U NIVERSITÁ DI P ISA
DOTTORATO DI RICERCA IN INGEGNERIA DELL’ENERGIA, DEI SISTEMI, DEL TERRITORIO E DELLE COSTRUZIONI
D ISSERTATION T ITLE
ANALYSIS OF A PUMPED THERMAL ELECTRICITY STORAGE SYSTEM WITH THE INTEGRATION OF LOW TEMPERATURE
HEAT SOURCES
CANDIDATE GUIDO FRANCESCO FRATE
SUPERVISOR PROF. ENG. UMBERTO DESIDERI
Pisa, October 2019
XXXII cycle
Abstract
Electric energy production systems all around the world are currently experiencing a major revolution caused by the massive introduction of non- programmable Renewable Energy Sources (RES). The widespread diffusion of such technologies is changing both the electric energy production and consumption paradigms. As a matter of fact, the systems are now shifting towards a less centralized configuration, and the consumers are assuming a more active role as they are becoming able to produce at least a part of the energy they need.
All these things are happening to decarbonize the electric energy production sector, which is the major net contributor to pollutants and CO
2emissions. To reach this ambitious goal, the RES penetration must be greatly increased, but this arises technical issues that must be solved before to continue the RES development. After a rapid initial RES growth, in which the electric systems demonstrated their ability of accommodating the RES, it is now starting a phase in which additional electric storage capacity must be deployed on the grids to balance the RES production fluctuations. As the sites suited for pumped hydro storage plants are already exploited at most, a strong research effort aimed at developing alternative storage technologies is taking place. Several alternative technology concepts have been proposed, ranging from electrochemical devices, to thermo-mechanical applications. However, which one could be the successor of pumped hydro, or even if there will be just one or more successors, is still an open question. To contribute to the outlined research line, in this dissertation an innovative electric energy storage technology potentially suited for grid scale applications is proposed and analyzed. The investigated system belongs to a broader technology family which comprises an heterogenous group of technologies based on the idea of storing electric energy as thermal energy. Such group of technologies is known in literature by several names, with Pumped Thermal Electricity Storage (PTES) being the most common. Notwithstanding, the name “Carnot Batteries” is lately growing in popularity and may be found as well in literature. In PTES systems, the charge phase is usually performed by using a Heat Pump (HP), the energy conservation is entrusted to a Thermal Energy Storage (TES), which can be either a latent or a sensible one, and the discharge phase is performed by means of a Heat Engine (HE). In this dissertation, a system based on Vapor Compression HPs (VCHPs) and Organic Rankine Cycles (ORCs) is investigated. The classical configuration which may be found in literature has been modified to allow the heat pump being powered also by low-temperature heat sources, such that the system performance is improved. The use of additional low temperature heat sources has been called Thermal Integration (TI), which led to the development of a TI-PTES system.
Compared to standard PTES configurations, the VCHP does not move the
thermal energy between two thermal reservoirs (hot and cold). In fact, by
exploiting additional thermal energy inputs, here the VCHP performs an
upgrading of the provided thermal energy, which is then stored in the TES. This
technique is known in literature, since it may have also some waste heat recovery
applications in industry. In the industrial context, the systems performing the heat
upgrading are called High Temperature HPs (HTHPs). Therefore, in this
dissertation a TI-PTEs system based on HT-VCHPs and ORCs is proposed and
investigated. Several TI-PTES design aspects are analyzed in detail, ranging from
the working fluids choice, to the thermodynamic cycle design optimization. In
the dissertation a multi-criteria approach is often assumed to characterize the TI-
PTES and HT-VCHP systems in respect to several performance metrics. Part of
the dissertation is focused on HT-VCHP design and economic analysis, as this
component is the most critical and the less studied of the proposed TI-PTES
system. In conclusion, in this dissertation a detailed theoretical analysis of a TI-
PTES system is provided. Several aspects are investigated and the trade-offs
between different performance parameters are characterized by means of a multi-
criteria analysis approach. Special attention is dedicated to the thermodynamic
design optimization of the TI-PTES sub-systems and to the economic analysis of
the HT-VCHP. A cost model for this component is developed and prosed as a
first step towards a complete TI-PTES cost model.
1-1
Chapter 1
Introduction
Table of contents
1 Introduction ...1-2 1.1 Foreword ...1-2 1.2 General remarks ...1-4 1.3 Electric system rigidity and potential solutions ...1-4 1.4 Grid scale storage technologies overview ... 1-11 1.4.1 Pumped Hydro Energy Storage (PHES) ... 1-13 1.4.2 Compressed Air Energy Storage (CAES) ... 1-16 1.4.3 Liquified Air Energy Storage (LAES) ... 1-18 1.4.4 Sodium sulfur (NaS) battery energy storage... 1-20 1.4.5 Flow battery energy storage ... 1-21 1.4.6 Pumped Thermal Electricity Storage (PTES) ... 1-23 1.5 Technology summary ... 1-27 1.6 EES technology economic comparison ... 1-28 1.7 Economic comparison conclusive remarks ... 1-34 1.8 Conclusion and research gaps ... 1-35 1.9 Dissertation novel contributions ... 1-36
1-2
1 Introduction
1.1 Foreword
Electric Energy Storage (EES) is one of the most researched and studied topic in the context of energy systems. This is because EES will likely to be one of the corner stones of the revolution that is transforming energy sector.
Energy fueled human society development, such that during most of human recent history energy consumption and economic growth have been inextricably linked [1]. Energy is used to produce the goods that we buy or eat. Energy is used to power the vehicles that brings us wherever we want. Energy is what keep us warm in the winter and cool in the summer.
It is true that in most cases our use of energy should be more rational, whereas in some other cases the uses themselves are so futile, that would be better to save the energy at all.
Nevertheless, a certain amount of energy is just vital for the society as we know it. Furthermore, millions of people around the world still have very limited access to electric energy or clean cooking fuels. Progresses have been made to solve this, as testified by the recent announcement of Republic of India electrification completion [2]. Progresses like this do not happen due to energy resources redistribution, and while the once called “developing countries” were becoming worldwide superpowers, the energy consumption just increased. This trend is deemed to continue, as confirmed by world basis forecasts, which set a +25% for the total energy demand in 2040 [2].
Energy conversion is never for free and the classic equation that links energy consumption to economic growth must be completed, accounting also for a further step which equals energy consumption and economic activities to pollutants emission (among the others the CO2) [3,4].
In this regard, evidences reveal that not only the projected, but also the current energy consumption rates are not sustainable [5].
In response to such a threat to human survival, several governmental and non-governmental organizations became aware of the risks and started to react [6,7]. A direct consequence of their struggles and actions undertaken over the years was the sudden, maybe unexpected, development of non-dispatchable Renewable Energy Sources (RES). Although the RES alone might be able to provide a solution to the environmental problems related to energy consumption [8,9], hybrid strategies based on significant consumption reductions, energy efficiency and the adoption of a more rational lifestyle may turn out to be more efficient and thus more successful in the long run [10,11].
Nevertheless, the power sector is the major contributor of pollutants and green-house gasses emission, and the RES represent the best way to decarbonize it. Since a significant share of untapped RES potential lies in solar PV and wind energy (which are non-dispatchable), EES will play a vital role in allowing such resources to be fully exploited. In fact, solar/wind power non-dispatchability, if not counterbalanced, may have disruptive effects on traditional power systems by causing a wide range of issues, from poor power quality to black outs.
Since the RES large-scale integration is hindered by many different problems, when we speak about EES we refer to a wide spectrum of technologies, each of which may be crucial.
Some niches in this spectrum already have their best candidates, even though the research is still on-going, and it may reserve surprises. There are some applications in which electrochemical storages seem to represent best bet. For example, in micro-scale applications batteries have already proved their disruptive potential, by changing human society through the development of wearable and portable electronic devices. In other contexts, the choice may be not so straightforward, and which one could be the right EES is still an open question. Grid
1-3
scale applications, in which MWh of electric energy are stored for several hours, belong to this group of applications. Several technologies have been proposed to fill this gap and some of them are actually battery technologies. Several others, however, are based on completely different working principles and they aim to outrank batteries by leveraging on features like the low cost.
The development of an EES technology suited for bulk storage still represents a conundrum because it should be characterized by a number of features which are potentially conflicting.
The ideal EES should be efficient, environmentally friendly, fast responding, with large capacity, independent from the geographical site and very cheap. None of the currently available technologies show all these features at once, so a trade-off must be searched.
Given all these considerations, it is clear how important and technically challenging the development of a grid scale EES technology might be. For this reason, this is a fecund and challenging research field, with much still left to be investigated. In order to contribute to these research efforts, the present dissertation is concerned with the analysis of a particular grid scale EES technology, which is based on storing electric energy in form of heat. This concept is gaining popularity and it can be traced back in literature under different names, like CHEST (Compressed Heat Energy STorage) or “Carnot Batteries”. In the present work, however, the name PTES (Pumped Thermal Energy Storage) will be used, to voluntarily mimic the name of the most established and widespread of all the grid scale EES technology, i.e. PHES (Pumped Hydro Energy Storage).
The content of the dissertation is organized as it follows:
the first chapter is dedicated to an overview of the main grid scale EES technologies, which will be introduced and reviewed. A more detailed analysis is dedicated to the PTES technology, by including also some potential improvements to the basic technology. After the technology overview, an economic comparison of the reported technologies is presented, to further justify the interest towards PTES technologies. The chapter ends with a conclusive section in which the motivations behind the dissertation, as well as its major contributions, are stated;
the second chapter introduces the concept of thermal integration, which is the use of low-grade heat resources to improve PTES performance. After a theoretical analysis based on Carnot cycles, a more realistic configuration based on direct and inverse Rankine cycles is presented. The resulting Thermally Integrated PTES (TI- PTES) system is mathematically modelled and simulated for several working conditions and operating fluids. Finally, a sensitivity analysis in respect of the major impacting parameters is presented;
the third chapter is focused on one the subsystems of the proposed TI-PTES system. This subsystem is the High Temperature Heat Pump (HTHP). In the TI- PTES context, this component is used for the charge phase, i.e. for upgrading the low-grade heat from the thermal source. However, the same system may be used also as a standalone waste heat recovery technology. In this chapter, a detailed analysis of the operating fluids suited for the use in HTHP is proposed. The potentially suited fluids are selected based on several different features like, safety, thermal stability, environmental impact and material compatibility. The rest of the chapter analyzes how the fluid choice may impact the trade-off between efficiency and volumetric flowrates, on which the HTHP costs strongly depend;
the fourth chapter is dedicated to a detailed analysis of a TI-PTES system equipped with sensible heat storage. A multi-objective optimized design is performed and the tradeoff between electric efficiency, exergy efficiency and energy density is investigated. Two different configurations, with and without internal regeneration,
1-4
are studied and compared. Finally, a set of realistic performance parameters is calculated, and the TI-PTES is compared to other storage technologies;
the fifth chapter is focused again on the HTHP analysis. In this chapter, a detailed cost model for this component is proposed. The trade-off between cost and performance is investigated by means of a multi-objective optimization approach.
Both the impact of the working fluid and cycle of design are investigated. With this analysis, the investigation started in Chapter 3 is brought to completion and a first step towards the developing of a complete TI-PTES cost model is performed;
the sixth, and last, chapter is a brief summary of the main conclusion and contribution of the previous chapters. Finally, some general considerations are drawn, and the potential developments of the present dissertation work are presented.
1.2 General remarks
In this chapter, the main grid scale EES technologies will be introduced and reviewed. For each technology, a brief operating principle description is presented. Furthermore, an overview of the achievable performance is reported, by also referring to the known practical technology implementations. Pros and cons of each technology are discussed, as well as the research challenges that remain to be addressed. Based on the review results, an economic comparison between the technologies is presented. The economic analysis is based on the current Italian energy price scenarios. However, a simplified approach to consider varying energy prices is also presented. As it was demonstrated, the interested towards PTES technology is further supported by the economic performance that it may achieve.
The results and the considerations reported in this chapter are largely based on the paper reported below [12]:
Guido Francesco Frate, Lorenzo Ferrari, Umberto Desideri. 2019. “Critical review and economic feasibility analysis of electric energy storage technologies suited for grid scale applications”. in Proceedings of XIV Research & Development in Power Engineering (RDPE) Conference (Warsaw)
1.3 Electric system rigidity and potential solutions
Recent interest for storage may be seen as a direct consequence of the electric systems rigidity. Just for the purpose of analyzing electric systems recent transformations, let us divide the electric systems into “traditional” and “modern”. The first are the systems before non- dispatchable RES introduction, whereas the second are the current electric systems.
Historically, in traditional electric systems the electric demand was mostly not flexible, as the customers always considered electricity as a service, rather than a commodity. Such conception is so rooted in users’ mind, that the electric systems that fail providing the energy on demand are considered immature, fragile and unreliable. Usually, the so-called undeveloped countries are characterized by such kind of electric systems, thus confirming the parallelism between electric energy access and economic development. However, since the demand was rigid, the production had to comply. To do that, production units were able to adjust their production, as well as to (slowly) turn on and off. Furthermore, a limited storage capacity was already available. It may be useful to think the electric system as a system that is concerned with the satisfaction of a certain demand, given a certain amount of dispatchable production
1-5
capacity. From a point of view purely focused on the energy, i.e. without considering all the issues like frequency and voltage control, the system operator wants to manage the production at the minimum cost and here is where the storage comes in play. If the production capacity is higher than the demand peaks, the storage is not strictly necessary. Theoretically speaking, only a careful scheduling of production unit availabilities and power outputs would be needed.
However, production units have turndown constraints and turning on and off times, such that it results to be more economical to deploy a certain number of flexible units that can act as buffer to partly decouple production and consumption. In fact, this allows to operate the production capacity more efficiently, as it must fulfill a residual demand (demand + storage inputs/outputs) which is less fluctuating.
In conclusion, traditional electric systems were characterized by a rigid demand, by a partly flexible production and by a limited amount of storage, which helped to operate the production capacity more efficiently.
Compared to the past, as already pointed out, electric systems are changing, mostly due to the introduction of non-dispatchable RES. By focusing again on flexibility, we could say that the vast majority of the demand is still not flexible. This is true, even though relevant efforts are dedicated to the flexibilization of the demand, through the development of Demand Response (DR) logics. DR is very appealing and researched, but actual implementations are still uncommon. DR is based on the idea that a relevant number of demand loads are actually deferrable in time. Therefore, if a proper (economic) compensation is provided, such loads could be moved in time to smooth demand peaks, thus allowing for a more efficient management of production units. Theoretically speaking, DR could provide several crucial benefits to the electric systems. As a matter of fact, DR performing agents can be thought like flexible production units, thus they should be even able to provide fast-starting reserve at cheap price [13]. DR applications in residential sector are very much studied, as this sector accounts for roughly 15% of final electric demand in OECD countries [14]. Recent advancements in monitoring and control techniques, may provide DR with the required technologies. Despite this, many factors still hinder DR development. The challenges that must be faced currently encompass regulatory framework and electric market inadequacies, as well as very limited economic benefits (in absolute terms) and modelling difficulties. These lasts, in particular, make very difficult to assess DR potential and thus building reliable business models [13].
If on the demand side not much changed, the same cannot be said for the production side, as the massive RES deployment took place. Apart from that, power plant fleets flexibility remained roughly the same during the last two decades. This is because no radical changes affected thermal production technologies. A slight increase of flexibility, might have come from the fact that most of the decommissioned units were old (and thus slower) or they belonged to categories, like nuclear or coal-fired power plants, which are notoriously rigid and slow [15].
Apart from that, increasing the flexibility of new and efficient power plants like GTCC might be a very appealing perspective. To this end, management strategies, plant layout variations and new components addition are being investigated [16,17]. Despite the research efforts, the implementations of such measures are still in a development phase.
Likewise, as far as the storage capacity is concerned, nothing really changed within developed electric systems, compared to the past. This is because no storage technologies, other than pumped hydro, have been deployed, at least on a large scale [18] and PHES suitable sites have been already exploited at most [19]. Global energy storage power capacity composition in 2017 is reported in Figure 1.1.
To summarize what said so far, in modern electric systems the demand is still not flexible, the thermal production fleet is as flexible as before and the available storage capacity is pretty much the same, compared to the past. In terms of flexibility, RES massive introduction tested the electric system capabilities. As a matter of fact, Wind turbines and solar PV panels are very
1-6
rigid: they produce when they can, and they cannot provide any regulation service to the grid.
Therefore, compared to the past, modern electric systems are more rigid than in the past, as a large share of rigid production capacity has been deployed, without any other flexible element to balance it.
Fig. 1.1. Global energy storage power capacity by technology groups in 2017. Artwork from [18].
Being rigid and often prioritized by market regulations, allowed to RES to easily erode traditional power plants market share. In Italy, from 2007 to 2017 thermal production fleet lost around 17% of its operational equivalent hours [20]. This is a direct consequence of massive RES deployment, which forced flexible power plants to part-load operation and more frequent start-ups. Similar trends can be found all across Europe, where GTCC plants are found to be the main providers of the flexibility required by the non-dispatchable RES [21].
As Figure 1.2 shows, most of the RES development within Europe was due to wind and solar energy exploitation. This trend is deemed to continue, as new RES must be introduced into electric systems [6,22], and projections show that most of RES potential growth still lies in solar and wind energy exploitation [2].
RES capacity increment might soon lead to an unbearable situation, as both demand and production sides might lack the flexibility required to safely operate the system.
Apart from this, well before incurring in technical limitations, the economic implications of off-loading all the flexibility burden on traditional power plants should be a concern. As a matter of fact, RES already created a fiercely competitive environment that tends to discourage investments in new generation capacity, both traditional and renewable [24]. Storage might help this situation because, as already pointed out, its primary function is to efficiently manage the production fleet.
The economic implications of a reduced flexibility might be even more severe in liberalized energy markets. As a matter of fact, monopolistic power systems might be more resilient to operational inefficiencies, as the additional costs coming from part-load operations and frequent start-ups can be socialized among all final consumers. Contrarily, in liberalized markets an inefficient operation is directly translated into reduced revenues and into the risk for the single power plant to fall out from the dispatch merit order [24]. In this case, not only further investments are discouraged, but also existing power plants might cease operation, due to insufficient revenues. A strong capacity loss might exacerbate flexibility-related problems, such that some countries already resorted to counter measures, e.g. capacity markets [25–27].
1-7
Fig. 1.2 European electric energy mix in 2005 (a) and 2015 (b). Data from [23].
Despite the potential benefits, capacity markets may be criticized by arguing that they are nothing but a form of subsidy to fossil fuel power plants. Who supports this argument might prefer to see the same funds dedicated to the development and support of storage plants, which to some extent could provide the same required flexibility, thus lessening the need for capacity markets themselves [28]. Whichever is right position, the need for capacity markets demonstrates that electric systems are already suffering from renewables introduction. Part of this is certainly due to shortage of storage capacity, which should be increased.
While it is clear that additional storage capacity would be needed, how much it is actually needed, and which technology should be used, are still questions that puzzle researchers. It is very difficult to have, if not a detailed, at least a reliable estimation of the actual storage capacity required by the grid. This is because such figure depends on a multitude of factors, each of which is difficult to estimate by itself. First and foremost, it is worth mentioning uncertainties about future energy policies, which could, and maybe should, firmly guide electric systems towards decarbonization. In particular, it is not even clear if RES will be increased as planned. In the same way, it is not clear how much, and in which way, the electric demand will change in the future. As a matter of fact, things like massive electrification of residential heating (which is still gas-based in some countries) and electric mobility could play a big role, both in increasing and shaping future demand profiles. Electric vehicles, in particular, could matter not that much in respect of total additional consumption, but they could affect demand shape in a substantial way, according to the adopted charging strategy [29].
1-8
There might be unsure things, but there are also projections that might provide some useful indications. The projected future electric system outlooks tell us that a storage able to charge at nominal power for several hours will be required. Figure 1.3 reports the projected future residual demand trend (“duck curve”) to be fulfilled with non-renewable production for the case of Qinghai Chinese province in 2020 [30]. Similar projections can be found for electric systems all around the world, such that the “duck curve” phenomenon was firstly popularized for the case of California (USA) [31].
The characteristic shape of duck curves is due to solar PV production, which is foresee to be the main driver of RES increment on a world-wide basis [2]. Solar PV production is at maximum during the central hours of the day and sharply drops in the late afternoon. This, combined with the recent trends which see the demand peak occurring in the evening, might force traditional power plants to a fast ramp operation. Such operational condition is technically challenging, economically penalizing and environmentally inappropriate. During fast ramping part loads the efficiency is reduced, the emissions increase, and the plant is exposed to low- cycle fatigue induced by thermal stresses. To support thermal power plant fleet in this task, a storage that can shift relevant quantities of energy might be required. A storage like this should charge for several hours to absorb energy during the solar production peak. Later, it should be able to quickly discharge the stored energy during the residual load peak, which usually lasts from one to two hours. The described operational profile has a name, which is “peak shaving”.
The basic principle of peak shaving is illustrated in Figure 1.4, where the traditional demand profile (low demand during night and demand peak at noon) is used.
Fig. 1.3. Projected residual net load of Qinghai Chinese province in 2020:an example of
“duck-curve”. Artwork from [30]
.
Peak shaving operational profile may provide an “identikit” of the EES technology that would be required. The following considerations may be done:
charge phase is performed during low demand moments, and discharge is performed during high demand moments. Since the demand has a cyclic behavior, the storage should be able to perform a complete charge/discharge cycle within a day. Peak shaving is a daily application, therefore any seasonal effect (although potentially strong in solar PV high penetration scenarios) is neglected;
due to demand profile shape, optimal charge and discharge time may be different. Charge time (h) is equal to the ratio of nominal storage capacity (MWh or kWh) and nominal charge power (MW or kW). The same holds for discharge time, but nominal discharge power is used instead. Once that storage capacity is fixed, charge and discharge equipment should be sized differently, if possible. This is applicable to PHES if pumps and turbines are used, but
1-9
it is not applicable to batteries or PHES with reversible turbines, for example. In these cases, the most limiting condition between charge and discharge must be chosen to size the storage power section;
Given the residual demand profile, charge phase should last between four and six hours, which correspond to the usual solar PV high production time span. Charge time is a proportionality constant between storage charge power and capacity. Therefore, the duck curve shape suggests that capacity numerical value is four to six times higher than that of charge power. In other words, if a minimum of 10 MW for charging power is considered for a grid-scale application, the capacity is expected to be around 40 – 60 MWh at minimum.
Fig. 1.4. Peak shaving operational principle. Artwork from [18].
At this point the question that should be answered is: which are the EES technologies (already developed, or being developed) which fit the requirements suggested by the duck curve? Surely, PHES is one of such technologies: its power rating can be huge (up to hundreds of MW) and charge/discharge times can be up to 24 h (therefore, also the capacity is not a limiting factor). This is obvious, since PHES was already used in the past for peak shaving, when the problem was to shift the production from nighttime to daytime.
Apart from PHES, which are the other technologies suited for peak shaving? To answer this question, it should be noted that neither the power rating, nor the capacity, are limiting factors per se. As a matter of fact, large values of both can be achieved by just putting in parallel several smaller systems. Nevertheless, each EES technology has its own range of characteristic nominal charge/discharge times, i.e. each EES is characterized by a typical power/capacity ratio. From this point of view, duck curve suggests that most suited EES for load shifting are those which can efficiently achieve a charge time equal to 4 – 6 h, which corresponds to 1/6 – 1/4 h-1 power/capacity ratio. EES characteristic charge time may vary, but it usually belongs to one of the following categories:
seconds – minutes: short duration storage, used when power is required and large capacity is not essential, e.g. for fast fluctuating usage profiles;
minutes – less than 1 hour: medium duration storage, same as before, but the phenomena involved are more energy demanding, or the storage has some technical limitations like minimum charge level or aging due to cyclic behavior, which limit charge/discharge rates;
more than 1 hour – 24 hours: long duration storage, energy-oriented applications.
Typical applications require to charge at nominal capacity for several hours (load shifting);
1-10
more than 24 hours: weekly – seasonal storage, for all the applications not based on daily cycles.
If a storage designed to have very high power/capacity ratio (i.e. low charge/discharge time), like a flywheel or a supercapacitor, is used for capacity-demanding applications, this would lead to a very inefficient use of available power rating. This is essentially because the available charge/discharge power would be disproportioned, if compared to the actual system requirements.
Power/capacity ratios cannot be arbitrarily decided, as they are often set by physical limitations. Flywheels cannot achieve very large capacity, because both rotational velocity and radius are limited essentially due to material strength limitations. Once that maximum capacity is reached, to further increase it, a second flywheel should be deployed. However, both storage kWh and kW have been doubled in this way, therefore the nominal storage charge/discharge time remains unchanged.
The case of Li-Ion batteries is opposite. As matter of fact, battery chemistry does not allow for charging very fast for long time, and prolonged high charge rates may result in storage damaging. This is the opposite in respect to flywheels, because now the physics sets a lower bound to charge/discharge times. However, this does not automatically make Li-Ion batteries a good candidate for peak shaving applications. The key concept, in fact, is to achieve the right power/capacity ratio (i.e. 1/6 – 1/4 h-1) efficiently, from all the point of views. In particular, in this case is the cost which discourages the use of Li-Ion batteries for peak shaving. As a matter of fact, Li-ion batteries cost more in terms of installed kWh, than in terms of kW, due to the materials, the production technologies, and so on. Consequently, although Li-Ion batteries are technically able to achieve the right power/capacity ratio, the price of a Li-Ion EES would be higher than that of an EES based on other technologies. In other words, since for Li-Ion batteries the capacity costs more than the power, they are most suited for power intensive applications, rather than for bulk energy storage. Evidence of this can be found by analyzing the largest Li-Ion battery application to date, which is a 100 MW EES deployed in South Australia [32]. Such storage has a power rating which fits completely to peak shaving, but the nominal capacity is around 129 MWh. This roughly corresponds to a charge/discharge time around of one hour, considering also that a minimum of 20% of capacity should not be used, to not let the storage age too quickly. Accordingly, the reported EES business case is based on providing back up production (through capacity market) and frequency regulation, two uses that favor power, rather than capacity.
Cost issues might not exclude Li-Ion batteries from the group of technologies suited for peak shaving forever. Technically speaking, Li-Ion batteries are very attracting. They feature very high efficiency, fast response and long operating life, hence if their cost will fall in the future, they might compete also for peak shaving applications. In the meantime, other less common battery technologies, mostly based on molten salt or liquid electrolytes, are already available for bulk energy storage. Such technologies currently show capacity related costs which are lower than that of Li-Ion batteries [33]. This allows them to more efficiently achieve the required power/capacity ratio and this makes them more suited than Li-Ion batteries for peak shaving, although they generally feature lower efficiencies.
Apart from batteries, other technologies are currently being developed for peak shaving duties. Such technologies generally have lower TRL, if compared to batteries, and usually they achieve lower efficiencies, being them mostly based on thermal or thermomechanical concepts.
However, these alternative technologies might have some edges against batteries, mostly due to environmental impact aspects and better economy of scale.
A detailed overview of currently available grid scale EES technologies is postponed to the following section, where such technologies will be described and compared, based and their respective pros and cons.
1-11
Let us draw some preliminary conclusion at the end of this introductory part of the analysis.
We discussed how storage necessity stems from a fundamental rigidity of electric systems.
Deep changes are occurring in the electric systems because of non-dispatchable RES massive introduction. Traditional dispatchable (i.e. flexible) power plants are being pushed out from the dispatch merit order, while no additional storage capacity is being installed, due to inherent technology limitations of pumped hydro. Storage is needed to safely and efficiently operate the electric systems and the increased rigidity due to RES deployment will most likely lead to a strong demand for storage capacity. RES development projections let us understand what the use of storage in the future could be. A power/capacity ratio of around 1/6 to 1/4 h-1 can be considered for an approximate storage sizing. These figures provide a criterium for understanding what the most suited technologies for bulk energy storage are. The key aspect is that more capacity than power it is required. Therefore, only those technologies that manage to have capacity related costs lower than power related ones, should be considered for grid-scale energy-intensive applications. This has the major consequence of ruling out Li-Ion batteries, which are the main EES technology (except for pumped hydro) developed so far. This leave the field open for other technologies, based on electrochemical concepts or not, that will be analyzed in detail in the next section.
1.4 Grid scale storage technologies overview
It has been already discussed how storage necessity is originated by electric system lack of flexibility. This general concept can be broken down in several aspects, such that different storage technologies may serve electric systems in different ways. It is out of the scope of the present analysis to provide a detailed overview of all the storage potential application.
Nevertheless, it is interesting to note that each application is characterized by a specific duration (i.e. characteristic charge/discharge time) which provides an indication about which EES technology should be used for it. Echoing what done for the peak shaving in the previous section, each application can be classified according to its characteristic time. By doing that, it can be understood whether an application is more oriented to power or energy, and thus which EES technology it requires, by matching storage and application characteristic charge/discharge time. Two similar classification of EES applications are reported in Figure 1.5 (a) and (b).
Fig. 1.5. Classification of EES application in terms of characteristic discharge time. (a):
Artwork from [18]. (b): Artwork from [34].
Although there is no perfect consensus regarding the used terminology, the message that is conveyed by the two figures is the same. In particular, what in Figure 1.5 (b) is called “Power
1-12
fleet optimization”, roughly encompasses “Integration of RES”, “Energy trading”, “Load levelling” and “Peak shaving” in Figure 1.5 (a). In Figure 1.5 (b) “Transmission & distribution investment deferral” is reported, which is missing in Figure 1.5 (a). This item refers to the ability of storage to solve grid congestions, thus deferring the need for grid upgrading. This is essentially achieved by performing peak shaving and load levelling, therefore there is no contrast between the two sources.
A little less consensus can be found regarding the EES technology classification resulting from Figure 1.5 (a) and (b), which is reported in Figure 1.6 (a) and (b).
Fig. 1.6. Classification of EES technologies in terms of characteristic discharge time and power rating. (a): Artwork from [18]. (b): Artwork from [34].
Both [18] and [34] more or less agree on the classification of EES technologies with high power to capacity ratio (flywheels and supercapacitors) and low power to capacity ratio, PHES and Compressed Air Energy Storage (CAES). However, slight differences can be found on the classification of battery EES. Most notably, [18] considers batteries to have lower discharge times in general, being most of them well under the “hours” category. This reflect the fact that while some technologies (with very low or very high capacity) are securely classified, batteries pose some issues, being them very flexible and various. Confusion may also stem from the fact that very few actual implementations of large-size battery EES exists to date, while PHES, CAES and flywheels have longer usage history.
Another peculiarity is that molten salt batteries (NaS and NaNiCl) have lower characteristic discharge time than Li-Ion batteries in [18], while the opposite is commonly assumed in literature (see for example [35,36]). The same holds for the discharge time of Vanadium based flow batteries (VRB) which is lower than what normally assumed. As a matter of fact, in [18]
VRB are reported to be somewhere between “minutes” and “hours” categories, while they are consistently reported to achieve around 10 h of nominal discharge time in other references [34–
36].
Another less qualitative classification can be found in [37], here displayed in Figure 1.7, where also single implementation cases are reported, and not only technological categories.
As it results from Figure 1.7, Li-Ion batteries are always located in proximity of 1 h line, while NaS and VRB are located halfway between 1 h and 24 h lines. Apart from batteries, the other technologies which can be found in proximity of the 24 h line are PHES, CAES (large scale) and thermal energy storage. These technologies, plus Liquified Air Energy Storage (LAES) and Pumped Thermal Energy Storage (PTES) will be reviewed in detail in the
1-13
following subsections. A special focus will be dedicated to PTES as it is the main topic of the thesis dissertation.
Fig. 1.7. Classification of EES technologies and single implementation cases in terms of characteristic discharge time and power rating. Artwork from [37].
1.4.1 Pumped Hydro Energy Storage (PHES)
Basic working principle of PHES is reported in Figure 1.8. The upper reservoir is connected by the penstock to the lower reservoir. By pumping the water from the lower to the higher reservoir the storage is charged. By discharging the water from the higher to the lower reservoir the storage is discharged. PHES facilities can be in closed loop, where the same water is constantly looped between the two reservoirs, but more often they are in open loop. In these last facilities, the external contribution of rivers is not negligible neither in the upper reservoir, nor in the lower one. Open loop PHES can be considered as regular hydroelectric facilities which have the ability of providing also pumped storage. PHES can use different machinery to charge (pumps) and discharge (turbines), or reversible machinery (reversible turbines). Similarly, they can use two different penstocks to charge and discharge, or they can have one. Of course, the choice between having different pieces of equipment or reversible ones, is a trade-off between efficiency and costs. In particular, having distinct charge and discharge equipment allow the plant to charge and discharge simultaneously. This is a non-sense from the energy point of view, but it allows for faster dynamics of the power plant, which would have to wait longer to invert the flux, to avoid water hammer effects.
PHES has many positive features like [18,34,35,37]:
High round trip efficiency, in the range of 65 – 85 %, depending on the age, the machinery and the operational condition of the plant;
Very long operating life, up to 40 years. Retrofitting and repowering of old plants can extend the operational life almost indefinitely [38];
Fast response time, most commonly in the range of seconds to minutes;
Large power and capacity ratings. Nominal power ranges from 100 MW to 3 GW and charge/discharge time can be up to 24 hours.
1-14
The outstanding number of positive features allowed the PHES of being the only successful storage technology in the past. Currently, as reported in Figure 1.1, PHES still represents more than 96 % of installed storage capacity worldwide.
Fig. 1.8. Pumped Hydro Energy Storage (PHES) working principle. Artwork from [18].
From a mere technical point of view, it could be said that the whole research on grid scale storage stems from the fact that more PHES is needed, but the lack of suitable sites makes additional deployment impractical. As demonstrated in [19] for Europe, what was actually depleted are the easily exploitable sites, such that a business-as-usual design of new PHES facilities is not going to provide any significant benefit in mature context like Europe, Japan and USA. If PHES design constraints are relaxed, and particularly if the length of the penstock can be longer than 1 km, 2 km or even 5 km, the potential is still of some relevance. Of course, longer penstocks entail major costs and higher losses, therefore the technical and economic feasibility of such PHES facilities should be carefully investigated further.
Figure 1.9 report the latest trends in PHES capacity for several countries. These trends demonstrate the general idea that, after a boom between sixties and eighties, the construction of new facility practically stopped, and a very slow increase in capacity characterized the last 30 – 40 years. Recently, a slight capacity increase occurred in Europe, most likely driven by repowering of old facilities, but the main net contributor is China, whose recent economy development is still driving its electric system development.
Despite PHES positive features, thinking that the storage problem could be solved with additional PHES facilities is a kind reductive idea. Of course, it is true that some more PHES capacity would (and will be) be commissioned, provided the possibility. Nonetheless, PHES has some major drawbacks that should be considered. As a matter of fact, PHES is one of the least
1-15
dense of all EES technology. This, plus the fact that the water intake system (the dams) is very costly and so must be large to benefit from the economy of scale, often leads to huge facilities.
These may be very impactful on the surrounding environment: they may have a disproportioned use of land area to the point of shaping the surrounding landscape. Furthermore, PHES facilities may result in river course change and diminished flow rates, thus impacting both human activities and wildlife downstream the plant. Having to be big is not a problem only in respect of the social acceptance of the plant [39], but also for economic reasons. Most of the electric systems in which the RES revolution is taking place are served by liberalized energy markets.
In liberalized contexts, the risk for the investment is fully borne by investors. From this point of view, PHES size could be a curse, because a new facility usually represents a very large investment (in absolute terms), which is taking place in an economic environment deemed to experience dramatic changes. RES introduction may not have fully expected outcomes, and their dispatchment actually reduced intra-day price volatility, at least in these first phases [40].
In the long run, RES would most likely lead to an economic environment fecund for storage, however, in the meantime, long term investments like those involved in PHES projects could be discouraged by strong uncertainties on the future. This problem is exacerbated by the long time required for being fully operative from the start of the project, which for PHES may be up to 10 years [18,37]. This is related to the size of the facility, which pose some technical bounds to construction time, but it is also related to a bureaucracy slowness caused, among the other things, also by citizenry concerns about land and water use [41].
Fig. 1.9. Pumped Hydro Energy Storage (PHES) worldwide capacity in time. Artwork from [38].
Potential solutions to address PHES shortcomings are being proposed. Lack of easily exploitable sites could be avoided by using sea water reservoirs and cliff heights, like proposed in [42–44]. Only one pilot plant of this kind has been built to date, a 30 MW facility in Okinawa (Japan) with a net head of 136 m and 564000 m3 of reservoir capacity [37]. Okinawa facility is reported to have been dismantled in 2016 due to insufficient profits, while some larger facilities are currently planned for Hawaii, Ireland and Greece [44,45].
Another (old) solution often reported is to use abandoned caves, or mines, as lower reservoir, and building the higher one just of top of the facility. The concept is called Underground PHES (UPHES) and was firstly proposed in 1910 [41]. UPHES could use already exploited terrains, if old mines are used, or it could be built in terrains that have no value from
1-16
both economic and environmental point of views. By using a closed loop concept, the environmental impact of UPHES could be very low, thus solving also the social acceptance problem and environmental concerns related to PHES [41].
1.4.2 Compressed Air Energy Storage (CAES)
Compressed Air Energy Storage (CAES) is based on the idea of storing electric energy as mechanical energy. This is accomplished by using a compressor to compress air coming from the environment and store it under pressure. In the discharge phase, the air is discharged and used to feed a high-pressure combustion chamber of a gas turbine. After the expansion in the turbine, the air is discharged into the environment. Nowadays, basic layout comprises an internal regenerator to preheat the air at the combustion chamber inlet, to exploit exhaust gasses residual thermal energy. A schematic representation of CAES operating principle is reported in Figure 1.10.
CAES is based on a very old concept, being the first patent deposited in 1940 [46]. In 1969 the first CAES plant was commissioned in Huntdorf (Germany). CAES concept did not have much success, most likely due to the competition of PHES, and only another CAES facility was commissioned, in McIntosh (Alabama, USA) in 1991 [46]. Since both Huntdorf and McIntosh facilities use natural gas as fuel to power up the turbine during the discharge phase, the efficiency takes that into account. A figure around 0.42 is provided for the Huntdorf efficiency, while 0.54 for McIntosh case. The difference between the two is mainly due to the fact the McIntosh feature the internal regenerator as in Figure 1.10, while Huntdorf does not. Recent concern about energy storage renewed interested for CAES and several additional facilities has been planned, but none of them has been actually commissioned so far [18,46].
Existing CAES facilities use abandoned salt mines as a storage tank for the compressed air, which is stored between 40 and 80 bar, typically [47]. This allowed reducing the plant cost, since a very large pressurized vessel could be either unfeasible or very costly to artificially build. The use of caverns limits the higher pressure, due to concerns about structural stability.
This limits also CAES energy density, which is usually lower than other storage technologies.
Furthermore, the maximum temperature is limited around 80 °C, for avoiding thermal stress on the cave walls, thus the air must be cooled down after compressor, and the compression heat gets wasted. The use of peculiar geological formations does not only limits CAES efficiency, but it also binds the facilities to specific geographical areas which could be either uncommon or distant from transmission lines and power grid nodes. Availability of suited sites for CAES is often reported as a concern, similarly to what is said for PHES [18,34,35,37,46,47]. Actually, an assessment of potentially suited areas for CAES was performed using GIS models, in analogy to what commonly done for PHES [48]. The study found that the areas that have the right geological structure to host salt domes, rocky caves and aquifers with porous rocks potentially suited for CAES are common all over the world. However, salt domes seem to be the best choice as porous rock aquifers must have the right porosity, otherwise the air mass flow rate that they can absorb/reject is limited [47], and rocky caves are often not sufficiently air tight [49,50]. Given the interest in CAES and the concern for the scarcity of suited sites, alternative solutions have been studied. The most promising solution might be Under Water CAES (UWCAES) in which the hydraulic head of sea/lake water is used to pressurize the storage [51].
Apart from the obvious advantage that water bodies are much more common than salt domes, UWCAES might also feature higher efficiencies, since the charge and discharge are performed at constant pressure [52], while in regular CAES a throttling valve is generally used to control pressure [53]. UWCAES research challenges are currently related to the design of underwater storage tanks/bags. To date, only one UWCAES pilot plant has been commissioned in Lake Ontario (Toronto, Canada) [46].
1-17
Fig. 1.10. Compressed Air Energy Storage (CAES) working principle. Artwork from [37].
Compared to PHES, CAES features a much lower land use and environmental impact if the facility alone is considered. Both PHES and CAES are very reliable, with a very long and comparable operating life. On the other side, PHES features much higher efficiencies and do not make use of fossil fuels, which lead to CO2 and NOx emissions in the case of CAES.
Furthermore, CAES has much longer response time, up to 10 minutes for large scale facilities [18,37]. To solve this, hybrid configurations have been proposed, like in [54], where a hybrid layout with flywheels and CAES was proposed.
The use of fossil fuel is considered the worst of CAES shortcomings. To go beyond classic CAES architectures, the so-called Adiabatic CAES (ACAES) has been proposed. ACAES recovers and stores the thermal energy in excess from the compression and use that to heat up the air during discharge phase. Commonly accepted roundtrip efficiencies for adiabatic configurations are around 65 – 70 %. Such figures essentially come from simulation-based studies, while the first pilot scale implementation (500 kW, 4 h) achieved a promising 64%
[18,49,50]. The first grid scale ACAES facility (90 MW, 360 MWh), called ADELE, is currently planned to be commissioned in Germany, and expected efficiencies are around 70% [18,37,47].
Heat recovery in ACAES is usually done with packed bed sensible heat storage [50], hybrid packed bed plus latent heat storage [49], or by using techniques to operate compressions and expansions in nearly isothermal conditions (ICAES). The use of latent heat storage, generally encapsulated PCM, might pose some of the frequently reported PCM issues like spilling out, degradation and phase separation [49,52].
Nearly isothermal compression can be achieved by extracting and storing excess heat during compression. This may be achieved with water sprays and liquid piston compression [52,55], which can be also combined with metal foam regenerators. The heat stored during compression is rejected while the air expands. In this way the cooling down characteristic of adiabatic expansions is counterbalanced.
ACAES gets rid of combustion chamber and use of fuels, while also improving the efficiency. For these reasons, it is regarded as one of the most promising CAES versions. The only drawback is that ACAES results to be even less energy dense than regular CAES, because the energy contribution of fuel is lost [52].
1-18
In regular CAES, NOx emissions can be lowered by injecting water before combustion chamber [52,56,57]. Such humidification lowers down combustion temperatures, thus lowering NOx. In addition to that, also the efficiency benefits from that (+9%), as well as the net power output (+14%) [57]. Water injection might be very effective, but it is also reported to be very water consuming, thus such solution is not suited for sites with not easy access to water [52].
Since CAES and ACAES are essentially GT cycles, might seem natural to include in these layouts also some bottoming cycles, like ORC or water steam cycles. Although this might improve the plant efficiency as suggested by [58], this would lead to a relevant increase of start- up times, as the heat recovery steam generator generally adds a lot of thermal inertia to the system.
Concluding, CAES could be a viable alternative to PHES. In this regard, ACAES is likely to be the best choice, as it reflects the general power sector trend towards decarbonization and feature higher efficiencies. Availability of suited sites might be an issue, but solutions like UWCAES are being proposed to overcome that.
Other unsolved issues are related to the energy density, which is very low, and to the design of suited turbomachinery [46]. As a matter of fact, CAES is characterized by operating conditions (temperature and pressure) which are quite different from those currently employed by GT cycles. Pressure ratios are very high, such that the temperature in compressor last stages is an issue. Turbine inlet temperature is lower than that of GTs, while pressure is higher, therefore a steam turbine-based design must be used [52]. For all these reasons, no off-the-shelf solution are currently available, and the cost might be negatively affected by this.
1.4.3 Liquified Air Energy Storage (LAES)
Although Liquified Air Energy Storage (LAES) is often considered just a version of CAES [46,47], proposed to improve energy density, it is gaining relevance among the academics and the variety of proposed LAES configurations is outstanding. LAES stores electric energy under the form of thermal (cryogenic) energy. To do so, LAES uses liquified air as storage medium.
LAES charge phase is based on the consumption of electric energy to liquefy air. The liquid air is stored and, when the discharge phase is to be performed, it is pumped, heated and expanded in a turbine [34,37]. LAES basic working principle is illustrated in Figure 1.11.
Being the liquified air much denser than compressed air, LAES has much higher energy density than CAES [18,46]. This, combined with the much lower storage tank pressures, leads to a much more compact and cheaper storage section, if compared with CAES. For all these reasons, LAES storage section is usually artificial, thus the storage is independent from the presence of caves, mines or other peculiar geological formations.
Since air liquefaction is very energy intensive, basic versions of LAES feature lower efficiency than CAES, around 40% [34]. Basic LAES layouts are based on Linde cycle, which is notoriously inefficient, if compared to most recent liquation cycles, like Claude and Kapitza [59]. More advanced configurations are supposed to be characterized by better efficiency in the order of 60% [60–62].
Until today, only one LAES pilot plant (300 kW, 2.5 MWh) has been successfully commissioned, based on Claude cycle [62,63]. The plant only reached around 8% of efficiency, but the projections for a full scale facility are around 50% [63]. The pilot plant was subjected to several tests based on TSO indications, aimed at proving the ability of providing ancillary services. The tests were passed with very promising results and this proved the fast response of LAES facilities during the discharge phase. This is because turbine thermal inertia tends to heat up the air during start up transients, which actually helps the start up. Furthermore, turbine thermal stresses are not an issue in this case, since the temperature difference between turbine and air in LAES is lower than that of GT cycles [63].
1-19
Apart from the small-scale pilot plant, a larger facility (5 MW, 15 MWh) is currently planned for commissioning in the near future [64].
Several improvements may be done to the basic LAES configuration to increase efficiency.
A very effective and widespread solution is to recycle compression and expansion waste thermal energy to use it in the next charge/discharge phase, see for example [61]. Apart from that, the largest exergy loss is reported to be at the turbine outlet [65]. Therefore, several waste heat solutions were proposed, like: ORC [64–66], Brayton cycle [64] and Absorption cooling [65]. The best strategy, however, seems to be the combination of LAES with other systems that could provide waste heat, like thermal power plants [67], or waste cold like LNG regassification facilities [59,66]. In particular, hybrid solutions with LNG facilities, seem to yield the highest efficiencies: 70% [66] and 88% [59].
Fig. 1.11. Liquified Air Energy Storage (LAES) working principle. Artwork from [62].
In attempt to reduce energy consumption of liquefaction, alternative fluids like CO2, which condenses at much higher temperature if compared to air, have been proposed [68]. Liquified Carbon-dioxide Energy Storage (LCES) is reported to achieve efficiencies between 40 – 57%
and might have some advantages for the use of more compact equipment [68].
In conclusion LAES is a promising technology for grid scale storage. LAES has some advantages over CAES, like higher energy density and independence from geographical sites.
However, LAES generally achieves lower efficiency if compared to CAES and PHES. This problem may be avoided by using non-standard liquefaction processes, by recycling and exploiting waste heat and cold energy and by siting the LAES facility near to sources of waste heat/cold like power plants and LNG regasification facilities. The use of these measures might entail higher costs and increase the start-up time of the plant, due to added thermal inertia.
Finally, siting the LAES in conjunction with LNG regasification plants might lead to lose the strategic advantage of being site independent.
Poorly addressed research topics related to LAES, to the best of the author knowledge, are the following ones:
1-20
In most of simulation-based studies it is not mentioned that the air is actually a mixture of oxygen and nitrogen which have different condensation temperatures and thus they must be divided using fractionating columns. The presence and the dynamic behavior of such component is completely disregarded by the vast majority of the reviewed studies;
While some studies demonstrated the fast response capability of simple and small- scale LAES facilities, dynamic analysis of large-scale applications are missing in literature. The discharge phase may not pose particular problems, as reported by [63]. However, during the charge phase, the thermal inertia of the whole set of regenerators, heat exchangers, turbo-expanders and storage tanks, could negatively affect start -up times and charge efficiency.
1.4.4 Sodium sulfur (NaS) battery energy storage
Sodium sulfur (NaS) batteries represent one of the few grid-scale storage technologies which is currently at the commercial stage. NaS batteries can be traced back since from 1960, and are commercially available in USA and Japan since from 2002 [69]. NaS batteries count several MW scale applications across USA and Japan for UPS service, peak shaving and load balancing [36,69] and several studies investigate the possibility of using NaS batteries to control wind farm power output. Such applications have been proved to be not viable from the economic point of view in current market scenarios [70].
NaS batteries use molten sodium (Na) as negative electrode and molten sulfur (S) as positive electrode. The electrodes are divided by a solid electrolyte β-alumina which allows for the ionic conduction. A representation of the NaS battery working principle is reported in Figure 1.12, where a single cell is represented. Cells are arranged in series and parallel to reach the desired capacity/voltage ratings, thus forming a module. NaS batteries modules are commercially available from 10 to 50 kW and from 50 to 400 kWh [71]. To reach MW scale several modules are assembled together. Thermal management of NaS batteries is done at the module level, where temperature sensors and dedicated heaters are usually installed. Obviously, very large NaS applications pose non-trivial control issues due to the number of modules which must be managed at the same time [72].
NaS batteries feature high energy density, fast response time (< 5 ms), long cycle life (>
2500 cycles at 80 – 100% DOD) and good cycle efficiency, around 85% [18,34,37,71].
Compared to Li-Ion batteries, NaS batteries generally show much lower costs, due to the materials which are used for their construction. A large share of the materials used for NaS batteries is recyclable [37,71], up to 99% according to [18]. This is a very positive feature, since a relevant concern about batteries is the sustainability of their mass production due to potential material scarcity.
NaS battery operates at temperature between 290 – 350 °C, which allows sodium and sulfur electrodes to be in liquid state. During discharge phase, losses induced by internal resistance provide the necessary heat to maintain the battery at the right temperature [69]. When the battery is in idle, or during the charge phase, the necessary amount of heat must be provided from the external and this leads to parasitic losses (up to 20% per day [73]) that rise NaS battery operating costs. Cold start-up of NaS batteries may last up to 15 h, which is the time needed for heating up the battery and let the electrodes melting [47,73].
Apart from high temperatures, other negative features are that sodium polysulfide, a compound produced during the operation, is highly corrosive and that β-alumina tubes are expensive and difficult to mass produce with the required degree of quality [36,69,74]. β- alumina tubes are crucial components for NaS batteries. They must have high purity to improve ionic conduction, while they must also be strong enough to resist to thermal stresses and
1-21
mechanical loads in general. In case of β-alumina tube failure, short circuit between the electrodes may occurs, which may lead to fire accidents [36].
Continuous research efforts are dedicated to the development of NaS batteries which are able to operate at lower temperature [75]. A partial solution to this problem is provided by NaNiCl batteries (also known as ZEBRA) which are very similar to NaS batteries but they are able to operate around 300 °C [34,69,71]. ZEBRA batteries are commercially available from since 1995 [18] and are based on the use of β-alumina solid electrolytes as well. Apart from that, ZEBRA batteries use different materials which are less corrosive and allows for an easier assembly of the battery [69,71].
In conclusion, NaS batteries are one of the most promising EES technologies for grid scale storage applications. Even though they are commercially available since from long time, there are still concerns about the corrosive behavior of molten electrodes and about the safety of NaS large size installation. Costs are still high, if compared to PHES and CAES, but the use of cheap and recyclable materials might lead to cost reduction if mass production is reached at some point. Research efforts are dedicated to the development of lower temperature NaS batteries, which might be operate more safely and with lower parasitic losses.
Fig. 1.12. Sodium sulfur (NaS) batteries working principle. Artwork from [69].
1.4.5 Flow battery energy storage
Flow batteries are based on the use of liquid electrolytes which contain one or more dissolved active species. Electrolytes are pumped through an electrochemical cell that converts chemical energy into electric energy. Electrolytes are stored in tanks, whose size determines battery capacity rating. Similarly, battery power rating is determined by the pumping capacity of the system. Therefore, in flow batteries capacity and power are decoupled, and this is the major advantages of this technology over traditional batteries [18,34,35,37,69,71,74]. A graphical representation of flow battery working principle is reported in Figure 1.13.
Other positive features of flow batteries are: high cycle efficiency (up to 85 %), very quick response (around 1 ms), very long cycle life (in the order of 10000 cycles), maximum discharge depth around 100%, whereas other batteries are limited to 80%, and possibility of being left discharged for long time without any consequence [18,34,37].
On the other hand, flow batteries currently might have higher cost than NaS ones, and the system complexity due to the presence of tanks, pumps, sensors, and flow management system
