NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

Developing a Cost Model and 

Methodology to Estimate Capital 

Costs for Thermal Energy 

Storage

G. Glatzmaier

Technical Report

NREL/TP-5500-53066

December 2011
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

National Renewable Energy Laboratory

1617 Cole Boulevard

Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Developing a Cost Model and 

Methodology to Estimate 

Capital Costs for Thermal 

Energy Storage

G. Glatzmaier

Prepared under Task No. CP09.2201

Technical Report

NREL/TP-5500-53066

December 2011
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Table of Contents

Introduction ..................................................................................................................................... 1

Objective ......................................................................................................................................... 3

Background ..................................................................................................................................... 3

Types of Thermal Energy Storage .............................................................................................. 3

Previous Analyses ....................................................................................................................... 6

2011 TES Cost Analysis ................................................................................................................. 7

Two-Tank Molten Salt Base Case .............................................................................................. 7

High-Temperature, Two-Tank Storage Cost Methodology and Model ...................................... 8

Results for High-Temperature Analysis ..................................................................................... 9

Methodology for Phase-Change Thermal Energy Storage ....................................................... 11

Methodology for Thermochemical Thermal Energy Storage ................................................... 12

Discussion ................................................................................................................................. 14

Future Work .................................................................................................................................. 15

References ..................................................................................................................................... 17

List of Figures

Figure 1. Power-cycle efficiencies for CSP technologies ............................................................... 2

Figure 2. Thermal energy storage options for CSP technologies. .................................................. 4

Figure 3. Assignment of components to power tower subsystems ................................................. 9

Figure 4. Costs for direct, two-tank thermal energy storage......................................................... 10

Figure 5. Components of a generalized thermochemical storage system for CSP. ...................... 13

List of Tables

Table 1. Component costs for direct, two-tank molten salt TES system (base case). .................... 7
1 

Introduction

The goal of the Department of Energy (DOE) Solar Energy Technology Program is to develop 

solar technologies that can make a significant contribution to the United States domestic energy 

supply. The recent DOE SunShot Initiative sets a very aggressive cost goal to reach a Levelized 

Cost of Energy (LCOE) of 6¢/kWh by 2020 with no incentives or credits for all solar-toelectricity technologies.

1

 As this goal is reached, the share of utility power generation that is 

provided by renewable energy sources is expected to increase dramatically. Because 

Concentrating Solar Power (CSP) is currently the only renewable technology that is capable of 

integrating cost-effective energy storage, it is positioned to play a key role in providing 

renewable, dispatchable power to utilities as the share of power generation from renewable 

sources increases. Because of this role, future CSP plants will likely have as much as 15 hours 

of Thermal Energy Storage (TES) included in their design and operation. As such, the cost and 

performance of the TES system is critical to meeting the SunShot goal for solar technologies.

The cost of electricity from a CSP plant depends strongly on its overall efficiency, which is a 

product of two componentsthe collection and conversion efficiencies. The collection 

efficiency determines the portion of incident solar energy that is captured as high-temperature 

thermal energy. The conversion efficiency determines the portion of thermal energy that is 

converted to electricity. The operating temperature at which the overall efficiency reaches its 

maximum depends on many factors, including material properties of the CSP plant components. 

Increasing the operating temperature of the power generation system leads to higher thermal-toelectric conversion efficiency. However, in a CSP system, higher operating temperature also

leads to greater thermal losses. These two effects combine to give an optimal system-level 

operating temperature that may be less than the upper operating temperature limit of system 

components. The overall efficiency may be improved by developing materials, power cycles, 

and system-integration strategies that enable operation at elevated temperature while limiting 

thermal losses. This is particularly true for the TES system and its components. 

Meeting the SunShot cost target will require cost and performance improvements in all systems 

and components within a CSP plant. Solar collector field hardware will need to decrease 

significantly in cost with no loss in performance and possibly with performance improvements. 

As higher temperatures are considered for the power block, new working fluids, heat-transfer 

fluids (HTFs), and storage fluids will all need to be identified to meet these new operating 

conditions. Figure 1 shows thermodynamic conversion efficiency as a function of temperature 

for the ideal Carnot cycle and 75% Carnot, which is considered to be the practical efficiency 

attainable by current power cycles. Current conversion efficiencies for the parabolic trough 

steam cycle, power tower steam cycle, parabolic dish/Stirling, Ericsson, and air-Brayton/steam 

Rankine combined cycles are shown at their corresponding operating temperatures. Efficiencies 

for supercritical steam and carbon dioxide (CO2) are also shown for their operating temperature 

ranges.
2 

Figure 1. Power-cycle efficiencies for CSP technologies

Figure 1 makes clear the benefit of increased power-cycle operating temperature. Moving in this 

direction requires the use of working fluids other than subcritical steam for parabolic troughs and 

power towers. Supercritical steam and CO2 are options that correspond to power cycles in the 

600o

 to 800oC range. Air-Brayton cycles are being considered in which a combination of solar 

energy and natural gas heat air to about 1,300oC and would be the first stage in a combined 

power cycle. These working fluids will impact the requirements for the HTF. In some cases, the 

HTF and working fluid may be the same, as in the case of a supercritical CO2 power cycle that 

uses a supercritical CO2 receiver or an air-Brayton cycle that uses an air receiver.

These cycles also dictate the requirements for the TES system that will couple to the power cycle 

and receiver. Temperatures greater than the current power tower temperature (565oC) will be 

required, and whether that temperature falls into the 565o

 to 800oC range or is closer to 1,300oC 

will depend, to a large extent, on the feasibility of developing a TES system able to operate at the 

corresponding temperature while keeping the associated system losses to a minimum with hightemperature operation. These performance requirements are captured in the round-tripefficiency of the TES system. This efficiency accounts for all thermal, exergy, and parasitic 

losses associated with the storage system and should have a value greater than 90% to have a 

positive impact on the LCOE of the plant. 

In addition to these performance requirements, the TES system will need to have a low capital 

cost. The target cost for the TES system depends on other cost and performance factors for the 

power plant but an initial target has been established at about $15/kWhth. The higher 

temperature drops across the power block for these advanced cycles increase the stored-energy 

density of the sensible portion of the TES system, which helps to reduce storage inventory and 
3 

capital costs. This effect can be substantial; for example, the cost for indirect, molten-salt TES 

for troughs operating at 390°C is about 2.5 times greater than the cost for direct, molten-salt TES 

for towers operating at 565°C. 

Objective

The objective of this work was to update the previous cost model for TES systems to allow us to 

estimate the costs of TES systems that are compatible with the higher operating temperatures 

associated with advanced power cycles. For sensible storage, we updated and developed a new 

TES cost model that is based on the commercialized, direct, two-tank molten salt system. The 

model estimates the capital cost for sensible storage systems as a function of maximum operating 

temperature, storage medium heat capacity, storage medium cost, number of storage tanks, and 

storage tank material cost. In addition, we developed methodologies for estimating the costs of 

phase-change and thermochemical storage. These methodologies take into account the increased 

storage density associated with these types of storage as well as considerations for power density 

requirements and exergy losses due to temperature drops within the TES system. 

The scope of this work was limited to TES capital cost estimation. It does not include an 

estimate of round-trip-efficiency for TES systems. A separate, ongoing analysis is evaluating 

power plant performance as a function of the thermophysical properties of likely HTFs and 

storage materials, and will be completed in FY12. In that analysis, varying thermophysical 

properties are provided to the System Advisor Model (SAM), which then determines power plant 

performance and LCOE impact as a function of the properties. Results from that analysis, along 

with the TES cost estimates from this work, will provide a complete assessment of LCOE impact 

of new TES systems.

Background

CSP plants with TES are unique among renewable technologies in that they provide utility-scale, 

dispatchable electricity to the power grid. Dispatchable delivery means power is reliably 

available when it is needed to match utility load and there is no need for backup power 

generation. This feature is enabled by the incorporation of TES into the power plants. TES 

allows electricity to be generated consistently at times when sunlight is not available, including 

momentary cloud transients, which otherwise disrupt electricity generation and cause widely 

varying power output. For longer time scales, TES allows CSP plants to generate electricity well 

into the evening hours when electricity is highly valued, making the power plant more costeffective. TES also allows greater use of the turbine and other power-block components. These 

features provide an economic incentive for the addition of TES. Without TES, CSP solar power 

is an intermittent power resource that depends on sunlight availability. CSP with TES may also 

enable increased deployment of photovoltaic and wind power systems, which do not yet have 

cost-effective energy storage.

Types of Thermal Energy Storage

Figure 2 lists a variety of TES options for CSP plants.2, 3 They fall into three general categories: 

sensible, latent, and thermochemical storage. A book published in the mid 1980s provides a 

comprehensive survey of the fundamentals of the storage options, examples of systems, and the 

issues that must be addressed for technologies in the range from low to high temperatures.4 The 
4 

only TES system that currently operates with multiple hours of storage is the sensible, two-tank, 

molten-salt system. This system is used because the components associated with molten-salt 

handling—pumps, valves, tanks, and heat exchangers—have demonstrated reliable operation at 

commercial scale. The design also exhibits excellent (>90%) round trip energy and exergy 

efficiency.

Figure 2. Thermal energy storage options for CSP technologies.

The molten-salt storage fluid in current commercial plants is a mixture of sodium nitrate

(NaNO3) and potassium nitrate (KNO3). This fluid is liquid in both the charge and discharge 

states, so there are minimal heat-transfer limitations, making the heat-exchanger design relatively 

straightforward. One drawback of this system is the relatively low stored-energy density, which 

requires a large storage medium inventory, which in turn requires large insulated storage vessels, 

especially when running at current parabolic trough operating temperatures. 

Integrating this TES system into parabolic trough power plants requires an indirect 

configuration—distinct heat-transfer and storage fluids—because the storage salt has a high 

freezing point (220o

C) and could possibly freeze in the solar collectors if used as the HTF. The 

indirect system requires a heat exchanger for transferring thermal energy between the HTF and 

storage fluid. This heat exchanger reduces the performance of the storage system and adds cost 

to the plant. This approach has been demonstrated commercially in Spain at the Andasol plants. 

Thermal Energy 

Storage

Thermochemical

Metal oxide

Ammonia 

decomposition

Sulfur cycles

Latent

Salts

Metal alloys

Sensible

Molten salt 

two tank

Concrete 

thermocline

Packed bed 

thermocline

Sand-shifting 

two tank
5 

Integrating this TES system into power towers can be accomplished using a direct configuration 

because the risk of salt freezing in the receiver and vertical transfer lines of the power tower is 

much less than the risk of salt freezing in a parabolic trough collector field. This configuration 

eliminates the need for the heat exchanger, thereby reducing capital cost and increasing the 

performance of the TES system. Direct storage decouples solar energy collection from power 

generation (salt can flow at different rates in the two loops), thereby providing greater operating 

flexibility. Direct TES is currently being used in the Gemasolar Power Tower Plant in Spain. 

This plant will have 15 hours of TES and be able to operate as a baseload power plant during the 

summer months. 

The stored-energy density of the two-tank system can be increased in two ways. First, increasing 

the maximum operating temperature of the power plant increases the temperature drop across the 

turbine. Higher-temperature drops increase the efficiency of the turbine power-cycle and the 

stored-energy density of the sensible portion of the TES system, which is proportional to mCpΔT. 

At very high temperatures, the cost of the containment vessel(s) for the storage system may 

negate the cost benefit from increased temperature drop. Second, increasing the heat capacity, 

Cp, of the storage medium also directly increases the stored-energy density. These effects are 

important to reducing size, and therefore affect the capital cost of the two-tank TES system.

Thermocline systems that use low-cost storage materials offer an opportunity for reducing TES 

costs. The cost benefit of thermoclines is significant, especially if the storage material is lowcost and self-supporting. In this case, the structural requirements of the containment vessel can 

be reduced. However, thermoclines have more complex operating requirements than the twotank, molten-salt system, which creates the potential for utilization and performance losses. 

Modeling and testing of thermoclines suggest they represent a likely near-term advance in TES 

design. 

In addition to thermoclines, other alternatives to the two-tank, molten-salt storage system are 

being considered to increase the stored-energy density and, ultimately, to reduce the cost of the 

TES system. The most developed alternative is the use of phase-change materials (PCMs) to 

increase stored-energy density. PCMs have both latent and sensible enthalpies that contribute to 

the stored-energy density, providing a potential benefit over purely sensible systems. PCM 

systems suffer from a limitation in heat transfer during the discharge process due to the generally 

low thermal conductivity of the solid phase. (The exception to this case is metal PCMs; however, 

cost prohibits the use of most metal PCM candidates.) The heat transfer limitation causes low 

power density in PCM systems and will need to be overcome if PCM storage is to become a 

viable alternative. PCM storage is the most compatible storage system for the parabolic 

dish/Stirling concentrator because thermal energy delivery to the engine is isothermal, matching 

the operating conditions for that cycle. 

The third option, thermochemical storage, offers perhaps the greatest benefit because of the large 

quantity of stored energy associated with the heat of reaction. Practical implementation of these 

systems is often limited by the loss of system performance as they are put through many 

charge/discharge cycles. System performance depends on maintaining consistent physical and 

chemical properties of the chemical components and of any solid-phase materials used in the 

system over many cycles. Over time, degradation of these material properties may result in 

reducing both the system heat-transfer rate and storage capacity. In addition, some cycles 
6 

require the handling of gas-phase reactants that may require compression or corrosive substances 

that require special materials of construction. The benefits of very high energy densities and the 

possibility of storing reaction products at ambient temperature keep thermochemical storage 

under consideration for CSP technologies. 

Previous Analyses 

In 2007, NREL and Sandia National Laboratories (SNL) developed the Advanced Thermal 

Energy Storage Plan5

 for parabolic trough technology. The plan included an analysis of the 

benefits of thermal energy storage, barriers to the implementation of TES, and recommendations 

for future R&D that will both reduce the cost and improve the performance of parabolic trough 

power plants that use TES. The primary recommendation of this analysis was to evaluate and 

develop molten salt as the HTF for the solar collector field as well as the storage fluid. 

In 2009, NREL and SNL developed a Multi-Year CSP Thermal Storage Plan6 that was a 

continuation and expansion of the 2007 Thermal Storage Plan. The goal of this plan was to 

establish cost targets, performance criteria, and methods for evaluating existing and new HTFs 

and thermal energy storage concepts as they are investigated and developed, both within the 

laboratories and through the TES Funding Opportunity Announcement (FOA) projects. Also in 

2009, NREL and Worley-Parsons updated costs for a 100 MWe parabolic trough power plant 

with 6 hours of TES. This analysis provided baseline capital costs for the major components and 

installation factors for the indirect, two-tank molten salt storage system.

In 2010, NREL and SNL conducted roadmapping exercises for line focus and power tower 

technologies. These plans focused on achieving cost targets for intermediate load markets that 

were less aggressive than the current SunShot targets. The Line Focus Development Plan7

identified capital cost reductions and performance improvements for components and systems 

relating primarily to parabolic trough power plants. The plan identified cost reductions resulting 

from improvements in operation and maintenance, parasitic power requirements, and other cost 

factors. Impacts to LCOE for these cost and performance improvements were quantified.

Both roadmaps identified and prioritized Technology Improvement Opportunities (TIOs) that 

will aid in meeting the future cost goals. TIOs were identified for collectors, heliostats, and 

other components as well as for TES. Among the TIOs relating to TES, the highest priority for 

both parabolic troughs and power towers was development of a high-temperature HTF500o

C 

for troughs, 600o

C for towers. The development of low-cost, high-energy-density materials and 

systems was also identified as a high priority for both systems.

In 2010, NREL conducted an evaluation of potential cost reductions resulting from the TES FOA 

projects using TIOs identified in the roadmapping exercises. All of the TES FOA projects 

addressed at least one of the TIOs identified in the trough and tower roadmapping exercises. To 

quantify potential cost reductions that may result from the FOA projects, NREL estimated the 

cost reduction associated with each of the TIOs for TES. Costs estimates of the two-tank molten 

salt storage system from the 2009 NREL/Worley-Parsons study were used as the base case for 

this analysis. Estimated cost reductions were determined using a TES cost model that provided 

capital costs to the Solar Advisor Model (SAM, version 2010-04-12). 
7 

2011 TES Cost Analysis

Two-Tank Molten Salt Base Case

The basis for the two-tank molten salt storage system was the 2009 capital cost estimate for twotank storage for a 100 MWe parabolic trough power plant with 6 hours of TES8

. Recent 

discussions with CSP industry members allowed us to update our cost estimates in 2011. 

Because this analysis is directed at higher operating temperatures, the 2011 base case TES 

system was assumed to be direct rather than indirect, as in the 2009 cost estimate. Our 2011 

component costs for the direct, two-tank TES system are presented in Table 1. 

The costs in Table 1 had the following assumptions: 

• High temperature = 565oC, low temperature = 293oC, ΔT = 272oC 

• High-temperature tank material321 stainless steel 

• Low-temperature tank materialcarbon steel

• Salt cost = $1.23/kg 

• Electrical and instrumentation costs = 7% of total tank costs 

• Piping, valves, and fittings costs = 3% of total tank costs 

• Sales tax = 4%

• Contingency = 7%. 

Table 1. Component costs for direct, two-tank molten salt TES system (base case). 

Component

Materials 

($/kWhth) 

Installation 

($/kWhth) 

Total Cost 

($/kWhth) 

High-temperature tankstainless steel 5.20 1.84 7.04

Low-temperatures tankcarbon steel 1.30 1.84 3.14

Tank supports, foundations, and site work 1.10 1.55 2.65

Storage medium 11.74 0.36 12.10

Electrical and instrumentation 0.47 0.43 0.90

Piping, valves, and fittings 0.20 0.18 0.39

Totals 20.01 6.22 26.22

The components listed in Table 1 do not include the hot and cold tank salt pumps. The 

convention for power towers is to include the cold-tank pump with the receiver system and the 

hot-tank pump with the steam generation system. The assignment of components to power tower 

subsystems is shown in Figure 3 and was used in the 2009 power tower road-mapping study that 

was conducted by SNL, DOE, and NREL.9
8 

High-Temperature, Two-Tank Storage Cost Methodology and Model

Based on the costs presented in Table 1, a cost model was developed to estimate the cost of any

direct, two-tank storage system. Cost factors were defined to account for variations in the 

following characteristics of the two-tank storage system: 

• Temperature drop across the thermal storage system (ΔT)

• Storage medium energy density (Cp for sensible media)

• Storage medium cost ($/kg) 

• High-temperature tank materials cost

• Scaling exponent for tank volume and equipment size 

The temperature drop factor (ΔT) accounts for temperature drops across the power block that are 

greater or less than 272oC. In all cases, the low-temperature tank was assumed to be 293oC. 

Storage medium Cp and cost account for variations in the storage medium characteristics. The 

material cost for the high-temperature tank accounts for the need to use more expensive 

construction materials as the maximum operating temperature of the plant increases. The scaling 

exponent for tanks and equipment accounts for the variation of cost with volume or size; 0.7 is 

the typical value used in the chemical process industries.

These cost factors were applied as appropriate to the material and installation costs presented in 

Table 1. For example, temperature drop (ΔT) and storage medium Cp along with storage 

medium cost ($/kg) determined the material cost of the storage medium. Temperature drop and 

storage medium Cp but not the storage medium cost determined the installation cost of the 

storage medium. 
9 

Figure 3. Assignment of components to power tower subsystems.

10

For the storage tanks, temperature drop and storage medium Cp determined tank size. Tank 

material cost was based on tank size using the scaling exponent along with the tank material cost 

factor. Tank installation cost was determined in the same way but without the tank material cost 

factor. This approach was used to estimate all of the material and installation cost components in 

Table 1 and the total capital cost ($/kWhth) for storage systems that can be used with hightemperature power cycles.

Results for High-Temperature Analysis

Figure 4 shows the capital cost of direct, two-tank sensible storage systems as a function of the 

maximum operating temperature of the power plant. Because the low-temperature tank is always 

293oC, the temperature drop is proportional to the maximum operating temperature. Two cost 

factors are included in the resultsthe Cp for the storage medium and the Cp for the hightemperature tank cost factor. The Cp factor, 1X, corresponds to Cp for the NaNO3/KNO3 binary 

mixture, 1.5 J/gK. The 1.5X and 2.5X factors are 2.25 J/gK and 3.75 J/gK respectively. Carbon 

steel can be used as the high-temperature tank material up to 450o

C (1X cost factor). From 

450oC to 650oC, the high-temperature tank construction material is 321 stainless steel (4X cost 

factor). Above 650oC, a nickel-based alloy having a 16X cost factor is required. The base case 

listed in Table 1 is shown as the triangle in Figure 4. 

This analysis estimated the cost of direct TES at 400o

C to be $52/kWhth. The 2009 WorleyParsons study8

 estimated the cost of indirect storage at this temperature to be about $80/kWhth. 

The difference in cost is due primarily to the additional costs of the heat exchanger, and hot and 

cold tank salt pumps, which are included in the cost of the indirect system. Commodity prices 

have also decreased somewhat in the past two years. 
10 

Figure 4. Costs for direct, two-tank thermal energy storage. 

Figure 4 shows that the TES cost goal of $15/kWhth can be met in the temperature range of 

500o

C to 650oC using a storage medium that has a Cp of 3.75 J/gK and stainless steel as the 

storage tank material. The operating temperature that minimizes storage capital cost is 

650o

Cthe maximum allowable temperature for 321 stainless steel. At 650oC, the cost goal can 

be met using a storage medium Cp of 2.25 J/gK (1.5 X Cp of NaNO3/KNO3). This Cp is in the 

range of heat capacities for materials that have been identified as candidate storage media for this 

temperature range. Looking at temperatures greater than 650oC, the cost of the nickel alloy tank 

material increases the cost of the storage system. The cost goal can be met at temperatures above 

700o

C when the storage medium has a Cp of 3.75 J/gK. The significant cost impact of nickelalloy containment vessels highlights the need for alternative designs that can reduce vessel cost. 

Internally insulated tanks are being investigated by at least two contractors.
11 

Methodology for Phase-Change Thermal Energy Storage

Thermal storage systems based on PCMs have the advantage of higher stored-energy density 

compared to sensible only thermal storage. Equations 1 and 2 depict the calculation for thermal 

energy storage capacity (kWhth) for a sensible and latent TES system respectively. Comparing 

equations 1 & 2, equation 2 shows the extra enthalpy term associated with the phase change at a 

given temperature. In this case, the enthalpy is the heat of fusion for a solid-liquid transition.

1 

2 

PCM storage can be incorporated into thermal storage in several ways. Nano- or micro-scale 

PCM particles can be suspended in a storage fluid to increase its effective heat capacity. In this 

case, the PCM flows with the storage fluid that remains liquid in both the charged and 

discharged states. The storage system can be the two-tank system with the PCM and storage 

fluid both contributing to the storage capacity of the system. Capital costs for this type of PCM 

storage can be estimated using the two-tank cost method described above, with the addition of 

nano- or micro-scale PCM to the storage fluid impacting the energy density factor and cost factor

of the storage medium. 

Another arrangement has the PCM fixed within the thermal storage system. In this arrangement, 

the PCM functions exclusively as the storage medium and an HTF passes near or through the 

PCM as the system charges or discharges. The PCM may be encapsulated as spheres or other 

shapes to fill a fixed bed. In this geometry, the HTF passes through the void volume of the fixed 

bed. Alternatively, a piping arrangement that functions as a heat exchanger may be embedded 

within a PCM monolith, with the HTF flowing through the pipes as the system charges or 

discharges.

In any of these arrangements, the phase transition of the PCM occurs at a single temperature or 

within a temperature range that is significantly less than the full temperature drop across the 

power block. This behavior may create excessive temperature drop and exergy loss during 

charge and discharge if the HTF has purely sensible enthalpy. To address this issue, multiple 

PCMs with a distribution of phase-transition temperatures may be incorporated in a cascaded

storage system so that the change in enthalpy of the total storage medium more closely follows 

the enthalpy change for the sensible HTF. 

The methodology for estimating the capital cost for a PCM storage system must include several 

additional design steps to obtain a storage system that has acceptable performance. The total 

enthalpy of the cascaded stages that make up the PCM system needs to be determined as a 

function of temperature within the temperature range of the storage system to determine the 

approach temperatures between the HTF and the PCM during charge and discharge. The 

contributions of these approach temperatures to exergy loss determine their impact on the 

performance of the power plant output. 

∫ =

HT

LT

Sensible cmQ p )( dTT

∫ ∫ = ∆+ + =

HT

mp

T

p

mp

T

LT mp

TT Latent cmQ p )( dTT hm fusion cm )( dTT
12 

Other design considerations are the material properties and vapor pressure of the HTF within the 

storage system. Tubing or encapsulation material must be selected that is compatible with HTF

and PCM at the operating temperature and pressure ranges. If the HTF has a vapor pressure 

greater than one atmosphere at the operating temperature of the storage system, then use of PCM 

in a packed bed without tubing to contain the HTF is not feasible. For high-pressure HTFs, 

tubing with the proper schedule is embedded with the PCM to contain the HTF pressure. 

A fundamental limitation of PCM storage systems is the low power density caused by the low 

thermal conductivity of the solid phase of most PCMs. Metals and metal alloys have 

conductivities in the range of 100 to 400 W/mK and do not present this problem when used as 

PCMs. Salts, however, have conductivities in the range of 0.5 W/mK and limit heat transfer and 

power density as the storage system discharges. To address this issue, a material with greater 

thermal conductivity may be suspended into the PCM to increase its effective thermal 

conductivity. The heat exchanger may be designed to increase the heat transfer surface and 

decrease the average distance from a PCM volume element to a heat transfer surface. A large 

difference in the PCM solid- and liquid-phase densities also presents a design issue and the tank 

must be sized to accommodate the volume of the lower density phase and also ensure that the 

heat transfer surfaces are contacted by both solid and liquid phases. 

Once the number of PCM stages is determined and the PCM, tubing, and encapsulation materials 

are selected, a basic design can be specified for each stage. Tank sizes, material quantities, and 

component costs can be estimated using the method described in the two-tank storage case. A 

separate analysis must be performed to determine the design and cost of the tubing schedules and 

heat transfer area of the heat exchanger for each stage of the PCM system.

Methodology for Thermochemical Thermal Energy Storage

Thermochemical storage has the advantage of very high stored energy densities compared to 

PCM or sensible only thermal storage. Comparing equations 1 & 3, equation 3 shows the extra 

enthalpy term associated with the forward reaction at temperature, TRf. The first term represents 

the enthalpy associated with heating the reactant(s) from TL to the forward reaction temperature, 

TRf. The third term in the equation accounts for the optional sensible enthalpy for increasing the 

temperature of the product(s) beyond the forward reaction temperature, TRf , to temperature, TH. 

3 

Figure 5 shows a schematic of a generalized thermochemical storage system in which A reacts to 

B in the forward endothermic reaction and B reacts back to A in the reverse exothermic reaction. 

The endothermic reaction absorbs solar energy as A converts to B and occurs in a solar 

receiver/reactor. Ideally, A and B are stored at ambient temperature, TL, so the sensible enthalpy 

in B is used to preheat A before it enters the reactor.

∫ ∫ = ∆+ + =

HT

RT

p

RT

LT

R

thermochemical p reaction TT

f

f

f Q cm )( dTT hm cm )( dTT
13 

Figure 5. Components of a generalized thermochemical storage system for CSP. 

To retrieve the stored energy, B is heated to the reverse exothermic reaction temperature, TRr, 

and converted back to A in a separate reactor. A supplies thermal energy for power 

generationdirectly as the working fluid or indirectly to heat a working fluid. A preheats B, and 

then rejects the remainder of its enthalpy to return to storage at ambient condition. 

Because the energy differences are the same for A → B and B → A, the energy absorbed during 

charging (left side of Figure 5) and discharging (right side of Figure 5) are the same. The key 

condition that drives the overall efficiency and exergy loss of the storage system is the

temperature difference between TRf and TRr. If TRr is much less than TRf, then the exergy loss 

will be significant and the overall performance of the storage system will be low.

Performing a complete cost analysis for thermochemical storage is more complex than the 

analyses for sensible or PCM storage. The schematic shown in Figure 5 includes a solar 

receiver/reactor, in which the forward endothermic reaction occurs, and several heat exchangers 

for heat rejection. These components are normally not included in the thermal storage system for 

cost analysis but are critical for thermochemical storage. To determine the cost of 

thermochemical storage, certain components may need to be omitted from the analysis even 

though they are required for the storage system. A cost comparison standard needs to be 

developed for thermochemical storage to fairly compare its costs to those of sensible and PCM 

storage systems.

Real thermochemical cycles are generally far more complex than the cycle shown in Figure 5. 

Multiple reactants and products along with multiple phases are usually involved, so kinetic 

limitations may reduce reaction conversion and rate. The first effect reduces the stored-energy 

density. The second effect reduces power density. Numerous types of thermochemical cycles

A  B

@TRf

ΔH > 0

B  A

@TRr

ΔH < 0

Heat 

exchangers

Storage

A

B

Power 

generation
14 

have been proposed and developed for thermal energy storage. Many use corrosive chemicals so 

material compatibility becomes an issue. Studies conducted by SNL summarized many of the 

possible thermochemical cycles that have been considered.

11, 12 At the time of the reports, these 

cycles generally had low conversion efficiencies and will need significant performance 

improvements before they can be applied to CSP technologies.

A cost methodology for thermochemical storage must include the basic steps: 

• Identify a basic thermochemical cycle that is compatible with the operating temperature, 

pressure, and HTF of the advanced cycles 

• Define all of the process components required to perform the cycle 

• Define the boundaries between the storage system itself and other power plant 

subsystems 

• Specify the reactor and storage tank materials based on reactant and HTF compatibilities 

and pressures

• Specify the heat exchanger tubing material and schedule based on reactant and HTF 

compatibilities and pressures

• Estimate material quantities, components and costs for the total system and calculate total 

installed cost

• Define how start up, shut down, and varying TES cycle performance will impact the 

overall generation from the power plant. 

The operational energy and exergy efficiency of a two-tank TES system are high, and well 

understood. This design places few constraints on the power block and solar receiver because 

thermal energy is provided at roughly constant conditions. However, thermocline, PCM, and 

thermochemical systems are more likely to output fluctuations in HTF temperature during their 

operational cycles. The impact of such variations is not tracked here, but can be important to 

overall plant performance and must be understood. 

Discussion

Results from the two-tank sensible storage analysis show that the optimal temperature for 

meeting the SunShot TES cost goal of $15/kWhth is the maximum allowable temperature for a 

stainless steel alloy tank wall in contact with a molten salt storage fluid. For this analysis, that 

temperature was assumed to be 650oC. At 650oC, the SunShot cost goal can be met using a 

molten salt that has a heat capacity of 2.25 J/gK or a factor of 1.5 times the heat capacity of the 

NaNO3/KNO3 mixture. Carbonate mixtures are thermally stable at these temperatures and some 

formulations may have the required heat capacity. If salt formulations with heat capacities in the 

range of 3.75 J/gK can be identified, sensible storage systems with operating temperatures in the 

range of 500oC to 650oC will meet the SunShot cost goal. The operating temperature range for 

the supercritical steam cycle is 600oC to 700oC and 550oC to 800oC for the supercritical CO2

cycle (Figure 1), so there is good overlap between the optimal sensible storage temperature range

and the operating temperature ranges for these advanced cycles.

Identifying or developing molten salt formulations that have heat capacities in the range of 2.25

to 3.73 J/gK can be accomplished in two ways. Using our thermodynamics database software 
15 

tools, we may be able to identify salt compositions that are thermally stable in this temperature 

range and that have the required heat capacity. These tools should allow us to identify specific 

compositions or composition ranges that show promise for meeting these requirements. Testing 

compositions in NREL’s Materials Laboratory will validate the software tool predictions. The 

heat capacities of promising compositions may be enhanced with the addition of micro- or nanoscale particles to obtain the required heat capacity to meet the cost goal. In addition, we need to 

develop a similar methodology to the two-tank, molten salt model to estimate the cost of 

thermocline storage as a function of temperature. These specific research activities are included 

in the FY12 operating plan. 

Cost methodologies for PCM and thermochemical storage systems were outlined and 

summarized in this work. Before a cost analysis of PCM storage can be completed, a PCM 

system will need to be specified as outlined in this report. The number of stages, including 

phase-change temperatures and enthalpies, needs to be specified. PCMs for each stage, 

including material properties, need to be identified. Basic heat transfer analysis will determine 

the specifications for the heat exchanger, or geometry of the packed bed if encapsulated PCMs 

are used. Vapor pressure of the HTF will also factor into the design of the heat exchanger. 

Complete specification of the storage system will allow material quantities, material costs, and 

component costs to be determined, which will lead to a total installed cost for the system.

Performing a complete cost analysis for thermochemical storage adds still more complexity. 

Many thermochemical cycles have been identified and investigated for thermal storage. These 

cycles typically have kinetic limitations that affect the storage energy and power densities of the 

system. Any thermochemical cycle needs a solar receiver/reactor, in which the endothermic 

reaction occurs, and a heat exchanger(s) for heat rejection. These components are normally not 

included in the thermal storage system for cost analysis but are critical for thermochemical 

storage. To fairly determine the cost of thermochemical storage, certain components may need 

to be omitted from the analysis even though they are required for the storage system. A cost 

comparison standard will need to be developed for thermochemical storage to compare its costs 

to those of sensible and PCM storage systems.

Future Work

We have several activities planned in FY12 that will be follow-on work to this report. For 

sensible storage, the cost analysis is complete and we will focus our work on identifying salt 

compositions that have the desired material properties to meet the SunShot cost goal. We plan 

to: 

• Use NREL’s thermodynamic database software tools to identify salt compositions that 

are thermally stable in the optimal temperature range for sensible storage

• Use NREL’s Materials Laboratory to measure and validate the properties of theses 

compositions 

• Continue work in nanofluids to identify nanomaterials that significantly enhance the heat 

capacity of storage fluids, 
16 

• Develop a similar methodology to estimate the cost of thermocline storage as a function 

of temperature. 

For PCM storage, the cost methodology has been outlined but specific cost analysis must be 

completed. We plan to: 

• Specify a complete PCM storage system, including number of stages and material 

requirements for each stagestages may consist of monolithic or encapsulated PCMs 

• Identify promising PCM candidates for each stage 

• Conduct computational fluid dynamics heat transfer modeling to determine the basic 

design requirements for the heat exchanger

• Specify the heat exchanger tubing material and schedule based on PCM compatibility and 

HTF compatibility and vapor pressure 

• Estimate material quantities, components, and costs for the total system and calculate 

total installed cost

• Develop a fully-integrated CSP plant model that includes PCM storage to evaluate the 

annual performance of a candidate PCM storage system and determine its effects on fullplant performance. 

For thermochemical storage, the cost methodology has been outlined but more work is needed to 

complete a basic cost analysis. We plan to: 

• Identify a basic thermochemical cycle that is compatible with the operating temperature, 

pressure, and HTF of the advanced cycles

• Define all of the process components required to perform the cycle 

• Define the boundaries between the storage system itself and other power plant 

subsystems 

• Specify the reactor and storage tank materials based on reactant and HTF compatibilities 

and pressures 

• Specify the heat exchanger tubing material and schedule based on reactant and HTF 

compatibilities and pressures

• Estimate material quantities, components, and costs for the total system and calculate 

total installed cost.

All of the work that is outlined is included within the planned tasks for FY12. 
17 

References

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www1.eere.energy.gov/solar/sunshot/. Accessed July 7, 2011. 

2. U. Herrmann, D. Kearney. (2002). J. Solar Energy Eng. 124, 145. 

3. G. Glatzmaier. (2011). Summary Report for Concentrating Solar Power Thermal Storage 

Workshop, NREL Technical Report: NREL/TP-5500-52134. 

4. H.P. Garg, S.C. Mullick, A.K. Bhargava. (1985). Solar Thermal Energy Storage, D. Reidel 

Publishing Company, Dordrecht, Holland. 642 pp. 

5. H. Price, D. Brosseau, D. Kearney, B. Kelly. (2007) DOE Advanced Thermal Energy Storage 

Plan for Parabolic Trough Technology.

6. C. Turchi. (2009). Multi-Year CSP Thermal Storage Plan: FY2009 – FY2020.

7. C. Kutscher, M. Mehos, C. Turchi, G. Glatzmaier, T. Moss. (2010) Line-Focus Solar Power 

Plant Cost Reduction Plan, NREL Technical Report: NREL/TP-5500-48175. 

8. C. Turchi. (2010) Parabolic Trough Reference Plant for Cost Modeling with the Solar 

Advisor Model (SAM), NREL Technical Report: NREL/TP-550-47605. 

9. G. J. Kolb, C. K. Ho, T. R. Mancini, J. A. Gary. (2011) Power Tower Technology Roadmap 

and Cost Reduction Plan, Sandia Report: SAND2011-2419 

10. H. E. Reilly, G. J. Kolb. (2001). An Evaluation of Molten-Salt Power Towers Including

Results of the Solar Two Project, Sandia Report: SAND2001-3674. 

11. R.D. Smith. (1979). Chemical Energy Storage for Solar Thermal Conversion, Final Report, 

Sandia Report: SAND79-8198, 190 pp. 

12. T.T. Bramlette, R.M. Green, J.J. Bartel, D.K. Ottesen, C.T. Schafer, T.D. Brumleve. (1976). 

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