Techno-economic analysis of an integrated liquid air and thermochemical energy storage system

Energy Conversion and Management 205 (2020) 112341

Contents lists available at ScienceDirect

Energy Conversion and Management journal homepage: www.elsevier.com/locate/enconman

Techno-economic analysis of an integrated liquid air and thermochemical energy storage system Sike Wu, Cheng Zhou, Elham Doroodchi, Behdad Moghtaderi

T

⁎

Priority Research Centre for Frontier Energy Technologies & Utilization, Discipline of Chemical Engineering, School of Engineering, Faculty of Engineering and Built Environment, The University of Newcastle, NSW 2308, Australia

A R T I C LE I N FO

A B S T R A C T

Keywords: Energy storage Thermochemical energy storage Liquid air energy storage Metal oxide Renewable energy

The rapid increase in renewable energy applications has heightened the need for developing efficient and costeffective energy storage technologies. In this study, a novel integrated liquid air and thermochemical energy storage system is proposed and examined. This integrated storage system is found to be superior in many aspects than both the stand-alone liquid air energy storage and thermochemical energy storage technologies, including high energy storage density, high round-trip efficiency, no geographical limitation, and negligible environmental concern. These are derived from the synergies when integrating those two subsystems. More specifically, the liquid air energy storage subsystem ensures a minimum storage volume of air and a high round-trip efficiency of the integrated system, while the thermochemical energy storage subsystem allows it to have a high energy storage density and high operating temperature without the necessity of burning fossil fuels. To assess the performance of the integrated storage system, thermodynamic and economic analyses are carried out by using Aspen Plus v10. According to the thermodynamic analysis, the round-trip efficiency and the energy storage density of the integrated storage system are found to be 47.4% and 36.8 kWh/m3, respectively. The round-trip efficiency is about 13.3% higher than that of the stand-alone thermochemical energy storage system and the energy storage density is nearly 3.4 times that of the stand-alone liquid air energy storage system. In terms of the economic performance, the integrated system with a plant size of 60 MWe presents a payback period of around 10 years and a levelized cost of electricity of 179–186 USD/MWh over a 30-year period.

1. Introduction The last decade has seen a rapid increase of renewable energy applications driven by efforts to lower carbon dioxide (CO2) emissions, mitigate environmental pollutions, and reduce reliance on depleting fossil fuels. For instance, the power generation of wind and solar was strongly boosted from 104 TWh and 4 TWh to 958 TWh and 328 TWh, respectively, during the period from 2005 to 2016 [1]. However, the fast-developing renewable energy also brings about challenges to ensuring a reliable and efficient power grid [2]. This is primarily because the power generation using renewable resources can be relatively unstable and subjects to the variations of weather, location, season, and/ or time [3]. Consequently, this intermittent nature becomes a major obstacle to promoting the deep penetration of renewable energy into the power grid. To address this problem, a variety of solutions is proposed and evaluated, among which energy storage has been recognized as a promising technology [4]. By employing energy storage, the excess or intermittent electricity sourced from renewables can be converted to

⁎

mechanical, electrochemical, chemical, or thermal energy [5]. When energy is required, the stored energy can be recovered via conventional power cycles. In this way, energy storage decouples the electricity supply and demand, which thus allows for a stable output of intermittent renewable energy [6]. Currently, only a limited number of energy storage technologies are considered as practical for utility-scale applications, including pumped hydro storage (PHS), compressed air energy storage (CAES), and batteries. Among them, PHS and CAES with large storage capacity have been commercialized [7]. Nevertheless, both PHS and CAES suffer from low energy storage density and therefore require large space for storage, such as two water reservoirs for PHS or a salt cavern for CAES. The geographical constraints then make the site selections of PHS and CAES difficult and hinder their wide applications [8]. On the other hand, batteries show excellent energy storage density and are geographically unlimited. Yet they present other constraints, including but not limited to, high capital cost, environmental concern, and poor scalability [9].

Corresponding author. E-mail address: [email protected] (B. Moghtaderi).

https://doi.org/10.1016/j.enconman.2019.112341 Received 9 August 2019; Received in revised form 8 November 2019; Accepted 24 November 2019 0196-8904/ © 2019 Elsevier Ltd. All rights reserved.

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

Nomenclature

LCOS levelized cost of storage LNG liquefied natural gas MET methanol tank NPV net present value ORC organic Rankine cycle Pb battery battery based on lead PC pneumatic conveyor PCR phase change redox PHS pumped hydro storage PHES pumped heat energy storage PRT propane tank RR reduction reactor TB turbine TCES thermochemical energy storage TCI total capital investment TDPC total direct plant cost TPC total purchased cost T-s temperature-entropy VRF battery vanadium redox flow battery

aCAES advanced compressed air energy storage CAES compressed air energy storage CEPCI Chemical Plant Cost Index CL air cooler CP compressor CSP concentrated solar power C&OC contingencies and owner’s costs C-pump cryogenic pump C-turb cryogenic turbine dCAES diabatic compressed air energy storage EPC engineering procurement and construction HX heat exchanger LAES liquid air energy storage LAES-A a conventional liquid air energy storage system LAES-B a liquid air energy storage system using natural gas LAES-TCES liquid air and thermochemical energy storage LCOE levelized cost of energy

According to the thermodynamic study implemented by Krawczyk et al., the round-trip efficiency of a typical LAES system can be up to 55%, which is approximately 15% higher than a comparable CAES system [11]. The round-trip efficiency of LAES can be further enhanced by integrating an organic Rankine cycle (ORC) and/or a sorption cooling system [16] although this may increase the complexity of the system. Moreover, LAES also features a higher energy storage density than that of CAES because of the vastly reduced storage volume. For instance, in Guizzi et al.’s study, the examined LAES system only requires a storage volume of 30 m3 for a power output of 1 MWh, which is much lower than the corresponding 180 m3 of the compared CAES plant [17]. Regarding economic feasibility, Xie et al. found that the payback period of a LAES system with a storage capacity of 200 MW could vary from 5.6 years to 25.7 years depending on the electricity spot price in the UK and whether waste heat recovery is implemented or not [18]. To increase the overall energy storage efficiency, in some advanced LAES systems the compression heat produced in the charging process is stored and used for preheating the air in the discharging process at a later stage. Table 1 summarizes the past studies on LAES systems that recycle the compression heat. As illuminated in Table 1, a typical way to store the compression heat is using thermal oil. For instance, Zhang et al. examined a LAES system that uses thermal oil and water to store the compression heat [19]. The highest operating temperature of the thermal oil is about 320 °C and the round-trip efficiency is found to be 45%. Alternatively, Peng et al. [20] employed steatite rocks to fulfill the heat storage function and the energy storage density is found to be about 23 kWh/m3. However, the thermal oil/rock storage gives rise to a significantly large footprint which ultimately reduces the energy storage density of the LAES system. For example, as depicted in Table 1, when all the storage tanks are considered, the energy storage density of

To address the above-mentioned problems and limitations, various novel concepts have also emerged in recent years in order to achieve cost-effective, geographically unconstrained, and environmentalfriendly solutions. Among these innovative proposals, liquid air energy storage (LAES) and thermochemical energy storage (TCES) appear to be promising and both have received increasing research attention. There is also a large knowledge gap and opportunity for integrated energy storage systems using the existing storage technologies. Identifying and evaluating a superior integrated system, thus, becomes the prime motivation and objective of the current study. 1.1. Review of liquid air energy storage The energy storage mechanism of LAES is relatively similar to CAES, in which air is compressed and stored in the charging process and later expanded in the discharging process. However, in a LAES plant, the compressed air is further liquefied using cryogenic technology, which substantially reduces the storage volume of air. In this way, the liquefied air can be stored in a tank instead of a cavern, which ultimately bypasses the geographical limitation. As of 1977, Smith first proposed the concept of LAES and claimed that the energy recovery efficiency can be up to 72% [10], while the efficiency of a CAES system is only about 40% as in Krawczyk et al.’s study [11] and up to 54% as in the McIntosh plant [12]. After three decades, the first LAES pilot plant with a storage capacity of 2.5 MWh (350 kW) was built in Scotland by Highview Power [13]. The round-trip efficiency is only 8% owing to its relatively small plant size and insufficient recycled coldness [14]. In 2018, a grid-scale LAES plant (15 MWh, or 5 MW) was launched in the UK and the round-trip efficiency was reported to be around 60% [15]. In comparison to the actual plant development, more studies on LAES were found to be theoretical. Table 1 Summary of LAES systems that recycle the compression heat. Reference

Heat storage

Heat source

Highest turbine inlet temperature (°C)

Round-trip efficiency (%)

Energy storage density* (kWh/m3)

Guizz et al. [17] She et al. [22] Khalil et al. [23] Tafone et al. [16] Peng et al. [20] Peng et al. [24] Zhang et al. [19]

Thermal oil Thermal oil Not specified Thermal oil Steatite rocks Thermal oil Thermal oil/water

Air Air Air Air Air Air Air

353 205 – 162 367 238 320/85

50–60% 60% 84% 55% 50–62% 60% 45%

18 13 – – 23 106 (based on air volume only) 21 or 118 (based on air volume only)

compression compression compression compression compression compression compression

*Either directly obtained from the literature or indirectly estimated in this study by considering all of the storage tanks (i.e. thermal oil, methanol, propane, and liquid air) unless otherwise specified. 2

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

the LAES systems falls in the range of 10–20 kWh/m3, which is only 3–6 times higher, rather than 30 times higher when only air storage volume is considered, than that of a comparable CAES system [4]. This is because the energy storage density is limited by the low heat capacity and low storage temperature (normally lower than 400 °C) of thermal oil or rocks. On the other hand, thermal oil may cause safety problems due to its flammability and should be kept a certain distance from other equipment [21]. This safety consideration also contributes to an increased plant footprint. In other variants of LAES systems, the compression heat is either partially used or totally rejected, which reduces the reliance on the use of thermal oil recovery system. However, an external heat source must now be applied to heat the stored cold air to a high temperature, otherwise power generation would become inefficient. Table 2 summarizes the previously examined LAES systems that employ various external heat sources. For instance, in Li et al.’s study, the liquefied air of a LAES plant is heated by the hot steam sourced from a nuclear plant [25]. Antonelli et al. studied a LAES system that used the combustion of natural gas to heat the liquefied air to around 1400 °C and the roundtrip efficiency reached 80% [26]. According to Table 2, the examined LAES systems present energy storage densities between 30 kWh/m3 and 80 kWh/m3. Hence, these LAES systems, which employed external heat sources, show a dramatic increase in energy storage density compared to those that fully rely on thermal oil as illustrated in Table 1. This can be explained by mainly two reasons: i) the overall storage volume is reduced due to the reduction or elimination of the use of thermal oil; ii) the turbine inlet temperature is elevated from 100 to 300 °C to a substantially high temperature (e.g. 1400 °C when using natural gas), which helps to increase the power output. Nevertheless, it should not be ignored that the use of external heat sources in LAES may result in negative impacts. For instance, the combustion of natural gas leads to CO2 emissions while the use of geothermal and nuclear power is highly limited by locations. Therefore, it is necessary to find an alternative or integrated approach, which provides a high-temperature heat source for LAES but also bypasses any environmental concerns and geographical limitations. One of the options would be the high-temperature heat stored under a thermochemical energy storage system, which will be explained in more detail in Section 1.3.

temperature and high-enthalpy, which help TCES system to achieve high operating temperature and high energy storage density [33]. Various TCES technologies have been proposed and those based on metal oxide redox are favorable due to their negligible corrosiveness, no necessity for the storage of reactant gas, and simple products separation [34]. Besides, oxygen is also produced in the TCES based on metal oxides, which further enhances its economic benefits [35]. The reversible reactions of the TCES system based on metal oxide redox can be noted as [36]:

Reduction: Mex Oy → Mex Oy − 1 + 1/2O2 ΔH > 0

(1)

Oxidation: Mex Oy − 1 + 1/2O2 → Mex Oy ΔH < 0

(2)

For the endothermal reaction (i.e. reduction), metal oxide (MexOy) is heated by external heat and then decomposed to reduced metal oxide (MexOy-1) and oxygen (O2). In this step, the external heat is stored as thermochemical energy in MexOy-1. For the exothermal reaction (i.e. oxidation), the reduced MexOy-1 is oxidized by O2 and thus MexOy is reproduced. In this way, the stored thermochemical energy is converted back in the form of heat. Most previous studies of TCES focus on the characteristics of material candidates. Among various material candidates, barium peroxide (BaO2)/barium oxide (BaO), tricobalt tetroxide (Co3O4)/cobalt monoxide (CoO), manganese trioxide (Mn2O3)/manganese tetroxide (Mn3O4), hematite (Fe2O3)/magnetite (Fe3O4), and copper oxide (CuO)/cuprous oxide (Cu2O) show great potentials. This is primarily because of their suitable reaction temperature, high reaction enthalpy, and acceptable material cost [37]. BaO2/BaO shows an energy storage density of around 432 kJ/kg but it suffers from a low oxidation rate [37]. Similar poor reversibility was also identified in Mn2O3/Mn3O4, which has a competitive cost and wide reaction temperature [38]. For Fe2O3/Fe3O4, its reduction temperature is up to 1361 °C and therefore brings significant challenges to heating and insulation [39]. By contrast, CuO/Cu2O and Co3O4/CoO present more accessible operating temperatures at about 900–1000 °C and high energy storage densities at 811 kJ/kg and 844 kJ/kg, respectively. The feasibility of CuO/Cu2O-based TCES systems has been independently validated by Alonso et al. [36] and Wong et al. noted the excellent longterm reversibility of Co3O4/CoO [37]. With respect to utility-scale energy storage performance, the relevant studies are rather limited in the open literature. Schrader et al. proposed a Co3O4/CoO-based TCES plant coupled with an air Brayton cycle [40]. The reported maximum round-trip efficiency is 44% with the compressor consuming nearly half of the work generated by the turbine during energy discharging. This is also the case found in a TCES system based on a phase change redox cycle using CuO/Cu2O [41]. To mitigate such high energy consumption of the air compression, Wu

1.2. Review of thermochemical energy storage Thermochemical energy storage is normally comprised of two reversible chemical reactions, which are endothermal and exothermal, respectively [32]. In the charging process, the endothermal reaction takes place while external heat is absorbed and stored. In the following discharging process, the exothermal reaction occurs in which the stored energy is then recovered. These chemical reactions normally are highTable 2 Summary of LAES systems using external heat. Reference

Air heating media

Heat source

Highest turbine inlet temperature (°C)

Round-trip efficiency (%)

Energy storage density* (kWh/m3)

Chino et al. [27] Li et al. [28] Li et al. [25] Al-Zareer [29]

Liquefied natural gas (LNG) Solar heat Nuclear reactor Air compression/natural gas

– 331 287 180

70 – 71 72

– 34 42 –

Antonelli et al. [26]

Flue gas Thermal oil Steam Not specified hot storage /flue gas Flue gas

Natural gas

1400

80**

Krawczyk et al. [11] Farres et al. [21] Kim et al. [30] Cetin et al. [31]

Flue gas Molten salt/ thermal oil Flue gas/thermal oil Water

Natural gas Air/helium compression LNG/air compression Geothermal heat

1300 547 1400/170 128

55 60–70 64 47

355–412 (based on air volume only) 33 60–80 75 33

*Either directly obtained from the literature or indirectly estimated by considering all of the storage tanks (i.e. thermal oil, methanol, propane, and liquid air) unless otherwise specified. **Equivalent efficiency considering the electricity generation efficiency of natural gas. 3

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

efficiency, energy storage density, and exergy efficiency. The economic analysis, on the other hand, assesses the economic feasibility and superiority of the integrated system over the stand-alone systems. These methods can also be extended to evaluate other novel utility-scale energy storage technologies. In Section 1, the background, motivation, literature review, and objective of the current study is presented. In Section 2, the system layout and operating mechanism of the proposed LAES-TCES system are described. Section 3 explains the methods applied in evaluating the techno-economic performance of the proposed system. Section 4 presents the results and discussions and Section 5 concludes the research findings. The supplement data of the current research can be found in Supplementary Materials.

et al. suggested a combined compressed air energy storage and thermochemical energy storage system. This combined system shows a round-trip efficiency of around 56%, which represents a 12% increase compared to the stand-alone TCES plant [42]. Nevertheless, this combined plant is still exposed to geographical limitations because a large cavern is required for air storage. 1.3. Objective of the current study The above reviews identify the bottlenecks of the current energy storage processes, namely (i) low operating temperature, large plant footprint, safety concern, and geographical constraints for CAES and LAES systems with/without external heat sources, despite relatively high round-trip efficiency; (ii) low round-trip efficiency of TCES system even though its operating temperature and energy storage density are high; and (iii) subject to a suitable geographical region for the combined compressed air and thermochemical energy storage system. Considering these technology statuses, an integrated liquid air and thermochemical energy storage (LAES-TCES) system is proposed in the current research to address those bottlenecks. This integrated storage system paves a new way to develop efficient and clean utility-scale energy storage technologies by utilizing the merits of the two standalone systems and generating more synergies after a delicate integration between them. Specifically, from the perspective of LAES, the integrated TCES subsystem acts as an external high-temperature heat source, which is beneficial to achieving a high energy storage density without using fossil fuels or other geographically limited heat sources. From the perspective of TCES, the integrated LAES subsystem shares its air compression process with the TCES subsystem when regenerating power from the stored thermochemical energy. What is intriguing here is that the air compression step that normally occurs during the discharging process and offsets a great amount of power output from the turbine, as in conventional TCES systems, can now take place during the charging process and plays a role in storing electrical energy. The LAES and TCES subsystems also share the same working fluid, air, as the heat transfer medium. A thorough literature review has indicated that no relevant study on this novel energy storage concept has been carried out before. Hence, it becomes the subject of the current work and the main objective is to explore and quantify the synergies and overall performance of such integrated LAES-TCES system. The study consists of mainly two parts, namely thermodynamic and economic analyses. The thermodynamic analysis focuses on the technical performance of the LAES-TCES plant, such as round-trip

2. System description Fig. 1 shows the schematic diagram of the integrated LAES-TCES system. As can be seen in Fig. 1, the key components of LAES-TCES are compressors, turbines, reduction and oxidation reactors, liquid and solid storage tanks, and heat exchangers, as in the stand-alone LAES or TCES plants. With regards to raw materials, air, water, methanol, propane, and Co3O4/CoO, are involved in the operation of the integrated LAES-TCES system. Meanwhile, the integrated LAES-TCES system comprises two main processes, namely the energy charging and discharging processes. The charging process of LAES-TCES can be further divided into two independent charging steps for the LAES and TCES subsystems. The discharging process involves an integrated function of the LAES and TCES subsystems. 2.1. Energy charging In the energy charging step of the LAES subsystem, both the electricity generated from intermittent renewable energy resources and the off-peak electricity from the power grid can be used as the energy source for its air liquefaction process. More specifically, ambient air (A1, see Fig. 1) is pressurized sequentially via a group of compressors (CP1-CP4). In order to reduce the compression work, the outlet air of compressors is cooled in a series of heat exchangers (HX1-HX4) by using cooling water (W11-W14). The heated water (W21-W24) can be further used for either direct domestic heating or indirect cooling by deploying an additional absorption refrigeration process [29]. The pressurized air (A10) is then cooled in a cold processing facility (also known as a cold box). This cold box is comprised of two heat exchangers (HX5 and HX6). The coldness of the cold box is sourced from:

Fig. 1. Schematic diagram of the proposed LAES-TCES system. 4

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

When power is needed, the stored liquid air (A17) from the liquid air tank is pumped to high pressure by using a cryogenic pump (C-pump, see Fig. 1). Then, the pressurized air (A18) is heated and evaporated sequentially to near-ambient temperature in two heat exchangers (HX7 and HX8). The heat sources for the heat exchangers HX7 and HX8 are provided by the exiting methanol (ME3) and propane (PR3) from the storage tanks MET2 and PRT2, respectively. In the heat exchangers HX7 and HX8, the coldness released by the liquefied air (A18 and A19) are transferred to the methanol and propane, which in turn will be later used for cooling the air in the charging step of the LAES subsystem. Meanwhile, the air (A20) leaving the heat exchanger HX8 at a nearambient temperature is further heated in a heat exchanger (HX9) by the hot air (A25) leaving the oxidation reactor. In the next step, the hightemperature air (A21) is expanded in a hot air turbine (TB1) to generate power. The exhaust air (A22) from the hot air turbine TB1 is reheated in an indirect-contact gas-solid heat exchanger (HX10) [43] by the reacted Co3O4 (MT4) from the oxidation reactor. The reheated air (A23) further expands to the atmospheric pressure in a second hot air turbine (TB2) before being released to the oxidation reactor and oxidizes the CoO (MT3) from the CoO tank. The oxidation reaction in the oxidation reactor is described as:

i) the stored low-temperature methanol (ME1) in the methanol tank MET1 and the stored propane (PR1) in the propane tank PRT1; 2) the cold air (A14) recovered from the gas-liquid separator. The further cooled air (A12) exiting the cold box is then expanded to the atmospheric pressure in a cryogenic turbine (C-turb) [20]. This is followed by a gas-liquid separation process where the liquefied air is stored in a liquid air tank while the uncondensed air is returned to the cold box. On the other hand, after the coldness being released, the methanol (ME2) and propane (PR2) are then stored respectively in the tanks MET2 and PRT2 while the recovered cold air (A16) flows into the first compressor CP1. In the energy charging step of the TCES subsystem, energy is stored via the endothermal reduction of metal oxide as well as the sensible heat associated with heating up metal oxide. In the current study, Co3O4/CoO is selected as the metal oxide redox candidate because of its high reversibility and high energy storage density. The reduction reaction of Co3O4/CoO can be described as:

2Co3 O4 → 6CoO + O2 (g)

(3)

The charging process begins with that the solid Co3O4 (MT1, see Fig. 1) is introduced from a Co3O4 tank to a reduction reactor. The transport of the solid Co3O4 can be realized by using well-developed pneumatic conveying. In the reduction reactor, the incoming Co3O4 is heated up by external heat and further decomposed into CoO and O2. As a result, the absorbed external heat is stored as sensible and thermochemical energy. The external heat can be sourced from either Joule heating using abandoned electricity or concentrated solar heat from a concentrated solar power (CSP) plant. When concentrated solar heat is applied, the proposed LAES-TCES becomes a combined energy storage system for both electricity and heat. Meanwhile, the produced CoO (MT2) out of the reduction reactor is then stored in a CoO tank as the hot storage medium. This CoO tank requires adequate insulation to minimize the losses of the stored sensible energy. The generated byproduct O2 (O1) can also be stored and sold to various industries, which benefits the overall economics of the integrated LAES-TCES system.

6CoO + O2 (g) → 2Co3 O4

(4)

In the oxidation process, the stored sensible and thermochemical energy in CoO (MT3) are released to the inlet air. Then, the hightemperature air is separated from the reproduced Co3O4 before being used as the hot fluid in the heat exchanger HX9 and repeats the processes as described previously. The regenerated Co3O4 (MT4) is transported to and stored in the Co3O4 tank after its sensible heat being partially recovered in the heat exchanger HX10. It is worth mentioning that in the proposed configuration, the oxidation process takes place at the atmospheric pressure. In this way, there is no necessity to build a pressurized oxidation reactor, which would be the case in several previously studied TCES installations [44]. Moreover, as the exhaust air from the oxidation reactor does not flow into the turbines, the need for setting a high-temperature filter before turbines is also avoided.

2.2. Energy discharging 3. Methods In the energy discharging step, the stored energy is converted back to electricity via two hot air turbines in the energy discharging process.

In the current work, a techno-economic analysis is conducted to

Fig. 2. Simulation flowsheet of the integrated LAES-TCES system. 5

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

equal. Also, the pressure ratios of the two air turbines are kept the same unless otherwise stated. Two stand-alone LAES and TCES plants are also examined to compare the energy storage performances among the integrated LAES-TCES, LAES, and TCES systems. The specific schematic diagrams, simulation flowsheets, and operating parameters of the stand-alone LAES and TCES systems can be found in Supplementary Materials. For the stand-alone LAES system, the thermal oil DOWTHERM-G is employed as the heat storage medium. Round-trip efficiency is a key performance indicator when it comes to evaluating an energy storage system. In this study, it is defined as the ratio of the energy output to the energy input, which can be described as:

evaluate the feasibility of the integrated LAES-TCES system. Specifically, a thermodynamic analysis is carried out to assess the technical performance and an economic analysis is performed to evaluate the economic performance. 3.1. Thermodynamic analysis The process simulation package Aspen Plus v10 is employed to implement the thermodynamic analysis. In the past studies on compressed air energy storage, Aspen Plus has shown high accuracy when comparing simulation results with practical data [45]. For the property method, the Peng-Robinson equation of state is selected. In terms of modeling solid streams, the conventional solid processing method is adopted without considering the impact of particle size. Furthermore, the reactors are modeled using the Rstoic reactor model where the conversion of reaction is specified. Specifically, the reduction reaction is fully completed in the examined range of operating conditions while the extent of oxidation reaction varies according to the reactivity of CoO. Fig. 2 shows the Aspen simulation flowsheet of the integrated LAES-TCES system. The following assumptions have been made throughout the modeling work: 1) 2) 3) 4) 5)

ηRTE =

EOUTPUT × 100% EINPUT

(5)

where ηRTE is the round-trip efficiency, %; EOUTPUT is the energy output of the discharging step, MWh; EINPUT is the energy input of the charging step, MWh. EOUTPUT can be calculated as: (6)

EOUTPUT = WTURB − WCRYOPUMP − WPC2

where WTURB is the total work output of the air turbines (TB1 and TB2), MWh; WCRYOPUMP is the power input of the cryogenic pump (C-pump), MWh; WPC2 is the power input of the phenumatic conveyor (PC2) in the energy discharging step, MWh. EINPUT can be calculated as:

Steady-state operation Negligible pressure drops in equipment other than the turbines Heat dissipations in the components are negligible Equal time periods of charging and discharging processes A designed net power output of 60 MWe

(7)

EINPUT = EINPUT − LAES + EINPUT − TCES

where EINPUT-LAES is the energy input of the LAES subsystem, MWh; EINPUT-TCES is the energy input of the TCES subsystem, MWh. EINPUT-LAES can be defined by:

Table 3 summarizes the main operating parameters applied in the thermodynamic analysis of the integrated LAES-TCES system. It should be noted that the compression ratios of all air compressors are set to be

(8)

EINPUT − LAES = WCOMP + WCL − WCRYOTURB

Table 3 Main operating parameters employed in the modeling of the integrated LAES-TCES system. Subsystem

Component

Parameter

Value

Turbomachinery

Air compressors

Isentropic efficiency Mechanic efficiency Stages Intercooling temperature Outlet pressure of the fourth compressor Isentropic efficiency Mechanic efficiency Stages Outlet pressure of the second turbine Isentropic efficiency Mechanic efficiency Outlet pressure Isentropic efficiency Mechanic efficiency Outlet pressure

0.89 0.98 4 35 °C 140.00 bar 0.90 0.98 2 1.01 bar 0.80 0.96 1.01 bar 0.70 0.96 50.00 bar

Minimum temperature Maximum temperature Minimum temperature Maximum temperature

−59.15 °C [17] 14.85 °C [17] −180.15 °C [17] −59.15 °C [17]

Air turbines

Cryogenic turbine

Cryogenic pump

Cold box

Methanol Propane

Heat exchangers

HX1-HX4 HX5, HX6 HX7, HX8 HX9 HX10

Minimum Minimum Minimum Minimum Minimum

Reactors

Reduction reactor

Temperature Pressure Temperature Pressure

950 °C 1.01 bar 850 °C 1.01 bar

Energy demand Temperature Energy demand Hour

10 MJ/tonne [46] 25 °C 0.8% of heat released [47] 8

Oxidation reactor Solids transport Ambient Heat rejection Time of charging/discharging

Pneumatic conveyor Air cooler

6

temperature temperature temperature temperature temperature

approach approach approach approach approach

5 °C 5 °C 2 °C 15 °C 30 °C

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

equipment type. Table 5 gives the specific calculation methods of the purchase costs. It should be noted that the purchase cost of the heat exchangers is estimated according to the heat exchange area. A more detailed calculation of the heat exchange area can be found in Supplementary Materials. Table 6 presents the assumptions of calculating the operating and maintenance cost (O&M cost) in the integrated LAES-TCES system. Table 7 presents the unit costs of storage materials used in the current study. Net present value (NPV) and levelized cost of electricity (LCOE) are introduced to compare the economic performance of the examined LAES-TCES, LAES, and TCES systems. Specifically, NPV indicates the profitability of a planned project and LCOE stands for the average cost at which electricity is generated. NPV is defined as the difference of present value between cash inflows and outflows over a period, which can be calculated as:

where WCOMP is the total energy consumption of the air compressors (CP1-CP4), MWh; WCL is the power input of the air cooler (CL), MWh; WCRYOTURB is the work output of the cryogenic turbine (C-turb), MWh. EINPUT-TCES can be defined by: (9)

EINPUT − TCES = QREDUC − WPC1

where QREDUC is to the energy input of the reduction reactor, MWh; WPC1 is the power input of the phenumatic conveyor (PC1) in the energy charging step, MWh. Apart from the round-trip efficiency, energy storage density is also crucial in evaluating an energy storage system. Normally, energy storage density is defined as the amount of recovered energy per unit volume or mass of storage medium used, namely volumetric energy storage density or gravimetric energy storage density, respectively. The volumetric one is widely applied in LAES systems primarily because the storage volume is usually a more important factor than the storage mass. However, the past studies on LAES systems failed to reach a consensus on the definition of the storage volume, which results in substantially varied values of energy storage density. For instance, as shown in Table 1 and Table 2, some studies only considered the storage of liquid air while others took the volume of both liquid air and thermal oil into account. In this study, considering that the footprint of the storage system is closely related to all the storage tanks, the energy storage density is defined as:

EDEN =

EOUTPUT × 1000 VSTORAGE

NPV =

R

∑ (1 +t j)t

(14)

where Rt means the net cash inflow-outflows in year t, USD; j refers to discount rate, %. LCOE allows for comparing electricity generation costs among different technologies. It is defined as the electricity generation costs over the life of the plant divided by the total amount of generated electricity, which can be expressed as [54]:

(10) 3

where EDEN is the energy storage density, kWh/m ; VSTORAGE is the total volume of all the storage tanks, m3, calculated by:

VSTORAGE = VLAIR + VMETH + VPROP + VMETA + VTHER

It + Mt + Ot (1 + r )t E ∑ (1 +tr )t

∑ LCOE =

(11)

where VLAIR is the storage volume of the liquid air, m3; VMETH is the total volume of the methanol storage tanks, m3; VPROP is the total volume of the propane storage tanks, m3; VMETA is the total volume of the metal oxides storage tanks, m3; VTHER refers to the total volume of the thermal oil storage tanks, m3. Based on the second law of thermodynamics, exergy analysis is also conducted to identify the losses caused by irreversibility [48]. The specific calculation methods employed in the current research can be found in a previous study [42].

(15)

where It is the total capital investment in year t, USD; Mt refers to the O &M costs in year t, USD; Ot is the off-peak electricity cost in year t, USD/ MWh; Et is the electricity generated in year t, MWh; r is inflation rate, %. Table 8 presents the economic estimation data used for calculations of NPV and LCOE.

4. Results and discussions 3.2. Economic analysis This section illustrates the techno-economic performance of the integrated LAES-TCES system according to the thermodynamic and economic analyses. Based on the obtained results, comparisons between the proposed LAES-TCES system and other parallel technologies (i.e. stand-alone LAES and TCES systems) are also conducted.

To examine the economic feasibility of the integrated LAES-TCES system, a lifetime cost analysis is performed in the paper. The lifetime cost is generally divided into total capital investment and operation and maintenance costs. Table 4 shows the assumed calculation methods of each item in the estimation of total capital investment. For some components with a historical quote per unit capacity, the current purchase cost can be obtained by:

C = CP × Q ×

CEPCI CEPCI0

Table 4 Assumptions in the calculation of total capital investment.

(12)

where C is the current purchase cost of the equipment with a capacity of Q, USD; CP is the unit price of the equipment, USD per unit; Q is the capacity of the equipment; CEPCI refers to the Chemical Plant Cost Index for the current year; CEPCI0 is the Chemical Plant Cost Index for the reference year. For other equipment (e.g. heat exchangers, reactors, cyclone, and pneumatic conveyor), the corresponding purchase costs can be calculated using the following equation:

Q C = C0 × ⎛ ⎞ Q ⎝ 0⎠ ⎜

⎟

M

CEPCI × CEPCI0

Parameter

Assumption

I. Total direct plant costs (TDPC) 1. Total purchased cost (TPC) 2. Installation 3. Instrumentation and controls, installed 4. Piping, installed 5. Electric, installed 6. Building 7. Land

25% of TPC [49] 8% of TPC [49] 10% of TPC [49] 10% of TPC [49] 10% of TPC [49] 4% of TPC [49]

II. Indirect costs (IC, e.g. engineering and supervision, contractor’s fee, yard development) Engineering procurement and construction (EPC)

(13)

where C0 is the reference purchase cost of the equipment with a capacity of Q0, USD; M is a constant which depends on the specific 7

14% of TDPC [50] TDPC + IC [50]

III. Contingencies and owner’s costs (C&OC) 1. Contingency 2. Owner’s cost

10% of EPC [50] 5% of EPC [50]

IV. Total capital investment (TCI)

EPC + C&OC [49]

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

4.1. Thermodynamic analysis

Table 5 Purchase costs estimation of equipment. Equipment

Cost estimation model

Cost year

CEPCI [51]

Compressor

C = 7.90 × (W)0.62, 103 USD [52] W: power input, kW C = 1.10 × (W)0.81, 103 USD [52] W: power output, kW C = 32.8 × (A/80)0.68, 103 USD [53] A: heat exchange area, m2 C = 48000 × (Q/910)0.6, 103 USD [54] Q: Thermal duty, MW C = 240.0 × (F/47.85)0.8, 103 USD [50] F: flow rate, m3/s C = 15.6 × (F/10)0.6, 103 USD [55] F: flow rate, tonne/h Same as the turbine [30] C = 483 × W, USD [30] W: power input, kW C = 500 × V, USD [56] V: volume, m3 C = 320 × V, USD [57] V: volume, m3 C = 423 × V, USD [30] V: volume, m3 C = 572 × V, USD [30] V: volume, m3 C = 1326 × V, USD [30] V: volume, m3

2009

521.9

2009

521.9

2005

468.2

2018

605.2

2013

567.3

2016

541.7

2018 2018

605.2 605.2

2018

605.2

2013

567.3

2018

605.2

2018

605.2

2018

605.2

Turbine

Heat exchanger

Reduction and oxidation reactors Cyclone

Pneumatic conveyor Cryogenic turbine Cryogenic pump Solid tank Cryogenic tank Thermal oil tank Methanol tank Propane tank

Fig. 3 compares the temperature-entropy (T-s) profiles of the working fluid, air, in the integrated LAES-TCES, stand-alone LAES, and stand-alone TCES systems. The corresponding properties of stream flows can be found in Supplementary Materials. In the T-s diagram of the integrated LAES-TCES system (see Fig. 3(a)), the inlet ambient air is compressed sequentially from state A1 to state A9. Meanwhile, the produced compression heat is taken away by the cooling water. The pressurized air is then introduced to the cold box which contains methanol, propane, and recovered cold air. As a result, the air is liquefied and achieves a low temperature of −175.55 °C at state A12. This is followed by a cryogenic expansion process, where the liquefied air expands to near-ambient pressure (see state A13 in Fig. 3(a)) in the cryogenic turbine C-turb. The produced mixture of liquid and gaseous air is then separated in the gas-liquid separator. Once separated, the gaseous air (state A14) flows to the cold box while the liquid air (state A17) is stored in the liquid air tank for later uses. In the discharging process of the integrated LAES-TCES system, the stored liquid air at state A17 is pumped to state A18 and then heated and evaporated in heat exchangers HX7 and HX8. Through this process, the temperature of the air is increased from −194.39 °C (state A17) to 8.82 °C (state A20). Prior to expanding in air turbine TB1, the air is further heated to 788.60 °C (state A21) in heat exchanger HX9. After expansion, the temperature of the air is reduced to 411.86 °C at state A22 and it is again heated to 622.00 °C (state A23) in the heat exchanger HX10. The reheated air flows into the air turbine TB2 and the pressure is reduced to near-ambient (state A24) after generating work. The exhaust air from the air turbine TB2 is introduced to the oxidation reactor and reacted with the stored CoO. During this step, the energy stored in the charging step of the TCES subsystem is released. Finally, the reacted air achieves a temperature of 849.97 °C at state A25 and its sensible heat is transferred to the incoming cold air in the heat exchangers HX9 and HX10. When comparing the T-s diagrams of the integrated LAES-TCES system, the stand-alone LAES system, and the stand-alone TCES system, it can be seen from Fig. 3 that the integrated LAES-TCES process shows a significantly wider operating temperature range. Specifically, the integrated LAES-TCES operates between −194.39 °C and 849.97 °C while the stand-alone LAES and TCES systems work under the temperature ranges of −194.39 °C to 217.88 °C, and 25.00 °C to 849.99 °C, respectively. This is simply because that the proposed LAES-TCES system consists of both LAES and TCES subsystems. Consequently, the integrated LAES-TCES system possesses a higher upper-limit temperature than the stand-alone LAES and a lower lower-limit temperature than the stand-alone TCES. This enlarged temperature range is beneficial to realizing a high thermodynamic efficiency according to Carnot principles [62]. Table 9 summarizes the overall performances of the studied LAESTCES, LAES, and TCES systems under the specified configurations in Section 3.1. The stand-alone LAES achieves a round-trip efficiency of 52.8%, which is considerably close to the value obtained by Guizz et al. [17] and Tafone et al. [16]. Meanwhile, the stand-alone TCES presents a round-trip efficiency of 34.1%, which is around 12% less than the 44% calculated by Schrader et al. [40]. However, this large difference in efficiency is due to the ideal isentropic efficiency of turbomachinery (i.e. 100%) employed in their study. From Table 9, it can be found that the integrated LAES-TCES system achieves a round-trip efficiency of 47.4%, which is 5.4% lower than the corresponding value of the standalone LAES. This is primarily because that, the compression heat of air, which acts as a heat source in the stand-alone LAES, is completely rejected in the integrated LAES-TCES system. This leads to the additional energy input of the TCES part and gives rise to a lower round-trip efficiency according to Equation (5). Provided that the compression heat can be partially used in the integrated LAES-TCES system, such as district heating or cooling, the efficiency of the LAES-TCES plant can

Table 6 Assumptions of calculating operating and maintenance costs. Parameter

Assumption

I. Total fixed O&M cost 1. Operating labor cost (OLC) 2. Maintenance labor cost 3. Administrative & support labor cost 4. Property taxes 5. Insurance

0.8% of TCI [49] 0.8% of TCI [49] 25% of OCL [49] 2% of TCI [49] 1% of TCI [49]

II. Total variable O&M costs 1. Storage materials cost 2. Off-peak electricity cost 3. Maintenance material cost 4. Storage material make up

According to Table 7 30 USD/MWh 2% of TCI [49,58] 5% per year

Table 7 Unit price of materials. Material

Unit cost

Cost year

Thermal oil Methanol Propane Co3O4

5,000 USD/tonne [56] 519 USD/tonne [59] 264 USD/m3 [60] 46,000 USD/tonne [61]

2018 2018 2018 2018

Table 8 Economic estimation data for calculations of NPV and LCOE. Parameter

Assumption

Inflation rate Discount rate Charge/discharge cycles Lifetime of plants

2% 8% 365 cycles/year 30 years

8

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

Temperature (°C)

750

950

LAES-TCES Hot gasous/liquid air Cold gasous air Air saturation line

A25 A21

Temperature (°C)

950

A23

550 A22

350 A9 A7 A5

150

Cooling water Methanol/cold gasous air Propane/cold gasous air

-50

A12

-250

TCES A24

A3

A10 A8 A6 A4 A1A2 A11 A20 A16 A26 A19 A15 A14

A18 A17 A13

-5

-4

-3

-2

-1

0

1

750

A7L

A20L

A5L A3LA24L A22L

A21L A6L A4L

A25L A23L A14L A2L A1L

550 A19L

350 150 -50

-250

2

LAES Hot gasous/liquid air Cold gasous air Air saturation line

Thermal oil

A8L

Methanol/cold gasous air A9L Propane/cold gasous air A16L

-5

A10L

A14L A18L A17L A13L A12L

A15L A11L

-4

-3

-2

-1

0

Entropy (kJ/kg·K)

Entropy (kJ/kg·K)

(a)

1

2

(b)

950

Temperature (°C)

TCES

A7T

A11T

750 A9T

550

TCES

350

A8T A10T A4T

150

Cooling water

A5T

-50 -250

-5

-4

-3

-2

-1

A12T A2T

A6T

A3T

0

A1T

Entropy (kJ/kg·K)

1

2

(c) Fig. 3. T-s diagrams of (a) LAES-TCES, (b) LAES, and (c) TCES systems.

According to Table 9, the integrated LAES-TCES system is found to have an energy storage density of around 36.8 kWh/m3. This value is close to those of the examined LAES systems using natural gas, as implied in Table 2. However, the proposed LAES-TCES system replaces the use of natural gas with the TCES subsystem and thus poses fewer impacts on the environment. Meanwhile, the energy storage density of the integrated LAES-TCES system is found to be more than 3 times as those of the LAES systems that use thermal oil as the heat storage medium. For instance, it is 3.4 times that of the stand-alone LAES examined in this study. The improvement in the energy storage density is also owing to the added TCES subsystem, which operates at a higher temperature and possesses a larger heat storage capacity compared to thermal oil storage. It should be noted the energy storage density of the integrated LAES-TCES system is much less than the 385.2 kWh/m3 of the compared stand-alone TCES system. This is simply due to the fact that the stand-alone TCES uses only metal oxides that have a high chemical energy content while the integrated LAES-TCES system uses a mixture of metal oxides and methanol, propane, and liquid air, which present significantly lower energy storage density. Fig. 4 illustrates the volumes of tanks and inventory requirements of the key materials in the integrated LAES-TCES, stand-alone LAES, and stand-alone TCES systems. As can be seen in Fig. 4(a), the total volume of the storage tanks in the integrated LAES-TCES system is found to be around 27 m3 per MWh power output, which is between the 93 m3/ MWh of the stand-alone LAES system and the 3 m3/MWh of the standalone TCES system. The proposed LAES-TCES system eliminates the use of the thermal oil storage in a typical LAES, which becomes the primary

Table 9 Overall performance of LAES-TCES, LAES, and TCES under the specified configurations. Name

Unit

LAES-TCES

LAES

TCES

Energy input Energy output Oxygen production TCES ratio Round-trip efficiency Energy storage density

MW MW kg/MWh % % kWh/m3

126.5 60.0 217.7 53.9 47.4 36.8

113.7 60.0 0.0 0.0 52.8 10.8

175.9 60.0 559.0 100.0 34.1 385.2

reach a similar level of the stand-alone LAES system. On the other hand, the round-trip efficiency of the integrated LAES-TCES system is found to be 13.3% higher than that of the stand-alone TCES system, which represents a large efficiency leap in thermochemical energy storage. In the stand-alone TCES system, the air compression step taking place in the discharging process consumes a large amount of the work generated by air turbines. By contrast, the air compression step is now shifted to the charging process in the integrated LAES-TCES system, which therefore reduces the energy consumption of air compression in the discharging process and ensures a much higher round-trip efficiency based on Equation (8). Meanwhile, as shown in Table 9, the TCES subsystem of the integrated LAES-TCES system contributes to 53.9% of the total energy input. This means that almost half of the stored energy is sourced from the TCES subsystem. In addition, the integrated LAESTCES system is still capable of producing oxygen as would be the case in the stand-alone TCES system. 9

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

100

Thermal oil Methanol Propane

30

Metal oxides Liquid air

Inventory requirement (tonne/MWh)

Volume of tank (m3/MWh)

120

80 60 40 20 0

LAES-TCES

LAES

20 15 10 5 0

TCES

LAES-TCES LAES TCES

25

Thermal oil Methanol

Co3O4

Energy storage systems

Propane

Liquid air

Materials

(a)

(b)

100 80

LAES-TCES

Power demand Power output

Charging

Power demand/output (MW)

Power demand/output (MW)

Fig. 4. Key materials requirements in LAES-TCES, LAES, and TCES: (a) tank volumes; (b) inventory requirements.

Discharging

60 40 20 0 4 b 1 2 3 1 RR CP CP CP CP -tur PC C

C L TB

1

100 80

Charging

Discharging

60 40 20 0

2 2 p TB pum PC C-

1 CP

2 CP

3 CP

(a)

Power demand/output (MW)

LAES

Power demand Power output

b

tur

C-

CL

TB

1

TB

2

TB

3

mp

pu

C-

(b)

200

Charging Discharging

TCES Power demand Power output

160 120 80 40 0 RR

1 PC

TB

1

TB

2

1 CP

2 CP

3 CP

2 PC

CL

(c) Fig. 5. Power demand/output of system components in: (a) LAES-TCES; (b) LAES; (c) TCES (RR: reduction reactor; CP: air compressor; C-turb: cryogenic turbine; PC: pneumatic conveyor; CL: air cooler; TB: air turbine; C-pump: cryogenic pump). 10

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

stand-alone LAES system are much bigger and more expensive than the ones in the integrated LAES-TCES system. For the stand-alone TCES, as Fig. 5(c) shows, the capacities of the reduction reactor, turbines, and compressors are greater than those of the proposed LAES-TCES system. For example, the power demand of the reduction reactor in the stand-alone TCES is about 174 MW, which is more than two times that of the integrated LAES-TCES system. Also, in contrast with the LAES-TCES and LAES systems, the air compression step of the stand-alone TCES takes place in the discharging process. Although the gross power output of the turbines in the TCES system is 160 MW, the net power output remains at 60 MW. The high energy consumption in the discharging process results in a low round-trip efficiency of the stand-alone TCES. Instead, by shifting the compression step to the charging process, the integrated LAES-TCES system realizes a much higher round-trip efficiency compared to the stand-alone TCES and, at the same time, requires smaller turbomachines, compressors, and reactors. Fig. 6 illustrates the Grassmann diagram of exergy flows of the integrated LAES-TCES system. This Grassmann diagram clearly shows the sources of input exergy in the two subsystems. Meanwhile, it can also be seen from Fig. 6 that the transfer, destruction, and loss of exergy in the equipment. Based on Fig. 6, the exergy efficiency of the proposed LAESTCES system is calculated to be 63.6%. Fig. 7 depicts the exergy efficiency of the key components in the proposed LAES-TCES system. For the air turbines TB1 and TB2 and air compressors CP1-CP4, they all share a high exergy efficiency of around 90.0%. By contrast, the cryogenic turbine C-turb and cryogenic pump C-pump present low exergy efficiency of 49.3% and 11.8%, respectively. The low exergy efficiency is mainly attributed to their low isentropic efficiency. Besides, a low exergy efficiency of around 50.0% is also found in the intercoolers HX1-HX4, which can be associated with the large temperature difference in the heat exchange processes. Fig. 7 also shows that the reduction reactor features a lower exergy efficiency than that of the oxidation reactor. This is primarily owing to the exergy losses associated with oxygen production in the reduction reactor. Fig. 8 illustrates the exergy destruction and exergy destruction ratios of the key components in the proposed LAES-TCES system. According to Fig. 8, the highest exergy destruction ratio is found in the

reason behind its significantly smaller volume of storage tanks. Also, the required storage volume of liquid air in the integrated LAES-TCES system is also decreased when compared with that of the stand-alone LAES. This is because the upper-limit temperature of the air is elevated to about 850 °C, as illustrated in the T-s diagram (see Fig. 3), which lifts its efficiency. Furthermore, this lowered requirement of liquid air in the integrated LAES-TCES system leads to the declined inventory requirement of methanol and propane, as shown in Fig. 4(b). According to Fig. 4(b), the inventory requirement of metal oxides in the integrated LAES-TCES system and the stand-alone TCES system are found to be 3.3 tonne/MWh and 8.4 tonne/MWh, respectively. The lowered inventory can be attributed to the LAES subsystem, which can also fulfill its energy storage function via air liquefaction. The considerably reduced inventory requirement of metal oxides in the integrated LAES-TCES system is expected to lower the total costs of the storage system, which will be discussed in detail in Section 4.2. Besides, the inventory requirements of methanol, propane, and liquid air are also declined in the integrated LAES-TCES system compared to the stand-alone LAES system. Fig. 5 compares the breakdown of power demand/output of the major system components in the three examined energy storage systems rated at a net 60 MWe output. Fig. 5(a) shows that in the charging process of the integrated LAES-TCES system, the power demand of the reduction reactor is the highest (68 MW) among all the equipment. This is followed by the total power demand of the four air compressors, accounting for about 56 MW. In the discharging process, the air turbine TB1 results in slightly greater power output than the air turbine TB2 due to the higher turbine inlet temperature of TB1. The power demand/ output of other components, such as cryogenic turbine (C-turb), cryogenic pump (C-pump), air cooler (CL), and pneumatic conveyors (PC1 and PC2), are relatively small. Similarly, in the stand-alone LAES (see Fig. 5(b)), the major power demand and output are found to be mainly in the compressors and turbines. It should be noted that the power demand of the air compressors in the examined LAES is found to be 50% larger than that in the integrated LAES-TCES system. This is simply because the stored energy in the stand-alone LAES is only sourced from the air liquefaction process. Hence, for the same power output the air compressors in the

Fig. 6. Grassmann diagram of LAES-TCES. 11

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

Exergy efficiency (%)

100 80 60 40 20

CP 1 CP 2 CP 3 CP 4 H X 1 H X 2 H X 3 H X 4 H X 5 H X 6 H X 7 H X 8 H X H 9 X 1 C- 0 tu C - rb pu m p TB 1 TB 2 O R RR

0

Fig. 7. Exergy efficiency of the key components in LAES-TCES.

reduction reactor, which contributes 33.8% of the total exergy destruction. This high exergy destruction implies high irreversibility of the reduction reaction, where high-quality energy, electricity or concentrated high-temperature heat, is converted to low-quality energy, namely sensible and thermochemical energy. The exergy destruction ratio of the oxidation reactor ranks the second, demonstrating nearly 9.7% of the total exergy destruction. The destruction ratio of the oxidation reactor is about one-third that of the reduction reactor, which is comparable to a previous study on metal oxide-based TCES [42]. Compared to the oxidation reactor, the heat exchangers HX6 and HX7 show slightly lower exergy destruction ratios. However, the exergy destructions of HX6 and HX7 are also found to be the greatest among all the heat exchangers units primarily owing to their high thermal duty, where a large amount of coldness and heat is transferred.

Table 10 Costs of equipment and storage materials used in LAES-TCES, LAES, and TCES.

4.2. Economic analysis Table 10 compares the specific costs of the equipment and storage materials of the integrated LAES-TCES, stand-alone LAES, and standalone TCES systems. From Table 10, the equipment cost of the integrated LAES-TCES system is found to be the lowest at 54 million USD while the stand-alone LAES is found to be the highest, reaching about 74 million USD. In between is the stand-alone TCES system costing 65 million USD. The high equipment cost of the stand-alone LAES plant is primarily because of the high demand for air liquefaction, where highcost compressors and storage tanks are required. In comparison, the integrated LAES-TCES system has smaller compressors that lead to a lower cost. With respect to the storage materials, the material cost of the integrated LAES-TCES system is found to be higher than that of the stand-alone LAES yet significantly lower than that of the stand-alone

Cost (USD)

LAES-TCES

LAES

TCES

Compressor Turbine Cryogenic turbine Cryogenic pump Heat exchangers Reactors Cyclone Pneumatic conveyor Cryogenic tank Thermal oil tank Methanol tank Propane tank Solid tank Total cost of equipment Thermal oil Methanol Propane Co3O4 Total materials cost Total cost of equipment and materials

$13,640,641 $10,947,688 $409,774 $285,015 $3,740,039 $10,123,292 $979,453 $276,273 $795,753 – $1,359,557 $11,312,452 $242,735 $54,112,671 – $386,539 $1,056,000 $72,358,068 $73,800,607 $127,913,278

$18,717,614 $11,880,074 $673,432 $535,769 $7,740,406 – – – $1,495,920 $9,380,334 $2,586,697 $21,259,828 – $74,270,075 $48,025,561 $769,408 $1,978,944 – $50,773,913 $125,043,988

$17,318,106 $23,819,980 – – $2,796,614 $17,788,771 $2,018,206 $327,803 – – – – $620,000 $64,689,480 – – – $185,747,424 $185,747,424 $250,436,904

40

Exergy destruction (kW)

20000 30

15000

20

10000

10

5000 0

1 2 3 4 1 2 3 4 5 6 7 8 9 10 rb p 1 2 R R CP CP CP CP HX HX HX HX HX HX HX HX HX X -tu pum TB TB O R H C C

Fig. 8. Exergy destruction and exergy destruction ratio of key components in LAES-TCES. 12

0

Exergy destruction ratio (%)

TCES plant. Specifically, the examined LAES-TCES, LAES, and TCES plants require total material costs of 74 million USD, 51 million USD, and 186 million USD, respectively. The high material cost found in the LAES-TCES and TCES systems can be mainly attributed to the metal oxide—Co3O4, which is expensive as a rare-earth metal oxide. Provided that the Co3O4 used in the proposed LAES-TECS system be replaced by other abundant metal oxides with high energy storage density and good

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

reversibility, the material cost can be reduced. Nevertheless, the integrated LAES-TCES system reveals a lower cost of Co3O4 in comparison to that of the stand-alone TCES because the TCES subsystem of the integrated system only accounts for about half of the energy storage capacity. It can be concluded from Table 10 that the integrated LAESTCES system shows a lower total cost of equipment and materials than that of the stand-alone TCES system although it is slightly higher than that of the stand-alone LAES system. Fig. 9 shows the contributions of specific components to the total equipment and material costs in the examined LAES-TCES, LAES, and TCES systems. As revealed in Fig. 9, the cost of the storage materials occupies the largest ratio of the total cost in all the examined storage systems. For instance, the costs of Co3O4 account for nearly 56.6% and 74.2% in the LAES-TCES and TCES systems, respectively. This high percentage of Co3O4 cost agrees well with a previous study on thermochemical energy storage, where the raw material Co3O4 contributes to more than 80% of the total cost [63]. Meanwhile, the cost of the thermal oil in the stand-alone LAES also achieves a large ratio of about 38.4%, which is significantly higher than the other system components. Apart from the storage materials, the turbomachinery accounts for another major fraction of the equipment and material costs in all the examined storage systems. For instance, in the integrated LAES-TCES plant, the cost ratios of the compressors and turbines are estimated to be 10.7% and 8.6%, respectively. Also, as shown in Fig. 9, around 7.1–7.9% of the total cost are spent on the reactors of the TCES and LAES-TCES systems. In the air liquefaction involved storage systems (i.e. LAES and LAES-TCES), the costs of the propane tank should not be ignored, which account for 8.8% in the integrated LAES-TCES system and 17.0% in the stand-alone LAES system. Fig. 10 shows how the NPV changes with time in the examined LAES-TCES, LAES, and TCES systems. As illustrated in Fig. 10, the initial investment of the integrated LAES-TCES and the stand-alone LAES are both around 200 million USD, which is nearly 120 million USD less than that of the stand-alone TCES with the same power output. The NPVs of the integrated LAES-TCES system and the stand-alone LAES plant both increase gradually and eventually reach roughly 141 million USD and 143 million USD, respectively. In comparison, the final-year NPV of the examined TCES system is predicted to be −122 million USD. The poor economic performance of the stand-alone TCES plant using Co3O4/CoO is also confirmed in Bayon et al.’s study [63]. Hence, by integrating the LAES system, the economic feasibility of the TCES system can be largely enhanced. According to Fig. 10, the payback periods of the integrated LAES-TCES and the stand-alone LAES are both found to be about 10 years with the integrated system presenting a

Fig. 10. NPV as a function of time in LAES-TCES, LAES, and TCES (off-peak electricity price = 30 USD/MWh).

Fig. 11. LCOE as a function of off-peak electricity price in LAES-TCES, LAES, and TCES.

Fig. 9. Contributions of specific components to the total equipment and material costs in LAES-TCES, LAES, and TCES. 13

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

is examined in this study and found to be superior in many aspects than both the stand-alone LAES and TCES technologies. Specifically, it is cleaner and safer than LAES technology because no fossil fuels/mineral oil need to be used. It is also more compact than LAES due to the inclusion of thermochemical energy storage with high energy density. When compared with the stand-alone TCES system, the integrated system is significantly more efficient because it alters the way how the stored thermochemical energy is converted into electrical power. This work proves that the new integrated system can join the emerging cutting-edge technologies and become an alternative for utility-scale energy storage with its own featured technical and economic edges. Thermodynamic and economic analyses are employed to assess and compare the performance of the integrated LAES-TCES system with the stand-alone LAES and TCES systems. The conclusions derived from the analyses are listed as follows:

slightly shorter payback period. This payback period is found to be not far from the 8.7–9.8 years obtained in Lin et al.’s study where a standalone LAES system was investigated [64]. For the examined stand-alone TCES plant, the initial investment, however, cannot be recouped in 30 years. Thus, the stand-alone TCES system cannot become economically competitive in the current market conditions. The shortest payback period for the integrated system is mainly due to its lowest initial capital investment and the cost saving as a result of the shared power generation facilities between its two subsystems. Fig. 11 reveals the LCOE as a function of the off-peak electricity price in the examined LAES-TCES, LAES, and TCES plants. The LCOEs of the investigated LAES-TCES and LAES systems are found to rise gradually from 110–120 USD/MWh to around 190–200 USD/MWh as the off-peak electricity is increased from 0 USD/MWh to 40 USD/MWh. Meanwhile, the corresponding LCOE of the stand-alone TCES system appears to be more adversely affected by an increased off-peak electricity price, changing from 190 USD/MWh to nearly 310 USD/MWh. With respect to LCOE, a comparison between the examined three systems and other typical storage technologies has been given in Fig. 12. It should be noted that the reference data adapted from Smallbone et al.’s research [65] and Jülch’s work [66] are named as levelized cost of storage (LCOS), which are calculated according to the same principle as LCOE [67]. As Fig. 12 shows, the proposed LAESTCES system achieves a moderate LCOE of 179 USD/MWh (off-peak electricity price = 30 USD/MWh) or 186 USD/MWh (off-peak electricity price = 30 EURO/MWh). These obtained LCOE values are lower than the LCOEs of TCES and various batteries but higher than those of the developed PHS and CAES plants. However, compared to PHS and CAES plants, an obvious advantage of the proposed integrated system is that it eliminates geographical limitations. In comparison with the other LAES systems, such as the LAES in the current study and the LAES-A in Guizzi et al.’s study [17], and Kim et al.’s research [30], the proposed LAES-TCES presents a relatively similar LCOE. It is worth noting that the LAES-B plant, a LAES-based storage system suggested by Kim et al. [30], has a low LCOE of nearly 150 USD/MWh. However, it was found that this plant involves the use of natural gas which gives rise to environmental concerns, such as carbon dioxide emission. Overall, the integrated LAES-TCES system is found to be a perfect alternative to the LAES system with similar capital cost, payback period, and LCOE, and as a cleaner, safer, and less constrained technology in addition to an enhanced energy storage density.

1) The round-trip efficiency of the LAES-TCES system reaches 47.4%, which is 13.3% higher compared to the stand-alone TCES system. The improved efficiency is mainly contributed by switching the high energy-consuming air compression process to the charging step. 2) The energy storage density of the integrated system, found to be 36.8 kWh/m3, is about 3.4 times as that of the stand-alone LAES system. 3) The NPVs of the integrated system and the stand-alone LAES system are 141 million USD and 143 million USD, respectively, both of which are significantly higher than that of the stand-alone TCES system. The stand-alone TCES system is found to be uneconomical at the examined conditions and results in a negative NPV. 4) The LCOE of the LAES-TCES system is found to range from 179 USD/MWh to 186 USD/MWh depending on the price of off-peak electricity. This is highly competitive compared to other parallel storage technologies. The above findings suggest that the proposed LAES-TCES system can realize its energy storage function in a cleaner, more efficient, and costeffective manner. It also confirms that by combining existed technologies it is possible to create synergies and outperform the related standalone systems. The current techno-economic assessment is just an initial step to fully evaluating the integrated LAES-TCES system. Future studies can focus on the parametric analysis of key operating parameters, such as pressure and temperature. Besides, the dynamic characteristics of the proposed system with unstable energy inputs are to be investigated. The exploration of using low-cost raw materials (e.g. CuO/Cu2O) may also lead to a reduced cost of the new technology.

5. Conclusion An integrated liquid air and thermochemical energy storage system

Fig. 12. Levelized costs ofelectricity among various storage systems (off-peak electricity = 30 EURO/MWh unless otherwise specified) [17,30,65,66]. *Off-peak electricity price = 30 USD/MWh, 1 EURO = 1.11 USD at 30th May 2019. 14

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

Declaration of Competing Interest

Transfer—Asian Res 2000;29:347–57. [28] Li Y, Wang X, Jin Y, Ding Y. An integrated solar-cryogen hybrid power system. Renewable Energy 2012;37:76–81. [29] Al-Zareer M, Dincer I, Rosen MA. Analysis and assessment of novel liquid air energy storage system with district heating and cooling capabilities. Energy 2017;141:792–802. [30] Kim J, Noh Y, Chang D. Storage system for distributed-energy generation using liquid air combined with liquefied natural gas. Appl Energy 2018;212:1417–32. [31] Cetin TH, Kanoglu M, Yanikomer N. Cryogenic energy storage powered by geothermal energy. Geothermics 2019;77:34–40. [32] Ströhle S, Haselbacher A, Jovanovic ZR, Steinfeld A. The effect of the gas-solid contacting pattern in a high-temperature thermochemical energy storage on the performance of a concentrated solar power plant. Energy Environ Sci 2016;9:1375–89. [33] Prieto C, Cooper P, Fernández AI, Cabeza LF. Review of technology: thermochemical energy storage for concentrated solar power plants. Renew Sustain Energy Rev 2016;60:909–29. [34] Wu S, Zhou C, Doroodchi E, Nellore R, Moghtaderi B. A review on high-temperature thermochemical energy storage based on metal oxides redox cycle. Energy Convers Manage 2018;168:421–53. [35] Moghtaderi B. Application of chemical looping concept for air separation at high temperatures. Energy Fuels 2010;24:190–8. [36] Alonso E, Pérez-Rábago C, Licurgo J, Fuentealba E, Estrada CA. First experimental studies of solar redox reactions of copper oxides for thermochemical energy storage. Sol Energy 2015;115:297–305. [37] Wong B. Thermochemical heat storage for concentrated solar power. Office of Scientific & Technical Information Technical Reports; 2011. [38] Carrillo AJ, Moya J, Bayón A, Jana P, O’Shea VADLP, Romero M, et al. Thermochemical energy storage at high temperature via redox cycles of Mn and Co oxides: pure oxides versus mixed ones. Sol Energy Mater Sol Cells 2014;123:47–57. [39] André L, Abanades S, Flamant G. Screening of thermochemical systems based on solid-gas reversible reactions for high temperature solar thermal energy storage. Renew Sustain Energy Rev 2016;64:703–15. [40] Schrader AJ, Muroyama AP, Loutzenhiser PG. Solar electricity via an Air Brayton cycle with an integrated two-step thermochemical cycle for heat storage based on Co3O4/CoO redox reactions: thermodynamic analysis. Sol Energy 2015;118:485–95. [41] Wu S, Zhou C, Doroodchi E, Moghtaderi B. A unique phase change redox cycle using CuO/Cu2O for utility-scale energy storage. Energy Convers Manage 2019;188:366–80. [42] Wu S, Zhou C, Doroodchi E, Moghtaderi B. Thermodynamic analysis of a novel hybrid thermochemical-compressed air energy storage system powered by wind, solar and/or off-peak electricity. Energy Convers Manage 2019;180:1268–80. [43] Flamant G, Gauthier D, Benoit H, Sans JL, Garcia R, Boissière B, et al. Dense suspension of solid particles as a new heat transfer fluid for concentrated solar thermal plants: on-sun proof of concept. Chem Eng Sci 2013;102:567–76. [44] Jafarian M, Arjomandi M, Nathan GJ. Thermodynamic potential of molten copper oxide for high temperature solar energy storage and oxygen production. Appl Energy 2017;201:69–83. [45] Meng H, Wang M, Aneke M, Luo X, Olumayegun O, Liu X. Technical performance analysis and economic evaluation of a compressed air energy storage system integrated with an organic Rankine cycle. Fuel 2018;211:318–30. [46] Edwards SEB, Materić V. Calcium looping in solar power generation plants. Sol Energy 2012;86:2494–503. [47] Ortiz C, Romano MC, Valverde JM, Binotti M, Chacartegui R. Process integration of Calcium-Looping thermochemical energy storage system in concentrating solar power plants. Energy 2018. [48] Chen S, Lior N, Xiang W. Coal gasification integration with solid oxide fuel cell and chemical looping combustion for high-efficiency power generation with inherent CO2 capture. Appl Energy 2015;146:298–312. [49] Ma L-C, Castro-Dominguez B, Kazantzis NK, Ma YH. Integration of membrane technology into hydrogen production plants with CO2 capture: an economic performance assessment study. Int J Greenhouse Gas Control 2015;42:424–38. [50] Spallina V, Pandolfo D, Battistella A, Romano MC, Annaland MVS, Gallucci F. Techno-economic assessment of membrane assisted fluidized bed reactors for pure H2 production with CO2 capture. Energy Convers Manage 2016;120:257–73. [51] Intelligence Access. Economic Indicators. Chem Eng 2018;125:76. [52] Couper JR, Penney WR, Fair JR, Walas SM. Chemical Process Equipment (Revised Second Edition); 2009. [53] Smith R. Chemical Process Design and Integration. John Wiley; 2005. [54] Farooqui A, Bose A, Ferrero D, Llorca J, Santarelli M. Techno-economic and exergetic assessment of an oxy-fuel power plant fueled by syngas produced by chemical looping CO2 and H2O dissociation. J CO2 Util 2018;27:500–17. [55] Walker J, Asim T, Mishra R, Adams M. Life-cycle cost modelling of pneumatic conveying pipelines for the lean phase. Transport Condition 2016. [56] Xue H, White A. A comparative study of liquid, solid and hybrid adiabatic compressed air energy storage systems; 2018. [57] Hu Y, Li X, Li H, Yan J. Peak and off-peak operations of the air separation unit in oxy-coal combustion power generation systems. Appl Energy 2013;112:747–54. [58] Li G, Liu Z, Liu T, Shan J, Fang Y, Wang Z. Techno-economic analysis of a coal to hydrogen process based on ash agglomerating fluidized bed gasification. Energy Convers Manage 2018;164:552–9. [59] Methanex Corporation. Methanex posts regional contract methanol prices for North America, Europe and Asia; 2018. [60] U.S. Energy Information Administration. Heating Oil and Propane Update; 2018. [61] Shanghai Metals Market. Prices of other minor metals; 2018.

The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. Acknowledgment The authors appreciate the funding that they received from The University of Newcastle. References [1] International Energy Agency (IEA). Key World Energy Statistics 2018; 2018, pp. 10–11. [2] Ji W, Zhou Y, Sun Y, Zhang W, An B, Wang J. Thermodynamic analysis of a novel hybrid wind-solar-compressed air energy storage system. Energy Convers Manage 2017;142:176–87. [3] Díaz-González F, Sumper A, Gomis-Bellmunt O, Villafáfila-Robles R. A review of energy storage technologies for wind power applications. Renew Sustain Energy Rev 2012;16:2154–71. [4] Chen H, Conga TN, Yang W, Tan C, Li Y, Ding Y. Progress in electrical energy storage system: a critical review. Progr Natural Sci: Mater Int 2009;19:291–312. [5] Hadjipaschalis I, Poullikkas A, Efthimiou V. Overview of current and future energy storage technologies for electric power applications. Renew Sustain Energy Rev 2009;13:1513–22. [6] Cheung BC, Carriveau R, Ting SK. Parameters affecting scalable underwater compressed air energy storage. Appl Energy 2014;134:239–47. [7] Luo X, Wang J, Dooner M, Clarke J. Overview of current development in electrical energy storage technologies and the application potential in power system operation. Appl Energy 2015;137:511–36. [8] Kondoh J, Ishii I, Yamaguchi H, Murata A, Otani K, Sakuta K, et al. Electrical energy storage systems for energy networks. Energy Convers Manage 2000;41:1863–74. [9] Mahlia TMI, Saktisahdan TJ, Jannifar A, Hasan MH, Matseelar HSC. A review of available methods and development on energy storage; technology update. Renew Sustain Energy Rev 2014;33:532–45. [10] Smith EM. Storage of electrical energy using supercritical liquid air. Proc Inst Mech Eng 1977;191:289–98. [11] Krawczyk P, Szabłowski Ł, Karellas S, Kakaras E, Badyda K. Comparative thermodynamic analysis of compressed air and liquid air energy storage systems. Energy 2018;142:46–54. [12] Budt M, Wolf D, Span R, Yan J. A review on compressed air energy storage: basic principles, past milestones and recent developments. Appl Energy 2016;170:250–68. [13] Highview Power. What is a Highview Power plant?; 2019. https://www. highviewpower.com/plants/. [14] Morgan R, Nelmes S, Gibson E, Brett G. Liquid air energy storage – analysis and first results from a pilot scale demonstration plant. Appl Energy 2015;137:845–53. [15] Peng X, She X, Li C, Luo Y, Zhang T, Li Y, et al. Liquid air energy storage flexibly coupled with LNG regasification for improving air liquefaction. Appl Energy 2019;250:1190–201. [16] Tafone A, Borri E, Comodi G, van den Broek M, Romagnoli A. Liquid air energy storage performance enhancement by means of organic rankine cycle and absorption chiller. Appl Energy 2018;228:1810–21. [17] Guizzi GL, Manno M, Tolomei LM, Vitali RM. Thermodynamic analysis of a liquid air energy storage system. Energy. 2015;93:1639–47. [18] Xie C, Hong Y, Ding Y, Li Y, Radcliffe J. An economic feasibility assessment of decoupled energy storage in the UK: With liquid air energy storage as a case study. Appl Energy 2018;225:244–57. [19] Zhang T, Chen L, Zhang X, Mei S, Xue X, Zhou Y. Thermodynamic analysis of a novel hybrid liquid air energy storage system based on the utilization of LNG cold energy. Energy. 2018;155:641–50. [20] Peng H, Shan X, Yang Y, Ling X. A study on performance of a liquid air energy storage system with packed bed units. Appl Energy 2018;211:126–35. [21] Farres-Antunez P, Xue H, White AJ. Thermodynamic analysis and optimisation of a combined liquid air and pumped thermal energy storage cycle. J Storage Mater 2018;18:90–102. [22] She X, Peng X, Nie B, Leng G, Zhang X, Weng L, et al. Enhancement of round trip efficiency of liquid air energy storage through effective utilization of heat of compression. Appl Energy 2017;206:1632–42. [23] Khalil KM, Ahmad A, Mahmoud S, Al-Dadah RK. Liquid air/nitrogen energy storage and power generation system for micro-grid applications. J Cleaner Prod 2017;164:606–17. [24] Peng X, She X, Cong L, Zhang T, Li C, Li Y, et al. Thermodynamic study on the effect of cold and heat recovery on performance of liquid air energy storage. Appl Energy 2018;221:86–99. [25] Li Y, Li D, Cao H, Wang X, Wang S, Jin Y, et al. Load shifting of nuclear power plants using cryogenic energy storage technology. Appl Energy 2014;113:1710–6. [26] Antonelli M, Barsali S, Desideri U, Giglioli R, Paganucci F, Pasini G. Liquid air energy storage: potential and challenges of hybrid power plants. Appl Energy 2017;194:522–9. [27] Chino K, Araki H. Evaluation of energy storage method using liquid air. Heat

15

Energy Conversion and Management 205 (2020) 112341

S. Wu, et al.

[65] Smallbone A, Jülch V, Wardle R, Roskilly AP. Levelised cost of storage for pumped heat energy storage in comparison with other energy storage technologies. Energy Convers Manage 2017;152:221–8. [66] Jülch V. Comparison of electricity storage options using levelized cost of storage (LCOS) method. Appl Energy 2016;183:1594–606. [67] Kost C, Mayer JN, Thomsen J, Hartmann N, Senkpiel C, Philipps S, et al. Levelized cost of electricity renewable energy technologies. Fraunhofer Inst Solar Energy Syst ISE 2013;144.

[62] Stekli J, Irwin L, Pitchumani R. Technical challenges and opportunities for concentrating solar power with thermal energy storage. J Therm Sci Eng Appl 2013;5. 021011-021011-021012. [63] Bayon A, Bader R, Jafarian M, Fedunik-Hofman L, Sun Y, Hinkley J, et al. Technoeconomic assessment of solid–gas thermochemical energy storage systems for solar thermal power applications. Energy 2018;149:473–84. [64] Lin B, Wu W, Bai M, Xie C, Radcliffe J. Liquid air energy storage: price arbitrage operations and sizing optimization in the GB real-time electricity market. Energy Econ 2019;78:647–55.

16