Energy Storage: Hybridization of Power-to-Gas Technology and Carbon Capture (SpringerBriefs in Energy) 3030465268, 9783030465261

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Manuel Bailera Pilar Lisbona Begoña Peña Luis M. Romeo

Energy Storage Hybridization of Power-to-Gas Technology and Carbon Capture

Energy Storage

Manuel Bailera Pilar Lisbona Begoña Peña Luis M. Romeo •

•

•

Energy Storage Hybridization of Power-to-Gas Technology and Carbon Capture

123

Manuel Bailera Department of Mechanical Engineering School of Engineering and Architecture University of Zaragoza Zaragoza, Spain Begoña Peña Department of Mechanical Engineering School of Engineering and Architecture University of Zaragoza Zaragoza, Spain

Pilar Lisbona Aragonese Foundation for Research & Development (ARAID) Zaragoza, Spain Luis M. Romeo Department of Mechanical Engineering School of Engineering and Architecture University of Zaragoza Zaragoza, Spain

ISBN 978-3-030-46526-1 ISBN 978-3-030-46527-8 https://doi.org/10.1007/978-3-030-46527-8

(eBook)

© The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2020 This work is subject to copyright. All rights are solely and exclusively licensed by the Publisher, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publisher, the authors and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publisher nor the authors or the editors give a warranty, expressed or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publisher remains neutral with regard to jurisdictional claims in published maps and institutional affiliations. This Springer imprint is published by the registered company Springer Nature Switzerland AG The registered company address is: Gewerbestrasse 11, 6330 Cham, Switzerland

Acknowledgements

The work described in this paper is supported by the R+D Spanish National Program from Ministerio de Ciencia, Innovación y Universidades (Ministry of Universities, Science and Innovation) and the European Regional Development Funds (European Commission), under project ENE2016-76850-R. This work has also been supported by the Government of Aragon and co-financed by FEDER 2014–2020 “Construyendo Europa desde Aragón” (Research Group DGA T46_17R, and project LMP134_18).

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Contents

1 The Role of Energy Storage and Carbon Capture in Electricity Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 Energy Storage Technologies . . . . . . . . . . . . . . . . . . . . . 1.2.1 Types of Energy Storage . . . . . . . . . . . . . . . . . . . 1.2.2 Energy Storage Services . . . . . . . . . . . . . . . . . . . . 1.2.3 Power to Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3 Carbon Capture Technologies and Decarbonisation Routes 1.3.1 Carbon Capture Technologies . . . . . . . . . . . . . . . . 1.3.2 Carbon Utilization Technologies . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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2 Integration of Power to Gas and Carbon Capture . . . . . . . . . . . 2.1 Power to Gas and Carbon Capture . . . . . . . . . . . . . . . . . . . . . 2.1.1 Sizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.2 Energy Requirements . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.3 End-Use of Produced Gas and CO2 Emissions . . . . . . 2.1.4 Water Utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.5 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 Configurations for the Integration of Power to Gas and Carbon Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.1 Amine Carbon Capture Integrated with CO2 Recycled . 2.2.2 Oxyfuel Combustion with CO2 Recycled . . . . . . . . . . 2.2.3 Comparison of Technologies . . . . . . . . . . . . . . . . . . . 2.3 The Implications of Transient Operation in Power to Gas (Energy Storage) Applications . . . . . . . . . . . . . . . . . . . . . . . . 2.3.1 Storage Vessels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.2 Operational Hours, Sizing and Economic Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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3 Status Review of PtG-CCU Hybridization . . . . . . . . . . . . . . 3.1 Power to Gas Within the Context of Hybrid Technologies for Storing Energy and CO2 . . . . . . . . . . . . . . . . . . . . . . 3.2 Overview of Power to Gas Technology . . . . . . . . . . . . . . 3.2.1 Electrolysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.2 Methanation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3 Research Projects on PtG-CCU Hybridization . . . . . . . . . 3.3.1 Projects Based on Biological Methanation . . . . . . . 3.3.2 Projects Based on Catalytic Methanation . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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4 Integration of Oxy-Fuel Combustion and Power to Gas . . . . . . 4.1 Concept and Technical Description . . . . . . . . . . . . . . . . . . . 4.1.1 Oxy-Fuel Boiler Integrated with Power to Gas . . . . . 4.2 Operational Ranges of the Hybrid System and Fuel Influence 4.3 Potential Applications and Case Studies . . . . . . . . . . . . . . . . 4.3.1 Renewable Back-Up Power in Combined Cycles . . . . 4.3.2 District Heating . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.3 Cogeneration in Urban Buildings . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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5 Integration of Amine Scrubbing and Power to Gas . . . . . . . . . 5.1 Description and Technical Assessment . . . . . . . . . . . . . . . . . 5.1.1 Amine Scrubbing Integrated with Power to Gas . . . . 5.2 Potential Applications and Case Studies . . . . . . . . . . . . . . . . 5.2.1 Power to Gas-Electrochemical Industry Hybridization 5.2.2 Power to Gas-Nuclear Power Hybridization . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Chapter 1

The Role of Energy Storage and Carbon Capture in Electricity Markets

Carbon capture and energy storage technologies will play an important role in the future energy system under high share of renewable electricity generation. This chapter reviews the energy storage technologies, with special attention to the potential use in electricity grid services, and the current status of CO2 capture technologies. The Power to Fuel concept emerges as the natural bridge between energy and CO2 storage and integrates in a smart energy system to all the involved sectors: power, transport, building and industry.

1.1 Introduction Global warming is nowadays unequivocal and extensively endorsed by scientific community. In 2016, the global land-ocean surface temperature had increased 1.26 °C with respect to the pre-industrial period (1880–1920), and the mean sea level had risen 0.23 m [1]. Heat waves occur more often and last longer, while extreme precipitations have become more intense and frequent [2]. According to the IPCC, this has affected many species that have shifted their geographic ranges, seasonal activities or migration patterns in response to ongoing climate changes. Moreover, hydrological systems are continuously altered, what harms fresh water resources and food production [2]. Carbon dioxide is the largest single contributor to these perturbations on Earth’s energy balance (greenhouse effect), and human beings are undoubtedly the main source [2]. Current atmospheric CO2 concentration is increasing at the fastest ever observed rate (2.0 ppm/yr), what made 2016 the first year in history in which CO2 concentration did not fall below 400 ppm at any time (Fig. 1.1) [3]. At the United Nations Climate Change Conference held in Paris at the end of 2015, about 190 countries agreed to reduce emissions of greenhouse gases (GHG). The aim is to limit

© The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2020 M. Bailera et al., Energy Storage, https://doi.org/10.1007/978-3-030-46527-8_1

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2

1 The Role of Energy Storage and Carbon Capture …

Fig. 1.1 Atmospheric CO2 concentration (ppm) [3]

global temperature increase below 2 °C by the year 2100, related to pre-industrial levels [4]. However, those scenarios that limit warming to 2 °C would require CO2 atmospheric concentrations below 450 ppm, which will be hardly accomplishable [2]. As the International Energy Agency stated [5], key measures to achieve such mitigation lie in decarbonizing electricity and heat generation sector, since it produces more than two-fifths of global CO2 emissions (Fig. 1.2) [6]. This is particularly notable in China, where total electricity output almost quadrupled since 2000 mainly based on carbon intensive coal-fired power plants. In North America, the shift from coal towards natural gas, together with improvements in generation efficiency, allowed them to slightly reduce their CO2 emissions related to the electricity sector. Meanwhile, Europe established in 2009 a common policy (Directive 2009/28/EC) [7] to achieve renewable shares of 34 and 21% in the electricity and heat sectors by

Fig. 1.2 World CO2 emissions by sector, 2016. Data taken from [6]

1.1 Introduction

3

2020. This clearly boosted the decarbonization of the European energy system, what have reduced the associated emissions more than a 12% since then [8]. Hence, the European Commission proved the relevance of largely deploying renewable energy sources (RES) to help palliating climate change. Most of European Member States are expected to meet their 2020 renewable energy targets [9], and Europe aims to produce the 53% of its electricity with renewable sources by 2050 [10]. However, moving in this direction implies large amounts of intermittent energy production in the electricity market [11] that difficult the balance between power generation and demand. The most recent data from Eurostat (2016) [12, 13] indicates that 29.6% of the European electricity came from renewable sources (917 TWh). This was mostly composed by hydropower (368 TWh), wind power (291 TWh) and solar power (90 TWh). Hydropower does not represent an issue, since hydro-electric plants handle short-term variability thanks to dams and reservoirs. However, wind and solar power exhibit a highly intermittent and variable dispatch that cannot be suitably managed. Photovoltaic production has a peak around noon as well as significant variations over minutes or hours due to cloud coverage. Besides, wind generation significantly fluctuates over periods of days to weeks, and needs to be balanced [11]. Generators and system operators can typically change and control just the 5–10% of the output coming from these types of plants (the degree of control in Spain is about 5%, in Sweden 6% and in Germany 7%) [14]. Thus, this varying nature leads to mismatches between supply and electrical demand that diminish the operational predictability and stability of the energy system. Traditionally, irregularities are balanced through fossil-based regulation, which keeps frequency and voltage within a stable range. Nowadays, due to the growing renewable share, fossil fuel power plants are compelled to additionally increase their flexibility and availability beyond the classic behavior of a backup facility. This kind of operation deteriorates the equipment of the power plants, and causes drops in efficiency that lead to additional CO2 emission. For instance, 50% partial loads imply efficiency falls from 55 to 35% in combined cycles (427 g CO2 /kWh increases to 670 g CO2 /kWh), and losses of 10 percentage points in coal-fired power plants (987 g CO2 /kWh increases to 1316 g CO2 /kWh) [14, 15]. In conclusion, increasing renewable share under current scenario actually leads to instability and safety drawbacks in the energy networks, together with an increment in specific CO2 emissions from the fossil-based backup power. Therefore, the key for a successful energy transition is an efficient management of these intermittent RES. Facing such situation, the European Commission proposed energy storage to overcome these problems [11]. Energy storage can balance both centralized and distributed electricity generation, as well as contribute to the decarbonization of other sectors such as transport, buildings or industry, by applying on them the stored renewable energy. Hence, the European Commission aims to progressively remove market, regulatory and administrative barriers affecting storage facilities, so that storage operators can provide services to electricity system operators in the same way that current flexibility solutions do [11].

4

1 The Role of Energy Storage and Carbon Capture …

This introductory chapter gathers the different energy storage technologies, including classification and comparative assessment of development status and suitable applications, and the energy storage services where are applicable. Additionally, the carbon capture storage and utilization (CCSU) technologies are overviewed with special focus to their capability of hybridization with power generation and storage systems.

1.2 Energy Storage Technologies Power systems use a wide variety of energy storage technologies (EST) to guarantee the required balance between demand and generation. Storage systems must satisfy multiple interrelated factors, which are sometimes incompatible: high specific energy, high specific power, suitable temperature operation range, high response time, security and reliability, low operation and capital costs, long lifetime and low self-discharge, among others. According to the nature of the storage processes, EST are usually classified into five categories (Fig. 1.3): mechanical, thermal, chemical, electrochemical and electrical systems. Given the intrinsic complexity of electricity network, the storage solution is not unique and the different storage technologies must coexist because their different nature and characteristics make them suitable for different applications. Mobile applications include autonomous and non-autonomous vehicles, such as trains or trams. Stationary applications, which are the main topic of this book, include stand-alone and grid connected power systems. In the latter case, the objective of energy storage system can be oriented to ensure power continuity and quality (energy services) or

Fig. 1.3 Electricity energy storage systems. Adapted from [11]

1.2 Energy Storage Technologies

5

to decoupling generation from demand (energy management). In this section, the different types of energy storage, as well as the services they may provide to the grid operator, are briefly reviewed, paying attention to the current technical readiness level (TRL), commercial deployment and capacity of hybridization with other technologies as CO2 capture.

1.2.1 Types of Energy Storage Attending to the form of storage, technologies can be classified in mechanical, thermal, chemical, electro-chemical and electrical (Fig. 1.3). The following subparagraphs summarize the concept and state of development of the different technologies, while techno-economic data are gathered in Table 1.1 [16–22].

1.2.1.1

Mechanical

Mechanical storage systems stores electricity excess into different mechanical forms to be later reconverted into electricity and discharged to the grid when it is required. The working principle varies from potential or kinetic energy to pressurized fluids or forced springs. Nowadays, mechanical storage technologies are the most used because of their maturity, flexibility and capacity [21]. Pumped Hydroelectric Energy Storage This technology stores electricity as potential energy by pumping water from a lower reservoir to a higher level reservoir. When it is required to dispatch electricity, water is returned to the lower reservoir to produce power through hydro turbines. Reversible turbines/generators are used in this type of systems. Installed capacities of 1000–1500 MW are common nowadays, although the most typical size globally still remains in the range of 300–400 MW [23]. Total installed capacity worldwide is around 130 GW, from which Japan (24.5 GW), China (22.6 GW) and USA (20.5 GW) are the top contributors [24]. There is a significant growth potential for this technology but it is subject to restrictions imposed by its environmental and social impacts [21]. Dry Gravitational Energy Storage Dry gravitational energy storage stores electricity surplus or low cost electricity by the elevation of massive objects against the force of gravity, and recovers the stored energy as the mass is returned to its original location. The energy losses over time once the train has reached high elevation are zero. This technology, based in concrete blocks transported in rail road shuttles, has been tested successfully in the pilot project Advanced-rail energy storage (ARES) in Tehachapi (California, USA). Its first commercial deployment is under development in Pahrump (Nevada, USA) and will tie into the California electrical grid [25]. A similar concept is the technology of

Power rating (MW)

3–15

5–300

0–9

2–100

CAES overground

CAES underground

Flywheel (steel/composite)

Liquid air (LAES)

1–60

High temperature

0–50

0–20

Q40 ) or operates with support of H2 buffer or stored SNG (Q100 > Qd ≥ QH2 > Q40 ). When necessary, next step checks if the total hydrogen (PH2 + Pb ) is enough to operate the methanation system (PH2 + Pb > P40 ) or, on the contrary, methanation will be turned off and the hydrogen production will be stored while the thermal demand is covered by the gas  network (just SNG or SNG plus purchased natural gas, depending on the case). If PH2 + Pb > P100 , the extra energy is stored in hydrogen buffer and, if possible, as SNG in the network. Finally, the thermal energy generated that can be generated with own fuels (QH2 + Qn + Qb ) is compared with the thermal demand, to identify situations of self-consumption or cases in which the purchase of natural gas is necessary. Thus, a total of 35 potential cases can be identified, which are thoroughly described in [20].

106 Fig. 4.13 Decision tree for managing the integrated system (PV solar, oxy-fuel boiler and Power to Gas) with H2 buffer and SNG storage [20]

4 Integration of Oxy-Fuel Combustion and Power to Gas

References

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References 1. M. Bailera, D.P. Hanak, P. Lisbona, L.M. Romeo, Techno-economic feasibility of power to gas–oxy-fuel boiler hybrid system under uncertainty. Int. J. Hydrogen Energy 44, 9505–9516 (2019). https://doi.org/10.1016/j.ijhydene.2018.09.131 2. Y. Hu, X. Li, H. Li, J. Yan, Peak and off-peak operations of the air separation unit in oxy-coal combustion power generation systems. Appl. Energy 112, 747–754 (2013). https://doi.org/10. 1016/j.apenergy.2012.12.001 3. A.S. Tijani, N.A.B. Yusup, A.H.A. Rahim, Mathematical modelling and simulation analysis of advanced alkaline electrolyzer system for hydrogen production. Procedia Technol. 15, 799–807 (2014). https://doi.org/10.1016/j.protcy.2014.09.053 4. P. Dieguez, A. Ursua, P. Sanchis, C. Sopena, E. Guelbenzu, L. Gandia, Thermal performance of a commercial alkaline water electrolyzer: experimental study and mathematical modeling. Int. J. Hydrogen Energy. 33, 7338–7354 (2008). https://doi.org/10.1016/j.ijhydene.2008.09.051 5. J. Kopyscinski, T.J. Schildhauer, S.M.A. Biollaz, Production of synthetic natural gas (SNG) from coal and dry biomass—a technology review from 1950 to 2009. Fuel 89, 1763–1783 (2010). https://doi.org/10.1016/j.fuel.2010.01.027 6. BOE-A-2013-185, Resolución de 21 de diciembre de 2012, de la Dirección General de Política Energética y Minas, por la que se modifica el protocolo de detalle PD-01, Ministerio de Industria, Energía y Turismo (2013) 7. T.T.M. Nguyen, L. Wissing, M.S. Skjøth-Rasmussen, High temperature methanation: catalyst considerations. Catal. Today 215, 233–238 (2013). https://doi.org/10.1016/j.cattod.2013. 03.035 8. K. Pedersen, J. Sehested, High temperature methanation. Sintering and structure sensitivity. Appl. Catal. A. Gen. 330, 134–138 (2007). https://doi.org/10.1016/j.apcata.2007.07.015 9. S. Heyne, M.C. Seemann, S. Harvey, Integration study for alternative methanation technologies for the production of synthetic natural gas from gasified biomass. Chem. Eng. Trans. 21, 409–414 (2010). https://doi.org/10.3303/CET1021069 10. J. Gao, Y. Wang, Y. Ping, D. Hu, G. Xu, F. Gu, F. Su, A thermodynamic analysis of methanation reactions of carbon oxides for the production of synthetic natural gas. RSC Adv. 2, 2358 (2012). https://doi.org/10.1039/c2ra00632d 11. J. Agersborg, E. Lingehed, Integration of Power-to-Gas in Gasendal and GoBiGas (Chalmers University of Technology, 2013). http://publications.lib.chalmers.se/records/fulltext/182610/ 182610.pdf 12. M. Bailera, P. Lisbona, L.M. Romeo, S. Espatolero, Power to Gas–biomass oxycombustion hybrid system: energy integration and potential applications. Appl. Energy 167, 221–229 (2016). https://doi.org/10.1016/j.apenergy.2015.10.014 13. F. Climent Barba, G. Martínez-denegri Sánchez, B. Soler Seguí, H. Gohari Darabkhani, E. John Anthony, A technical evaluation, performance analysis and risk assessment of multiple novel oxy-turbine power cycles with complete CO2 capture. J. Clean. Prod. 133, 971–985 (2016). https://doi.org/10.1016/j.jclepro.2016.05.189 14. S. Sharma, S.K. Ghoshal, Hydrogen the future transportation fuel: from production to applications. Renew. Sustain. Energy Rev. 43, 1151–1158 (2015). https://doi.org/10.1016/j.rser.2014. 11.093 15. M. Bailera, N. Kezibri, L.M. Romeo, S. Espatolero, P. Lisbona, C. Bouallou, Future applications of hydrogen production and CO2 utilization for energy storage: Hybrid Power to GasOxycombustion power plants, Int. J. Hydrogen Energy. 1–8 (2017). https://doi.org/10.1016/j. ijhydene.2017.02.123 16. M. Kanniche, R. Gros-Bonnivard, P. Jaud, J. Valle-Marcos, J. Amann, Pre-combustion, postcombustion and oxy-combustion in thermal power plant for CO capture. Appl. Therm. Eng. 30, 53 (2009) 17. Jean M. De Saint, P. Baurens, C. Bouallou, K. Couturier, Economic assessment of a power-tosubstitute-natural-gas process including high-temperature steam electrolysis. Int. J. Hydrogen Energy 40, 6487–6500 (2015). https://doi.org/10.1016/j.ijhydene.2015.03.066

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18. D. Ferrero, M. Gamba, A. Lanzini, M. Santarelli, Power-to-Gas Hydrogen: techno-economic assessment of processes towards a multi-purpose energy carrier. Energy Procedia 101, 50–57 (2016). https://doi.org/10.1016/j.egypro.2016.11.007 19. T. Nussbaumer, S. Thalmann, Status Report on District Heating Systems in IEA Countries (2014) 20. M. Bailera, B. Peña, P. Lisbona, L.M. Romeo, Decision-making methodology for managing photovoltaic surplus electricity through power to gas: combined heat and power in urban buildings. Appl. Energy 228, 1032–1045 (2018). https://doi.org/10.1016/j.apenergy. 2018.06.128

Chapter 5

Integration of Amine Scrubbing and Power to Gas

Abstract Among the different Power to Gas hybridizations proposed to improve the efficiency of PtG energy storage technology, the integration with amine scrubbing process as carbon source is the most mature option. The concept, main operation parameters and points of integration are described in the first section of this chapter. Two application cases are also presented to illustrate the real operation and efficiencies of the concept. First, an integration with electrochemical industry is presented. This configuration, which appears to be economically feasible under current scenario, avoids the typical water electrolysis stage of PtG since hydrogen is available. A second case study describes a new concept to control nuclear power production through the joint operation of a nuclear power plant, a coal power plant with amine scrubbing capture and a PtG plant. The cost effectiveness of this technology and its capability to reduce the CO2 emissions are assessed through the design and economic and environmental analysis of a hybrid facility.

5.1 Description and Technical Assessment There are alternatives to the hybrid oxy-combustion Power to Gas systems, presented in Chap. 4, to connect the electric and gas grids to store electricity. A suitable option to supply the required source of CO2 for methanation is the use of amine scrubbing technology in postcombustion systems. This carbon capture technology, patented in 1930, is based in the absorption of CO2 from a fuel gas near ambient temperature into an aqueous solution of amine with low volatility. The amine is then regenerated by stripping with steam at 100–120 °C, and the water is condensed from the stripper outlet stream, leaving pure CO2 [1]. Methanation heat may be integrated and used for regenerating the solvent when amine capture technology is used (Fig. 5.1). If the concept is applied to a power plant or industrial process, the heat can be integrated in the thermal power cycle or process to increase their energy efficiency. Moreover, the energy requirements for CO2 conditioning (compression and purification for transport and disposal) are also avoided or reduced.

© The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2020 M. Bailera et al., Energy Storage, https://doi.org/10.1007/978-3-030-46527-8_5

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5 Integration of Amine Scrubbing and Power to Gas

Fig. 5.1 Concept of the energy system amine scrubbing-power to gas

The Amine-PtG hybrid system is the only one with commercial experience, the Audi e-gas project at Werlte in Lower Saxony, Germany, in operation since 2013 [2]. It is located next to a biogas plant which produces separate streams of biomethane and CO2 . This facility includes three alkaline water electrolyzers of 2.0 MW and produces up to 1300 m3 /h (NTP) of hydrogen. The CO2 separated by means of amine scrubbing is combined with the produced hydrogen in the methanation process to produce up to 325 m3 /h (NTP) of synthetic natural gas [3, 4]. The methanation process uses a catalytic process under high temperature (300–400 °C) and pressure. This plant is qualified to participate in the electricity balancing market, and the availability of the renewable energy consumed gives about 4000 operating hours per year [4, 5].

5.1.1 Amine Scrubbing Integrated with Power to Gas Chemical absorption by amine scrubbing has been considered the most suitable technology for CO2 capture to be integrated with existing flue gas streams as sources of carbon. Figure 5.2 illustrates the main mass and energy flows involved in the process. Flue gas from a typical boiler must be cooled down to around 70 °C before being introduced at the bottom of the absorber or scrubber. The solvent (lean amine

Fig. 5.2 Layout of the amine scrubbing integrated with power to gas

5.1 Description and Technical Assessment 111

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5 Integration of Amine Scrubbing and Power to Gas

solution) is introduced at the top of the scrubber. Absorption reactions take place in the absorber between the solution of amine—commonly monoethanolamine (MEA)— and the CO2 flowing counter current. Vent gas leaves absorber at the top of the scrubber and a solution of CO2 and aqueous MEA (rich amine solution) leaves the column at the bottom. Then, the temperature of the rich amine solution must be increased from in a heat exchanger (rich/lean exchanger) before being introduced at the top of the second reactor. This reactor is the stripper where the absorbent is regenerated and the CO2 released. This process takes place at temperatures around 100 °C and, therefore, steam is required in the step of amine regeneration. Steam is generated in the reboiler whose temperature is limited to 120 °C to prevent high amine degradation rates and corrosion issues. The lean amine solution leaves stripper at temperatures near 100 °C and is fed to the heat exchanger to transfer part of its sensible heat to the rich amine solution flow. An additional cooler is required to further reduce solvent temperature prior to enter again the stripper. Finally, most of the water content in the CO2 flow leaving the stripper is removed in the condenser. A high purity CO2 gas flow leaves flash separator and this stream may be directly fed into the methanation plant as carbon source for methane production. The description of methanation plant or electrolysis stage presented in Chap. 4 for Fig. 4.2 may be revisited to describe also Fig. 5.2. The most significant difference is the presence of the condenser at the outlet of the stripper which reduces to two the number of condensers in the methanation plant in Fig. 5.2. The second large difference between both schemes is the presence of a compression train taken into consideration for the CO2 stream from the carbon capture plant which cannot be consumed in the methanation plant. However, amine scrubbing hybridation with PtG could also present a surplus of CO2 which should be directed to transport and storage.

5.1.1.1

Definition of Efficiencies

The energy efficiencies of the subsystems which conform the proposed integrated concept are defined by Eqs. 5.1 to 5.3. Equation 5.1 presents the efficiency of the electrolyzer where the chemical energy content of the hydrogen produced per unit of time is compared to the electric power consumed. Methanation plant efficiency is calculated through Eq. 5.2, comparing the chemical energy of the synthetic gas at the outlet of the methanation facility with the chemical energy of the input flow of hydrogen and the compression of the inlet gases, and blowers. Lastly, Eq. 5.3 expresses the efficiency of the Power to Gas subsystem. All of these efficiencies are the ratios between useful energy output and energy input for the different control volumes. ηele =

LHVH2 m˙ H2 W˙ ele

(5.1)

5.1 Description and Technical Assessment

ηmeth =

113

LHVSNG m˙ SNG LHV H2 m˙ H2 + W˙ aux, meth

(5.2)

LHVSNG m˙ SNG ˙ Wele + W˙ aux, meth

(5.3)

ηptG =

Since the amine scrubbing capture plant has no energetic purpose, no energy efficiency is defined for this system. However, its energy requirements (heat in the reboiler and electric power for auxiliaries) are included when the global efficiency is calculated. The overall efficiency of the hybrid plant, integrating methanation heat, Q˙ m , as useful heat, is given by Eq. 5.4. ηPtG + amine =

LHVSNG m˙ SNG + Q˙ m . Q˙ reboiler + W˙ aux, amine + W˙ ele + W˙ aux, meth

(5.4)

Depending on the operation of the system, the electric consumption of the compression train of CO2 surplus should be included among the energy inputs demanded in the hybrid system in the denominator of Eq. 5.4.

5.2 Potential Applications and Case Studies This section presents two potential applications of a Power to Gas system whose carbon source is provided by an amine scrubbing capture plant. As previously highlighted, this configuration requires the pre-existence of a combustion stage which produces a flue gas stream. First, electrochemical industry hybridization with PtG is analysed, a type of integration that implements methanation in chemical plants whose lines of production are based on chemical electrolysis. Chemical electrolytic process generates hydrogen as by-product which can be easily integrated in a PtG process (Fig. 5.3). Therefore, PtG-Electrochemical combination avoids the water electrolysis stage and its large demand of electricity since hydrogen is already available in the plant. In parallel, CO2 emissions from the boiler in the electrochemical plant are captured by

Fig. 5.3 Layout of the electrochemical plant integrated with power to gas

114

5 Integration of Amine Scrubbing and Power to Gas

Fig. 5.4 Lay-out of the nuclear power plant integrated with power to gas

an amine scrubbing facility and fed to a TREMP methanation plant. The available heat from methanation must be properly integrated in the amine scrubbing capture plant through an optimized heat exchanger network. Secondly, the analysis of the utilization of PtG technology to store electricity from nuclear power plants in the form of synthetic methane is presented. In this case, the source of carbon dioxide is an amine scrubbing plant which capture carbon from flue gas of a coal-fired power plant to reduce their net emission (Fig. 5.4). The application of the proposed solution is assessed for a system consisting of a nuclear power plant, a coal-fired power plant with amine carbon capture, and a Power to Gas plant. The management of the coal-fired power plant to avoid partial load whenever the plant is operative is the main objective of this configuration.

5.2.1 Power to Gas-Electrochemical Industry Hybridization In PtG-Electrochemical industry hybridizations, the electricity demanded is partially consumed in the facility and partially stored. This concept avoids the largest capital cost of water electrolyzers and a significant share of operational costs related to electricity consumption in Power to Gas plants. These costs are removed since hydrogen is directly provided as a by-product through other already existing electrochemical processes in the plant. The case study presented in the following describes an existing industrial facility with a significant amount of available by-product hydrogen produced in two electrolytic production lines: sodium chlorate (NaClO3 ), Eq. (5.5), and chlorine (Cl2 ) and potassium hydroxide (KOH), Eq. (5.6). NaCl + 3H2 O ↔ NaClO3 + 3H2

(5.5)

2KCl + 2H2 O ↔ 2KOH + Cl2 + 3H2

(5.6)

5.2 Potential Applications and Case Studies

115

In the actual configuration of the facility, both sources of hydrogen are purified and mixed for further use. Half of the hydrogen is devoted to ammonia production (NH3 ), one quarter to hydrochloric acid (HCl), the 20% to hydrogen peroxide (H2 O2 ); the remaining hydrogen is vented. Given the higher profitability of natural gas, the proposed hybridization makes use of the hydrogen originally fed into the ammonia line, to the production of methane. Methanation process would consume CO2 from a boiler existing in the plant. Additionally, energy penalty of the amine capture plant is buffered through the integration of the heat released in the methanation reaction in the production of steam. This case study explores three relevant issues: (i) the hourly distribution of the H2 availability, (ii) the modelling and simulation of the hybrid plant, and (iii) the assessment of the economic feasibility [6].

5.2.1.1

Evaluation of Hydrogen Availability and Plant Sizing

The chemical electrolysis lines present intensive energy consumptions, so their operation must follow the electrical market to reduce the operational costs. Since the electrochemical industry mainly operates during off-peak periods, the availability of hydrogen varies with electricity market (Table 5.1). This oscillation will also affect to the share of the flow of carbon dioxide produced in the boiler which will be required in methanation. January and February show potential CO2 utilizations below 60%, whilst CO2 usage capability is over 90% in August. The maximum potential consumption of CO2 in yearly basis achieves the 68% of total emissions. This value is limited whenever the methanation plant must operate at partial load due to low H2 production or low availability of CO2 . The hourly production pattern of H2 is Table 5.1 Available H2 and share of CO2 usable in PtG

Month

Available H2 [km3 (NTP)]

Max. usable CO2 (%)

January

1058

51

February

1067

57

March

1253

68

April

1260

67

May

1175

66

June

1116

89

July

949

61

August

1670

92

September

1179

61

October

1303

89

November

1078

76

December

1007

53

14,115

68

Total

116

5 Integration of Amine Scrubbing and Power to Gas

Table 5.2 Rates of H2 production and electrolysis parameters, for the six market periods NaCl electrolysis

KCl electrolysis

P1

P2–P5

P6

P1

P2–P5

P6

V˙H2 (Nm3 /h) V˙H2 NH3 (Nm3 /h)

0

2333

3629

486

689

1296

0

1166

1814

0

344

648

h (h/year)

0

1581

4584

570

2846

4584

analysed to determine the actual potential of integrating Power to Gas in a given electrochemical plant. The price of electricity takes different values depending on the periods (P1 to P6) established by Spanish legislation [7, 8]. Thus, the plant accordingly adapts to mostly operate within the most economic period, P6, as well as reduces the production load during periods P1 to P5. The hourly availability of H2 along the whole year is completely defined by also considering the unplanned shutdowns. The operating hours of the electrochemical plant throughout periods P1 to P6 are summarized in Table 5.2. The largest hydrogen production occurs when both chemical electrolysis lines simultaneously operate at Period 6 providing a maximum flow of 4926.0 m3 /h (NTP). Only the amount of hydrogen used to currently produce ammonia will be transferred to methanation plant. During period P1, hydrogen production is very limited given the cost of electricity. Therefore, there is no hydrogen available for methanation during this period. The boiler of the electrochemical plant, which acts as CO2 source, is operative 24 h/day, except when the facility is closed. Hence, monthly emissions are equally divided among operating days. Hydrogen availability The hydrogen was assessed for a reference year (2014) taking into account the amount of hydrogen available for each period presented in Table 5.2 and the planned and unplanned shutdowns of the facility. Most of the time, the boiler supplies enough CO2 to methanize all the produced hydrogen. The limited emissions during months like November temporally makes CO2 insufficient at H2 peaks; i.e. it occurred 1344 h during the reference year. This situation forces the storage of part of the available H2 . There are also periods in which the hydrogen production is too low to reach the minimum operating load of the methanation plant; 60% according to [9]. In those cases, the plant must be shutteddown and both resources (CO2 , H2 ) must be stored. Therefore, the maximum use of CO2 and H2 , α i , is limited to 62.5% and 91.9% respectively may be calculated through Eq. (5.7) which represents the amount consumed each hour, vi, j [m3 (NTP)] divided by the sum of the available amount, vi,j [m3 (NTP)]. The number of operating hours, j, varies from 1 to 8760. VH2 ,ptG stands for the nominal hourly H2 input of the methanation plant. For maximum usage, vH2 ,ptG is 2462.9 m3 (NTP), which is the available H2 when both lines of production operate at P6 (Table 5.2).

5.2 Potential Applications and Case Studies

 αi = 

j

vi, j

j

vi, j

117

⎧  ⎪ ⎨ vi, j = 0 if vH2 , j ≤ 0.6 VH2 ,PtG i = H2 vi, j = vH2 , j if 0.6 VH2 ,PtG < vH2 , j ≤ 4 vC O2 , j ⎪ ⎩ v = 4 v CO2 , j if 4 vCO2 , j < vH2 , j ⎧i, j · 100  ⎪ ⎨ vi, j = 0 if vH2 , j ≤ 0.6 VH2 ,PtG i = CO2 vi, j = vH2 , j /4 if 0.6 VH2 ,PtG ≤ vH2 , j ≤ 4 vCO2 , j ⎪ ⎩ v = v CO2 , j if 4 vCO2 , j < vH2 , j i, j (5.7)

Methanation plant sizing The size of the hybrid plant was defined taking into account the following criteria (i) a minimum of 6000 operating hours, and (ii) a minimum 85% of H2 utilization for methanation. A storage tank for H2 is included in order to soften the intermittent supply of both resources. The sizing which minimizes the economic investment on equipment corresponds to a small H2 tank of 1000 m3 and a methanation plant of 6 MW H2 input (1998.7 m3 /h (NTP)), which leads to 6070 operating hours per year and 85.9% usage of the available hydrogen. The associated amine plant required to fulfill the requirements of methanation has a nominal output of 500 m3 /h (NTP) of CO2 , thus consuming up to the 58.2% of the emitted carbon.

5.2.1.2

PtG-Electrochemical Hybrid Plant Model

In this section, the Aspen Plus model of the proposed hybrid plant is presented. The thermal integration of the different heat streams was performed with Aspen Energy Analyzer through the Pinch analysis technique [10, 11]. Model of the amine scrubbing plant A monoethanolamine (MEA) absorption facility was designed and modelled in Aspen Plus [12] following a configuration similar to the capture process flowsheet presented in Fig. 5.2. Flue gas from the boiler is cooled down to 70 °C before entering the absorber to favour the exothermic absorption reaction (1.92 MJ/kgCO2 ) [13, 14]. Reaction takes place between the counter-flowing solvent and CO2 . The vent gas leaves the absorber at the top and the solution of CO2 and aqueous MEA leaves the column at the bottom The temperature of the rich amine solution is increased from 64 to 80 °C in the rich/lean heat exchanger before entering at the top of the stripper. Steam reboiler temperature is limited to 120 °C, in order to prevent high MEA degradation rates and corrosion problems. The solvent and CO2 will be separated in the stripper The lean amine solution leaves stripper at 103 °C and then transfers its energy to the rich amine solution flow decreasing temperature down to 87 °C. An additional cooler is required for reducing solvent temperature to 37 °C before being again introduced to the absorber.

118

5 Integration of Amine Scrubbing and Power to Gas

Besides operation temperature levels [15], the main assumptions required to accurately run the Aspen Plus model according to a quite conservative scenario [16, 17] were: (i) the MEA percentage in the absorption solvent was 20% wt., (ii) the solvent regeneration energy required in the stripper is below 6 GJ/tCO2 to obtain a concentrated CO2 flow over 94% vol., (iii) the capture efficiency of the amine scrubbing plant is over 90% (iv) facility size was set according to methanation plant requirements. Model of methanation plant The methanation scheme is based on TREMPTM technology [18] composed by three adiabatic reactors at 30 bar, a recycling loop in the first reactor, and an intermediate water condensation after the second stage, Fig. 5.2. Synthetic natural gas reaches 95 vol.% of methane. Adiabatic catalytic methanation given its greater potential for scalability and energy integration [19]. First, hydrogen and carbon dioxide lines are pressurized through two multi-stage compressors, increasing their temperature up to 300 °C. The outlet gas of the first reactor is cooled down to 300 °C and partially recirculated (72%) to this reactor. The temperature of the remaining flow is reduced to 250 °C prior entering into the second reactor. After this second absorption stage, water content normally exceeds a 60 vol.%, what inhibits the reaction. Hence, this water content is reduced to 13% through a first stage of condensation. Then, the syngas is preheated back to 250 °C for the third methanation stage. Last, water content is removed again in a second condensation stage to achieve the required SNG quality. The plant has been simulated in Aspen Plus considering pressure drops of 0.3 bar at methanation reactors and 0.6 bar at condensation tanks. Performance of the PtG-Electrochemical hybrid plant The amine scrubbing plant was designed once methanation plant was sized; 496 m3 /h (NTP) of CO2 nominal output. Table 5.3 presents the main results obtained from Aspen Plus simulation of the CO2 capture plant. The CO2 output from the amine plant meets the requirement of the reactors in the methanation plant. A total gas flow of 524.3 m3 /h (NTP) is produced from the stripper with a composition of 94.6 vol.% CO2 and 5.4 vol.% H2 O. While, the auxiliaries’ consumption in the capture plant (14.2 kW) is well below the consumption in the methanation plant (513.7 kW). Heating and cooling demands are significant, especially in the reboiler (1494.3 kW) and in the additional solvent cooler (−937.6 kW). The total auxiliary consumption of the methanation plant mostly comes from the multi-stage compressors, while blowers’ consumption represents less than 1%. Besides, whenever the plant is operating at full load and simultaneously storing H2 , the hydrogen compressor could require up to 495.6 kW. The simulated methanation plant produces 518.6 m3 /h (NTP) of SNG composed by 95.2 vol.% CH4 and 4.1 vol.% H2 . These figures make the produced SNG suitable for conventional applications (LHV of 49.8 MJ/kg, density of 0.694 kg/m3 (NTP), and Wobbe index of 49.76 MJ/m3 ). Relevant data of temperature, pressure and mass flows in the methanation plant are gathered in Table 5.4.

5.2 Potential Applications and Case Studies

119

Table 5.3 Results from CO2 capture plant simulation Absorber Design stages

14

Pressure (bar)

1

Top stage temperature (ºC)

63.5

Bottom stage temperature (ºC)

64.3

Reflux ratio

3.9

Boilup ratio

0.3

Stripper Design stages

14

Pressure (bar)

1

Top stage temperature (ºC)

88.9

Bottom stage temperature (ºC)

102.8

Reflux ratio

0.4

Boilup ratio

0.15

Reboiler type

Kettle

Thermal energy demand (GJ/tCO2 )

5.5

Concentrated CO2 flow Temperature (ºC)

34

Pressure (bar)

1

Volume flow (m3 /h (NTP))

524.3

Mass flow (kg/h)

997.5

Mole fraction (%) CO2

94.6

H2 O

5.4

O2

3 ppm

N2

132 ppm

Table 5.4 Molar compositions [%] in the methanation plant H2, in CO2

R1, in

R1, out

R2, out

R3, in

R3, out

SNG

94.6

9.9

4.3

1.3

3

0.2

0.3

100

0

41.5

19.6

6.2

14.3

3.3

4.1

CH4

0

0

15.5

24.5

30.2

69.7

76.8

95.2

H2 O

0

5.4

32.8

51.1

62.3

13

19.7

0.4

CO

0

0

0.3

0.5

0

0

0

H2

0

CO2, in

0

120

5 Integration of Amine Scrubbing and Power to Gas

The cooling and heating needs of the hybrid plant are 3675.3 kW and 1533.7 kW, respectively. Most of the heat requirement is associated to the desorption stage of the captured CO2 in the amine plant. Nevertheless, this external heating demand can be removed through the integration of the streams of both systems, which concurrently diminishes the cooling needs down to 2141.6 kW. Both resources are fed into the methanation plant at atmospheric pressure and near ambient temperature. After compression to 30 bar, the hydrogen flow of 1998.7 m3 /h (NTP) is heated up to 305.2 °C while CO2 stream reaches 287.4 °C. The mixture is introduced to reactor 1 where the first stage of methanation takes place. At the R1 outlet, the temperature is 582.7 °C. After cooling down the mixture down to 300 °C, part is recirculated to the same reactor and the remaining is directed to the next cooling stage before being introduced to the second stage of methanation. The stream is cooled down to 250 °C and then, introduced in R2. Once reaction takes place in the second reactor, the mixture leaves the equipment at 414.1 °C. The required step of water condensation reduces the temperature to 136.1 °C. Thus, the flow to the third stage of methanation will be heated up to 250 °C prior to being introduced. The mixture leaves the third reactor at 358 °C and the second condensation stage takes place at 40 °C. Moreover, the cooling necessities with high temperature level (R1 outlet) allow producing 238.8 kg/h of steam at 180 °C for the electrochemical plant; the remainder energy can be cooled with water since the temperatures to reach are not lower than 34 °C. The heating and cooling necessities in every equipment of the hybrid plant (amine capture plant, methanation plant and electrochemical plant) and the initial and final temperatures of the exchanging stream are characterized in Table 5.5. The minimum temperature difference between hot and cold streams for the design of the exchanger network is 10 °C. Figure 5.5 illustrates the optimized heat exchanger network after applying Pinch methodology to the case study. The black lines represent hot streams, while the grey lines stand for the cold streams [6].

5.2.1.3

Economic Analysis

First, the costs of the main equipment for the three processes (amine plant, methanation plant and optimized heat exchanger network) were gathered. Then, total capital investment (CAPEX) was completed with other direct and indirect costs. The operating cost (OPEX) includes production costs, which consist of the O&M, electricity, cooling water, MEA and catalyst renovation. Regarding the economic incomes, two concepts were considered: natural gas (NG) and medium pressure (MP) steam produced in the optimized HEN. This steam is used in the electrochemical industry and hence, can be considered as an input from the network. Meanwhile, natural gas is used in the boiler of the electrochemical plant to avoid its purchase. The NG price according to the market was 28.99 e/MWh and the MP steam price was obtained as the NG saving for its generation in conventional gas fired boilers in the baseline scenario (24.64 e/t). Table 5.6 gathers the complete CAPEX and OPEX of the PtGElectrochemical hybrid plant and the total year incomes of the facility. Some costs

5.2 Potential Applications and Case Studies

121

Table 5.5 Streams involved in the pinch analysis T i (°C)

T f (°C)

Q (kW) −937.6

Amine capture plant Solvent cooler

Hot

85

37.8

Gas cooler

Hot

175

70

−238

Stripper condenser

Hot

88.9

88.7

−270.4

Flash unit

Hot

89

34

−443.8

Reboiler

Cold

120

120.5

1494.3

R1 outlet

Hot

582.7

300

−920.9

R2 inlet

Hot

300

250

−42.6

R2 outlet

Hot

414.1

136.1

−645.5

R3 inlet

Cold

141.1

250

39.4

R3 outlet

Hot

358.1

40

−176.5

Cold water

Cold

20

25

1939.2

Steam

Cold

50

180

202.4

Methanation plant

Electrochemical plant

Fig. 5.5 Optimized heat exchanger network [6]

122

5 Integration of Amine Scrubbing and Power to Gas

Table 5.6 CAPEX, OPEX and incomnes for the PtG-Electrochemical hybrid plant

TOTAL CAPEX [5138691 €] Ref. Equipment/Process Cost Direct costs [4178188 €] Equipment costs [2861772 €]

Parameter, A

CO2 capture amine plant [Total cost, 523486 €] [20] Amine Plant 523486 Captured CO2 [t/h] Methanation plant [Total cost, 2158644 €] H2 compressor 286978 CO2 compressor 101916 Power [kW] [21] Recirculation blower 10390 Blower 6150 [22] Reactors 1660500 SNG Power [kW] 50614 H2 [kg, 30bar] [23] H2 storage tank [21] Catalyst 42097 Catalyst [m3] HEN [Total cost, 179642 €] E-108 22992 E-113 45716 E-109 13459 E-114 9912 E-112 14981 Model E-104 10546 Area [m2] E-106 14894 E-110 11276 E-111 11822 E-105 10135 E-107 13908

Cost equation

26.094·10 6·(A/408) 0.65

26.7·10 4·(A/445) 0.67 300·A 563·A 187500·A

Aspen Energy Analyzer 9016.3 + 721.3·(A) 0.8

Other equipment costs [1316416 €]

[20]

Installation Instrumentation & Control Piping Electrical Building Land

400648

14%·A

286177 457884 85853 57235 28618

10%· A Total equipment costs [€]

16%·A 3%·A 2%·A 1%·A

Indirect costs [960503 €] [20]

Engineering

292473

Total direct costs [€]

7%·A

Legal expenses Construction expenses Contingency

51387 102774 513869

Total CAPEX [€]

1%·A 2%·A 10%·A

TOTAL OPEX [215666 €] Ref.

Equipment/Process

Cost

Parameter, A

Cost equation

[21]

MEA renovation

27679

1520·A

-

Catalyst renovation

6315

[7] [20]

Waste management Electricity O&M

2000 25512 154161

MEA [t/year] Initial catalyst cost [€] [kWh] Total CAPEX [€]

Pricing period 3%·A

SNG [MWh/year] MP steam [t/year]

28.99 (€/MWh) · A 24.64 (€/t) · A

15%·A

TOTAL INCOMES [1009706 €] Natural Gas MP steam

976990 35716

ANNUAL BENEFIT [794040 €]

5.2 Potential Applications and Case Studies Table 5.7 PB, IRR and NPV evaluation for different discount rate

123

Discount rate (%)

PB (years)

IRR (%)

NPV (Me)

3.00

7.3

11.07

6.68

4.00

7.6

10

5.65

5.00

8

8.96

4.76

6.00

8.4

7.93

3.97

7.00

8.9

6.92

3.27

of the amine plant were included in the HEN disaggregated costs to avoid duplicities in equipment costs. Solvent cooler, gas cooler and reflux condenser cooling needs are covered with cooling water and heat exchangers are already included in the HEN (E-112, E-113 and E-114). Considering the figures presented in Table 5.6, total CAPEX of the facility is around 5.13 Me. A 56% of the CAPEX corresponds with the cost of the equipment. OPEX is about 0.216 Me/year and total incomes are 1 Me/year. To obtain the Net Present Value (NPV), the Internal Rate of Return (IRR) and the Pay-back (PB) of the investment, a 5% discount rate and a 20 years lifetime were considered. Table 5.7 presents the economic results for the base case and for different discount rates. The results obtained from an economic analysis are encouraging and can make attractive the erection of a PtG-Electrochemical plant. The base case scenario (5% of discount rate) highlights that the capital investment could be recovered in 8 years, generating a 4.8 Me NPV at the end of the project lifetime with an IRR of 9%. Hence, the present case study avoids the requirement of subsidies to achieve the economic feasibility, contrarily to similar PtG research projects that can be found in literature [19]. This is mainly because the availability of H2 in the electrochemical industry itself. Normally, water electrolyzer represents the highest equipment cost in a PtG facility and it makes very difficult to recover capital investment in a reasonable period of time. Furthermore, the size of the facility must be carefully chosen to maximize the economic profitability. Further sensitivity analyses have been performed to analyse two main parameters with significant influence on the final revenues of the project: NG price and CO2 credit price. Firstly, NG price is usually quite unstable and its final value depends on the oil and gas market. In addition, final use of the SNG can be also influenced on the sale price. Regarding CO2 credit price, there also exists a high uncertainty. No CO2 credit revenue has been initially considered in this study since this particular industry was not bound to pay for its carbon emissions. However, if we consider that SNG feeds the boilers of the chemical facility, CO2 is not emitted but captured and used for SNG production itself. In addition, electricity price variation will also have influence on the cost analysis. Especially, a change in the pricing system will have a significant influence because it will modify not only the OPEX but also the operation hours which directly depend on the billing periods. In any case, this kind of chemical plants based on electrolyzers follow the same operational procedure and their production depends on the electricity price, working at nominal load when electricity prices are low and diminishing

124

5 Integration of Amine Scrubbing and Power to Gas

production when electricity prices are higher. This pattern is perfectly adapted to the hybrid concept since it also takes advantage of the lower electricity prices periods when the largest by-production of hydrogen occurs. The higher NG price is, the more profitable will be the investment. It is difficult to predict the evolution of oil and gas fuels, but it is expected a future rise of their prices. For instance, a 15% increase of NG price (from 29 to 33.3 e/MWh) would increase IRR up to 12% with a PB of 6 years and a half achieving very remarkable results for this kind of projects. The estimation of CO2 credit price evolution is more complex. The lack of a clear regulation or definitive taxes for these singular facilities make difficult to establish a future price. Nevertheless, 30 e/tCO2 is a reasonable value for making competitive the most CO2 capture technologies. With this price of CO2 credit, PB would be reduced below 6 years and a half and IRR is increased up to 12.4%.

5.2.2 Power to Gas-Nuclear Power Hybridization The use of long-term massive storage of electricity as a regulation tool to avoid partial load operation for coal-fired power plants while increasing the profitability of nuclear production can lead to new concepts which make economically feasible these power plants. The proposed hybrid system allows for the regulation of the nuclear power offered in the electric daily market through the storage of part of the produced electricity as synthetic natural gas [24]. From the producer point of view, this concept would permit to choose the most adequate selling hours, which maximize the economic incomes. From the consumer point of view, long-term storage of the electricity provides a more stable price of electricity, a reduction of prices and regulate the uncertainty of the market. Besides, environmental load associated to carbon emissions of the electricity production will be reduced.

5.2.2.1

Avoidance of Part-Load Operation Penalties

Electricity dispatch of nuclear and coal power Typically, nuclear power plants operate at nominal load throughout the year achieving equivalent availability factors over 85% [25]. Its operation flexibility is clearly limited by start-ups that may last more than 24 h [26]; e.g. in France, shut-downs related to low demand of electricity are limited to one per reactor and year on average [27]. Besides, fuel replacement only takes place every 12–24 months [28] and partial load operations are not recommended during the reactor lifetime to minimize the usage of neutron poisons in the core [27]. Given the nature of nuclear and renewable energy sources, coal and natural gas technologies are compelled to fulfil demand under a variable profile derived from the high penetration of solar and wind power. In this context, gas-fired combined

5.2 Potential Applications and Case Studies

125

cycles are less penalized than coal-fired power plants given their higher efficiency, lower emissions and better performance at partial loads [26]. Therefore, the critical variable operation of coal-fired power plants deserves a deeper analyse. Partial load operation in coal-fired power plants implies a reduction of overall efficiency derived from worse radiative and convective exchanges inside the boiler [29]. This disadvantage also implies: (i)

an increment in the operating cost of the facility related to the increase of specific fuel consumption; (ii) a handicap to fulfil the legislative regulation given the increase of specific emissions hardly meets the demanding restrictions of the European Directive 2010/75/UE [30] and (iii) a reduction in the facility life-time since a high number of hot- and cold startups reduces the lifetime of facilities; some studies estimates 200 cold start-ups and 5000 hot start-ups on average for subcritical coal-fired power plants [26]. Power to Gas as a tool to avoid penalties of partial load operation Despite nuclear power does not directly emits CO2 , its base load operation collaterally increase the specific emissions of the coal-fired power plants in the energy mix of a country. A potential solution could be the implementation of electricity storage systems for the nuclear electricity production to limit the fluctuant operation of coalfired power plants [27]. This mode of operation should be considered as a short- and mid-term solution, which reduces specific carbon emissions of the national energy mix. The concept proposes the utilization of Power to Gas technology to store nuclear electricity in the form of synthetic methane, which can be introduced in the gas grid [31]. The final aim is to establish a connection between electric and gas grids, through which the nuclear electricity can be stored and later used to satisfy end-user thermal or electrical demand (industry, households, buildings or transport). The process follows the scheme presented in Fig. 5.1 where a nuclear power plant supplies energy to the electrolyzers and the source of carbon comes from an amine scrubbing plant that treats the flue gas stream of coal-fired power plants. Then, the methanation reaction stage combines the produced hydrogen with carbon dioxide to produce the synthetic methane. The performance of the proposed solution is simulated for a system consisting of a nuclear power plant, a coal-fired power plant with amine carbon capture, and a Power to Gas plant. The sizes of the power plants correspond to average current values (1060 MW for nuclear power [32], Wnucl,0 , and 350 MW for coal-fired power [33], Wcoal,0 ). While the Power to Gas plant is sized to store up to a 60% of the power capacity of the coal-fired power plant, i.e., 210 MW. In practice, the concept pretends to avoid the partial load of the coal-fired power plant whenever it is operative; i.e., when the operating load must be reduced below the 40% of the nominal load, the plant will be off. Hence, the coal-fired power plant will operate during the same periods, but always at nominal load through the regulation of nuclear contribution based on PtG.

126

5.2.2.2

5 Integration of Amine Scrubbing and Power to Gas

Hybrid System Model

The characterization of the coal-fired power plant under part-load operation provides the instantaneous amount of electricity to be stored, and allows the comparison of partial load performance with the operation at full load. Then, the energy penalty of the amine carbon capture plant is calculated through simulation, while the model of the methanation plant provides the energy efficiency of the energy storage (i.e., available methane for selling). Model of part-load operation in coal-fired power plants The characterization of the coal-fired power plant under partial load operation must consider three key aspects: (i) operating hours, (ii) energy efficiency, and (iii) carbon emissions. Operating hours The coal-fired power plant is assumed to operate 3500 equivalent hours per year, h eq [34]. Thus, the electricity produced annually in the coal-fired power plant, E coal , amounts to 1228.5 GWh as presented in Table 5.8. To compare with different partial loads operation, the current number of operating hours to generate the same amount of electricity is calculated through Eq. 5.8. The number of operation hours is 4756.5 h when the load varies between 40 and 100%. W coal,0

E coal = h eq · Wcoal,0 =

h dWcoal

(5.8)

0.4·Wcoal,0

Table 5.8 Production and stored electricity at different loads Coal power plant load (%)

Coal power (MW)

Operating hours (h)

Electricity from coal (GWh)

Electricity to be stored (GWh)

[40–45]

140–157

170.3

25.4

34.4

(45–50]

158–175

228.2

38.1

42

(50–55]

176–193

293.7

54.3

48.8

(55–60]

194–210

340.4

68.8

50.6

(60–65]

211–228

424.2

93.2

55.7

(65–70]

229–245

451.9

107.2

51.5

(70–75]

246–263

516.5

131.5

49.8

(75–80]

264–280

503.9

137.1

39.8

(80–85]

281–298

526.7

152.5

32.4

(85–90]

299–315

469.4

144.1

20.7

(90–95]

316–333

447.8

145.2

12

(95–100]

334–351

383.4

131.2

3.4

Total range:

140–351

4756.5

1228.5

441

5.2 Potential Applications and Case Studies

127

where h represents the real number of operating hours and Wcoal is the actual operating power of the coal-fired power plant under part-load scenarios. The amount of electricity that has to be stored from nuclear production to ensure the nominal operation of the coal-fired plant is given by Eq. 5.9, which depends on the instantaneous operating partial load through h and E coal . E st = h · Wcoal,0 − E coal

(5.9)

As a reference, a representative electrical market was used to set the electricity prices. In this case, the Spanish electrical market scenario where the cost of the most expensive 4757 h in the daily electricity market ranges from 45.9 to 120.0 e/MWh [35]. This means that the coal-fired power plant do not operate whenever hourly revenues are below 45.9 e/MWh. In the economic study, this threshold is assumed as operating cost of the facility. Efficiency According to Linneberg et al. [36], the efficiency of coal-fired power plants may decrease down to 2.8 points from full to 40% partial load. Since average net efficiency of this technology is near 36% [37], an efficiency curve is modelled in the study for partial loads from 40% to nominal load. The trend presented by Linneberg [36] is also considered in this study, proportionally scaling-down the values in order to fit the selected range of efficiencies. Besides, the curve is adjusted to a quadratic polynomial (Eq. 5.10) as recommended in literature when the boiler efficiency is only a function of the boiler part-load [38]. 2 ηcoal = 0.28 + 4.644 × 10−4 · Wcoal − 6.818 × 10−7 · Wcoal

(5.10)

This loss of efficiency in coal power plants associated to partial load operation could be avoided by storing electricity from nuclear power through a Power to Gas facility. Specific carbon emissions The carbon dioxide emissions depend on the operating load through the net efficiency, ηcoal (Eq. 5.10). The lower operating load, the higher specific emissions of CO2 , tCO2 . In order to avoid this increment of specific carbon emissions that prevents from meeting the European Directives, the present study assesses the storage of part of the electricity from nuclear power to the gas grid (instead of load reduction in coal-fired power plants) by using the Power to Gas energy storage technology. Model of amine capture in coal-fired power plant The carbon dioxide consumed in the methanation reaction is assumed to be captured from the coal-fired power plant by amine scrubbing. The energy penalty must be quantified to properly compare the operation at nominal load with a small carbon capture plant versus the conventional operation at variable load without carbon capture. The amine carbon capture plant is modelled following the configuration illustrated in Fig. 5.2. The fraction of flue gas to be treated varies depending on the amount

128

5 Integration of Amine Scrubbing and Power to Gas

of electricity stored in the PtG plant. This flue gas flow is introduced into the plant and compressed to 1.5 bar. Then, flue gas is cooled down to 45 °C before entering the absorber to favour the exothermic absorption reaction (1.92 MJ/kgCO2 ) [13, 14]. The cyclic sorption capacity of MEA, ηMEA , is assumed to be 0.144 kgCO2 /kgMEA [39]. Reaction takes place between the counter-flowing solvent (MEA 30%wt. in water) and CO2 . The vent gas leaves the absorber at the top and the solution of CO2 and aqueous MEA leaves the column at the bottom The rich amine solution is pre-heated from 57 to 95 °C prior to entering the stripper. The solvent and CO2 will be separated by increasing the temperature up to 110 °C in the stripper. Thus, the rich amine solution is regenerated by separation of the aqueous MEA and the carbon dioxide. The CO2 outlet is typically at 90%vol. with 10%vol. of steam, which must be condensed and recycled into the stripper, to obtain a pure stream of CO2 . The regenerated aqueous MEA is directed to the absorber to close the cycle after cooling it to 50 °C. The amount of carbon dioxide to be treated will depend on the produced amount of hydrogen; i.e., on the power consumed by the electrolyser, Wel , and its efficiency, ηel , which is assumed 75%. The mass flow introduced in the stripper has to be heated to desorb the CO2 . A small recirculation from the outlet of the stripper is indirectly heated with steam from the power cycle of the coal-fired power plant. The steam is taken prior the low-pressure turbine, at 160 °C and 3 bar, and then returned to the deaerator as saturated liquid at the same pressure. It is assumed that the thermal energy required to desorb the CO2 is 1.92 MJ per kilogram of carbon dioxide [13, 14], and that the specific heat capacity of MEA is constant at 182 kJ/kmol·K [40] with a molar mass of 61.09 kg/kmol [41]. The efficiency of the coal-fired power plant will vary depending on the steam bleed and the power consumed by the compression stage (isentropic efficiency of 0.9). The higher amount of energy is stored from nuclear power plant; the more hydrogen is produced in electrolysis, the more CO2 has to be captured to perform methanation, and the greater penalties in the efficiency of the power plant. Model of methanation plant The overall efficiency of the Power to Gas plant must be computed in order to quantify how much synthetic natural gas is produced (i.e., the available amount for selling) from the electricity stored from the nuclear power plant. The methanation plant is modelled following the configuration of Fig. 5.2. The scheme is based on TREMP technology [42, 43]. This comprises three adiabatic methanators operating at 25 bar with recycling loops in the first and third ones, and an intermediate water condensation after the second methanator. This configuration allows reaching methane contents above 95%vol. under the proper operating conditions. First, hydrogen and oxygen are produced through electrolysis by consuming electricity from the nuclear power plant. Then, the hydrogen and the carbon dioxide are pressurized to 25 bar by two multi-stage compressors, which also increase the temperature of the gasses thus avoiding pre-heating prior the first methanator. The outlet gas of reactor 1, R1, is cooled down to 300 °C and the 78% of the flow is recirculated

5.2 Potential Applications and Case Studies

129

to control the temperature increase. After the second reactor, the water content normally exceeds the 60%, which inhibits the reaction. Therefore, approximately the 90% of the water is condensed and the resulting stream must be pre-heated again to 300 °C before entering the third methanator. Again, a 78% of the outlet stream of R3 is recirculated is placed in the third reactor. The water content is condensed, and the dry synthetic gas injected in the gas grid. Mass and energy balances are applied to the three reactors to calculate mass fraction of outlet streams and energy flows for each reactor. The overall efficiency of the Power to Gas plant is computed as the ratio between the energy contained in the produced synthetic natural gas and the electricity consumed in the electrolysers and compressors.

5.2.2.3

Performance of the Coal-Fired Power Plant with Amine Carbon Capture and PtG

The amine plant treats up to 33.45 kg/s of flue gas, from which 7.16 kg/s of CO2 are captured. This amount represents a 12.9% of the flue gas flow produced in the coal power plant. This is later combined with hydrogen to finally obtain 2.67 kg/s of synthetic natural gas, composed by 95.5 vol.% CH4 , 3.6 vol.% H2 and 0.9 vol.% CO2 . The composition of the synthetic gas at relevant points of the plant is presented in Table 5.9. The electricity consumption of the Power to Gas plant mostly comes from the electrolyser (210 MW), as the multi-compressors (9.45 MW) account only for the 4.5% of the total consumption. Besides, the heating demands prior the third reactor can be fulfilled with the cooling demands after reactors R1 and R2. The efficiency of the Power to Gas plant achieves the 59.7%. For each MWh stored from nuclear power, 33.3 kWh are used in the amine plant, 41.65 kWh in the auxiliaries of the Power to Gas plant, and 576.7 kWh are stored in SNG, leading to an overall efficiency of 57.7%. The low energy penalization of the amine plant is related to the limited amount of flue gas from the coal power plant which are treated in the capture plant (only 12.9%). Table 5.9 Composition [molar %] in the methanation plant CO2,in

H2,in

R1out

R2out

R3in

R3out

SNG

CO2

100

0

4.8

2.3

5

0.7

0.9

H2

0

100

21.3

9.3

20.1

2.8

3.6

CH4

0

0

24.1

29.4

63.4

74.4

95.5

H2 O

0

0

49

58.9

11.4

22.1

0

CO

0

0

0.7

0.1

0.1

0

0

130

5.2.2.4

5 Integration of Amine Scrubbing and Power to Gas

Comparison Between Nuclear Electricity Storage and Coal Power Load Modulation

The conventional dispatch of electricity based on the regulation of the operating load of coal-fired power plants leads to a reduction in the thermal efficiency described by Eq. 5.10. The proposed concept continuously operates the coal-fired power plants at nominal load and stores the excess electricity from nuclear power plants. This solution also reduces somehow the efficiency due to the energy penalty of the CO2 capture plant. Both efficiencies are compared in Fig. 5.6, for operating loads between 40 and 100%, i.e., for power storage between 210 and 0 MW. Under conventional operation, the efficiency drops 2.8 points when operating load varies from nominal to 40%. Under the proposed solution, the efficiency decreases less than 0.8 points for nuclear power storage of 210 MW. The penalization in ηcoal,st is low because the percentage of flue gas to treat with amine scrubbing is always below 12.9%. From near 79 to 100%, the conventional dispatch of electricity is preferable to the proposed method since the energy penalty of the carbon capture plant is avoided in the conventional operation (Fig. 5.6). Nevertheless, the overall performance of the system is clearly advantageous for the displacement method, as the thermal efficiency greatly increases compared to the conventional dispatch in the range 40–79% of operating loads. The conventional dispatch based on regulating the operating load of coal-fired power plants makes specific CO2 emissions to increase 8.2% due to the loss in the thermal efficiency. Contrarily, the electricity dispatch based on the storage of nuclear power leads to a reduction in the specific emissions as power is stored (i.e., thanks to amine carbon capture). The specific emissions of the proposed method may be as Fig. 5.6 Comparison between ηcoal versus load and ηcoal,st versus stored power [24]

5.2 Potential Applications and Case Studies

131

low as 0.90 tCO2 /MWhe, which represents a 12.7% lower than the emissions when operating at 40% load in the coal-fired power plant.

5.2.2.5

Economic Analysis

The operation of the Power to Gas system combines two different strategies regarding the storage of the nuclear power production: (i) the avoidance of partial load operation in the coal-fired power plant and (ii) the storage of nuclear electricity whenever the selling price is below the operating cost of the nuclear power plant. The first strategy does not intend to avoid partial loads whenever is operating; i.e., the coal-fired power plant will still operate during the same periods of the year, but always at nominal load. The amount of stored nuclear electricity to allow for nominal operation of the coal-fired power plant is 441 GWh. The Power to Gas plant (210 MW of nominal capacity) will operate 2100 equivalent hours at nominal load following the first strategy in order to store 441 GWh from the nuclear power plant. The second strategy accounts for those periods in which the selling price of electricity in the market is lower than the operating costs of the nuclear power plant. This electricity is stored through Power to Gas and then sold as synthetic natural gas at a higher price. In these cases, the CO2 which has been previously stored is used, as the coal-fired power plant would not be in operation. In 2013, nuclear power plants were operated during 1059 h without profit (assuming an operating cost of 18 e/MWh [44]). Therefore, these hours are also included in the planning of the Power to Gas plant operation in order to avoid sales below the production cost. In total, the Power to Gas plant will operate 3159 h in a year. As the present case study assesses the standalone techno-economic feasibility of the hybrid PtG plant, the consumed electricity is directly bought to the nuclear power plant and the revenues from the sale of the synthetic natural gas will amortize the investment. The average price to be paid for the electricity takes into account both economic strategies described above and the average price over the total operation of the PtG plant is considered to be 13 e/MWh. Besides, the annual payment to amortize the loan is calculated through the French Amortization formula (Eq. 5.11): A=L

i(1 + i)n (1 + i)n − 1

(5.11)

The economic analysis of the base case scenario together with the cost equations considered in the study are presented in Table 5.10. An operation of 3159 equivalent hours is assessed, with an electricity cost of 13 e/MWh, a CO2 allowances price of 19 e/tCO2 , and selling prices for the SNG and the O2 of 50 e/MWh [45] and 80 e/tO2 [46, 47]. The amortization of the loan is considered to happen in 20 years with and annual interest of the 4%. Moreover, the volume of the reactors is calculated assuming a GHSV of 5000 h−1 [9], and the catalyst is supposed to occupy the 60% of that volume [48].

132

5 Integration of Amine Scrubbing and Power to Gas

Table 5.10 CAPEX, OPEX and incomes for the hybrid plant TOTAL CAPEX [212400000 €] Ref. Equipment/Process Cost Direct costs [169910000€] Equipment costs [91320000 €]

Parameters,

Cost equation

CO2 capture amine plant [Total cost, 4350000 €] [50] Amine Plant 4350000 Electrolysis [Total cost, 84000000 €] [49] Electrolyzer 84000000 Methanation plant [Total cost, 2720000 €] 1800000 H2 compressor [21] CO2 compressor 670000

[50]

Reactors

180000

Catalyst [51] HEN [Total cost, 250000 €]

[45]

70000

Heat exchangers

250000

Captured CO2 [t/h]

26.094·106·(A/408)0.65

Power [kW]

400·10-6·A

Power [kW]

26.7·104·(A/445)0.67

Diameter [m], Height [m] Catalyst [m3] Cost of methanation plant [M€]

0.0189·A1.066·B0.802 0.01242·A

0.10·A

Other equipment costs [78590000 €]

[52]

Installation Instrumentation & Control Piping Electrical Building Land

21240000

10%·A

8500000 25490000 10620000 10620000 2120000

4%·A Total CAPEX [M€]

12%·A 5%·A 5%·A 1%·A

Indirect costs [42490000 €] [52]

Engineering Legal expenses Construction expenses Contingency

14870000 4250000 8500000 14870000

Total CAPEX [M€]

7%·A 2%·A 4%·A 10%·A

TOTAL OPEX [15300000 €] Ref. [53] [21]

Equipment/Process

Cost

MEA renovation

100000

[45]

Catalyst renovation

10000

[2]

Water

190000

-

Electricity

8620000

[52]

O&M

6370000

Parameter, A, B CO2 captured [t/year] Initial catalyst cost [M€] Water [m3/y] Electricity cost [€/MWh], Eq hours [h] Total CAPEX [€]

Cost equation 1.2·10-6·A 15%·A 1.47·10-6·A 210·10-6·A·B 3%·A

TOTAL OUTCOMES [30900000 €/y] Annual amortization OPEX

15600000 15300000

TOTAL INCOMES [23290000 €/y] Natural Gas

19130000

Oxygen

2610000

CO2 allowance price

1560000

ANNUAL BENEFIT [-7630000 €]

SNG selling price [€/MWh], SNG generated [MWh/y] O2 selling price [€/tO2], O2 generated [tO2/y] CO2 allowance price [€/tCO2], CO2 consumed [tCO2/y]

10-6 · A · B

10-6 · A · B

10-6 · A · B

5.2 Potential Applications and Case Studies

133

Fig. 5.7 Annual benefit [Me] as a function of the electricity price and the operating hours [24]

The annual benefit of the base case scenario is negative, what implies that the loan cannot be amortized. Actually, it can be seen that under current economic juncture the incomes barely covers the OPEX. An economic parametric study was performed looking for those combinations of operating hours and electricity prices that allow the Power to Gas to be economically viable for this proposed solution. The obtained results are presented in Fig. 5.7. It can be seen that even with electricity prices of 0 e/MWh, a minimum of 3000 equivalent hours are required to amortize the investment. Nevertheless, when the annual operation is increased to typical values of the industrial sector (~4800 h), a cost of up to 13 e/MWh can be assumed. The proposed concept reduces the annual specific emissions from 0.967 tCO2 /MWh to 0.913 tCO2 /MWh. However, the total emissions increase from 1.19 MtCO2 to 1.55 MtCO2 , since the full-load operating coal-fired power plant is producing a 36% more electricity with the consequent consumption of fuel.

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