1. Introduction
The goal of reaching net-zero CO
2 emissions by 2050 has been driving the introduction of renewable energies in recent years. In 2023, the increase in renewable electricity capacity additions amounted to approximately 507 GW, nearly 50% higher than the previous year. This increase is primarily led by photovoltaic (PV) energy followed by wind energy [
1]. The penetration of these technologies in the global mix constitutes a challenge to electrical power distribution systems because they are not dispatchable. This fact entails difficulty in adjusting production to meet demand, which tends to generate large price disparities when production exceeds demand, and vice versa. To counteract this, energy storage systems are being proposed and installed [
2]. The need for further integration of renewable energies became evident following the events in Europe in 2022, when electricity prices rose as a result of the increase in gas prices. The high increase in electricity prices during peak hours caused coal-fired power plants to raise their production compared with previous years, failing to meet decarbonization goals [
3]. In the Spanish electricity system, the production of coal-fired power stations in 2022 increased by 55.8% compared with the previous year [
4]. Additionally, in Spain and Portugal, a cap was set on the price of electricity generated using natural gas in order to reduce electricity peak prices [
5].
There are different ways to store and later dispatch electricity excess. The most common and economically feasible option today is pumped hydro energy storage (PHES) [
6]. However, this system is geographically limited and only suitable for large-scale applications. Another system considered for large-scale use is compressed air energy storage (CAES), but only two commercial plants have been built [
7]. On the other hand, despite the increasing implementation of commercial lithium-ion battery systems, the low battery life and the high costs per capacity unit mean that they are mainly deployed for applications with low power capacity ratios. Finally, Carnot batteries (CBs) have drawn considerable attention in recent years because of their non-geographic limitation, their application to existing power plants, and their scalability from small to medium systems [
8]. CBs are systems that convert electricity into thermal energy, which is stored in a reservoir when electricity prices are low (charging process). When the price is high, the electricity is restored using a heat engine or power cycle (discharge process).
Current technologies primarily differ in how the charging process is carried out. The so-called pumped thermal energy storage (PTES) systems use a heat pump for charging the store and a heat engine to restore the electricity, in both cases based on Brayton- or Rankine-like cycles.
In Brayton cycles, for both the heat engine and the heat pump, a compressor and an expander are required. In the case of using turbomachinery, a total of four machines are necessary (two compressors and two expanders) [
9]. In the case of using volumetric machines, typically reversible machines are employed, requiring only two machines [
10]. In this case, the efficiencies obtained are lower. To achieve good efficiency, the temperature difference between the hot and cold heat reservoirs is typically high (i.e., above 500 °C for the hot one and below −70 °C for the cold one [
11]). Although two-tank storage systems have been considered [
12], the most used technology for heat storage is sensible packed-bed systems [
13]. Currently, there is only one experimental Brayton PTES plant [
14].
PTES based on Rankine cycles can be subcritical or transcritical. Their main advantage over Brayton cycles is that they operate at lower maximum temperatures (usually below 200 °C) while achieving similar efficiencies. However, the reversible operation of the machines is not possible since a pump is used during discharge while a compressor is used during charging. Transcritical PTES usually uses CO
2 [
15,
16]. Subcritical Rankine PTES systems typically consist of Organic Rankine Cycle (ORC) systems [
17,
18,
19] or cycles using ammonia [
20]. The hot storage system usually consists of pressurized water tanks, and some authors propose cold storage using slurry ice [
20]. One of the main drawbacks is that an additional heat pump is necessary to generate ice. Currently, there is a commercial transcritical Rankine PTES installation working [
21].
The previous works describe PTES system designs as standalone installations. However, the integration of PTES systems into existing conventional plants allows for advantages due to system synergies. In [
22], a PTES that uses a subcritical ORC cycle for both charging and discharging is presented. The particularity lies in the use of the heat rejected by the condenser of a coal-fired power plant to evaporate the working fluid of the heat pump. Ref. [
23] presents a PTES where, for the discharging process, a coal-fired power plant is reused. This is achieved by replacing the conventional boiler with a steam generator fed by the thermal energy storage coupled with the pumped heat. Furthermore, the heat rejected by the heat engine condenser is used to evaporate the working fluid of the heat pump, as in [
22]. Another possibility is to use electric heaters that replace the heat pump of the PTES. In this case, the investment is reduced, although the round-trip performance decreases. An example of this is the reuse of coal-fired power plants replacing the conventional boiler with a steam generator that is fed by thermal energy storage [
24,
25].
Regarding financial assessment, Ref. [
26] provides average levelized cost of storage (LCOS) values of 230 EUR/MWh for Rankine PTES and 369 EUR/MWh for Brayton PTES. However, one of the main drawbacks of evaluating profitability through LCOS is its implicit dependency on the market, as it heavily depends on the considered electricity purchase price, which introduces some uncertainty when comparing case studies. For example, in [
27,
28], LCOS values are close to 100 EUR/MWh; however, the selected purchase price is hardly achievable nowadays in the open electricity market. To assess the impact of this technology in the actual markets, some studies have considered charging and discharging schedule optimizations over a year of market operation. Risthaus et al. [
29] state that incorporating a CB into a coal-fired powerplant, a combined cycle powerplant, and a CSP was not profitable for the wholesale electricity market prices in Germany and Spain in 2016. Frate et al. [
30] conduct mixed-integer linear programming (MILP) to set operating schedules that optimize the profitability of different storage technologies, including PTES. This analysis was carried out considering the 2019 electricity prices in the Italian market. The analysis concludes that the projects are not profitable in the open market and that the subsidy required to operate at zero cost should be equal to the cost of storage itself, as revenues cover at best only about 1/10 of the capital cost.
In line with including the PTES integrated into a power plant and as a novelty of the present work, the PTES proposed in this paper is integrated within the power block (PB) of a concentrated solar power (CSP) plant, allowing for synergies in the form of a decrease in investment compared with CBs proposed in other works, as it utilizes the same turbine as the CSP part of the plant while enhancing the dispatchability of the CSP part of the plant. During the charging phase, the PTES reduces the nominal electrical production of the plant, as part of the electrical energy consumed by an added compressor in the PB is stored. During discharge, electrical production is increased above the nominal value.
The PB of the plant is based on a Hybrid Rankine–Brayton (HRB) power cycle that operates with propane (further described in
Section 2). The degradation temperature of the propane is around 400 °C, so this power cycle is suitable for a CSP working with parabolic through collector solar fields. The HRB propane cycle was formerly introduced in [
31], and its application to CSP plants was proposed in [
32]. It incorporates certain aspects from both a recuperative transcritical ORC and a supercritical CO
2 recompression Brayton cycle (sCO
2-RB). Like in sCO
2-RB, a fraction of the vapour that goes out of the recuperator, namely, the balancing flow, is bypassed through a compressor (auxiliary compressor). The other part, namely, the main flow, is condensed and then driven by a pump (main pump) like in an ORC. The integration of a PTES introduces some components to the HRB propane, including an additional compressor (PTES compressor), two storage tanks with pressurized water, a water/propane heat exchanger, and a second pump, but it does not require any additional expander for the electricity production stage (described in detail in
Section 3). As it is later explained, in the charging process, an additional compression work is consumed over the reference configuration, which is used to store energy; and during the discharging, a similar compression work is saved from the reference operation fraction, restoring the electricity consumed previously.
An additional advantage of the proposed PTES integration is that it also enables the storage of thermal energy that would otherwise be rejected through the condenser if the PTES were turned off, leading to efficiency improvements in some cases.
The main goal of this study is to assess if this synergetic PTES integration is profitable and to compare it to the results from other works. First, the PTES is sized and the CSP is simulated for a typical meteorological year in Sevilla. Then, economic results considering the 2022 electricity hourly price market of Spain are used to compare the reference CSP without PTES to the proposed configuration. This involves calculating incremental incomes and costs between the two configurations. Finally, the LCOS is calculated in order to compare the proposed system to other systems in other works.
Section 2 presents the reference configuration,
Section 3 analyses the configuration including the PTES, and
Section 4 explains the methodology used to size the PTES systems, calculate off-design operating points, and carry out the annual simulations, as well as establish the economic scenario.
Section 5 shows the results, and
Section 6 presents the conclusions.
3. Synergetic PTES Integration into an HRB Propane Plant
The layout of the HRB-PTES-propane at the charging process is shown in
Figure 3. It includes the following new components that are added to the system: the two water tanks for the PTES storage system, the water–propane heat exchanger (PTES HX), and the PTES compressor for the heat upgrade to charge the PTES.
Table 3 summarizes its data. Three and four hours of storage are considered in the analysis.
During charging, water is taken from the cold tank, heated up with the propane fraction coming from the additional compressor, and finally introduced to the hot tank. The additional fraction of propane is taken from the low-pressure side of the recuperator, which is subtracted from the main fraction that goes to the condenser and is directed to the second compressor instead. The PTES compressor is identical to that of the reference configuration, but it runs on a separate shaft. Under nominal conditions, the PTES compressor rotates at the same speed as the reference one, so the flow rate and thermodynamic conditions for both configurations coincide. Furthermore, under nominal conditions, the thermodynamic state of the propane at the outlet of the storage system is the same as that of the main stream after the pump. The rest of the thermodynamic states coincide with those of a reference plant. A pinch point of 5 °C is considered in the water/propane heat exchanger. The water pump operates at a constant flow rate.
Figure 4 shows the T-s diagram of the charging layout under nominal conditions, where the equality of the properties of the states mentioned earlier can be observed.
Under off-design conditions, the PTES compressor speed is controlled to maintain the same mass flow rate as at nominal conditions, which provides certain advantages compared with the case of being the same as that of the turbine shaft. If the compressor were on the same shaft as the turbine, the propane mass flow rate passing through it would depend on the ambient temperature, since the pressure at the compressor inlet coincides with the condensation pressure. At ambient temperatures higher than the nominal value, the value of both the propane mass flow rate and the temperature at the compressor outlet would increase, as the temperature at the compressor inlet would also be higher. This would cause the water–propane heat exchanger to be unbalanced and lead to excessive compressor consumption work and excessively high temperatures in the hot tank. Furthermore, this would result in higher costs for the water tanks because of the increased pressure they should guarantee. These issues are avoided by keeping constant the propane mass flow rate that passes through the compressor.
The layout of the HRB-PTES-propane at the discharging process, including also the second pump to circulate propane, is shown in
Figure 5. In this operation mode, both compressors are turned off, and the bypassed mass flow required to balance the recuperator (balancing flow) comes from the new pump, and it is now heated with the thermal energy previously stored in the water tanks. The use of a pump instead of a compressor reduces the energy consumption, increasing the gross power rate compared with the reference configuration and restoring the electricity that was consumed by the new compressor during the charging mode.
The introduction of the PTES also improves the off-design behaviour of the system over the reference one since a more constant bypass flow rate is achieved when the condensation pressure varies, resulting in a more balanced recuperator and higher overall efficiency than in the original configuration.
Finally, when the PTES is deactivated (it neither charges nor discharges), the HRB-PTES-propane behaves like the reference CSP case.
5. Results
In
Section 5.1, the results of sizing each component of the PTES are presented, which is required to estimate their costs. In
Section 5.2, the behaviour of the CSP including the charging and discharging modes of operation of the PTES at different conditions is presented with the aim of showing the advantages of integrating the PTES within a CSP plant.
Section 5.3 analyses the economic results of the base case and the scenarios proposed in the sensitivity analysis. Finally, in
Section 5.4, the LCOS is calculated to compare the proposed system to other proposals using the same reference framework.
5.1. Sizing Results
The main results of the sizing of the propane–water heat exchanger, the water storage tanks, the propane compressor, and the equivalent air compressor are shown, respectively, in
Table 8,
Table 9 and
Table 10.
The propane–water heat exchanger is divided into two heat exchangers in series to avoid excessive tube lengths. The area of each one along with the internal pressure of the tubes is used to calculate the costs.
The dimensions of the tanks are the same for both the 3-h and 4-h cases. The only difference is that five tanks are required for the 4-h case, whereas four tanks are required for the 3-h case. The weight of each tank is the parameter used to calculate the costs. The nominal temperature drop per hour refers to a hot-filled tank at the nominal temperature. Typically, hot-filled tanks are emptied before 24 h. In cases where the hot-filled tank remains full for 24 h, the approximate temperature loss is only 1 °C.
Table 10 shows the main results of the propane compressor, as well as those of an equivalent air compressor of the same size and stages as the propane one. The reason for this is that an air compressor correlation is used for cost estimation, so the mass flow rate, efficiency, and pressure ratio of the equivalent air compressor are the parameters required to calculate the equipment cost. For each compressor, the parameters at the first and last rotor inlet are shown. The total–total efficiency of the propane compressor corresponds to the isentropic efficiency calculated through the thermodynamic states at the inlet and outlet of the compressor. The maximum Mach is achieved at the inlet of the first rotor stage.
For the sizing of the equivalent air compressor, it is considered that both the flow coefficient, the loading coefficient, the degree of reaction, the number of stages, the Mach number at the inlet of the first rotor stage, solidity, as well as the pitch/height ratio of each stage are the same as those of the design propane compressor. The chosen inlet pressure is the ambient inlet pressure, as it is the most common in air compressors. The inlet air temperature, as well as the air mass flow rate, are the parameters that are adjusted to obtain the same mean diameter and the same mean blade height in the first rotor stage as those achieved in the propane compressor. It should be noted, however, that the height of the last stage differs between both compressors. This is because each fluid has unique characteristics, resulting in different compression processes. On the other hand, a significant disparity in flow rates between both compressors can be observed. This is primarily due to the difference in inlet density. Thus, for a given size of equivalent air compressor, the propane compressor consumes a considerably higher power.
The equipment costs including installation costs, for the 3-h and 4-h HRB-PTES-propane cases are shown in
Table 11. The water pump and its respective motor consumptions are negligible because of the low water flow rate and the low pressure drop in the propane–water heat exchanger. The costs of the pump and compressor motors are calculated assuming that the electric motors have an efficiency of 99%. The cost of the additional propane required is less than 0.1% of the total additional investment, so it is taken into account. It is assumed that the total volume occupied by the additional propane is twice the volume occupied by the propane in the water/propane heat exchangers.
5.2. Operation of HRB-PTES-Propane
Table 12 compares the main results of the CSP when the PTES is off versus when it is charging under nominal conditions.
Table 13 shows the mass flow fractions circulating through each component for each case. These fractions are expressed as a fraction over the total propane mass flow rate.
During the charging, the evacuated thermal power is lower than in the reference case because the fraction of propane flow circulating through the condenser is also lower. This is due to the additional extraction passing through the PTES compressor. Furthermore, the difference in gross power produced is equal to the consumption of the PTES compressor minus the difference between the main pump consumptions for the two cases. The main pump consumption is different because it drives different flow fractions for each case.
Furthermore, it can be observed that the thermal power absorbed by the PTES storage is greater than the consumption of the PTES compressor. This is because the energy related to the enthalpy difference between the compressor inlet and the PTES storage outlet is also stored. This is shown in Equations (10) and (11). The nomenclature used is the same as that shown in
Figure 3 and
Figure 4.
is the thermal power absorbed by the PTES storage,
is the propane mass flow that goes through the PTES in the charging process,
is the specific enthalpy difference between the PTES storage inlet and outlet,
is the specific enthalpy transferred from the compressor to the power fluid, and
is the specific enthalpy difference between the compressor inlet and PTES storage outlet.
can be evaluated considering sensible and latent energy contributions through Equation (12).
and
refer to the equivalent sensible and latent energy that would be evacuated through the cooler.
is the specific enthalpy difference between the PTES storage outlet and the condenser outlet. If the energy stored related to the term
is not completely evacuated through the cooler during discharge, the overall efficiency of a PTES charging and discharging cycle will be higher than that obtained if the CSP had operated with the PTES off. This happens when the equivalent thermal energy that would be evacuated through the cooler in the reference case is stored in the charge and used later to produce power during discharge.
Table 14 compares the main results of the CSP when the PTES is off versus when the PTES is charging and discharging for a condensation temperature 10 °C higher than the nominal value.
Table 15 shows the mass flow fractions circulating through each component for each case. The bypassed propane high temperature stands for the temperature reached by the propane at the outlet of the auxiliary compressor for either the reference case or at the PTES compressor outlet when charging. In the discharge case, the bypassed propane high temperature stands for the propane temperature at the outlet of the PTES storage. The difference between the temperature of the hot tank and the bypassed propane maximum temperature is due to irreversibility in the heat transfer in the propane/water heat exchanger. The chosen cold-water temperature for the charging case is the one that allows for obtaining the same value of cold-water temperature during discharge. In this way, the heat absorbed and evacuated by the PTES storage coincide, and the power gross efficiency obtained in the reference case can be compared to the power gross efficiency of a PTES operational cycle.
It should be noted the gross power efficiency does not consider the consumption of the fans of the air condenser. It can be observed that the power gross efficiency obtained for the PTES operational cycle is higher than that of the reference case. Since the condensing temperature (in this specific analysis) is the same in the charging and discharging process, the performance is increased solely because of the difference in sensible heat. A sign of this is that during discharge, the temperature at the outlet of the low-pressure side recuperator is lower than in both the charging and reference cases. This means that the sensible heat transferred to the cooler during discharging is lower than in the reference case.
The reason for the decrease in outlet temperature from the low-pressure side of the recuperator is that the recuperator is better balanced during discharge. This means that the heat capacity ratio between both low- and high-pressure flows is closer to one, compared with the reference case. The heat capacity ratio is defined in Equation (13). In the reference case, since the auxiliary compressor is coupled to the turbine, an excessive fraction of propane is bypassed. As a result, the thermal capacity of the fluid on the low-pressure side of the recuperator becomes greater than that on the high-pressure side. This leads to a higher outlet temperature for the propane on the low-pressure side. However, during PTES discharge, the bypass fraction flow is controlled by a pump. As a result, the thermal capacities of both fluids in the recuperator are balanced, leading to a lower outlet temperature of the recuperator on the low-pressure side.
Table 16 compares the main results of the CSP when the PTES is off versus when the PTES is charging and discharging for a condensation temperature 10 °C lower than the nominal value.
Table 17 shows the mass flow fractions circulating through each component for each case.
In this new analysis, the efficiency of the plant with the integrated PTES is lower than that of the reference plant. It can be observed that, unlike the previous case, the temperature at the outlet of the low-pressure side recuperator is higher during discharge than the temperature reached when the PTES is off. In contrast to the previous case, the heat capacity is lower than one. This happens because as the inlet pressure of the auxiliary compressor is lower than nominal, a smaller fraction than necessary to balance the thermal capacities of both fluids is diverted. However, unlike in the previous case, the work of the auxiliary compressor is also lower, so the efficiency in the reference is reduced less.
It should be noted that, in most cases, charging and discharging do not occur at the same temperature. Charging typically occurs at a higher temperature, while discharging occurs at a lower temperature. Electricity prices tend to be cheaper during the warmer hours of the day and more expensive in the evening. The efficiency in this case is improved because the maximum temperature reached by the bypassed propane during the PTES discharge is higher than if the charging were performed at a lower condensing temperature. On the other hand, both charging and discharging typically occur at ambient temperatures higher than the nominal temperature. This is because the CSP operates for a greater number of hours during the summer months. As demonstrated previously, this has positive effects on efficiency, contributing to the introduction of synergies.
5.3. Annual Results and Sensitivity Analysis
Table 18 shows the annual economic results for the reference case, the HRB-PTES-propane with 3 h of storage, and the HRB-PTES-propane with 4 h of storage.
Figure 7 shows the values of LC
INV, LC
O&M, and LI for the two cases presented in
Table 18. If LI is greater than the sum of LC
INV and LC
O&M, the project is profitable. This agrees with the values of the figures of merit in
Table 18. The net energy of the HRB-PTES-propane cases is slightly higher than that of the reference case. This is due, in part, to the synergies explained in the previous section about the potential improvement in the PTES integration.
The capacity factor is the total number of operating hours of the CSP divided by the total hours of one year, while the PTES capacity factor considers the total number of operating hours of the PTES (charging plus discharging). The incremental incomes are calculated by subtracting the incomes of HRB-PTES-propane cases from the incomes of the reference case. The incremental investment refers to the total PTES equipment costs shown in
Table 11 of
Section 5.1. The 4-h HRB-PTES is feasible under the proposed economic scenario, offering 5.46% in the profit–income ratio. The 3-h HRB-PTES is not profitable as the cost–income ratio exceeds 1. The charging and discharging electricity prices refer to the average prices obtained during the simulation. As one can expect, the price difference between charging and discharging for the 3-h case is greater than that for the 4-h case.
Table 19 shows the economic results for the sensitivity analysis. Only the HRB-PTES-propane case with 4 h of storage is analysed.
Figure 8 shows the values of LC
INV, LC
O&M, and LI for the sensitivity analysis cases presented in
Table 19. The “base case” is the same as that shown in
Table 18. The “+30% equipment cost” and “−30% equipment cost” scenarios increase and reduce the investment cost by 30%, respectively. The maintenance cost is also affected, varying proportionally with the investment cost. In the “2019 market scenario”, the simulation is performed considering the year 2019 instead of 2022. The costs are also updated considering the CEPCI ratio between 2019 and 2022. Finally, the last case considers the financial scenario of the article [
30] (as commented in the Methodology Section).
It can be observed that the feasibility is quite sensitive to the economic framework, concluding that, currently, incentives to systems aiming to stabilize the grid may be required. The worst scenario corresponds to the 2019 market scenario. It is observed that despite the lower investment cost compared with the base case, the levelized costs exceed the levelized revenues by 8 times. This is because the annual incomes are reduced almost tenfold compared with the base case. Next, a more detailed analysis is conducted on the differences in the electricity prices and incomes obtained for the years 2022 and 2019.
Figure 9 shows the monthly averages for 2022 of the CSP hourly price, market hourly price, PTES discharge hourly price, and PTES charge hourly price.
Figure 10, respectively, shows the monthly incremental revenues and the number of monthly operational hours for the PTES.
Figure 11 and
Figure 12, respectively, show the same information as
Figure 9 and
Figure 10 but for the year 2019.
In
Figure 9, it can be observed that the average price of the CSP tends to be higher than the market average during the months with lower radiation (January, February, March, October, November, and December). This is due to the dispatch optimization of the salt storage, which operates the PB preferably during the evening peak hours. In months with higher irradiation, as the operating hours of the CSP increase, the average price of the CSP tends to be the same as the average market price. It can also be observed that except for January, February, November, and December, the difference between the average discharge and charge electricity prices tends to be higher in months with lower irradiation and it tends to be lower in the summer. January, February, November, and December cannot be considered to follow this trend since the number of hours in which the PTES operates is not representative. In
Figure 10, it can be observed that in months with higher radiation, the PTES operates for a greater number of hours, while in months with lower radiation, it operates for fewer hours. This is logical since the CSP operates for a larger time during months with higher radiation. Monthly revenues do not follow a clear trend because in months when the PTES typically operates for a few hours, the price difference tends to be high, and vice versa.
The average electricity prices in
Figure 11 follow a similar trend as those in
Figure 9; however, it can be observed that they are considerably lower. Also, it should be noted that during January, the PTES does not work. The reduction in the price difference between charging and discharging is significant. So, the monthly incomes are greatly reduced despite the number of working hours of the PTES being similar to those in the previous case. In
Figure 13, the monthly revenues for the year 2022 and 2019 are presented. Finally,
Table 20 summarizes the main annual results of the comparison between the two years.
5.4. Comparison of the Proposed PTES Integration to Those of Other Works
The sensitivity analysis conducted in the previous section revealed that, assuming the same economic scenario as [
30], the cost-to-income ratio is 2.57. This is considerably lower (better) than the value obtained by [
30] for the cheapest storage technology, which was 10. This suggests that, under the economic framework considered in this study, energy storage technologies seem to have higher profitability than in [
30]. However, the frameworks are not the same and the feasibility of the proposed PTES cannot be directly compared. For this purpose, the LCOS is calculated using the same electricity purchase prices and financial scenario as in [
30].
Table 21 shows, respectively, the equivalent gross energy purchased (electricity not supplied to the grid and used to charge the PTES), the equivalent gross energy produced (compression work saved when discharging the PTES), the purchased net energy, and the equivalent net energy produced for the year 2022 and 2019. The difference between the net and gross energy is the consumption of the fans of the condenser.
Table 21 also shows the LCOS values obtained for the years 2022 and 2019 considering the net power values, a standardized purchase price of 50 EUR/MWh, and the financial scenario provided in [
30]. The discrepancies between the LCOS of both years are due, on one hand, to the updating of equipment costs for each year, and, on the other hand, to the lower number of operating hours of the PTES in the year 2019 (because the price difference between peak and off-peak hours was sometimes very small).
For the comparison, the LCOS of the year 2022 is considered, as it is the most unfavourable. As it can be observed, the LCOS of the proposed integration is considerably lower than the average value reported in the reference [
30] for Rankine and Brayton PTES (around 400 EUR/MWh). The obtained LCOS value is around the average value for a PHES (Pumped Hydro Energy Storage) with 4 h of storage according to [
30], which is the cheapest technology.
6. Conclusions
In this work, an integrated PTES in a CSP operating with an HRB-propane power cycle has been proposed. This novel configuration allows for leveraging the dispatchability of CSP plants while introducing cost savings compared with conventional PTES, as it allows for the use of the same turbine as the reference power block. Additionally, the PTES storage takes advantage of synergies in performance that arise from charging the system at high ambient temperatures while discharging at low ambient temperatures. This allows, in some cases, for increasing the efficiency of the HRB-PTES-propane compared with the reference CSP configuration without the PTES integration.
The HRB-PTES-propane with 4 h of storage has proven to be feasible under the proposed economic scenario. However, it has been observed that the results are very sensitive to changes in the economic frame. The worst-case scenario is the simulation considering Spanish electricity market prices in 2019. In this scenario, the revenues are nearly 10 times lower than in the original one of 2022. This generates considerable uncertainty regarding the profitability of this type of technology, as there are only a few years between 2022 and 2019, while amortization periods tend to be longer (+30 years). Furthermore, this leads to the additional conclusion that incentives may be required to introduce systems that increase the dispatchability of renewable energy unless the market tends to high electricity price difference between peak and valley periods.
The LCOS of the proposed PTES has been compared to those of other studies using a common reference framework. The results demonstrate that the obtained LCOS is significantly lower (around 200 EUR/MWh less) than the average LCOS of other Brayton and Rankine PTES systems. Specifically, the obtained LCOS is similar to that of the cheapest storage technology, pumped hydro heat storage, which stressed the advantages of introducing the PTES within CSP plans instead of as a standalone plant. While more validation is needed through a comprehensive optimization, these results encourage further investigation into the project.
For future works, we recommend establishing an MILP (mixed-integer linear programming) model to optimize the production dispatch schedule of the PTES in order to maximize revenues. Similarly, the proposed PTES could be extended for integration into other power cycles that include a compression process, like the recompression sCO2 cycles, where it can introduce similar benefits.