capture and storage (CCS) or carbon capture, utilization, and storage (CCUS) technologies. This paper proposes a novel optimization framework to minimize the transportation cost of CO2 by determining the required number of booster pumps, with the consideration of the impact of pipeline length and CO2 flow rate. As a case study, we conducted a study of optimally transporting 1 Mt (million tonnes) of CO2 through pipelines from four well-defined sources over 62 miles (sink) in the greater Houston area (Texas, USA). This optimization problem considers the impact of pipeline length and CO2 flow rate on the transportation cost of CO2. The results from the optimized system show that the pipeline length and CO2 flow rate need to be tuned properly to optimally transport and recover the investment price. For the system to be cost-effective, it is preferable to transport a high flow rate of CO2 (>50 Mt) over a longer distance (>100 miles); anything outside the mentioned ranges or less can increase the investment and CO2 transportation costs.
... Capturing and compressing the CO2 gas accounts for about 75% of the total cost of CCS [6]. Employing CCS technologies can reduce emissions from power generation industries and other industrial applications such as cement, oil refining, and biofuel. ...
... Moreover, extensive operation has yet to be fully implemented. It is important to align the assessment of the efficiency and process considerations of high-performing adsorbents with their 6 design, development, and evaluation process. Furthermore, the absorbent features that will be employed should be considered in any cyclic process's design and optimization [48,54]. ...
Addressing escalating energy demands and greenhouse gas emissions in the oil and gas industry has driven extensive efforts in carbon capture and utilization (CCU), focusing on power plants and industrial facilities. Utilizing CO2 as a primary feedstock for industrial fuels and petrochemical materials offers a favorable alternative to sequestration, with byproducts substituting traditional chemical feedstocks. This comprehensive review explores the current landscape of CO2 capture technologies, examining opportunities, economic viability, and efficiency challenges. It provides a detailed analysis of various CO2 utilization methods and the combined process of capture and utilization. The review highlights primary obstacles in planning, production, and widespread implementation, emphasizing the need for strategic integration of materials research, process performance, and cost-effectiveness to advance new technologies.
... Certain cost models have also been developed to optimize the CO 2 pipeline networks [16]. There has also been a focus on the techno-economical cost estimations of pipeline transportation [17][18][19]. However, these studies have primarily focused on a limited number of case studies and do not provide a detailed analysis of the cost impact with varying transport mass and distance. ...
... with µ being the dynamic viscosity calculated with CoolProp [31]. The assumptions to calculate the pressure drop in a pipeline are given in Table 5. [19,39] 0.045 mm Pipeline inlet pressure (P in ) [29,38] 150 bar ...
Meeting Germany’s climate targets urgently demands substantial investment in renewable energies such as hydrogen, as well as tackling industrial CO2 emissions with a strong CO2 transport infrastructure. This is particularly crucial for CO2-heavy industries such as steel, cement, lime production, power plants, and chemical plants, given Germany’s ban on onshore storage. The CO2 transport network is essential for maintaining a circular economy by capturing, transporting, and either storing or utilizing CO2. This study fills gaps in CO2 pipeline transport research, examining pipeline diameters, costs, and pressure drop, and providing sensitivity analysis. Key findings show that the levelized cost of CO2 transport (LCO2T) ranges from 0.25 €/t to 55.82 €/t based on varying transport masses (1000 t/day to 25,000 t/day) and distances (25 km to 500 km), with compression costs pushing LCO2T to 33.21 €/t to 92.82 €/t. Analyzing eight pipeline diameters (150 mm to 500 mm) and the impact of CO2 flow temperature on pressure loss highlights the importance of selecting optimal pipeline sizes. Precise booster station placement is also crucial, as it significantly affects the total LCO2T. Exploring these areas can offer a more thorough understanding of the best strategies for developing cost-effective, efficient, and sustainable transport infrastructure.
... Besides the DAC cluster, BECCS had the largest distribution of costs, ranging from USD 25 per metric ton of CO 2 to a high of USD 190 per metric ton of CO 2 . All data for BECCS capture costs pertained to biomass energy plants, with variation in capture costs possibly caused by varying plant efficiencies [50]. CCS, in contrast, takes up most of the avoided cost observations. ...
... Environments 2024, 11, x FOR PEER REVIEW 9 of 16 ton of CO2 to a high of USD 190 per metric ton of CO2. All data for BECCS capture costs pertained to biomass energy plants, with variation in capture costs possibly caused by varying plant efficiencies[50]. ...
In this paper, we use the literature to help us better understand carbon capture costs and how these estimates fare against those of avoided costs, focusing on bioenergy carbon capture and storage (BECCS), carbon capture and storage (CCS), as well as direct air capture technologies. We approach these questions from a meta-analysis perspective. The analysis uses meta-analysis tools while applying them to numerical rather than statistical studies. Our analysis shows that avoided costs are, on average, 17.4% higher than capture costs and that the carbon intensity of the feedstock matters: the estimates for coal-based electricity generation capture costs are statistically smaller than those for natural gas or air. From a policy perspective, the literature suggests that the costs of CCS are like the 45Q subsidy of USD 50 per metric ton of carbon captured.
... In addition, the carbon capturing process increases the investment and operational costs when it is used to separate CO 2 in the fossil fuel power generation sector. Rubin et al. (2015) indicated that the carbon capturing systems could increase the levelized cost of electricity by 26 % in natural gas combined cycle power (NGCC) plants. Implementing carbon capturing technologies in NGCC power plants can increase the investment cost by 76 % to 121 %. ...
... Since the economic value of the heat was considered in this study, carbon taxation was not included when evaluating the economic value of the heat. The economic value of CO 2 was considered USD 36/ tCO 2 , which is the selling price of CO 2 in the Enhanced Oil Recovery industry (Rubin et al., 2015). The economic value of the K 2 CO 3 was given by the manufacturer of the KOH-based system as CAD 1700 per ton of K 2 CO 3 . ...
Buildings are responsible for 40 % of the global energy consumption, thus leading to significant climate change and other environmental impacts. Adopting carbon capturing, storage, and utilization technologies (CCSU) can be a solution for reducing greenhouse gas (GHG) emissions from natural gas building heating systems. However, the current knowledge base lacks definitive knowledge on the possibilities and impacts of building level CCSU. The goal of this study is to investigate the feasibility of implementing CCSU technologies in natural gas building heating systems. A comparative performance assessment framework was developed to evaluate the environmental and economic performance of building-level CCSU technologies over their life cycle. These performances were then compared against alternative GHG emissions mitigation methods used for building heating systems. The results obtained by a case study indicated that adopting CCSU technologies in residential buildings is not economically and environmentally competitive against electricity-based heating systems when the regional electricity is generated using renewable energy sources and nuclear energy. However, there is a potential for the building-level CCSU in regions that depend on fossil fuels to generate electricity. The research outcomes will further develop and improve building-level carbon capturing technologies and will provide confidence to stakeholders to invest.
... Oil and gas companies can become leaders in the energy transition and contribute to the global effort to combat climate change by following these research directions and implementing the recommended strategies for managing the financial risks and opportunities associated with CCS deployment [1][2][3][4][5][6][7][8][9][10][11]. ...
This paper thoroughly examines the financial risks and opportunities related to implementing carbon capture and storage (CCS) in the oil and gas sector. We utilize sophisticated machine learning techniques to create a robust methodology for measuring CCS projects’ economic feasibility and risk level. Our approach encompasses various crucial factors, such as investment costs, operational expenditures, carbon pricing, and the oil and gas market dynamics. By utilizing discounted cash flow modeling, sensitivity analysis, and Monte Carlo simulation, we produce probabilistic financial results that offer valuable insights for decision-makers. The findings emphasize the crucial significance of policy backing, technological progress, and strategic portfolio management in influencing the financial outcomes of CCS investments. This study enhances the comprehension of Carbon Capture and Storage (CCS) as an essential instrument for reducing carbon emissions in the oil and gas industry while effectively managing the intricate financial aspects of transitioning to cleaner energy sources.
... CCS stands out as a pivotal eco-friendly technology essential for minimizing economically feasible CO 2 emissions from power plants [218]. Despite recent validation of full-scale amine-based CO 2 capture systems [219], the persistent hurdle of costly CO 2 emission reductions has spurred the exploration of innovative technologies [220]. Among these technologies are molten carbonate fuel cells (MCFCs) [221], membranes [222], pressured combustion capture [223], supersonic separator [147], and flow-driven anti-sublimation. ...
Carbon capture and storage is recognized as one of the most promising solutions to mitigate climate change. Compared to conventional separation technologies, supersonic separation is considered a new generation of technology for gas separation and carbon capture thanks to its advantages of cleaning and efficient processes which are achieved using energy conversion in supersonic flows. The supersonic separation works on two principles which both occur in supersonic flows: the energy conversion to generate microdroplets and supersonic swirling flows to remove the generated droplets. This review seeks to offer a detailed examination of the cuttingedge technology for gas separation and carbon dioxide removal in the new-generation supersonic separation technology, which plays a role in carbon capture and storage. The evaluation discusses the design, performance, financial feasibility, and practical uses of supersonic separators, emphasizing the most recent progress in the industry. Theoretical analysis, experiments, and numerical simulations are reviewed to examine in detail the advances in the nucleation and condensation characteristics and the mechanisms of supersonic separation, as well as new applications of this technology including the liquefaction of natural gas. We also provide the perspective of the challenges and opportunities for further development of supersonic separation. This survey contributes to an improved understanding of sustainable gas removal and carbon capture by using the newgeneration supersonic separation technology to mitigate climate change.
... В России более 70% выбросов парниковых газов приходится на предприятия топливно-энергетического комплекса 2 . Основным путем сокращения выбросов в энергетике, предлагаемым мировым сообществом, является их улавливание и последующее захоронение, что приводит к существенному удорожанию энергоснабжения конечных потребителей и снижению конкурентоспособности производимой ими продукции (Rubin, Davison, Herzog, 2015;Large pilot testing …, 2020;Stanger et al., 2015). ...
Общемировой тенденцией становится рост затрат на энергоснабжение по мере все более широкого распространения технологий снижения выбросов парниковых газов. Следствием проектов поглощения СО2 на российских тепловых электростанциях станет удорожание производимой ими электроэнергии на 120–230%, что негативно повлияет на социально-экономическое развитие страны. Предлагаемая международным сообществом абсорбция углекислого газа из уходящих газов в промышленности и энергетике является капиталоемким и энергозатратным процессом. Альтернатива предотвращения повышения стоимости энергоснабжения для Российской Федерации — снижение негативного антропогенного воздействия путем использования ее природного потенциала. Целью статьи является обоснование необходимости изменения методологии решения задачи перехода к безуглеродной энергетике. В отличие от перенесения в Россию апробированных на Западе проектов абсорбции СО2 уходящих газов промышленности и энергетики следует основываться на системном подходе к секвестру углекислого газа с использованием не реализованных в настоящее время возможностей. На примере исследования управления природопользованием в районе Рыбинского водохранилища показано существование более эффективного решения по сравнению с реализуемыми в западных странах проектами сокращения содержания СО2. В связи с ростом мощности энергосистемы, опережающей электропотребление, значимость производства электроэнергии Рыбинской ГЭС значительно снизилась. Платежи за утилизацию парниковых газов за счет восстановления леса будут не менее чем в 13 раз превышать снижение выручки ГЭС при изменении уровня ее водохранилища. За счет восстановления лесов на части территории водохранилища в результате самозарастания относительно сегодняшнего уровня (базовой линии) можно обеспечить верифицированный секвестр более 1,5 млн т СО2 в год, что эквивалентно реализации проектов улавливания СО2 уходящих газов на газовых электростанциях мощностью не менее 920 МВт.
The transfer of the currently emerging international practice of solving the problem of global warming to Russia will lead to an increase in energy supply costs. The result of CO2 absorption projects at thermal power plants will be a 120–230% increase in the cost of electricity produced by them, which will have a negative impact on socio-economic development. The absorption of carbon dioxide from exhaust gases in industry and energy is a capital-intensive and energy-consuming process. An alternative to preventing an increase in the cost of energy supply for the Russian Federation is to reduce the negative anthropogenic impact by using its natural potential. The increase in the annual absorption of carbon dioxide by Russian forests, which happened over 30 years, is comparable to its current emissions in thermal power engineering and heat supply. The purpose of the article is to substantiate the need to change the methodology for solving the problem of transition to carbon-free energy. In contrast to the transfer into Russia the projects tested in the West for the absorption of CO2 of exhaust gases from industry and energy sector, one should be based on a systematic approach to carbon dioxide sequestration using opportunities that have not yet been implemented. Using the example of a study of environmental management in the area of the Rybinsk reservoir, the existence of a more effective solution for reducing CO2 content is shown in comparison with projects implemented in Western countries. Due to the growth of the power system capacity, which is ahead of electricity consumption, the importance of electricity generation at the Rybinsk HPP (hydro power plant) has significantly decreased. Payments for the utilization of greenhouse gases due to reforestation will be at least 15 times higher than the decrease in the HPP’s revenue due to a change of reservoir level. Due to the restoration of forests in part of the reservoir area, it is possible to ensure the sequestration of 1.5 million tons of CO2 per year, which is equivalent to the implementation of projects to capture CO2 of exhaust gases at gas-fired power plants with a capacity of at least 0.92 MW.
... Such mitigation scenarios generally involve phaseout and retirement of fossil fuel-fired powerplants before their expected lifetime, resulting in stranded assets [8][9][10] . Although carbon capture and storage (CCS) would facilitate fossil fuel-fired power generation under the low emissions scenarios, CCS-based electricity generation is limited in the mitigation scenarios of the Intergovernmental Panel on Climate Change Sixth Assessment Report (IPCC AR6), with a median value <10% in 2050 11 due to several barriers, such as incremental capital costs and energy penalties 12,13 . ...
Climate change mitigation generally require rapid decarbonization in the power sector, including phase-out of fossil fuel-fired generators. Given recent technological developments, co-firing of hydrogen or ammonia, could help decarbonize fossil-based generators, but little is known about how its effects would play out globally. Here, we explore this topic using an energy system model. The results indicate that hydrogen co-firing occurs solely in stringent mitigation like 1.5 °C scenarios, where around half of existing coal and gas power capacity can be retrofitted for hydrogen co-firing, reducing stranded capacity, mainly in the Organization for Economic Co-operation and Development (OECD) countries and Asia. However, electricity supply from co-firing generators is limited to about 1% of total electricity generation, because hydrogen co-firing is mainly used as a backup option to balance the variable renewable energies. The incremental fuel cost of hydrogen results in lower capacity factor of hydrogen co-fired generators, whereas low-carbon hydrogen contributes to reducing emission cost associated with carbon pricing. While hydrogen co-firing may play a role in balancing intermittency of variable renewable energies, it will not seriously delay the phase-out of fossil-based generators.
... This is primarily attributed to several factors, including economies of scale, standardized manufacturing processes, minimized contingencies, more affordable financing options, and the utilization of shared CO2 transport and storage infrastructure. [58] [59]. CCS is fundamentally dependent on government intervention in some form of incentive to store CO2 [26]. ...
Implementing carbon capture and storage (CCS) technologies is essential to
mitigate the damaging effects of climate change due to the earth’s temperature
increase. However, despite the potential benefits of CCS, its acceptance has
been slow. This paper identifies and examines the barriers to CCS acceptance,
which include technical, economic, regulatory, and social factors. Economic
barriers include the lack of financial incentives while regulatory barriers include
the absence of a comprehensive legal framework. Lastly, social barriers include
the lack of public awareness and understanding of CCS and the negative
perception of technology. Technical barriers include a deficiency of desired
infrastructure in all stages of CCS including capture, transportation, and storage.
... Costs for CO₂ capture to decarbonize fossil-fuel power plants have been extensively modeled by Rubin et al. [20], Vasudevan et al. [21], and NETL [22,23]. However, modelling for industrial facilities is more limited. ...
A model for estimating CO₂ capture retrofit costs at many types of industrial facilities is developed and then applied in a case study exploring alternative designs for capture, transport, and underground storage of CO₂ from a cluster of industrial facilities in Southeast Louisiana, USA. The capture cost model is anchored by granular chemical process simulations used to determine capacities of individual equipment components, the capital costs for which are estimated using factoring methods. To generalize the cost model, process simulations are developed for target capture streams having CO₂ concentrations of 5, 10, 15, and 94 mol%, and for each concentration, seven different scales of capture plants are modelled. The cost model is then embedded in SimCCSPRO, a customized version of open-source software for optimizing CO₂ pipeline capacities and routings to underground storage sites. For a 22-facility cluster of industrial CO₂ sources with collective emissions of 8.1 million tCO₂/year today, we explore capture, transport and storage (CTS) system designs with varying levels of shared capture and transport infrastructure. When CO₂ pipelines are shared rather than dedicated to individual capture facilities, average transport costs can be reduced by up to two-thirds (and aggregate pipeline length by more than this) for the same level of CO₂ capture and storage. However, capture costs dominate total CTS costs. Because of this, pooling emission streams from multiple facilities and sharing the scale-economy benefits of larger capture facilities enables more significant reductions in CTS costs per tonne of CO₂ stored, even though some of the savings are offset by the added flue gas transport costs. The cost benefits of shared infrastructure are most significant for smaller facilities, i.e., with emissions less than 0.1 million tCO₂/year.
... The expenses associated with capturing CO2 through the chemical absorption process vary, spanning from 50-100 USD per ton of CO2. These costs are contingent on factors such as the industry and the specific type of solvent employed [15]- [17]. An alternative post-combustion chemical absorption technologies include the piperazine-based CO2 capture (TRL 7-8) and the CO2 sorption using chilled ammonia (CAP) (TRL 7). ...
... Deep geologic sequestration of carbon dioxide requires an appropriate geologic formation into which carbon dioxide can be injected, as well as an approved injection facility. Prior literature has focused on individual aspects of CCS project development including cost analysis, geologic characterization, and non-technical barriers that have inhibited large-scale deployment (18)(19)(20)(21)(22)(23)(24)(25)(26)(27)(28)(29). What has been less understood until recently are the regulatory and other bottlenecks that may be encountered when securing approval to create and operate a sequestration facility in the United States. ...
Many studies anticipate that carbon capture and sequestration (CCS) will be essential to decarbonizing the U.S. economy. However, prior work has not estimated the time required to develop, approve, and implement a geologic sequestration site in the United States. We generate such an estimate by identifying six clearance points that must be passed before a sequestration site can become operational. For each clearance point (CP), we elicit expert judgments of the time required in the form of probability distributions and then use stochastic simulation to combine and sum the results. We find that, on average, there is a 90% chance that the time required lies between 5.5 and 9.6 y, with an upper bound of 12 y. Even using the most optimistic expert judgements, the lower bound on time is 2.7 y, and the upper bound is 8.3 y. Using the most pessimistic judgements, the lower bound is 3.5 y and the upper bound is 19.2 y. These estimates suggest that strategies must be found to safely accelerate the process. We conclude the paper by discussing seven potential strategies.
... Integrated gasification combined cycle (IGCC) has several advantages compared with a pulverized coal (PC) power plant [1][2][3][4][5][6][7][8][9][10]. It has better environmental performance, less solid waste, lower water consumption, and capability of phased construction. ...
Compared with a pulverized coal power plant, the integrated gasification combined cycle (IGCC) has several advantages, including, among others better environmental performance and low CO2 capture cost. Hot/warm CO2 removal from syngas has also been a subject of research due to its potentially higher thermal efficiency. In this study, we proposed a generic adsorption based hot/warm CO2 removal process for IGCC power plants. Through analyses of the proposed generic process we have demonstrated that higher temperature of the hot/warm CO2 removal process will results in larger heat of adsorption, which in turns may increase energy consumption of the process. Under most of the operating temperature range, hot/warm CO2 removal process will lead to more electricity loss compared to the baseline Selexol process. However, if the adsorption step takes place at a temperature close to or higher than the highest steam temperature in steam cycle, our analysis indicates that the process may lead to minimal electricity loss. The study also provided some other insights into the pathways for hot/warm CO2 removal process to improve its energy performance through process and sorbent designs.
Graphical Abstract
... The most promising method of reducing atmospheric CO 2 is the "carbon capture and storage (CCS) process," in which atmospheric CO 2 is compressed and stored in liquid form at an underground site or the bottom of the deep ocean [5]. Although this method can significantly reduce the concentration of CO 2 in the atmosphere, its high cost is a major problem [6,7]. Currently, converting CO 2 into value-added fuels instead of treating it as waste is considered economical, and efforts are being made to achieve this. ...
Global warming is accelerating, and the average global temperature is projected to rise from 3.5 to 5.7°C by the end of this century. Therefore, there is a strong possibility that we will soon experience frequent global-scale abnormal weather events and severe water and food shortages. To avoid such crises, three issues must be urgently addressed: reduction of CO2 emissions, securing of energy sources that can replace fossil fuels, and securing of groundwater and food supplies. In this introductory chapter, we first discuss the development of new biotechnology processes such as CO2 sequestration by algae, biofuels, and biopolymers. Biofuels and biopolymers, in particular, will soon play an important role as alternatives to scarce fossil fuels. In addition, bioremediation technologies for widespread groundwater and soil contamination are discussed. Novel bioremediation technologies, such as gene editing and the use of artificial enzymes, have the potential to dramatically improve bioremediation throughput. This new biotechnological approach to the environment will be a decisive factor in ensuring food and beverage safety.
Energy consumed in 1950 reached 25.6 TWh with a population of 2.5 billion people, then increased almost 7 times to reach 168.5 TWh in 2020 with a population of 8 billion people, around 3 times the population in 1950. The rate of increase in energy consumption is greater than the rate of increase in human population. There has been an increase in the amount of energy consumption per capita, both globally, in Asian countries and in Indonesia. On a global average, energy consumption per capita in 1970 was 15.4 MWh, then increased to 21.1 MWh in 2020. The phenomenon of increasing the amount of energy consumption and energy consumption per capita cannot be separated from the increase in the amount of CO2 emissions released into the atmosphere. This is characterized by the linearity of the amount of CO2 emissions which gradually increases. In 1980, CO2 emissions released into the atmosphere were 5.93 tons and continue to increase along with energy consumption and per capita energy consumption will reach 37.2 tons in 2022. As a result, the earth's surface temperature increased by 0.86°C compared to the earth's surface temperature before the industrial revolution (National Centers for Environmental Information, 2022), thus causing the potential for a global climate crisis. As part of the UN and its commitment to preventing the climate crisis, Indonesia based on the initial NDC target has a commitment to reduce CO2 emissions by 29% in 2030 or by 2.87 gigatons CO2-eq independently and 41% if considering assistance and support finance, technology transfer, development and capacity building on an international scale. This target was then revised into an ENDC (Enhanced Nationally Determined Commitment) document, where Indonesia's commitment to reducing CO2 emissions increased to 31.89% independently and 43.2% if considering financial assistance and support, technology transfer, development and improvement. capacity on an international scale.
Colombia committed to reducing its greenhouse gas emissions by 20% concerning the 2030 projected levels according to the Paris Agreement; sugarcane mills are of high interest in reaching Colombian mitigation goals. Currently, sugarcane mills are producing raw sugar, but also; bioethanol and bioenergy by using fermentation and combustion processes, respectively, producing several million tons of CO2 as a by-product. The evaluation of CO2 capture requires an exhaustive delimitation of the generation unit, and the purification requirements vary depending on the final use, therefore it is important to study the CO2 source and the utilization processes that proceed in an integrated manner, known as the CO2 valorization chain. Bioenergy with carbon capture and utilization (BECCU) is an approach that aims at harnessing the two essential carbon sources in post-fossil scenarios, biomass and CO2 while looking to achieve global mitigation goals. Thus, this chapter presents, based on a literature review and process data analysis from local Sugarcane mills, an approach to a CO2 valorization chain considering Colombian legislation and incentives around CO2, integrating a sugarcane cogeneration plant as a CO2 source, absorption with amine solvents or calcium carbonate looping as options for carbon capture, and CO2 bioconversion into succinic acid. Technologies for CO2 utilization are often developed separately, and each sugarcane mill explored in the light of BECCU systems presents challenges and opportunities that may affect its implementation possibilities. On a one-year basis, technical and economic parameters calculated for a particular sugarcane mill show that of the 628,7 kilotons of CO2 produced by sugarcane bagasse burning, 452,7 and 402,4 tons can be captured at 34,6 and 58,3 US$/ton of CO2 captured by absorption with amine solvent or calcium carbonate looping, respectively. Then, putting the captured CO2 to use in anaerobic fermentation produces close to one thousand kilotons of succinic acid per route. This scenario can help to analyze the panorama of CO2 emissions and valorization in Colombia suggesting a need for growth in the overall technology carbon conversion yield, and that capture and CO2 use as feedstock does not automatically guarantee environmentally friendly processes; there appear to be more challenges to take care of in the current Colombian Sugarcane and CO2 incentives scenarios.
Climate change is one of the most pressing challenges facing our planet today. To abort this problem, the importance of reducing greenhouse gas emissions, particularly carbon dioxide (CO2), has been considered. Applying carbon capture, transport, and storage systems is vital to the mitigation process in this context. However, evaluating and selecting the most influential and appropriate technologies for a specific environment can be a complex challenge due to the many variables involved. In this regard, a critical review of carbon capture, transport, and storage technologies is presented, applying the formal concept analysis (FCA) method to evaluate the compliance of a series of attributes or characteristics with the technologies to some extent. The review process is subdivided into CO2 capture, CO2 transport, and CO2 storage. For the treatment of the information, the free access software Concept Explorer is implemented to obtain a series of diagrams that simplify the treatment of the information and facilitate the understanding of the results. Finally, among the results, it is highlighted that traditional carbon sequestration technologies have partially overcome some limitations presented in decades: efficient application at a low scale. At the same time, traditional carbon transport methods prevail over emerging alternatives. Finally, traditional technologies stand out notoriously for storage at large-scale levels concerning the new proposals. However, there are emerging applications with potential storage capacity for low-scale systems.
We describe a roadmap using three sets of technologies to enable base-load nuclear reactors to replace all fossil fuels in a low-carbon world. The technologies integrate nuclear, wind, solar, hydroelectricity and biomass energy sources. Base-load nuclear reactors with large-scale heat storage enable dispatchable electricity to the grid. The low-cost heat storage enables buying excess wind and solar electricity to charge heat storage for later electricity production while providing assured generating capacity. Nuclear hydrogen production facilities at the scale of global oil refineries produce hydrogen to replace natural gas (gaseous fuel) as a chemical feedstock and heat source. Single sites may have tens of modular reactors produced in a local factory to lower costs by converting to a manufacturing model for reactor construction. Nuclear heat and hydrogen convert cellulosic biomass into drop-in liquid hydrocarbon biofuels to replace fossil-fuel gasoline, diesel, jet fuel, and hydrocarbon feed stocks for the chemical industry. External heat and hydrogen inputs increase the quantities of biofuels that can be produced per unit of cellulosic feedstock, thus assuring sufficient biomass feed stocks to replace all crude oil without major impacts on food and fiber prices. The biofuel production system enables the removal of large quantities of carbon dioxide from the atmosphere that is sequestered as carbon char in the soil while recycling plant nutrients (potassium, phosphorous, etc.) to assure agricultural and forest sustainability.
Biomass frequently constrains its widespread application due to its low economic efficiency. In this project, a new approach of biomass application was explored to reduce bio-syngas production cost. A model for the bio-syngas production from biomass gasification and bio-syngas purification (Selexol and water scrubbing) were studied. Based on the simulation results, we assessed the feasibility and viability of the project. Preliminary results showed that the bio-syngas production cost with Selexol (2.15 $/Nm3) is even higher than biomass used in power generation systems (equal to 1.58–2.21 $/Nm3). However, water scrubber was used as bio-syngas purification, the capital investment cost and bio-syngas production cost (1.34 $/Nm3) was significantly reduced. A sensitivity analysis was conducted on the bio-syngas price, which could be further reduced by various factors: biomass price, carbon taxes, and carbon credits. We assumed that bio-syngas was applied to natural gas pipeline, our analysis showed that the application of bio-syngas (2 to 10% content) to natural gas had little impact on natural gas properties: combustion value and price. The technology of water scrubber makes the applications of biomass-based fuels competitive.
Research on metal-organic frameworks (MOFs) based membranes has gained a lot of attention in the last decade thanks to the unique and highly versatile chemistry of MOFs, which allows one to synthesize a variety of structural dimensions, topologies, pore sizes, pore shapes, functional groups, and chemical environments. For membrane application, the field is rapidly progressing, with the focus shifting from the synthesis of pinhole-free polycrystalline films to the synthesis of ultrathin MOF films on scalable support to surpass the performance of polymeric membranes. In this research update, we review promising methodologies for the synthesis of ultrathin MOF membranes. We then discuss the application of these ultrathin MOF films in gas separation, ion transport and ion–ion separation, and desalination. We then provide our perspective on opportunities and challenges for the future development of ultrathin MOF membranes.
Carbon capture and utilization has gained attention to potentially curb CO2 emissions while generating valuable chemicals. These technologies will coexist with fossil analogs, creating synergies to leverage circular economy principles. In this context, flue gas valorization from power plants can assist in the transition. Here, we assessed the absolute sustainability of a simulated integrated facility producing ammonia and synthetic natural gas from flue gas from a combined-cycle natural gas power plant based in Germany, using hydrogen from three water electrolysis technologies (proton exchange membrane, alkaline, and solid oxide cells), nitrogen, and CO2. For the first time, we applied the planetary boundaries (PBs) framework to a circular integrated system, evaluating its performance relative to the safe operating space. The PB-LCA assessment showed that the alternative technologies could significantly reduce, among others, the impact on climate change and biosphere integrity when compared to their fossil counterparts, which could be deemed unsustainable in climate change. Nevertheless, these alternative technologies could also lead to burden shifting and are not yet economically viable. Overall, the investigated process could smoothen the transition toward low-carbon technologies, but its potential collateral damages should be carefully considered. Furthermore, the application of the PBs provides an appealing framework to quantify the absolute sustainability level of integrated circular systems.
There are significant differences in the methods employed by various organizations to estimate the cost of carbon capture and storage (CCS) systems for fossil fuel power plants. Such differences often are not apparent in publicly reported CCS cost estimates, and thus contribute to misunderstanding, confusion, and mis-representation of CCS cost information, especially among audiences not familiar with the details of CCS costing. Given the international importance of CCS as an option for climate change mitigation, efforts to harmonize methods of estimating CCS costs and improving the communication of cost assumptions and results are especially urgent and timely. Based on an analysis of current deficiencies, this paper recommends a common costing methodology plus guidelines for CCS cost reporting to improve the clarity and consistency of cost estimates for greenhouse gas mitigation measures.
Development of the FutureGen geologic storage site in Morgan County Illinois is part of a larger project to design, build, and operate a commercial-scale carbon capture and storage (CCS) system capable of capturing, treating, and storing the CO2 off-gas from an oxy-combustion coal-fueled power plant located in Meredosia, Illinois. The geological storage site is designed to capture approximately 1.1 million metric tons (Mt) of CO2 each year. To support the selection and design of the site, a comprehensive characterization effort was conducted in order to acquire fundamental subsurface site specific information. These characterization activities included seismic surveys coring, geophysical wireline logging, hydrologic testing and geomechanical testing. The characterization results combined with pertinent research literature were used to build a conceptual model of the site, which in turn informed the development of computer models. Collectively this work supported both the design work and the permitting under the U.S. Environmental Protection Agency's class VI Underground Injection Control (UIC) permit process which was developed specifically for CO2 injection. The detailed design of the injection wells and associated monitoring network were completed in early 2014 and in August 2014 the site received the first issued set of class VI UIC permits in the Unites States for the planned injection wells.
This paper summarizes the final results of the pilot plant operation and R&D programme of the CO2 Catch-up project (2008- 2013). The objective of the CO2 Catch-up project is to demonstrate pre-combustion CO2 capture at the pilot plant in Buggenum, the Netherlands, in order to verify the technology performance and to generate knowledge in the form of validated models and operational experience.
United States Department of Energy (DOE) and Archer Daniels Midland Company (ADM) has made substantial progress in the development and construction of the largest saline storage project in the U.S. This commercial-scale project is located at the ADM's agricultural processing and biofuels complex in Decatur, Illinois. The Office of Fossil Energy's National Energy Technology Laboratory manages this project. Detailed design, installation of the CO2 compression, dehydration, and transmission system, and installation of related piping, electrical, and instrumentation was completed and commissioning of this system was initiated. The construction of a 100-MW electrical substation, which will supply power to the compressors and other equipment, is in progress. A 2206 m deep monitoring well and a 1083 m geophysical well were drilled. The U.S. Environmental Protection Agency (EPA) issued a draft permit for a Class VI injection well with a capacity to inject 3000 tonnes of CO2 per day. This is expected to be the first geological sequestration project to operate with EPA's Class VI well permit in the U.S. The project is scheduled to begin CO2 injection into the Mount Simon Sandstone, a deep saline reservoir, early 2015. The project team members include Schlumberger Carbon Services, Illinois State Geological Survey (ISGS)-University of Illinois, and Richland Community College (RCC). Public education and outreach for CCS is an integral part of this ICCS project and to this end, the project has established the National Sequestration Education Center (NSEC) at RCC in Decatur. NSEC is implementing a new associate degree program, first in the United States, with an emphasis on CCS. This project was recognized by the Carbon Sequestration Leadership Forum.
As part of the United States Department of Energy's Office of Fossil Energy, the National Energy Technology Laboratory (NETL) implements research, development and demonstration (RD&D) that is focused on maximizing system efficiency and performance while minimizing the costs of coal-based power production with carbon capture and storage. In order to evaluate the benefits and market competitiveness of ongoing RD&D, NETL conducts engineering studies to evaluate the cost and performance of plants integrating multiple advanced technologies currently under development. This paper evaluates two different coal conversion pathways - combustion and gasification - and their potential to provide low-cost, low-carbon power from coal.
As with many technologies, carbon capture and storage (CCS) faces social acceptance challenges that can impact the pace of its development and deployment. Previous studies on the social acceptance of CCS have tended to rely on case studies of pilot projects or surveys of decision makers and the general public. Here, we take a different approach, using real world data about the social acceptance of hydraulic fracturing technologies to glean lessons for future carbon storage efforts. Hydraulic fracturing has many of the same operations, risks, and social narratives as carbon storage, making it a valid comparison. We conduct a statistical analysis on the relationship between various state demographic and economic factors and the stringency of state regulations governing the hydraulic fracturing industry. As a complement to this analysis, we conduct a comparative case study on the development of hydraulic fracturing regulations in New York and Pennsylvania. We find robust statistical evidence that familiarity with the oil and gas industry is associated with a decrease in regulatory variance among states where hydraulic fracturing takes place. Moreover, we identify a tension between regulatory control of hydraulic fracturing at the state level and regulatory control at the local level. This dynamic suggests that carbon storage policymakers and industrial leaders should emphasize local engagement in addition to state-level participation.
This paper reviews and compares the prevailing methods, metrics and assumptions underlying cost estimates for CO2 capture and storage (CCS) technologies applied to fossil fuel power plants. This assessment reveals a number of significant differences and inconsistencies across different studies, not only in key technical, economic and financial assumptions related to the cost of a CCS project (such as differences in plant size, fuel type, capacity factor, and cost of capital) but also in the underlying methods and cost elements that are included (or excluded) in a particular study (such as the omission of certain “owner's” costs or the cost of transport and storage). Such differences often are not apparent in the cost results that are reported publicly or in the technical literature. In other cases, measures that have very different meanings (such as the costs of CO2 avoided, CO2 captured and CO2 abated) are all reported in similar units of “dollars per ton CO2”. As a consequence, there is likely to be some degree confusion, misunderstanding and possible mis-representation of CCS costs. Given the widespread interest in the cost of CCS and the potential for lower-cost CO2 capture technology, methods to improve the consistency and transparency of CCS cost estimates are needed.
Carbon capture and storage (CCS) is widely seen as a critical technology for reducing atmospheric emissions of carbon dioxide (CO2) from power plants and other large industrial facilities, which are major sources of greenhouse gas emissions linked to global climate change. However, the high cost and energy requirements of current CO2 capture processes are major barriers to their use. This paper assesses the outlook for improved, lower-cost technologies for each of the three major approaches to CO2 capture, namely, post-combustion, pre-combustion and oxy-combustion capture. The advantages and limitations of each of method are discussed, along with the current status of projects and processes at various stages in the development cycle. We then review a variety of “roadmaps” developed by governmental and private-sector organizations to project the commercial roll-out and deployment of advanced capture technologies. For perspective, we also review recent experience with R&D programs to develop lower-cost technologies for SO2 and NOx capture at coal-fired power plants. For perspective on projected cost reductions for CO2 capture we further review past experience in cost trends for SO2 and NOx capture systems. The key insight for improved carbon capture technology is that achieving significant cost reductions will require not only a vigorous and sustained level of research and development (R&D), but also a substantial level of commercial deployment, which, in turn, requires a significant market for CO2 capture technologies. At present such a market does not yet exist. While various incentive programs can accelerate the development and deployment of improved CO2 capture systems, government actions that significantly limit CO2 emissions to the atmosphere ultimately are needed to realize substantial and sustained reductions in the future cost of CO2 capture.
The use of log-linear experience curves (or learning curves) relating reductions in the unit cost of technologies to their cumulative production or installed capacity has become a common method of representing endogenous technical change in energy-economic models used for policy analysis. Yet, there are significant uncertainties in such formulations whose impact on key model results have been insufficiently examined or considered. This paper reviews the major types of uncertainty in log-linear experience curves and their effect on projected rates of cost reduction. Uncertainties are found not only in the learning rate parameter of a log-linear model, but also in the functional form that determines the shape of an experience curve. Evidence for alternative forms such as an S-shaped curve is reviewed along with case studies that demonstrate the uncertainties associated with cost increases during early commercialization of a technology—a phenomena that is widely recognized but rarely quantified or incorporated in learning models. Additional factors discussed include the effects of learning discontinuities, institutional forgetting, and the influence of social, economic and political factors. We then review other models of causality, which aim to improve modelers’ ability to explain and predict the influence of other underlying processes that contribute to technology cost reductions in addition to learning. Ignoring other types of underlying mechanisms can create a false sense of precision and overestimate the true contribution of learning. Currently, however, uncertainties in such multi-factor models remain large due to the difficulties of estimating key parameters (such as private-sector R&D investments) and extending models of a specific technology to a broader suite of technologies and cost projections. Pending the development and validation of more robust models of technological change, we suggest ways to significantly improve the characterization and reporting of current learning model uncertainties and their impacts on the results of energy-economic models to help reduce the potential for drawing inappropriate or erroneous policy conclusions.
This paper demonstrates the concept of applying learning curves in a consistent manner to performance as well as cost variables in order to assess the future development of power plants with CO2 capture. An existing model developed at Carnegie Mellon University, which had provided insight into the potential learning of cost variables in power plants with CO2 capture, is extended with learning curves for several key performance variables, including the overall energy loss in power plants, the energy required for CO2 capture, the CO2 capture ratio (removal efficiency), and the power plant availability. Next, learning rates for both performance and cost parameters were combined with global capacity projections for fossil-fired power plants to estimate future cost and performance of these power plants with and without CO2 capture. The results of global learning are explicitly reported, so that they can be used for other purposes such as in regional bottom-up models. Results of this study show that IGCC with CO2 capture has the largest learning potential, with significant improvements in efficiency and reductions in cost between 2001 and 2050 under the condition that around 3100 GW of combined cycle capacity is installed worldwide. Furthermore, in a scenario with a strict climate policy, mitigation costs in 2030 are 26, 11, 19 €/t (excluding CO2 transport and storage costs) for NGCC, IGCC, and PC power plants with CO2 capture, respectively, compared to 42, 13, and 32 €/t in a scenario with a limited climate policy. Additional results are presented for IGCC, PC, and NGCC plants with and without CO2 capture, and a sensitivity analysis is employed to show the impacts of alternative assumptions on projected learning rates of different systems.
Given the dominance of power plant emissions of greenhouse gases, and the growing worldwide interest in CO2 capture and storage (CCS) as a potential climate change mitigation option, the expected future cost of power plants with CO2 capture is of significant interest. Reductions in the cost of technologies as a result of learning-by-doing, R&D investments and other factors have been observed over many decades. This study uses historical experience curves as the basis for estimating future cost trends for four types of electric power plants equipped with CO2 capture systems: pulverized coal (PC) and natural gas combined cycle (NGCC) plants with post-combustion CO2 capture; coal-based integrated gasification combined cycle (IGCC) plants with pre-combustion capture; and coal-fired oxyfuel combustion for new PC plants. We first assess the rates of cost reductions achieved by other energy and environmental process technologies in the past. Then, by analogy with leading capture plant designs, we estimate future cost reductions that might be achieved by power plants employing CO2 capture. Effects of uncertainties in key parameters on projected cost reductions also are evaluated via sensitivity analysis.
This paper examines the cost of CO(2) capture and storage (CCS) for natural gas combined cycle (NGCC) power plants. Existing studies employ a broad range of assumptions and lack a consistent costing method. This study takes a more systematic approach to analyze plants with an amine-based postcombustion CCS system with 90% CO(2) capture. We employ sensitivity analyses together with a probabilistic analysis to quantify costs for plants with and without CCS under uncertainty or variability in key parameters. Results for new baseload plants indicate a likely increase in levelized cost of electricity (LCOE) of $20-32/MWh (constant 2007$) or $22-40/MWh in current dollars. A risk premium for plants with CCS increases these ranges to $23-39/MWh and $25-46/MWh, respectively. Based on current cost estimates, our analysis further shows that a policy to encourage CCS at new NGCC plants via an emission tax or carbon price requires (at 95% confidence) a price of at least $125/t CO(2) to ensure NGCC-CCS is cheaper than a plant without CCS. Higher costs are found for nonbaseload plants and CCS retrofits.