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Research Papers: Energy Systems Analysis

Performance Analysis and Detailed Experimental Results of the First Liquid Air Energy Storage Plant in the World OPEN ACCESS

[+] Author and Article Information
A. Sciacovelli, D. Smith, M. E. Navarro, A. Vecchi, X. Peng, Y. Li, J. Radcliffe, Y. Ding

Birmingham Centre for Energy Storage,
School of Chemical Engineering,
University of Birmingham,
Birmingham B15 2TT, UK

Contributed by the Advanced Energy Systems Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received January 26, 2017; final manuscript received October 30, 2017; published online November 28, 2017. Assoc. Editor: George Tsatsaronis.

J. Energy Resour. Technol 140(2), 020908 (Nov 28, 2017) (10 pages) Paper No: JERT-17-1039; doi: 10.1115/1.4038378 History: Received January 26, 2017; Revised October 30, 2017

Liquid air energy storage (LAES) is a technology for bulk electricity storage in the form of liquid air with power output potentially above 10 MW and storage capacity of 100 s MWh. In this paper, we address the performance of LAES and the experimental evidences gathered through the first LAES pilot plant in the world developed by Highview power storage at Slough (London) and currently installed at the University of Birmingham (UK). We developed a numerical model of LAES plant and carried out an experimental campaign to gather new results which show the LAES operating principles, the reliability of the technology, the startup/shut down performance, and the influence of operational parameters. In summary, this work (a) contributes to the advancement of thermomechanical storage systems, (b) provides new experimental evidences and results for LAES technology, and (c) highlights the crucial aspects to necessarily improve the performance of LAES.

FIGURES IN THIS ARTICLE
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The world wide average CO2 intensity of power generation is still above 500 kg of CO2 per MWh [1]. To align with 2 °C global warming scenario, the current emissions need to fall to about 80 kg of CO2 per MWh by 2040. Ways to achieve this inevitably include a strong penetration of renewable energy sources which, according to the International Energy Agency scenario, could reach a global share nearly 60% by 2040 [1]. This path is already undergoing and undeniable; in 2015, renewable electricity capacity exceeded 150 GW and renewables accounted for more than half of annual additions to power capacity [2].

Such radical transformation of the energy sector brings multiple technical challenges, such as lack of balance between supply and demand, risk of curtailment, and increased stress on networks. In this context, the energy storage has the potential to play key roles including balancing generation and demand, maintaining system reliability, and deferring network reinforcement. Both distributed and bulk energy storage are expected to play an important role in future energy systems [36], but although distributed storage has seen major progresses in recent years [7,8], bulk storage still relies on pumped hydroelectricity storage (PHS) [9,10]. Figure 1 compares the rated power and the rated capacity of possible large-scale energy storage technologies; electrochemical batteries mainly cover the power range below 10 MW, while the only solutions with power rating of 100 s MW remain to be compressed air energy storage (CAES) and PHS which accounts for 99% of the worldwide storage capacity [9]. However, PHS has major drawbacks and the extension of PHS storage capacity is problematic. PHS is geographically limited, which severely impacts on the surrounding environment and brings high capital costs. Similarly, CAES is limited by geographical restrictions and by relatively low round trip efficiency [1517].

Alternative solutions for grid scale storage are needed now more than ever given the expected increase in renewable generation. This paper investigates one on the most attractive solutions: liquid air energy storage (LAES) [1820]. Here, we present the concept, the experimental and numerical analysis of the first LAES pilot plant currently installed at the University of Birmingham. We operated the pilot plant to prove the key concepts, components, and processes of LAES. The experimental results were then used to validate the developed mathematical model. The experiments indicate that, at full scale, LAES has the potential to provide bulk storage with far superior flexibility and opportunities of integration compared with PHS and CAES.

The three distinct processes characterize liquid air energy storage, charge, storage, and discharge, as schematically illustrated in Fig. 2. Excess electricity during charge drives an air liquefaction unit which compresses and refrigerates air to its liquid state. Liquid air is then stored in insulated tanks which act as energy store. liquefied natural gas-type cryogenic tanks can be readily used without modification to store liquid air; the state of the art insulation can limit boil off rate as low as 0.07% [21] enabling long term storage. During the discharge process, liquid air is withdrawn from storage tanks, pumped at high pressure (>50 bar), and evaporated in a series of heat exchangers, before expanding in turbines to generate electricity. Waste heat sources (e.g., thermal plants, stationary diesel engines, and geothermal energy) collocated with the LAES plant can be harnessed during discharge to evaporate and reheat air between expansion stages. During discharge, the cold thermal energy is stored in the high grade cold thermal storage (HGCS). The stored cold thermal energy from the HGCS is then made available during charging process to displace part of the refrigeration load required to liquefy air, increasing the round trip efficiency of LAES. Liquid air energy storage extensively uses commercially available components. For example, air liquefiers that are available from cryogenic industry can be used during charge, while gas turbines and turbomachinery from the power industry employed during discharge. Thus, the availability of off the shelf components with a proven supply chain makes LAES capable to provide grid scale storage capacity without geographical constraints and at a competitive cost; an estimation of LAES costs can be found in Refs. [19] and [21].

Liquid air energy storage ideally operates according to the thermodynamic processes shown in Fig. 3. Air is liquefied through a Claude cycle which comprises isothermal compression from ambient to maximum pressure (1C–2C); isobaric refrigeration (2C–3C) until optimal conditions for isenthalpic expansion (3C–4C) and separation of liquefied fraction; and recirculation of vapor fraction of air (5C–1C). The discharge process consists of pumping of liquid air (1D–2D), vaporization of liquid air under supercritical conditions (2D–3D), and expansion of air in turbine stages (dashed lines in Fig. 3 right) with reheating.

The theoretical performance of LAES, quantified by the round trip efficiency ηcycle, can be expressed as follows: Display Formula

(1)ηcycle=wtwc=YWtWc

where wt is the specific power output (kW/kg) during discharging, while wc is the specific power input required during charging to liquefy air. It is important to notice that the flow rate of air differs from charge to discharge mode. The liquid yield Y appears in Eq. (1) if the ratio of power output to power input is used to calculate the round trip efficiency. The liquid yield represents the ratio of flow rate of liquefied air to total flow rate. From the analysis of the thermodynamic cycle in Fig. 3, it is possible to quantify Y as Display Formula

(2)Y=h1Ch2C+qCRh1Ch4l

where h is the specific enthalpy, qCR is the amount of cold thermal energy recycled by the cold storage (Fig. 1), and the subscripts refer to the thermodynamic states indicated in Fig. 3. In Eq. (2), h4l is the enthalpy of air at saturated liquid conditions for the same pressure of point 4C, i.e., the enthalpy of air on the saturated liquid curve of the T-s diagram. The amount of cold recycled is given by Display Formula

(3)qCR=heD(h1D+wp)
in which heD is the enthalpy of air at ambient temperature and at discharge pressure, namely inlet pressure of the first turbine stage; in other terms, heD is the enthalpy of air before superheating. Finally, wp is the specific pumping power required to pressurize liquid air before its evaporation.

Combining Eqs. (1)(3) allows to evaluate the theoretical round trip efficiency of LAES given the thermodynamic state points for the charging and discharging processes. Figure 4 presents the obtained results as a function of the charging pressure and discharging pressure, namely the inlet turbine inlet pressure during power recovery. The trends in Fig. 4 clearly indicate that LAES efficiency benefits from increasing both charging and discharging pressure. Higher charging pressure increases the liquid yield, while the discharging pressure has two effects: (i) increase turbine power output and (ii) reduce the recycled cold thermal energy which, however, is largely offset by the increase in power output.

System Layout.

The Birmingham Centre for Energy Storage, University of Birmingham (UK) hosts the first liquid air energy storage plant in the world, as shown in Fig. 5. The technology concept was originally developed by Highview Power Storage [18,22,23] together with researchers at the University of Birmingham, and the pilot plant was first constructed by Highview at their development site in Slough before being relocated to Birmingham in 2014. The pilot plant has a rated power of 350 kW and a rated capacity of 2.5 GWh; the main parameters of the plant are summarized in Table 1. All the components of the plant are commercially available with the exception of the high grade cold thermal storage. The liquefaction unit was supplied by Chengdu Air Separation Corporation and its main component is shown in Fig. 6. Compression of air to maximum pressure (p4) is carried out through a main air compressor and by a booster driven by a cryogenic turbine which expands a spilled fraction of the air mass flow rate flowing through the cold box. The main air stream (5–10 in Fig. 6) is refrigerated by the recirculated stream of cold air and by the stream from the high grade cold storage. Finally, the air stream not recirculated is liquefied by sub cooling and stored in the cryogenic tank. Table 2 lists the thermodynamic states for the liquefaction process. The maximum pressure is about 12 bar, i.e., lower than the optimal one predicted and presented in Fig. 4, since the liquefaction unit is small compared to state of the art art commercial liquefiers (up to 1000 ton/day), which enable optimal charging pressure and therefore better performance. When relocated at Birmingham, the plant was equipped with a hot water thermal storage tank to provide heat for evaporation of air (discharge process) and to investigate the effect of waste heat recovery. The hot water tank is charged through a steam to water heat exchanger in which the steam is supplied by the near by university combined heat and power plant.

Figure 7 illustrates the process flow diagram and main components for the discharge process. Two reciprocating cryogenic pumps pressurize the stream of liquid air (1–2 in Fig. 7) from the cryogenic tank up to 60 bar before its evaporation in a gas to gas parallel type heat exchange in which secondary stream consists of gaseous air from the outlet of the turbine. Air is then heated and reheated between expansion stages by means of water glycoll/air heat exchangers; heat for reheating is supplied by the hot water storage tank through a secondary water/water glycol loop. Finally, air expands in a four stages radial turbine manufactured by Concepts NREC. Thermodynamic states and performance of LAES during discharge are detailed in the following paragraph.

The evaporator (Fig. 7) enables to implement the recycling of cold thermal energy between discharge and charge processes. During discharge, the secondary stream of the evaporator (15–16) provides heat to evaporate the liquid air; the resulting cold stream, rather than being exhausted to ambient, flows through a modular packed bed cold thermal storage (Fig. 8). The quartzite rocks exchange cold thermal energy by direct contact with the cold air stream and retain it in the form of sensible thermal energy. During subsequent air liquefaction process, the cold thermal energy is retrieved by flowing a stream of air from ambient through the packed bed and then direct the resulting cold stream to the cold box (Fig. 6). Quartzite rocks with an average diameter of 15 mm are used in eight cells with two pairs of four cells arranged in parallel. A modular design of the cold storage presents several advantages: (i) scalability by connection of more cells; (ii) efficiency operation at reduced duty charging/discharging might involve different mass flow rates flowing through the cold thermal storage; and (iii) less structural issues and reduced mechanical stresses.

Figure 9 presents the predicted roundtrip efficiency for the pilot plant as a function of the discharge pressure, which was possible to control though the cryogenic pumps during the operation of the LAES pilot plant. A comparison between Figs. 9 and 4 indicates that the estimated pilot plant efficiency is about half the theoretical limit. This is due to the small size of the liquefaction unit of the pilot plant and the corresponding charging/discharging pressures, which are significantly lower than the optimal one presented in Fig. 4. Moreover, only about 50% is recycled through the high grade cold thermal storage which limits the overall efficiency. At full commercial scale, a standalone LAES is expected to approach an efficiency of 60% (stand alone plant without waste heat integration). A precommercial scale demonstrator 5 MW/15 MWh installed in Manchester (UK) will demonstrate performances at scale and will allow to assess the operational costs for different energy storage services.

Thermodynamic Model of LAES.

A thermodynamic model of the charging and discharging process was developed to predict the pilot plant performance and enable further research on optimal design and operation of LAES. For each component illustrated in Figs. 6 and 7, engineering equation solver [24] was used to implement mass balance, energy, and entropy balance equations Display Formula

(4)im˙i=0
Display Formula
(5)ΦW˙t=im˙i(houthin)i

The cold box was represent in more detail to account for possible pinch point conditions occurring inside the heat exchanger. From modeling point of view, the cold box was discretized along the streams direction and at each evaporator, and balance equations were applied to each section.

The work required by cryogenic pumps was calculated as Display Formula

(6)W˙P=V˙ΔpηP

where V˙ is the volumetric flow rate crossing the component and Δp the pressure rise liquid air is subject to. Effectiveness εi was used to characterize two streams heat exchangers: Display Formula

(7)εi=(m˙cp)h(TinTout)h(m˙cp)minΔTMAX=(m˙cp)c(ToutTin)c(m˙cp)minΔTMAX

where min refers to the stream with smaller heat capacity rate and ΔTMAX is the difference between inlet temperatures of hot and cold streams. Finally, the pressure drop within each component was quantified as a function of the inlet pressure [20] Display Formula

(8)pi,out=(1ξi)pi,in

The cold recycle and the specific cold recycle qCR were defined as Display Formula

(9)ΦCR=m˙lqCR=m˙CB(hCB,inhCB,out)

The high grade cold thermal storage was considered fully stratified; thus, the air outlet temperature from the HGCS (see Fig. 9) was considered constant and destratification of the HGCS was neglected.

The performance of the pilot plant was assessed through an experimental campaign that aimed at identifying the key feature of charging/discharging processes, the thermal behavior of components, and validating the model proposed in the previous section. Thermodynamic state along the pilot plant is summarized in Table 2 for the charging process and in Tables 35 for the discharging process. The experimental data for the charging process were gathered when the plant was located in Slough (London). The tables also report the prediction of the numerical model. Under nominal condition, the liquefaction unit operates at 12.2 bar (5 in Fig. 6) and expands about 78% of the main air stream to ambient pressure through the cryogenic turbine. A liquid yield of 17% was achieved during charging process. At scale (liquefier with production capacity >500 ton/day), liquid yield above 70% is proved [19,21], which significantly contributes to improved round trip efficiency LAES at commercial scale. Furthermore, the use of multiple cryoturbines along the cold box can improve the match of temperature profiles of cold and hot streams in the main heat exchanger [25] reducing exergy losses and improving further the overall efficiency.

During LAES discharge, power output was modulated to investigate the response time of the pilot plant and assess the capacity of LAES to follow time variation of demand; a typical service of energy storage systems. Figure 10 shows the time evolution of the power output and the air flow rate for three power levels. The pilot plant shown excellent response time for a thermomechanical storage system; it was brought to ∼70% of maximum power output in less than 2 min, delivering nearly constant power for 15 min. A minimum flow of liquid air was necessary to effectively produce electricity during discharge. This was necessary to bring the turbine train to 3000 rpm before its synchronization with the electric generator. Such initial stage can be potentially avoided by operating the system in spin generation mode which enables continuous synchronization of the turbine/generator assembly. Power output slightly drifts within the first 20 min due to the increase in temperature of the lubricant oil loop and consequent reduction of friction in the supports of the turbine train. However, constant power generation was achieved once steady-state temperature was reached (t > 25 min in Fig. 10). The pilot plant also showed excellent response time during ramp down; the power output was brought to zero within two minutes.

Tables 35 show how variation in power output affects the thermodynamic state along the discharging process. Once the system is in operation, discharge process is controlled by acting on the speed of the cryogenic pumps, right after the liquid air storage tank. This modifies the mass flow rate which is crossing the expansion stage and thus the total power output. The inlet pressure in the first turbine is also influenced by the operating condition. The circuit characteristic in fact accounts for a total pressure drop which is a function of fluid velocity, and thus, mass flow rate. However, the pressure ratio between turbine stages stays nearly constant which reduces the impact of off-design conditions onto the performance of the system.

The predictive capability of the mathematical model was tested by comparing the computed thermodynamic states with the measured values. The results are presented in Tables 25. For the discharging process, the values are compared once the nominal power output is achieved. The model shows solid performance and it is capable to predict accurately the thermodynamic states for both the charging and discharging processes. The largest difference between experimental and numerical results, still within 10%, occurred for the lower power generation. This difference can be attributed to off-design conditions, in particular variation of turbine isentropic efficiency with respect to mass flow rate. The former was assumed constant in the model. Finally, Table 6 presents the predicted energy transfer rates during the discharge process for different power outputs generated by the turbine train. The heat transfer rate for each heat exchanger is enumerated following the direction of the flow air in Fig. 7. Namely, the first heat transfer rate corresponds to the evaporator, while the last one corresponds to the heater before the HGCS. All the energy rates can be obtained by applying Eq. (5) and using the results in Tables 25.

Liquid air energy storage technology offer multiple opportunities for process integration. As illustrated in the schematic of Fig. 2, waste heat from sources such as gas turbines, diesel generators, and industrial processes can be harnessed during LAES discharge. Waste heat is used to increase the intrastage reheat temperature of the turbine train during power generation. We varied experimentally the pilot plant intrastage reheat temperature by adjusting the water flow rate in the reheaters and we recoded the corresponding change in LAES power output; thus, we mimicked the effect of waste heat temperature on LAES performance. The results presented in Fig. 11 (left) show that the intrastage reheat temperature strongly affects the power output; an increase of 1 °C brings an increment of about 0.45% in generated power. Furthermore, LAES is capable of harnessing from low to high grade heat sources thanks to the low operating temperature of liquid air. Figure 11 (right) also shows how the power output from the LAES plant correlates with the flow rate of air during discharge process. A linear trend can be clearly observed, indicating that speed variation of cryogenic pumps, and thus variation of flow rate, can effectively be used to modulate the power output from LAES. The identified trend is also beneficial from modeling prospective, since can be used to develop input–output correlations necessary to formulate optimization problems (e.g., through MILP technique) to address, for example, the optimal operation of LAES systems.

The performance of the high grade cold thermal storage were also scrutinized during the operation of the pilot plant. Figure 12 (left) shows the evolution in time and temperature of the packed bed. The three thermocouples were installed at the bottom, middle, and top of one packed bed cell. The trends in Fig. 12 (left) are typical of packed bed thermal storage systems; each temperature drop at a specific time (TCbott: 5 min; TCmiddle: 20 min; and TCtop: 30 min) which indicates the propagation of a thermal front, commonly named thermocline [26,27], along the packed bed. The sharp drop of temperature visible in Fig. 12 (left) indicates that the temperature stratification in the HGCS is satisfactory. Therefore, the experimental results positively confirm the use of packed bed thermal storage as a viable way to store cold thermal energy available during LAES discharge process.

The amount of cold recycled by the HGCS drastically affects the performance of LAES. Figure 12 (right) shows that the specific liquefaction work (wc in Eq. (1)) decreases by about 35% when specific cold recycled is about 160 kWh/kg. It is worthy to note that the liquefaction work without cold recycled is about 0.7 kWh/kg; however, at larger scale, state of the art liquefier can produce liquid air at the expense of 0.5 kWh/kg [11]. Thus, at commercial scale, LAES will be intrinsically more efficient than at the pilot scale and the benefits of cold recycle will be greater.

In this work, we presented the performance and the modeling of the first liquid air energy storage pilot plant in the world. In LAES, energy is stored and retrieved by consecutive liquefaction and vaporization of air. The technology is intended to provide large scale energy storage at grid level with potential power rate above 10 MW, storage capacity of 100 s MWh, and expected round trip efficiency of 60%. The pilot plant at Birmingham, a 350 kW/2.5 MWh demonstrator, shows promising performance and excellent reliability; in particular, the experimental results point out the following:

  • The charging process can be implemented using off the shelf liquefier from gas industry; this guarantees the supply chain for LAES and ensures high reliability of components. At commercial scale, LAES is expected to benefit from the high efficiency of large scale liquefier
  • Discharging process responds rapidly (80% of max power within 2 min), easily follows changes in power demand, and presents excellent opportunities for waste heat integration
  • Recycling cold thermal energy from discharge to charge process proved to be essential. The modular cold packed bed recycles about 160 kWh/kg which reduces by 35% the amount of work necessary for air liquefaction.

Further development is required to fully optimize the LAES cycle to achieve efficiency close to the theoretical limit; key elements around LAES that should be thoroughly investigated are as follows:

  • Thermal energy storage materials and systems to improve storage of both cold and heat during discharging and charging processes. Cycling operation, energy storage density, and costs should be addressed.
  • Efficiency and life span of cryogenic pumps and turbines under off design conditions expected for liquid air energy storage process; Novel thermodynamic cycles for discharge process to increase round trip efficiency. In particular, indirect cycles with cryogenic fluids such as CO2, CH4, and C3H8.
  • Process integration of LAES with other generation facilities (thermal plants, diesel generators, and solar thermal) and with liquefied natural gas terminals to exploit waste heat and waste cold.
  • Optimal operation and dispatching strategies to exploit multiple revenues streams, stack services provided, and support strong business cases.

The authors would like to thank Highview Power Storage for the technical support with the LAES pilot plant.

  • Engineering and Physical Sciences Research Council (Grant No. 1EP/L019469/1).
  • Energy Storage for Low Carbon Grids (Grant No. EP/K002252/1).
  • NexGen-TEST Next Generation Grid Scale Thermal Energy Storage Technologies (Grant No. EP/L014211/1).
  • Consortium for Modelling and Analysis of Decentralised Energy Storage (Grant No. EP/N001745/1).

  • h =

    specific enthalpy (J kg−1)

  • m˙ =

    mass flow rate (kg s−1)

  • p =

    pressure (Pa)

  • qCR =

    specific cold recycle (J kg−1)

  • T =

    temperature (K)

  • V˙ =

    volume flow rate (m3 s−1)

  • w =

    specific work (J kg−1)

  • W˙ =

    power (W)

  • Y =

    liquid yield

 Greek Symbols
  • ε =

    heat exchanger effectiveness

  • ηp =

    cryogenic pump efficiency

  • ηcycle =

    round trip efficiency

  • ξ =

    relative pressure drop

  • ρ =

    density (kg m−3)

  • Φ =

    heat flux (W)

  • ΦCR =

    cold recycle (W)

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References

IEA, 2016, “World Energy Outlook,” International Energy Agency, Paris, France, accessed Nov. 13, 2017, https://www.iea.org/publications/freepublications/publication/WorldEnergy Outlook2016ExecutiveSummaryEnglish.pdf
IEA, 2016, “Renewable Energy Medium-Term Market Report,” International Energy Agency, Paris, France, accessed Nov. 13, 2017, https://www.iea.org/Textbase/npsum/MTrenew2016sum.pdf
D. Martens , ed., 2013, “EASE/EERA European Energy Storage Technology Development Roadmap Toward 2030,” European Association for Storage of Energy, Brussels, Belgium, accessed Nov. 13, 2017, https://www.eera-set.eu/wp-content/uploads/148885-EASE-recommendations-Roadmap-04.pdf
Carbon Trust, 2016, “Can Storage Help Reduce the Cost of a Future UK Electricity System?,” Carbon Trust, London, accessed Nov. 13, 2017, https://www.carbontrust.com/media/672486/energy-storage-report.pdf
Cho, J. , Jeong, S. , and Kim, Y. , 2015, “ Commercial and Research Battery Technologies for Electrical Energy Storage Applications,” Prog. Energy Combust. Sci., 48, pp. 84–101. [CrossRef]
Zakeri, B. , and Syri, S. , 2015, “ Electrical Energy Storage Systems: A Comparative Life Cycle Cost Analysis,” Renewable Sustainable Energy Rev., 42, pp. 569–596. [CrossRef]
Aneke, M. , and Wang, M. , 2016, “ Energy Storage Technologies and Real Life Applications—A State of the Art Review,” Appl. Energy, 179, pp. 350–377. [CrossRef]
Chauhan, A. , and Saini, R. P. , 2014, “ Review on Integrated Renewable Energy System Based Power Generation for Stand-Alone Applications: Configurations, Storage Options, Sizing Methodologies and Control,” Renewable Sustainable Energy Rev., 38, pp. 99–120. [CrossRef]
Luo, X. , Wang, J. , Dooner, M. , and Clarke, J. , 2015, “ Overview of Current Development in Electrical Energy Storage Technologies and the Application Potential in Power System Operation,” Appl. Energy, 137, pp. 511–53. [CrossRef]
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Figures

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Fig. 1

Comparison of for large scale energy storage technologies [1114]. PHS: pumped hydroelectric storage; CAES: compressed air energy storage; Li ion: lithium ion batteries; NaS: sodium–sulfur batteries; VRB: vanadium redox flow battery; and LAES: liquid air energy storage.

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Fig. 2

Schematic of liquid air energy storage system

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Fig. 3

Thermodynamic cycles for the charging (left) and discharging (right) processes

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Fig. 4

Predicted theoretical round trip efficiency for the LAES

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Fig. 5

Liquid air energy storage pilot plant at the University of Birmingham, School of Chemical Engineering, UK

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Fig. 6

Liquid air energy storage pilot plant process flow diagram for charging process

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Fig. 7

Liquid air energy storage pilot plant process flow diagram for discharging process

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Fig. 8

Schematic of the HGCS

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Fig. 9

Predicted theoretical round trip efficiency for the LAES pilot plant

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Fig. 10

Power output of LAES pilot plant power during discharge trial. The dashed lines identify the beginning of the initial start up and final shutdown of the plant.

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Fig. 11

(Left) Influence of turbine inlet temperature on power output of LAES pilot plant. (Right) Power output versus mass flow rate of the LAES pilot plant.

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Fig. 12

(Left) Temperature evolution in the high grade cold storage during LAES pilot plant operation. (Right) Effect of cold recycled.

Tables

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Table 1 Main parameters of LAES pilot plant
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Table 2 Thermodynamic states for pilot plant charging process; experimental values (gray) versus predicted (white)
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Table 3 Thermodynamic states for pilot plant discharging process at power output of 230 kW; experimental values (gray) versus predicted (white)
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Table 4 Thermodynamic states for pilot plant discharging process at power output of 210 kW: experimental values (gray) versus predicted (white)
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Table 5 Thermodynamic states for pilot plant discharging process at power output of 160 kW: experimental values (gray) versus predicted (white)
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Table 6 Energy transfer rates computed for different conditions during LAES discharge process

Errata

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