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Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

Technical Report

NREL/TP-5500-71793

November 2018

Solar-Driven Steam Topping Cycle for a 

Binary Geothermal Power Plant

Joshua D. McTigue,

1 Nick Kincaid,1 Guangdong Zhu,1

Daniel Wendt,

2 Joshua Gunderson,3 and Kevin Kitz4

1 National Renewable Energy Laboratory

2 Idaho National Laboratory

3 POWER Engineers

4 KitzWorks LLC (formerly with U.S. Geothermal)
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

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Technical Report

NREL/TP-5500-71793

November 2018

Solar-Driven Steam Topping Cycle for a 

Binary Geothermal Power Plant

Joshua D. McTigue,

1 Nick Kincaid,1 Guangdong Zhu,1

Daniel Wendt,

2 Joshua Gunderson,3 and Kevin Kitz4

1 National Renewable Energy Laboratory

2 Idaho National Laboratory

3 POWER Engineers

4 KitzWorks LLC (formerly with U.S. Geothermal)

Suggested Citation

McTigue, Joshua D., Nick Kincaid, Guangdong Zhu, Daniel Wendt, Joshua Gunderson, and 

Kevin Kitz. 2018. Solar-Driven Steam Topping Cycle for a Binary Geothermal Power Plant. 

Golden, CO: National Renewable Energy Laboratory. NREL/TP-5500-71793.

https://www.nrel.gov/docs/fy19osti/71793.pdf.
NOTICE

This work was authored in part by the National Renewable Energy Laboratory, operated by Alliance for Sustainable 

Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. Funding 

provided by U.S. Department of Energy Office of Energy Efficiency and Renewable Energy, Geothermal 

Technologies Office. The views expressed herein do not necessarily represent the views of the DOE or the U.S. 

Government.

This report is available at no cost from the National Renewable 

Energy Laboratory (NREL) at www.nrel.gov/publications.

U.S. Department of Energy (DOE) reports produced after 1991 

and a growing number of pre-1991 documents are available 

free via www.OSTI.gov.

Cover Photos by Dennis Schroeder: (clockwise, left to right) NREL 51934, NREL 45897, NREL 42160, NREL 45891, NREL 48097, 

NREL 46526.

NREL prints on paper that contains recycled content.
iv

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Acknowledgments

This work was authored, in part, by the National Renewable Energy Laboratory, operated by 

Alliance for Sustainable Energy, LLC, for the U.S. Department of Energy (DOE) under Contract 

No. DE-AC36-08GO28308. Funding provided by the U.S. Department of Energy, Office of 

Energy Efficiency and Renewable Energy, Geothermal Technologies Office (GTO). The views 

expressed in the article do not necessarily represent the views of the DOE or the U.S. 

Government. The U.S. Government retains and the publisher, by accepting the article for 

publication, acknowledges that the U.S. Government retains a nonexclusive, paid-up, 

irrevocable, worldwide license to publish or reproduce the published form of this work, or allow 

others to do so, for U.S. Government purposes.
v

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Nomenclature or List of Acronyms

BES Battery energy storage

CSP Concentrating solar power

FCR Fixed-charge rate

GBPP Geothermal binary power plants

HP High pressure

HTF Heat-transfer fluid

INL Idaho National Laboratory

ITC Investment Tax Credit

LCOH Levelized cost of heat

LCOE Levelized cost of electricity

LP Low pressure

LFC Linear Fresnel collector

NREL National Renewable Energy Laboratory

NSRDB National Solar Radiation Database

O&M Operations and maintenance

ORC Organic Rankine cycle

PFD Process flow diagram

PTC parabolic trough collector

PV Photovoltaics

SAM System Advisor Model

TES Thermal energy storage

TMY Typical Meteorological Year
vi

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Executive Summary

Greater deployment of moderate-temperature geothermal binary power plants (GBPPs) and 

concentrating solar power (CSP) can be limited in some markets by their respective generation 

characteristics and/or levelized cost of electricity (LCOE). Worldwide, both geothermal power 

and CSP are under intense pressure from the rapidly dropping cost of solar photovoltaic (PV) 

and wind energy. In the United States, there is further pressure from the ongoing era of low 

natural gas prices. CSP can generate high-temperature thermal energy that enables high cycle 

efficiency and low-cost thermal storage systems, and GBPP can produce baseload power 

generation. Hybridization may take advantage of technical merits of both technologies to 

produce energy at a levelized cost of energy (LCOE) competitive in the future energy market. 

New approaches that can lower the LCOE of both geothermal power and concentrating solar can 

therefore help to increase adoption of both technologies. 

In this technical report, we explore several methods of combining heat generated by a 

concentrating solar field with an existing geothermal binary power plant. The Raft River 

geothermal power plant in southern Idaho operates below its rated capacity because the reservoir 

is unable to deliver the design flow and temperature of geothermal energy. The GBPP is a twopressure cycle with independent high-pressure and low-pressure isopentane turbines. Solar heat 

may be added in several ways to this cycle and we perform a screening study and then more 

detailed calculations for several configurations, including:

1. Geothermal production brine directly heated by solar energy;

2. A fraction of geothermal brine extracted from some part of the binary plant, heated with 

solar energy, and mixed with the production fluids; and

3. The addition of a steam topping cycle, the hot exit flow of which is used to:

a. Heat brine, as in points 1 and 2, and

b. Vaporize the binary-cycle working fluid after the fluid has been preheated by the 

geothermal brine.

The initial screening study was performed on a large number of different cycle configurations at 

a single operating condition. Subsequently, a more detailed study investigated annual cost and 

performance. Both the screening study (using one set of modeling software) and the detailed 

analysis (using another software package) were calibrated against one or more aspects of the Raft 

River operating condition. The combined results of the screening and detailed study are shown in 

Table A (although the results from one model should not be compared to those of the other).
vii

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Table A: Comparison of different hybrid plant configurations from the screening study and 

detailed study. ‘—’ indicates that the configuration was not studied.

Design-Point Cycle 

Efficiency

Annual 

Efficiency

Cycle and Description Screening 

Study

Detailed 

Study

Detailed 

Study

Two solar steam turbines: Use high-temperature solar steam in 

two turbines, which exhausts to HP and LP isopentane boilers.

Isopentane vapor is used in the GBPP isopentane turbine.

35% 33% 30%

One solar steam turbine with steam cross-over: Eliminate the 

small turbine to the LP isopentane boiler, and instead, use some 

of steam from HP turbine exhaust to feed the LP isopentane

boiler.

— 32% 29%

One solar turbine with geo-heat bypass: All solar turbine steam 

is used on HP side. Eliminate LP steam isopentane boiler. Reduce 

geo-heat extraction from the HP side of the GBPP and bypass it to 

the LP geo-boiler.

— 32% 29%

Solar steam turbine to reheat internal brine slip-stream: Use 

one steam turbine, and then recirculate and reheat brine from 

inside the GBPP, after either the HP or LP vaporizers.

27% to 

30% — —

One solar turbine to heat incoming brine: One solar turbine is 

used to heat the entire flow of brine coming into the GBPP. This 

raises temperature but not flow. Calcium mineral precipitation is a 

risk.

— — —

One solar turbine to reheat brine from plant exit: A slipstream 

of brine from the plant exit is reheated and added back to the inlet 

flow, increasing brine flow to the plant, and possibly temperature,

as well.

24% to 

27% — —

Directly heat incoming brine with solar energy: No hightemperature solar steam turbine. Heat all incoming brine with 

direct solar energy.

16% 16% 16%

Directly heat brine from exit with solar energy: No solar steam 

turbine. Heat exit brine slipstream with solar energy, recirculate to 

plant inlet.

— 13% 13%

The following are some key insights into the design of geo-solar hybrid configurations from the 

two modeling efforts and the table above:

1. The studies confirm that creating and using high-exergy (high-temperature, i.e., 700°F) 

solar energy in a steam turbine creates up to twice as much net power as if the solar 

energy is used directly to heat brine at moderate temperatures (i.e. < 300°F).

2. Multiple steam turbines and multiple steam extraction and heating points are the most 

efficient; but from a practical perspective, a single steam turbine and single heating point 

appear to be the preferred mode of converting the high-temperature steam, at least for the 

relatively small installation being considered at Raft River.
viii

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3. Cycles that minimize the temperature rise of the brine exiting the GBPP are more 

efficient. Conceptually, increasing brine temperature implies that solar energy is used to 

heat the injection brine. The most efficient cycles reduce the brine temperature exiting the 

plant, effectively using solar energy to increase the extraction of geothermal energy.

4. The best cycles use the solar energy to vaporize the GBPP working fluid, whereas the

worst cycles add heat and/or flow to the incoming brine flow to the GBPP. 

5. If brine heating is undertaken, it is best to heat the incoming flow to the GBPP, rather 

than to recirculate and re-heat brine from within the GBPP.

6. Cycles that heat brine using a steam topping turbine are significantly more efficient than 

cycles that directly heat the brine with the collected solar energy. 

As the study progressed, additional steam-topping cycle configurations were compared with the 

aim of simplifying the cycle and reducing the capital cost. The most promising configuration 

uses a single steam turbine whose exit flow vaporizes the binary-cycle working fluid. This cycle 

achieves a conversion efficiency of solar thermal power to electricity of 32.0% at the design 

point, and 29% over the year. The advantages of this cycle were that it reduced the number of 

equipment components added to the cycle, made use of the existing brine bypass to transfer heat 

to the low-pressure turbine, and retained the advantage of lowering the brine exit temperature 

when the solar turbine was operating.

The influence of geographical location was investigated, and we found that locating the hybrid 

geothermal-solar plant in southern California would lead to lower total power outputs than a 

plant in southern Idaho because of California’s higher average annual wet-bulb temperatures. 

This effect is, in part, because the heat-rejection system for a plant located in Idaho is undersized 

compared to a plant located in California. However, the greater solar resource in southern 

California led to a 23% increase in the addition of electricity from the hybrid plant, thereby 

leading to a lower LCOE—0.118 $/kWhe in southern California, compared to 0.126 $/kWhe in 

Idaho, both with no U.S. tax code investment tax credit (ITC).

It is important to note that the costs given in this report include a large number of assumptions. 

The values are reasonable, but greater accuracy will be derived from comparing calculated costs 

with each other within this report, rather than with costs from outside the bounds of this 

particular study. On the other hand, these costs may also be high. The DOE SunShot target aims 

to develop low-cost solar collectors for < 75 $/m2

. The cost of collectors assumed in the study 

was 125 $/m2. 

Designing the solar field to return the geothermal plant to its design power output at the optimal 

solar irradiance of 950 W/m2 means that the hybrid plant will operate off-design for a large 

portion of the year. Increasing the size of the solar field means that the plant can operate at or 

above the design point for a greater percentage of the year. Unlike conventional CSP plants, 

where any excess solar power from an oversized solar field must be curtailed, in the hybrid plant, 

the excess solar heat may be bypassed around the steam turbine and transferred directly into the 

geothermal plant. This option reduces curtailment and increases the annual energy generation. 
ix

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However, the geothermal power plant converts heat less efficiently than the steam turbine. 

Thermal energy storage (TES) may be used to avoid curtailment and still convert excess solar 

heat with a higher efficiency. Although thermal storage increases the capital cost of the plant, the 

increased annual power generation acts to reduce the LCOE. For the LCOE to be lower than a 

plant with no storage, it is found that the storage should have a capital cost of less than 35 

$/kWhth. (Currently, two-tank TES costs 30–50 $/kWhth, whereas other pre-commercial 

technologies such as packed beds may achieve lower costs.)

If subsidies are available, then the cost of the hybrid plant with TES is significantly reduced. 

Table B indicates that an ITC of 30% (which is available to plants that have commenced 

construction before 2019) would reduce the LCOE of a hybrid plant with 4 hours of TES by 0.02 

$/kWh.

Table B: LCOE of a hybrid geothermal–solar power plant with four hours of TES in two locations 

for different values of the ITC.

LCOE ($/kWhe)

Burley, ID Imperial, CA

TES Cost Tax incentive % Tax incentive %

$/kWhth 0% 30% 0% 30%

25 0.113 0.085 0.088 0.067

50 0.125 0.093 0.097 0.073

Finally, the incremental cost of the hybrid geothermal–solar power plant with TES is compared 

to a photovoltaic array with battery energy storage (PV+BES). We found that the hybrid plant is 

significantly less expensive than the PV+BES system due to the high cost and replacement rate 

of batteries. However, without energy storage, the PV plant has a lower LCOE (see Table C).

The low cost of stored solar energy is a significant result from this work. If validated in more 

detailed studies, it could have important implications for both the geothermal and concentrating 

solar industries. However, its greatest impact could be on the storage market and on the role that 

geothermal can play in dispatchable power.

Table C: Comparison of the LCOE of a hybrid plant with TES versus a PV array with BES, for 

different storage durations and geographical locations.

Levelized Cost of Storage – LCOE ($/kWhe)

0 h storage 4 h storage

PV Hybrid PV+BES Hybrid+TES

Burley, ID 0.074 0.116 0.187 0.118

Imperial, CA 0.063 0.092 0.148 0.091
x

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Conclusions:

• Use of a high-pressure steam turbine to capture the high-temperature potential of solar 

thermal in a geothermal binary hybrid power plant doubles the efficiency of direct solar 

heat addition to brine options. As a result, the cost of the power generated by the hybrid 

is significantly reduced.

• The addition of solar thermal storage to the hybrid plant provides multiple benefits: it 

lowers the LCOE of the hybrid plant, and it provides dispatchability at a lower cost than 

photovoltaic power with batteries. This potentially opens new markets for existing and 

new geothermal power plants.

• Several further areas of investigation were identified that could build on the successful 

findings of this study.
xi

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Table of Contents

1 Study Basis ........................................................................................................................................... 1

Motivation .............................................................................................................................................. 1

Economic and Technical Drivers for a Successful Hybrid Plant ........................................................... 1

Thermodynamic and Economic Evaluation Parameters......................................................................... 2

Description of Raft River Geothermal Power Plant ............................................................................... 3

2 Screening and Review of Geothermal and Solar Thermal Hybrid Technologies .......................... 6

Overview: Methods and Technologies Used for Adding Solar-Thermal to a GBPP ............................. 6

Raft River Solar/Geothermal Hybrid Cycle Screening Evaluation ........................................................ 7

Description of Preferred Cycle............................................................................................................... 8

Literature Review................................................................................................................................. 11

3 Modeling Methodology ...................................................................................................................... 14

Modeling of the original Raft River GBPP with IPSEpro.................................................................... 15

Addition of Solar Heat to the Raft River GBPP in IPSEpro ................................................................ 17

Off-Design Steam-Turbine Modeling .................................................................................................. 18

Determination of Plant Performance for a Typical Meteorological Year ............................................ 20

Solar-Field Modeling with SAM.......................................................................................................... 21

Economic Modeling ............................................................................................................................. 24

Levelized Cost of Electricity................................................................................................................ 26

4 Results................................................................................................................................................. 28

Comparison of Thermal and Generation Performance......................................................................... 28

Influence of Geographical Location..................................................................................................... 30

Effect of Re-Routing Excess Solar Heat around the Steam Turbine and Adding to the Vaporizer ..... 32

Optimal Solar-Field Sizing................................................................................................................... 33

Integrating Thermal Storage with Solar-Field Sizing in the Geo–Solar Hybrid .................................. 34

Effect of Tax Incentives on Economic Results .................................................................................... 36

Influence of Solar-Field Costs.............................................................................................................. 36

Comparison with a Photovoltaic Array with Battery Energy Storage.................................................. 37

5 Further Work ....................................................................................................................................... 40

6 Conclusions ........................................................................................................................................ 42

References................................................................................................................................................. 44

Appendix A ................................................................................................................................................ 47

Appendix B: Component Cost Estimates............................................................................................... 55
xii

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List of Figures

Figure 1. Raft River Geothermal Power Plant Process Flow Diagram. Key: CT: cooling tower; EV: 

evaporator; HPT: High-pressure turbine; LPT: Low-pressure turbine; PH: Preheater; CWP: 

Cold-water pump; PW: Production well; IW: Injection well; G: Generator; CP: Circulation 

pump. ....................................................................................................................................... 4

Figure 3. Case 1A—Process flow diagram of the hybrid solar–geothermal system with two steam 

turbines..................................................................................................................................... 9

Figure 4. Case 1B—Process flow diagram of the hybrid solar–geothermal system with one steam turbine. 

Steam turbine exit flow heats both the HP and LP working-fluid cycles. ............................. 10

Figure 5. Case 1C—Process flow diagram of the hybrid solar–geothermal system with one steam turbine. 

Steam turbine exit flow heats only the HP working-fluid cycles........................................... 11

Figure 7. Comparison of gross power reported in Raft River plant operating data with predicted values. 17

Figure 8. Comparison of net power reported in Raft River plant operating data with predicted values..... 17

Figure 9. Off-design performance of back-pressure steam turbines. Curves are the relative efficiency 

compared to the design point. Data from Bahadori et al. [29] and Atlas CopCo................... 20

Figure 10. Multiple linear-regression model of hybrid plant net power generation as function of wet-bulb 

temperature for varying solar-field thermal output. IPSEpro model output is included as 

discrete points while the regression function output is depicted as curved lines................... 21

Figure 11. Solar-field thermal power produced for PTC 2 from SAM for a 50-MW solar field with N-S 

orientation. ............................................................................................................................. 22

Figure 12. LCOH for various solar collectors............................................................................................. 24

Figure 13. Solar-field thermal power output for PTC 2 comparing collector orientation during a) summer 

day and b) winter day............................................................................................................. 24

Figure 14. The solar conversion efficiency ηηηηηηηη, 11 and LCOE of several hybrid-plant configurations. ... 30

Figure 15. The influence of location on the hybrid-plant performance. a) Higher average annual wet-bulb 

temperatures lead to lower solar conversion efficiencies. b) The geothermal power plant 

produces less electricity in warmer regions. However, more solar heat is generated............ 32

Figure 16. The hybrid-plant power output for several ambient temperatures as the solar thermal input 

varies. There is a noticeable kink at the point where excess solar heat is re-routed around the 

steam turbine.......................................................................................................................... 33

Figure 17. The effect of solar-field size on the LCOE. Curves are shown for a hybrid plant with one 

turbine with the solar field oriented north-south. Curves are shown for two locations and for 

configurations where the solar heat is either curtailed or re-routed directly into the 

geothermal plant vaporizers. .................................................................................................. 34

Figure 18. Thermal storage increases the optimal solar multiple. a) Hybrid plant at Burley, ID. b) Hybrid 

plant at Imperial, CA. Results are for a hybrid plant with one steam turbine with the solar 

field oriented north-south....................................................................................................... 35

Figure 19. The effect of the cost of thermal storage on the LCOE of the hybrid plant for a) Burley, Idaho, 

and b) Imperial, California..................................................................................................... 36

Figure 20. The LCOE of a hybrid plant with no storage and a solar multiple of 1.5 at two locations. The 

grey lines indicate the LCOE that may be achieved using current solar-field costs (including 

collectors, site improvements, and HTF system), or target costs according to the DOE CSP 

COLLECTS Funding Opportunity Announcement. (Costs without tax incentives.)............. 37

Figure 21. Case 2—Geothermal production fluids are heated directly by the solar field........................... 48

Figure 22. Case 4A—Injection brine is heated in the condenser of a topping steam turbine. The hot brine 

is recirculated and mixed with the production fluids. ............................................................ 49

Figure 23. Case 4B—Injection brine is heated in the condensers of a three-stage topping steam turbine. 

The hot brine is recirculated and mixed with the production fluids....................................... 50

Figure 24. Case 5A—Brine is extracted before the binary-cycle preheaters. It is then heated in the 

condenser of the steam topping cycle and then mixed with the production fluids. ............... 51
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Figure 25. Case 5B—Brine is extracted before the binary-cycle preheaters. It is then heated in the 

condensers of a three-stage steam topping cycle and then mixed with the production fluids.

................................................................................................................................................ 52

List of Tables

Table 1. Selected isopentane design state points on Figure 1 (SH = superheated)....................................... 5

Table 2. Comparison of design and actual operating conditions and generation.......................................... 5

Table 3. Collector specifications for PTCs and LFCs................................................................................. 22

Table 4. Annual simulation results for N-S oriented collectors.................................................................. 23

Table 5. Installed capital costs for brine-preheating, dual-turbine topping-cycle, and single-turbine 

topping-cycle hybrid-plant configurations............................................................................. 26

Table 6. Economic factors used in LCOE calculations............................................................................... 27

Table 7. Solar heat input, marginal solar efficiency, and additional power generation for candidate Raft 

River geo–solar hybrid-plant configurations ......................................................................... 29

Table 8. Typical solar properties at various geothermal plant locations in the USA.................................. 31

Table 9. Electrical work output, solar conversion efficiencies, and LCOEs of hybrid plants in different 

geographical locations............................................................................................................ 32

Table 10. Tax incentives reduce LCOE significantly, even for high storage costs. Systems include four 

hours of storage...................................................................................................................... 36

Table 11. Current solar-field costs, and target costs based on the DOE SunShot target. (Costs without tax 

incentives.)............................................................................................................................. 37

Table 12. Capital cost assumptions for photovoltaic cells and lithium-ion batteries.................................. 39

Table 13. Comparison of costs and LCOEs for a hybrid plant and a photovoltaic array with batteries. Both 

plants are located in Burley, Idaho (without tax incentives).................................................. 39

Table 14. Comparison of costs and LCOEs for a hybrid plant and a photovoltaic array with batteries. Both 

plants are located in Imperial, California............................................................................... 39

Table 15. Preliminary results comparing several hybrid geothermal–solar configurations. These results are 

for the case where the solar-field heat input restores the geothermal plant to its design point.

................................................................................................................................................ 53

Table 16. List of equipment, equipment sizing, and installed capital costs for brine-preheating, dualturbine topping-cycle, and single-turbine topping-cycle hybrid-plant configurations........... 55
1

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1 Study Basis 

Motivation

Greater deployment of moderate-temperature geothermal binary power plants (GBPP) and 

concentrating solar power (CSP) may be limited in some markets by their respective generation 

characteristics and/or levelized cost of electricity (LCOE). Worldwide, both geothermal power 

and CSP are under intense pressure from the rapidly dropping cost of solar photovoltaic (PV) 

and wind energy. In the United States, there is further pressure from the ongoing era of low 

natural gas prices. CSP can generate high-temperature thermal energy that enables high cycle 

efficiency and low-cost thermal storage systems, and GBPP can produce baseload power 

generation. Hybridization may take advantage of technical merits of both technologies to 

produce energy at an LCOE that is competitive in the future energy market, thereby increasing

the adoption of both technologies.

In this report, we describe an investigation into the addition of a steam topping cycle to an 

existing geothermal binary power plant named Raft River, in southern Idaho. The Raft River 

GBPP is currently operating below its design capacity because incoming geothermal fluid 

temperature and mass flow rates are lower than the design value. As a result, revenue and 

profitability are reduced. This problem is not unique to this plant. Although not applicable to 

Raft River, in some power sales contracts, the reduced output may also trigger fees or penalties 

[1]. 

The extent of any resource decline is unique to that geothermal field, if it exists at all. A survey 

of geothermal power plants in California and Nevada found that flash plants typically 

experienced a temperature decrease of 0.8% per year, and the value was 0.5% for binary plants 

[2]. In many cases, the reduction in temperature can be offset by an increase in flow rate, such as 

with makeup drilling, to keep plant output constant; however, this is not always possible. In such 

cases, the unfilled portion of the GBPP’s power sales contract provides an opportunity to install a 

concentrating solar plant at reduced cost because there is also unused turbine and heat-rejection 

system capacity (condenser and cooling tower). This has been the motivation for this study, but

also for several of the other studies described below. Consequently, the results of this work are 

broadly applicable to other under-performing GBPPs. Future work will examine the potential to 

add solar thermal to a plant from the initial design, and strategies to accommodate large 

variations in heat input without proportionate increases in the cost of the turbines and heatrejection system of the base GBPP.

Economic and Technical Drivers for a Successful Hybrid Plant

One intrinsic limit to lowering the LCOE of geothermal binary power is physics. The Carnot 

efficiency describes how much of any energy source can be converted to electricity. The higher 

the maximum temperature of the system, the higher the percentage of energy that can be 

converted to electricity. In operating GBPPs, only 12%–15% of the incoming energy is typically 

converted to electricity. The same physics applied to the relatively high temperatures of 

concentrating solar thermal results in 30%, or more, of the energy being converted to electricity. 

Modern combined-cycle gas-turbine power plants with even higher temperatures can now 

achieve a 60% conversion of the available energy (on a low heating-value basis).
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Integrating solar thermal and geothermal has been proposed previously in other studies, pilot 

plants, and at least one commercial installation. One common approach of integrating solar 

thermal energy into existing geothermal projects is to heat either incoming or recycled injection 

brine to increase the temperature and/or flow rate of brine to the power plant. This approach 

results in an inefficient 15% conversion rate of the solar energy because the heat is converted in 

the geothermal plant. Because the GBPP conversion efficiency in only half that of conventional 

solar thermal, this approach effectively doubles the cost per unit power of the solar collector. The 

solar collector itself is the most expensive part of a solar thermal plant, so solar brine heating has 

seldom been found to be economical, unless there are extraordinary financial incentives.

A new thermodynamically favorable approach was investigated, seeking to marry the high 

efficiency of traditional CSP into a GBPP. The intent was to develop a hybrid plant that would 

provide a lower LCOE than either technology could alone, thus improving market-penetration 

opportunities for both technologies. The CSP was designed to produce high-temperature steam. 

A back-pressure turbine extracts power from the high-exergy fluid and is designed such that the 

exhaust steam vaporizes the binary cycle’s working fluid, thereby adding heat to the geothermal 

plant. 

The CSP retrofit study was undertaken for the Raft River plant, which operates at only about 

90% of the design inlet geothermal energy flow, and thus, was not making the contracted amount 

of power. However, the technology would be applicable to retrofit any existing under-performing 

geothermal binary power plant. 

Thermodynamic and Economic Evaluation Parameters

Geothermal–solar hybrid plants are typically evaluated using techno-economic analysis. A 

variety of metrics are available for evaluating the plants, as follows.

The solar-conversion efficiency, or incremental or marginal solar efficiency, may be used to 

compare different cycles. It measures how effective the hybrid configuration is at converting the 

additional thermal input (i.e., the solar energy added) into useful work (net power, which is the 

gross power minus the associated parasitic loads). Two main definitions exist and differ in the 

denominator. In one definition, the incremental solar energy added to the cycle is that which is 

actually collected and transferred to the main power cycle. The second is where the incremental 

solar energy is that which actually falls on the collector.

Thus, the first version of the incremental solar efficiency is defined as

ηηsol,1 = WẆ

net − WẆ

net

oo

QQ̇

add

(1)

where WẆ

net is the net work produced by the hybrid plant, WẆ

net

oo is the net work that would have 

been produced by the geothermal plant in isolation, and QQ̇

add is the thermal power added to the 

hybrid power cycle. It does not consider the efficiency of the production of that heat, e.g., the 

efficiency of the solar collector. It therefore indicates the effectiveness of the hybrid power cycle. 

ηηsol,1 may be used to compare the performance of different power systems proposed in the 

literature without considering differences in the solar-collection technology (including projectspecific choices of collector efficiency, or advances over time in solar-collector efficiency) or 
3

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differences in modeling of the solar field (which can be done to variable degrees of complexity).

This metric can also be useful for considering heat that may have been produced and added from 

any other source besides solar, such as industrial waste heat or a combustion turbine.

The second definition of solar conversion efficiency includes the efficiency of generating (or 

collecting) the heat, and for a solar–geothermal hybrid, it is defined as

ηηsol,2 = WẆ

net − WẆ

net

oo

QQ̇

sol

(2)

where QQ̇

sol is the total power incident on the solar collectors. This definition accounts for the 

optical and thermal efficiency of the solar field, and any other thermal losses that may occur in it. 

ηηsol,2 is a measure of the complete hybrid system and necessarily ηηsol,2 < ηηsol,1.

Another common measure of the overall plant performance is given by the first or second law 

efficiency, which accounts for the net power produced, and the total heat (or exergy) added to the 

system. Care must be taken when comparing values presented in the literature because different 

definitions of these efficiencies exist. For instance, when considering the exergy available in the 

geothermal stream, some authors use the available work that could be extracted if the geothermal 

fluids are taken to the dead state—i.e., to ambient temperature and pressure. (Of course, ambient 

temperature and pressure varies from study to study.) Other authors argue that geothermal fluids 

are typically re-injected at reasonably high temperatures and pressures to support the geothermal 

resource, and that the available work in the flow is the difference between the exergy of the 

production and injection fluids. However, this definition penalizes the performance of an 

“efficient” plant that extracts considerable heat from the available geothermal flow. Because of 

this variability in definition—and hence, in the calculated “efficiency”—this metric is not used in 

this study.

The LCOE is commonly used to evaluate many types of electric power plants, including the 

hybrid plants of this study. Several definitions exist, and the one used in this report uses the fixed 

charge rate (FCR) method described in section 3.5. The LCOE is defined differently if the 

proposed system involves retrofitting an existing geothermal plant or installing a full hybrid 

system in a greenfield installation. The retrofit analysis of this study assumes that the existing 

plant is a “sunk” cost and not relevant to the equipment additions being considered. Comparing 

the LCOE among different studies is problematic because of different methods and economic 

assumptions (e.g., lifetime, discount rate, overhead) used in the literature, but often the costs 

assigned to certain components (especially the solar field) can vary widely between research 

articles and over time. This is particularly relevant to hybrid system retrofits, where the total 

capital cost is dominated by the cost of the solar field. Solar-field costs have decreased rapidly in 

recent years, and the LCOEs reported in articles several years old could be high, and thus,

outdated. LCOEs are best used within one article, rather than comparing between research 

projects. A detailed review of assumptions and standardization to a single common set of 

parameters is required to compare LCOEs between research projects.

Description of Raft River Geothermal Power Plant

The Raft River geothermal power plant uses a dual-pressure-level binary cycle (organic Rankine 

cycle) and was designed and constructed by Ormat. The basic power cycle was described in
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detail in two previous publications [3], [4]. A high-pressure (HP) and low-pressure (LP) turbine 

are connected on either side of a common generator. Both sides are separated from each other 

and use isopentane as the working fluid. The heat-rejection system is a shell-and-tube condenser 

with a 4-cell cooling tower. Geothermal brine flows into the HP and LP vaporizers in series, and 

then the brine splits to feed the preheaters of both systems. The cooled brine is then injected into 

the geothermal reservoir. Figure 1 is a process flow diagram of Raft River plant, with selected 

state points in Table 1 and Table 2.

The plant began commercial operation in 2006 and has run at a high plant availability ever since. 

However, the reservoir was never able to provide sufficient flow to the plant; so, the output of 

the plant has been below the contract maximum. This reduced output was what drove the interest 

in the study of a solar thermal retrofit of the plant.

=

Figure 1. Raft River Geothermal Power Plant Process Flow Diagram. Key: CT: cooling tower; EV: 

evaporator; HPT: High-pressure turbine; LPT: Low-pressure turbine; PH: Preheater; CWP: Coldwater pump; PW: Production well; IW: Injection well; G: Generator; CP: Circulation pump.
5

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Table 1. Selected isopentane design state points on Figure 1 (SH = superheated)

State Description P, psia T, °F x

HP Isopentane Cycle

7 Condensate 13.0 67.80 0 (saturated)

4 Turbine inlet 138.7 236.35 1 (slight SH)

5 Turbine exhaust 13.0 144.31 1 (high SH)

LP Isopentane Cycle

e Condensate 12.7 66.90 0 (saturated)

c Turbine inlet 74.3 184.54 1 (slight SH)

d Turbine exhaust 12.7 118.74 1 (mod SH)

Table 2. Comparison of design and actual operating conditions and generation

State Description Design Point Current Op.

Geothermal Brine Flow, Klbs/hr T, °F Flow, Klbs/hr T, °F

A To Plant 3,150 280 2,700 272

H From Plant 3,150 150 2,700 145

Generation MWgross MWnet MWgross MWnet

Power Cycle, no brine pumps 15.9 13.7 13.8 ~11.7
6

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2 Screening and Review of Geothermal and Solar 

Thermal Hybrid Technologies

Several methods of integrating geothermal power and solar thermal power have been proposed, 

including but not limited to: using geothermal energy within a primarily solar thermal power 

plant, using solar thermal power in a geothermal steam power plant, and using solar thermal 

power in a binary geothermal power plant. This study evaluates the last option. The solar heat 

may be added in several ways, and potential locations are schematically illustrated in Figure 2. 

These options are discussed in more detail below.

Figure 2: A simplified geothermal binary cycle with potential solar heat addition locations noted. 

The solar heat can be added directly, or first drive a high-temperature topping steam turbine. If 

cooled brine is heated, this brine is then recirculated to mix with the production fluids.

Overview: Methods and Technologies Used for Adding Solar-Thermal 

to a GBPP

In general, previous examinations can be grouped such that the solar heat is added to one of three 

places in the GBPP:

1. Heating geothermal brine: Either increase the temperature of brine from the production 

wells before it gets to the GBPP, or take a stream of cooled/cooler brine and increase its 

temperature. The former raises temperature but not flow rate, whereas the latter increases 

flow rate and may or may not result in an increase in brine temperature compared to the 

no-solar condition.

Turbine

Condenser

Circ Pump

Cooling

Tower

Vaporizer Pre-Heater

Production Wells Injection Wells

Binary working fluid

Cooling water

Geothermal fluids

Legend

G

Potential solar heat location

Potential solar heat location 

(fluid must be recirculated).

Generator
7

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2. Superheating working-fluid vapor: Saturated or slightly superheated vapor is produced 

from the GBPP, and then the vapor on the way to the turbine is superheated significantly 

above saturation.

3. Increasing vapor flow to turbine: The solar heat is used to vaporize the GBPP working 

fluid, and the additional vapor is added to the flow of vapor from the geothermal brine 

heat exchangers.

Typically, two primary ways of collecting solar thermal heat and adding it to a GBPP are 

considered:

1. Directly heating fluids going to or within the GBPP with no additional turbines and 

generators. This generally results in solar thermal collection temperatures slightly higher 

than that of the GBPP.

2. Collecting the solar heat at a much higher operating temperature than the GBPP, and 

then, through additional turbine/generators, directly generating solar-thermal electricity. 

Heat from the exhaust of the solar-thermal turbine is used to heat one of the fluids in the 

GBPP.

It is also worth noting in the interest of fully describing the ranges of options for hybrid 

technology that there are various solar-collection technologies available. For instance, solar heat 

may be collected in parabolic troughs, linear Fresnel reflectors, or power towers. The heat is 

transferred to a working fluid, which may be a thermal oil, water/steam, or molten salts. In this 

application, it was decided that readily available conventional technology should be used that is 

commonly used in these relatively small solar-thermal collectors. This led to selecting a linear 

collector with a thermal oil heat-transfer fluid (HTF). In Section 3.5, various parabolic troughs 

and linear Fresnel reflectors are compared, with parabolic trough being chosen as the study basis. 

The selection of collector and heat-transfer medium would be revisited in a more detailed study.

Raft River Solar/Geothermal Hybrid Cycle Screening Evaluation

Funding for this study was provided with the specific intention of evaluating a hybrid cycle with 

a high-temperature (exergy) solar steam topping cycle to extract net electric power from the 

energy collected in the solar field—after which the steam would then be cascaded to add solar 

heat to the GBPP to fill the plant’s under-used turbine and heat-rejection system capacity. 

However, it was recognized that the proposed system was substantially more complex and 

expensive than some of the simple solar-heat addition cycles that had been studied and/or 

constructed. To get a feel for whether the project concept would yield a substantial improvement 

in economics, the initial work was a high-level screening evaluation at a single operating point 

using the HYSYS software package, calibrated to the original design process flow diagram 

(PFD).

Further details about the screening study methodology and results are provided in Appendix A. 

The configurations studied included brine preheating, recirculated brine heated directly by the 

solar field, and various configurations using a steam topping cycle where the exit flow heated 

either the brine or the binary-cycle working fluid. The results confirmed that the proposed cycle, 
8

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using topping steam turbines, delivered the best performance in terms of electrical power 

generation and solar efficiency. 

Description of Preferred Cycle

The screening study was a simplified comparison of cycle options, and it identified a system with 

a topping cycle as the most promising configuration—known here as Case 1. More detailed 

models were then developed and validated against operational data, and the underlying 

assumptions were refined. Exhaust heat from the steam turbines vaporizes GBPP working fluid 

(isopentane) to increase flow to the binary-cycle turbines. This is accomplished through a 

condenser/vaporizer (con/vap), which is a heat exchanger in which steam condenses on one side, 

which releases heat, and the isopentane is vaporized on the other side. Several variations on this 

cycle were considered: 

Case 1A: Two High-Pressure Steam Topping Turbines

The original concept for the study was to use the solar field to generate high-pressure, hightemperature steam. The steam would be converted to power using two steam topping turbines 

with a backpressure saturation temperature about 20°–30°F above the isopentane vaporization 

temperature. 

The Raft River binary cycle has two pressure levels, so adding solar thermal heat to both sides 

was expected. Thus, the topping cycle was initially laid out with two steam turbines with 

different condenser pressures to produce isopentane vapor at the two different turbine inlet 

pressures. This configuration is referred to as Case 1A and is illustrated in Figure 3. 

Case 1B: One High-Pressure Steam Topping Turbine with a Steam Crossover

When the cycle using two steam turbines was first analyzed, it was noted that little solar steam 

was used in the low-pressure (LP) con/vap. Consequently, an alternative option is to use a single 

steam turbine, referred to as Case 1B, shown in Figure 4

. The key variation of Case 1B from Case 1A is that instead of using a very small, dedicated 

turbine to provide the small steam load of the LP con/vap, only the steam turbine serving the HP 

side of the GBPP is used. Some of the steam from the HP turbine exhaust is crossed over to the 

serve the LP con/vap, with most of the turbine steam being used in the HP con/vap. This results 

in a small loss of efficiency, because the steam is throttled as it is dropped from the HP turbine 

exhaust to the LP con/vap. However, the amount of steam being crossed over is small, and the 

pressure loss is also small. Consequently, there is only a small reduction in the output of this 

option compared to the two-turbine option. 

Case 1C: One High-Pressure Steam Topping Turbine and Reduced GBPP HP Isopentane Vapor 

Flow

Late in the study, another variation was considered, which was to eliminate the LP con/vap and 

the steam crossover valve from the discharge of the HP steam turbine. Instead of adding solar 

energy to bring the LP turbine back to design output, less geothermal energy was extracted from 

the HP portion of the GBPP, allowing more geothermal energy to be extracted by the LP side of 
9

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the GBPP. There are at least two ways to accomplish this: reduce the flow of isopentane to the 

HP vaporizer, or use the HP vaporizer brine bypass line to reduce the amount of geothermal 

energy flowing into the HP vaporizer. A schematic diagram is presented in Figure 5.

Figure 3. Case 1A—Process flow diagram of the hybrid solar–geothermal system with two steam 

turbines.

G

G

Solar Boiler Pump

Solar Collector

Solar Steam Turbine

HP pre-heater HP Vaporizer

LP pre-heater LP Vaporizer

HP Turbine LP Turbine

LP Condenser

HP Condenser Circ Pump

Cooling

Tower

HP Pre-Heater

LP Pre-Heater

HP Vaporizer LP Vaporizer

Production Wells Injection Wells

Existing 

Binary 

Power 

plant

New 

Solar 

Topping 

Cycle

HP Isopentane

LP Isopentane

Cooling water

Steam

Geothermal fluids

Solar heat transfer fluid

Legend

Economiser Boiler Bypass for low solar / 

excess solar
10

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Figure 4. Case 1B—Process flow diagram of the hybrid solar–geothermal system with one steam 

turbine. Steam turbine exit flow heats both the HP and LP working-fluid cycles.
11

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Figure 5. Case 1C—Process flow diagram of the hybrid solar–geothermal system with one steam 

turbine. Steam turbine exit flow heats only the HP working-fluid cycles.

Literature Review

Previous research has investigated hybrid systems using binary plants and single-/double-flash 

plants, and numerous methods for integrating the two systems have been proposed. The most 

suitable hybridization scheme is unique to each plant, depending on the geothermal fluid 

properties, the solar resource, and whether the plant is a new development or a retrofit of an 

existing system. Methods of hybridization can be broadly categorized as follows:

1. The geothermal system provides feedwater heating to a solar-driven power cycle [5], [6].

2. Solar heat is added to the geothermal fluids at some point in the cycle [1], [7]–[13].

3. Solar heat is used to vaporize and/or superheat the power-cycle working fluid [14]–[17].

4. Solar heat drives a topping cycle, with heat rejected into the bottoming geothermal cycle 

[18], [19].

G

G

Solar Boiler Pump

Solar Collector

Solar Steam Turbine

HP pre-heater HP Vaporizer

HP Turbine LP Turbine

LP Condenser

HP Condenser Circ Pump

Cooling

Tower

HP Pre-Heater

LP Pre-Heater

HP Vaporizer LP Vaporizer

Production Wells Injection Wells

Existing 

Binary 

Power 

plant

New 

Solar 

Topping 

Cycle

HP Isopentane

LP Isopentane

Cooling water

Steam

Geothermal fluids

Solar heat transfer fluid

Legend

Bypass for low solar / 

excess solar

Economiser Boiler
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Comparing results between studies is challenging because technical assumptions and economic 

parameters can vary widely. In the literature review that follows, most of the reported LCOEs are

typically too high to be commercially viable. However, the approach may still have merit for 

various reasons, including different economic assumptions, and better and cheaper solarcollector systems. For instance, previous studies typically assume collector costs around 250–

300 $/m2, whereas more recent estimates are closer to 150 $/m2.

Geothermal Heat Integration into a CSP Plant

One of the first hybrid plants was proposed in 1979 and used geothermal heat for feedwater 

heating and solar heat to generate steam for a steam turbine [6]. At the time, these hybrid plants 

demonstrated no economic advantages over stand-alone geothermal plants. However, CSP prices 

have dropped significantly and it is appropriate to reconsider this technology. More recently,

Turchi et al. [5] also considered a similar system that reportedly converted geothermal energy to 

electricity at an efficiency 1.7 to 2.5 times greater than would have occurred in a stand-alone 

geothermal binary power plant. Thermodynamically, this is good use of geothermal energy 

because the available energy is “upgraded” with more temperature to increase the efficiency of 

conversion. Furthermore, it is a relatively simple configuration and could reduce costs if 

inexpensive geothermal wells can be drilled near the CSP plant. However, geothermal heat is 

only used to heat the water going to the CSP boiler, whereas generating steam for the CSP plant 

requires significantly larger quantities of energy. Hence, the reduction in solar-collector cost 

resulting from the geothermal preheater is small and may not significantly change the economics 

of the CSP plant.

Solar Integration Geothermal Power Plants by Direct Brine Heating

The first commercial-scale geothermal–solar hybrid plant was developed at the Stillwater Power 

Plant, Nevada, and began operation in 2015. A solar field of parabolic trough collectors supplies 

17 MWth of thermal power to the 33 MWe geothermal power plant and augments production by 2 

MWe [20]. Note that the incremental solar efficiency is 2/17 = 11.8%, which is lower than the 

results from the screening study and could be due to a variety of factors, including that the 

screening study did not sufficiently account for the parasitic loads of the solar field. The plant 

also includes a 26-MWe PV solar array, which offsets the decrease in power generation that 

occurs at high ambient temperatures [21]. 

Operators of the 13.2-MWe Gümüşköy geothermal binary plant in Turkey aimed to reduce the 

detrimental impact of high ambient temperatures by using solar heat to augment generation [22]. 

Tests were conducted with a 200-kWth array of parabolic trough collectors in 2014.

Solar Integration by Heating Working Fluid in a Geothermal Binary Power Cycle

Research articles that investigated hybridizing binary cycles with solar initially concentrated on 

using the solar heat to vaporize (and sometimes superheat) the organic Rankine cycle (ORC)

working fluid. Manente et al. [23] proposed such a hybrid cycle that could overcome variations 

in the geothermal fluid flow rate and temperature, and the effect of ambient temperatures. They 

also included thermal storage in the model and demonstrated that this could increase the quantity 
13

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of energy generated. An LCOE analysis gave the cost of the retrofit system as 0.18–0.19 $/kWhe. 

This high cost is heavily influenced by an expensive solar field at 300 $/m2. 

Although Manente et al. did not evaluate the solar conversion efficiencies, a similar hybrid 

system was investigated by Astolfi et al. [16], where solar heat vaporized the ORC working 

fluid. (Note that Astolfi et al. studied a supercritical cycle, whereas Manente et al. investigated a 

subcritical cycle.) Astolfi et al. achieved solar conversion efficiencies of ηηsol,1 = 15.1%–16.8% 

and ηηsol,2 = 8.6%–9.4%. (This indicates that the overall efficiency of the solar collectors was 

56%–57%.) This proposed system is also a retrofit, and as such, it faces technical challenges 

because the turbine inlet temperature of the hybrid plant is 200°C, compared to 150°C in the 

original plant design. The authors considered several locations for the hybrid plant in California 

and Italy, and they evaluated the LCOE to be 0.145–0.280 euro/kWhe (0.22–0.43 $/kWhe) for a 

solar-field cost of 175 euro/m2 (268 $/m2).

Ghasemi et al. [14] and Ayub et al. [15] considered a slightly different approach to vaporizing 

the ORC working fluid. Rather than using the geothermal fluid to preheat the working fluid and 

the solar heat to vaporize it, the working fluid is preheated by the brine and then split into two 

streams. One stream is vaporized by the geothermal fluid and the other by the solar heat. The 

maximum solar efficiency achieved was ηηsol,2 = 7.8%. The LCOE of a new-build hybrid plant 

was 0.066 $/kWhe, compared to a stand-alone geothermal plant LCOE of 0.065 $/kWhe. 

Zhou et al. [19] also considered a system similar to those proposed above and improved the 

design by introducing a topping cycle. The binary-cycle working fluid was superheated by the 

solar collectors and then expanded through an additional turbine. The turbine outlet provided 

heat to the bottoming-cycle recuperators. The LCOE of a greenfield design was found to be 0.17 

$/kWhe with a solar-collector cost of 250 $/m2

. This was compared to stand-alone CSP systems 

and an enhanced geothermal power plant, which were 0.113–0.156 $/kWhe and 0.225 $/kWhe, 

respectively. If a retrofit was feasible (that is, only the solar plant required construction), then the 

LCOE decreased to 0.10 $/kWhe. 

Bonyadi et al. [18] also investigated retrofitting a geothermal plant with a solar-driven topping 

Rankine cycle. In the proposed system, the steam-turbine exit flow is used to heat up a fraction 

of cooled geothermal brine from the GBPP. The reheated brine is then added to the production 

fluids, thereby increasing the mass flow rate of brine through the geothermal plant, and 

increasing the power output, similar to case 3A in the screening study in Appendix A. The 

authors also described a system whereby the geothermal fluid mass flow rate could be kept 

constant. Because brine is recirculated, the rate of fluid extraction from the reservoir is reduced, 

which they report can increase the reservoir lifetime. This system had a solar conversion 

efficiency of ηηsol,2 = 12.2% and an LCOE of 0.163 $/kWhe assuming a solar-field cost of 250 

$/m2

. Furthermore, the geothermal fluid extraction over a year was reduced 17.1%.

Another option for an integrated cycle meant to take advantage of high temperatures—and the 

efficiency they engender—was proposed by Zhou [17]. In the study, subcritical and supercritical 

binary cycles were designed with the geothermal fluid heating the working fluid up to around 

150°C and the solar system increasing the temperature up to 400°C. Zhou noted that the heat 

addition was more effective in supercritical cycles, which were therefore able to attain higher 

temperatures. The author considered designs with various sizes of solar field and found that 
14

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larger fields led to higher solar conversion efficiencies: up to ηηsol,2 = 14.4%. Zhou calculated the 

LCOE if the solar field was added as a retrofit, with costs as low as 0.10 $/kWhe. 

Sizing of the Solar Field and the Use of Thermal Storage

The above research articles provide a detailed overview of hybrid plant configurations, 

efficiencies, and costs reported in the literature. However, most papers seemed to size the solar 

field to provide the design quantity of heat at optimal solar conditions (normally 950 or 1,000 

W/m2). This means that for the majority of the year, the power plant operates at less-efficient, 

off-design solar heat input conditions. In conventional CSP plants, the solar field is typically 

oversized so that the plant can operate close to its design point for a greater portion of the year. 

However, if too much solar energy is available, this power has to be curtailed through defocusing 

of the mirrors or stored if sufficient thermal energy storage (TES) is available. These proven 

techniques in the CSP industry are not widely presented in the geothermal–solar hybrid 

literature.

An evaluation of oversized fields and storage was investigated in a previous paper by Bassetti et 

al. [13]. They demonstrated that these methods could increase the total electricity dispatched by 

the system by 5%–6%. However, the authors did not undertake a comprehensive survey of 

different storage and solar-field sizes; nor was an economic analysis presented. 

In section 4, oversized fields are evaluated, as well as the use of thermal storage. Both are 

evaluated on their ability to increase annual generation, but also, on the effect on the hybrid 

LCOE. It is found that oversized solar fields and TES both reduce the cost of the hybrid plant. 

This is a valuable approach to use in future geothermal–solar hybrid studies.

3 Modeling Methodology

The geothermal binary power plant was modelled with the flow-sheeting software IPSEpro. The 

additional heat integration from the solar field was also included in this model. The model was 

used to develop regression equations of hybrid plant performance with solar heat input and 

ambient temperature. The performance of the solar collector field was evaluated using the 

System Advisor Model (SAM). This model calculated hourly ambient temperatures and solar 

thermal heat available to the hybrid plant. The output of these two models were combined in an 

Excel spreadsheet and the hybrid plant performance was calculated for every hour of the year. 

Figure 6 gives a schematic representation of the various tools used in the modeling work. The 

influence of various solar field sizes and thermal storage durations was also investigated. The 

annual calculations were then used to evaluate the levelized cost of electricity.
15

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Figure 6: Analysis tools and flow of data for evaluation of hybrid plant performance.

Modeling of the original Raft River GBPP with IPSEpro 

SimTech IPSEpro Process Simulation Environment version 7.0 U, Release 12, Build 1744 

software was used to model the performance of the Raft River geothermal power plant—both 

with and without the addition of the solar topping cycle. Process flow diagrams of the Raft River

power plant obtained from US Geothermal provided the mass and energy balance data used to 

develop the ORC power-block model. The Raft River design-point PFD was used to establish 

equipment sizing parameters and design-point process operating conditions and performance. 

The Raft River off-design PFDs were used along with additional equipment performancespecification data to adjust the model input parameters to accurately simulate off-design process 

performance.

The Raft River ORC power plant comprises two turbines with a shared generator configured to 

extract heat from a common geothermal brine feed stream using preheaters and vaporizers. Both 

turbines use isopentane working fluid, with the L1 unit having a higher turbine inlet pressure 

than the L2 unit. The L1 unit includes a recuperator at the discharge of the turbine to capture 

isopentane superheat, whereas the L2 unit does not. The separate L1 and L2 condensers are 

water-cooled.

The Raft River ORC cycle model incorporates sub-models of major process equipment including 

the working-fluid preheaters, vaporizers, condensers, L1 recuperator, ORC turbine-generator set, 

evaporative cooling tower, working-fluid feed pumps, control valves, and all associated piping. 

The majority of the equipment sizing parameters required to simulate the Raft River ORC 

performance can be determined from the PFD state point data. One exception to this is the 

cooling tower, which has an ambient-temperature design point that varies from that of the 

remainder of the power block. Separate cooling-tower design and off-design data were used to 

SAM IPSEpro

Excel

Aspen

Literature

Industry

Economic 

correlations

Off-design 

performance 

correlations

Solar heat

Ambient temp.

Location

TMY3 data Hybrid plant layout

Hourly power output

Hourly efficiency

LCOE
16

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specify the parameters required for the cooling-tower model, which uses the Merkel method to 

predict cooling duty as a function of the wet-bulb temperature and fluid flow rates.

Off-design heat-exchanger performance is determined by correcting the design UA (product of 

the heat-transfer area and overall heat-transfer coefficient) as predicted by the appropriate heattransfer correlations, e.g., shell-and-tube heat-exchanger tube-side heat-transfer coefficients 

modeled as proportional to Nu0.8 [24], whereas the shell-side heat-transfer coefficients are 

modeled as proportional to Nu0.6 [25]. Rotating-equipment design-point efficiency was 

calculated from power input/output and stream data, and representative rotating-equipment 

performance curves from equipment manufacturers were used to estimate off-design 

performance. Finally, pressure loss in heat exchangers and process piping was adjusted for offdesign conditions by adjusting the pressure drop in proportion to the square of the fluid velocity 

in accordance with the Darcy-Weisbach equation.

Prior to incorporating the solar topping cycle into the power-plant model, the ORC model 

predictions were compared with actual power-plant operating data to verify the ability of the 

model to accurately predict plant performance. Power-plant operating data obtained from US 

Geothermal was filtered to include points with brine mass flow rate within ±100 kph and brine 

inlet temperature within ±2°F of typical current conditions. Additionally, the simulation data 

were adjusted to include typical values for parasitic loads that are not included in the flowsheet. 

Initial comparison of the IPSEpro model and Raft River gross and net power data indicated that 

the IPSEpro model was under-predicting power generation. The L1 and L2 ORC turbine designpoint efficiencies were subsequently adjusted until the model predictions matched the operating 

data. Although the revised turbine efficiency specifications resulted in a better match between 

the model off-design power-generation predictions and the power-plant operating data, this 

modification resulted in the model’s design-point power calculation being more than 1 MW 

higher at design conditions than that specified in the Raft River PFDs. However, because the 

objective of this study was to compare cycle options, rather than specify an actual design for the 

Raft River GBPP, this discrepancy was not important. Other options to calibrate the model to the 

performance would include geothermal heat-exchanger fouling factors, and the original 

performance test output compared with the guarantee-point PFDs. Such an approach could result 

in a model with power-generation predictions matching the Raft River design-point PFD as well 

as the off-design power-plant operating data.

The gross and net power predicted by the off-design Raft River IPSEpro model are plotted with 

power-plant operating data as a function of wet-bulb ambient temperature in Figure 7 and Figure 

8, respectively. Figure 7 and Figure 8 present gross and net power on a fractional basis, where a 

value of 1.0 corresponds to the design-point value. The power-plant data do not cover the full 

range of wet-bulb temperatures necessary to predict performance over the course of a full oneyear period. But the figures indicate that the model adequately predicts plant performance over 

the available range of wet-bulb temperature data.
17

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Figure 7. Comparison of gross power reported in Raft River plant operating data with predicted 

values.

Figure 8. Comparison of net power reported in Raft River plant operating data with predicted 

values.

Addition of Solar Heat to the Raft River GBPP in IPSEpro 

Following verification of the model’s ability to adequately predict gross and net power output of 

the GBPP, the solar topping cycle was added to establish the integrated hybrid-plant model. As 

with the GBPP model, the solar topping cycle was developed with the ability to model design 

and off-design operating conditions. The GBPP model input parameters were specified to 

provide the best match with existing plant-design and operating data; but the solar topping cycle 

design configuration and input parameters were chosen at the discretion of the project team, with 

the overall goals of maximizing power output and minimizing capital costs for additional topping 

cycle equipment. Key solar topping-cycle design configuration and input parameters include:

40%

50%

60%

70%

80%

90%

100%

35 40 45 50 55 60 65

Percent of Design Pt Gross Power

Wet Bulb T [°F]

plant operating data

simulation

Design Point

40%

50%

60%

70%

80%

90%

100%

35 40 45 50 55 60 65

Percent of Design Pt Net Power

Wet Bulb T [°F]

plant operating data

simulation

Design Point
18

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• Steam Rankine-cycle heat input is obtained via heat exchange with a heat-transfer oil that 

is circulated through the solar field. 

• Specification of 700°F and 1,200 psia steam at exit of superheater.

• Turbine design isentropic efficiency of 75% specified based on personal communication 

with steam-turbine manufacturer.

• Minimum internal temperature approach of 5°F specified in steam condenser (ORC 

secondary working-fluid vaporizer); this specification is a primary factor in defining the 

size of the heat exchanger (or UA in the power-plant model).

• Total steam-cycle pressure drop of ~100 psi assumed to account for losses in heat 

exchangers (economizer, boiler, superheater, and condenser), control valves, and piping.

In addition to the 1,200 psia steam-turbine design inlet pressure, a design inlet pressure of 700 

psia was also evaluated, both at 700°F. Although the 1,200 psia design requires equipment and 

piping with higher pressure ratings, it has numerous performance advantages, such as greater 

enthalpy drop across the turbine and lower-quality exhaust steam. These contribute to greater 

power generation in the steam topping cycle than with a design turbine inlet pressure of 700 psia. 

Annual calculations performed with an identically sized solar field indicated that a 1,200-psia

topping-cycle design pressure provided greater net output and greater marginal solar efficiency 

than the 700-psia design. However, it remains possible that a lower inlet pressure may be 

preferential for one of the following reasons:

• Contract pricing of the geothermal power vs the solar-derived power.

• Availability factors of GBPP and solar field (percentage of time able to operate when fuel 

is present).

• Location and quality of solar resource.

• The higher exhaust enthalpy reduces the size of the solar collector, which is the most 

expensive component of the retrofit.

• The lower pressure rating results in significantly cheaper power-plant equipment: piping, 

vessels, and turbines.

• Direct-steam-generation solar collectors are used, and there is a significant difference in 

the resulting collector cost.

• The isentropic efficiency of the turbine improves with lower pressure and/or the type of 

turbine that can be used is much less expensive.

• The methods, goals, and costs of thermal storage favor one or the other option.

In summary, the selection of 1,200 psia does not represent an optimized evaluation, but it was a 

reasonable decision that allowed the rest of the analysis to proceed.

Off-Design Steam-Turbine Modeling

Unlike many conventional power-plant steam turbines, a steam turbine on a solar field will 

operate significantly off-design over a large percentage of total annual operating hours. The 

reasons include, but are not limited to:
19

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• The overall goal of maximizing generation on the solar energy that is available.

• Daily startup and shutdown at sunrise and sunset.

• Cloudy periods in which solar irradiance is diminished.

• Winter, when solar irradiation is lower even on a clear day.

• Bright clear days on which solar irradiance exceeds the design point of 950 W/m2.

Off-design behavior of the steam turbine is modeled using Stodola’s ellipse, which relates the 

mass flow rate and the inlet and outlet pressures through [26]:

( ) ( )

1/2 2

01 01 0 01 / 1/ mT p k p p e = −      . (3)

Here, mṁ is the mass flow rate, T01 is the inlet temperature, p01 is the inlet pressure, p0e is the 

outlet pressure, and k is a constant of proportionality. Assuming that k is constant for all cases, 

off-design performance may be related to design performance with the following equation [27]:

( )

( )

1/2 2

0 01 01 01 , ref

1/2 2 ref 01 , ref 01

0 , ref 01 , ref

1 /

1 /

e

e

p p m T p

mT p p p

    −     =       −    



 . (4)

A variety of physical mechanisms lead to entropy generation in the steam turbine, as described in 

[28]. 

Steam turbines may be operated with “sliding pressure” control or “throttling” control. In 

sliding-pressure control, the turbine “reacts” to the operating point set by the rest of the system. 

For instance, the outlet pressure may be fixed by the condenser pressure. The inlet pressure then 

“floats” in response to variations in the system mass flow rate, in accordance with Stodola’s 

ellipse. Throttling control can be considered as a valve before the turbine inlet. The mass flow 

rate and inlet and outlet pressures are still related by Stodola’s ellipse. However, the throttle is 

used to select an inlet pressure that allows the required mass flow rate to be passed through the 

turbine. This requires the fluid pressure before the valve to be sufficiently high and leads to 

significant losses.

Having related the inlet and outlet quantities with Stodola’s ellipse, the off-design efficiency is 

then evaluated with a correlation, such as that provided in Bahadori [29]. Data were also 

obtained from a turbine manufacturer (Altas CopCo), and off-design results for a back-pressure 

steam turbine are shown in Figure 9. An estimate of the isentropic efficiency at the design point 

is also required, and discussions and calculations with Atlas CopCo suggested a value of 75%. 

There is some deviation between the manufacturer’s curve and Bahadori’s correlation, 

particularly at low mass flow rates. The reason for this difference is unclear but may be because 

the two turbines under consideration are not equivalent. For example, it is likely that Bahadori 

was using an axial-flow turbine, whereas the Atlas-Copco machine is a radial-inflow turboexpander. Also, the mode of operating the turbines may contribute to differences in the 

efficiency (e.g., sliding pressure vs. fixed inlet pressure), as well as where the inlet condition was 
20

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measured (e.g., upstream or downstream of the turbine inlet control valve on an axial-flow 

turbine.)

Figure 9. Off-design performance of back-pressure steam turbines. Curves are the relative 

efficiency compared to the design point. Data from Bahadori et al. [29] and Atlas CopCo.

Determination of Plant Performance for a Typical Meteorological Year

To fully assess the benefits of geo-solar hybridization of the Raft River geothermal plant, a 

determination of the amount of total additional annual power generation that would result from 

hybridization was necessary. This required estimation of the annual power generation for both 

the unmodified Raft River plant and the proposed Raft River hybrid power plant assuming 

identical geothermal resource and ambient-condition data. Power-plant performance for the 

unmodified and hybrid plants was characterized by using multiple linear-regression to establish 

correlations that predict net power output as functions of wet-bulb temperature and solar heat 

input (hybrid plant only). The hybrid-plant net power-generation data regression is shown in 

Figure 10.

0

20

40

60

80

100

120

0.0 0.5 1.0 1.5

Percentage change in efficiency, %

Fractional change in mass flow

Bahadori

Atlas Copco
21

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Figure 10. Multiple linear-regression model of hybrid plant net power generation as function of 

wet-bulb temperature for varying solar-field thermal output. IPSEpro model output is included as 

discrete points while the regression function output is depicted as curved lines.

Geographic site-specific typical meteorological year (TMY) data from the System Advisor 

Model (SAM) was used to provide hourly wet-bulb temperature data. TMY data provide solar 

input conditions based on expected normal hourly variations (not long-term averages) in key 

parameters (e.g., solar insolation, ambient temperature, wind speed). Additionally, SAM was 

used to simulate the solar-field operation and provide hourly solar-field heat-output estimates 

based on TMY data. The regression functions were then used to predict hourly power-plant net 

output from the wet-bulb temperature and solar-field heat-output data. Summation of the hourly 

power-generation data (minus hourly solar-field parasitic loads) provided an estimate of the 

annual net power generation for both the unmodified and hybrid power plants.

Having calculated the annual net power generation, this value is multiplied by a capacity factor 

of 95% to represent maintenance or downtime. Following correspondence with the Raft River 

geothermal plant, this value is deemed to be conservative, with actual capacity factors being 

98%–99%.

Solar-Field Modeling with SAM 

Annual thermal output of the solar field is generated using NREL’s System Advisor Model 

(SAM) [30]. The Physical Parabolic Trough Model in SAM is used in all parabolic trough 

collector (PTC) simulations and the Molten-Salt Linear Fresnel Model is used for linear Fresnel 

0

5

10

15

20

25

0 20 40 60 80

Net Power (MWe)

Wet Bulb T (°F)

25 MWt Qsolar

15 MWt Qsolar

5 MWt Qsolar

0 MWt Qsolar

25 MWt Qsolar

15 MWt Qsolar

5 MWt Qsolar

0 MWt Qsolar
22

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collector (LFC) simulations. In both models, Therminol VP-1 oil is used as the HTF and the 

solar-field design outlet temperature is set to 391°C. The efficiency and cost of several different 

commercially available solar collectors—four PTCs and two LFCs—were compared. Collector 

cost estimates and performance characteristics were obtained from a prior vendor survey 

conducted by NREL and are summarized in Table 3. High and low estimates represent 

variability in estimated raw material and labor costs.

Table 3. Collector specifications for PTCs and LFCs

Collector PTC 1 PTC 2 PTC 3 PTC 4 LFC 1 LFC 2

Geometric concentration ratio 26 24 25 24 25 55

ηηoo,dddddddddddd 0.79 0.76 0.77 0.74 0.635 0.68

Estimated installed low $/m2 285 190 248 210 220 210

Estimated installed high $/m2 325 245 293 255 265 255

To compare the different collector technologies, initial SAM simulations use Burley, ID TMY3 

solar resource data from the National Solar Radiation Data Base (NSRDB) [31]. The solar field 

is initially sized with a solar multiple equal to one, such that the thermal output of the field is 50 

MWth under design-point conditions. The solar multiple of a field can be increased so that the 

size of the field is increased proportional to the solar multiple, and the desired thermal output of 

the field is reached even at off-design-point conditions. This may be advantageous with the 

addition of thermal storage, or other heat-sink possibilities that exist in the geothermal plant. The 

individual loop size and control system of the model is altered such that no defocusing of the 

solar field occurs, under the assumption that thermal energy production that exceeds the turbine’s 

limitations can bypass the solar-field turbine and be used elsewhere in the geothermal plant or 

storage. The mass flow rate of the HTF is allowed to vary in order to reach the desired solar-field 

outlet temperature of 391°C during varying solar resource, which is the common method of 

control in CSP plants. There is assumed to be no thermal energy storage (TES) for initial 

simulations. Orientation is varied between North-South (N-S) and East-West (E-W). Solar-field 

size, TES, solar multiple, location, and orientation are all varied in later sections. A sample 

thermal output profile can be seen in Figure 11.

Figure 11. Solar-field thermal power produced for PTC 2 from SAM for a 50-MW solar field with N-S 

orientation.
23

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The levelized cost of heat (LCOH) is used as a metric to select a collector for further analysis in

the hybrid plant simulations. The LCOH is the cost that would have to be paid by a user of the 

heat for every MWhth that the collectors deliver over the lifetime of the collectors (typically 30 

years). The LCOH is calculated with the FCR method, which is described (along with economic 

assumptions) in more detail in section 3.6. The LCOH is given by 

cap

SF

FCR

LCOH = 

C M

Q

+ , (5)

where Ccap is the capital expenditures of the project, FCR is the fixed-charge rate, M is the 

operations and maintenance (O&M) cost, and QSF is the annual thermal energy produced by the 

solar field. More details of the FCR method can be found in SAM’s documentation [30]. 

Results of the initial solar-field simulations can be found in Table 4 and Figure 12. Under current 

assumptions, PTC 2 with a N-S orientation generates the lowest LCOH of the analyzed solarfield collector technologies and is selected as the collector to be further analyzed with the hybrid 

system. 

The orientation of the solar field for PTC 2 collectors is compared in Figure 13. The E-W 

orientation results in a higher LCOH due to lower annual energy production relative to N-S 

orientation. But the E-W orientation produces a more consistent production profile over the 

course of the year, which may be desirable. The thermal output may then be coupled with the 

IPSEpro power-plant model to analyze the performance and economic characteristics of the 

hybrid plant.

Table 4. Annual simulation results for N-S oriented collectors

Collector PTC 1 PTC 2 PTC 3 PTC 4 LFC 1 LFC 2

Annual optical efficiency % 56 53 53 55 38 41

Annual thermal efficiency % 85 82 83 80 84 90

Total annual efficiency % 48 43 44 44 34 37

LCOH low estimate ¢/kWhth 3.5 2.8 3.4 3.0 4.0 3.6
24

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Figure 12. LCOH for various solar collectors.

Figure 13. Solar-field thermal power output for PTC 2 comparing collector orientation during a) 

summer day and b) winter day.

Economic Modeling

The economic evaluation considers the costs of the additional equipment required to retrofit the 

Raft River GBPP with a solar heat input. It is assumed that any expenses incurred in modifying

the ORC piping, instrumentation, etc. due to solar hybridization is included in the costs of 

installing the hybrid-plant retrofit equipment.

The capital cost estimate for the solar topping-cycle power block includes major equipment 

items such as heat exchangers, pumps, and turbines. The steam topping-cycle hybrid-plant 

configuration uses three heat exchangers for transferring heat from the solar-field HTF to the 

water in the steam Rankine cycle; these include an economizer, vaporizer, and superheater to 

generate superheated steam from the subcooled boiler feedwater. Additionally, two condensers 

transfer the thermal energy from the steam-condensation process to the L1 and L2 ORC working 

fluid. Cases with one and two steam turbines are evaluated; in the single-turbine case, the 

PTC 1 PTC 2 PTC 3 PTC 4 LFC 1 LFC 2

0

1

2

3

4

5

6

y - LCOH (Cents/kWh)

N-S Low N-S High E-W Low E-W High

5 10 15 20

x - Time (hours)

0

10

20

30

40

50

60

y - Thermal Power Produced (MW th )

N-S

E-W

5 10 15 20

x - Time (hours)

0

10

20

30

40

50

60

y - Thermal Power Produced (MW th )

N-S

E-W

a. Summer Day b. Winter Day
25

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exhaust flow is distributed to both condensers whereas in the dual-turbine case there is a separate 

turbine–condenser pairing associated with each of the L1 and L2 ORC units.

The brine preheating hybrid-plant configuration requires the addition of less equipment to the 

existing ORC than the solar topping cycle. In the brine-preheating configuration, the additional 

major equipment is limited to the heat exchanger used to transfer heat from the solar-field HTF 

to the brine upstream of the power block. 

Aspen Process Economic Analyzer V10 (1st Qtr 2016 pricing basis) was used to determine the 

capital costs for the heat exchangers and pumps. The heat-exchanger capital costs were 

determined by inputting the design-point mass and energy balances from the IPSEpro hybridplant model into Aspen Exchanger Design and Rating V10 software. Results from Aspen 

Exchanger Design and Rating “design (sizing)” simulations were transferred to Aspen Process 

Economic Analyzer to obtain equipment costs as well as total installed costs. The capital costs of 

the boiler feedwater pumps in the solar topping cycle were also determined using Aspen Process 

Economic Analyzer with the flow rate and fluid head data obtained from the IPSEpro hybridplant design-point simulation used as the basis for the pump cost estimates.

The steam topping-cycle turbine costs were based on equipment cost quotations provided by a 

steam-turbine manufacturer. The pricing data were specific to the single-turbine case. For the 

dual-turbine case, installed equipment costs of 500 $/kW for the L1 turbine-generator and 1,100 

$/kW for the L2 turbine-generator were estimated based on values presented in the Combined 

Heat and Power Technology Fact Sheet Series [32] (DOE, 2016). Based on this costing 

approach, the turbine-generator installed capital cost for the dual-turbine configuration is 34% 

greater than that of the single-turbine configuration despite the similar gross power-generation 

capacity of the single and dual steam-turbine topping-cycle configurations. Steam turbine O&M 

costs are assumed at 0.01 $/kWh (DOE, 2016).

Based on recent developments in solar-collector design and manufacture, the solar-collector cost 

is assumed to be 125 $/m2

. The installation of the solar field also requires site improvements (20

$/m2) and a HTF, including piping and pumps (40 $/m2). The annual operating cost associated 

with the solar field is 8 $/kWth. Sensitivity to the solar-field cost is investigated in section 4.6.

Design-point additional power generation, installed capital costs, and installed capital costs per 

unit net power generation for the brine-preheating, dual-turbine topping-cycle, and single-turbine 

topping-cycle hybrid-plant configurations are provided in Table 5. Table 16 in Appendix B 

includes a detailed listing of individual equipment component sizes and capital costs.

Note the significant reduction in capital cost per unit power when a steam turbine is included in 

the hybrid plant. Despite the larger amount of equipment needed for the topping turbine, the 

installed cost is cut by 40% over the brine-preheating option.
26

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Table 5. Installed capital costs for brine-preheating, dual-turbine topping-cycle, and single-turbine 

topping-cycle hybrid-plant configurations

Hybrid-Plant 

Configuration

Design-Point Additional 

Power (kWe)

Installed Capital 

Costs ($)

Installed Capital 

Costs* ($/kWe)

Brine preheating 3,080 7,998,400 2,596

Solar-steam topping 

cycle (dual turbines) 8,146 12,688,700 1,557

Solar-steam topping 

cycle (single turbine) 7,910 11,862,300 1,499

* at hybrid-plant design conditions

Levelized Cost of Electricity

The levelized cost of electricity is the cost that, if assigned to every unit of electrical energy 

produced over the lifetime of the plant, will equal the total life-cycle costs when both are 

discounted back to the current year [33]. The total life-cycle costs include capital costs and O&M 

costs. In the case of the hybrid plant where the power block and geothermal wells already exist, 

the annual electrical energy generated by the solar equipment addition is the marginal increase in 

electrical energy above the base rate provided by the geothermal plant. Similarly, the LCOE is 

also computed based on the annual solar power generation (assumed the same in all years) and 

the CAPEX/OPEX associated with the addition of the hybrid-plant equipment. The costs and 

power generation of the existing Raft River GBPP are not included in the LCOE calculation.

The LCOE is calculated using the fixed-charge rate method, where

capFCR

LCOE = 

C M

E

+ , (6)

where Ccap is the capital cost, M is the annual O&M cost, E is the annual electricity generation, 

and FCR is the fixed-charge rate. FCR is defined as the revenue per unit of investment that must 

be collected annually to pay for the carrying charges of the investment. Details of how to 

calculate the FCR may be found in [33].

FCR PFF CRF = ( ) ( ) , (7)

where PFF is the project financing factor and CRF is the capital recovery factor. PFF is given by

1 PVDEP ( ) PFF

1

T

T

− = − , (8)

where T is the tax rate and PVDEP is the present value of depreciation, which is given by

0 ( ) ( )

PVDEP

1 WACC 1

N

j

j j

j

D

= i = + + ∑ , (9)
27

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where Dj is the depreciation rate in year j, i is the inflation rate, and WACC is the weightedaverage cost of capital, given by

1 1 1 RROE 1 1 1 1 RINT 1 1 ( )(( )( ) ) ( )(( )( ) ) WACC 1

1

d i dT i

i

+− + +−+ − + +− = − + , (10)

where d is the project debt fraction and RROE is the real return on investment, given by

1 IRR RROE 1

1 i

+ = − + , (11)

where IRR is the internal rate of return and RINT is the real debt interest rate, given by

1 NINT RINT 1

1 i

+ = − + , (12)

where NINT is the nominal debt interest rate. The CRF is given by

WACC CRF

1 1

1 WACC

N =

  −    + 

, (13)

where N is the lifetime of the plant in years. Assumed values for each of the economic 

parameters are given in Table 6.

Table 6. Economic factors used in LCOE calculations

Economic Parameters Assumed Values

Lifetime years 25

Tax rate, T % 25

Inflation rate, i % 2.5

Project debt fraction, d % 70

Internal rate of return, IRR % 10

Nominal debt interest rate, NINT % 8

Depreciation rate, Dj % 20, 32, 20, 14, 14; 0 thereafter

Fixed-charge rate, FCR 0.075
28

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4 Results

In this section, the calibrated thermodynamic modeling software and economic evaluation 

methods are brought together. The orientation of the solar field and other key geothermal 

resource sites at more southern latitudes are evaluated. More advanced operation, such as 

including thermal storage and bypassing the steam turbine when excess solar heat is available,

are also considered. The influence of key economic variables such as the solar-field cost and the 

inclusion of an investment tax credit are investigated.

Comparison of Thermal and Generation Performance 

Annual power generation and LCOE calculations are performed for several different hybridplant configurations. In all cases, the solar field was sized to restore the Raft River GBPP to the 

power block’s original design net generation. 

Cycle 1A – Two HP steam turbines: The solar field generates HP steam that is fed to two 

turbines. The steam exiting each turbine condenses in a heat exchanger and vaporizes isopentane. 

There is a separate cond/vap for each of the L1 and L2 sides of the GBPP (see Figure 3). 

Cycle 1B – One HP steam turbine: HP steam is generated in the same way as for Cycle 1A in a 

single turbine, but there are separate cond/vaps for L1 and L2. The steam is mostly directed to 

the HP cond-vap, and the rest is crossed over to feed the LP cond-vap (see Figure 4).

Cycle 1C – One HP steam turbine, simplified. In this variation, the steam cross-over and the L2 

cond/vap of Cycle 1B are eliminated. Instead, enough of the incoming geothermal brine from the 

production wells is bypassed around the HP brine/isopentane vaporizer (using an existing brine

bypass) to supply the LP brine/isopentane vaporizer with its design energy input.

Cycle 2 – Solar heating of incoming brine: The solar field is used to heat the brine going to the 

GBPP. The mass flow rate to the plant is unchanged, but the temperature is increased enough to 

restore the GBPP to its design point. At Raft River, this approach has high calcite-scaling 

potential when the brine temperature is raised in the solar heat exchanger, as discussed in [10], 

[34]. The cost of continuously injecting scale inhibitors to prevent calcite precipitation is not 

included in the LCOE calculations for this option.

Cycle 3 – Solar heating of a returned slipstream of cooled brine: The solar field is used to heat 

some of the brine exiting the GBPP to restore the design inlet flow rate and temperature. The 

results are presented in Table 7, but no further consideration of this option is made because of its 

large required solar field and low conversion efficiency and net power increase.

These cycles were evaluated, and the results are presented in Table 7. Cycle 2 (brine preheating) 

is the simplest to implement, and it has the smallest solar field. But it has a much lower marginal 

solar efficiency and higher LCOE than the configurations that use turbines. Implementing a 

topping cycle allows for much more efficient use of the high-exergy flow that the solar field 

generates. For instance, Table 7 demonstrates that for both Cycle 1A and Cycle 1B, the solar 

conversion efficiency reaches 30%, which is almost double that of brine preheating and more 

than double that of brine recirculation. 
29

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Table 7. Solar heat input, marginal solar efficiency, and additional power generation for candidate 

Raft River geo–solar hybrid-plant configurations 

Cycle

#

Hybrid Plant 

Configuration

LCOE

($/kWhe)

Solar heat 

input (MWth)

Marginal solar efficiency Additional power generation

Design point

ηηsol,1 (%)

Annualizeda,b

ηηsol,1 (%)

Design point 

(MWe)

Annualizedb

(GWhe)

1A Solar-steam topping 

cycle (2 turbines) 0.129 24.95 32.6 29.6 8.1 12.41

1B Solar-steam topping 

cycle (1 turbine) 0.126 24.71 32.0 28.7 7.9 12.05

1C Solar-steam topping 

cycle (1 turbine) 0.120 24.63 32.1 29.4 7.9 12.34

2 Brine preheating 

(no turbines)

0.158 18.84 16.3 15.8 3.1 6.24

3 Recirculated brine 

heating (no turbines) 0.230 23.85 13.0 12.5 3.1 4.54

4A/B

c,d

Cycle 3 with a solar 

steam turbine — 28–29 24–27 — 3.6–4.8 —

5A/B

c,d

Internal brine reheat 

w/ steam turbine — 22–23 27–30 — 2.8–3.6 —

a Annual average (total additional power generation / total solar heat input)

b Based on a solar field with 25-MWth design condition output c These options were only considered in the screening study. See Appendix A.

d In the screening study, the calculation basis is different, so the values are not entirely comparable, but 

are indicative of the magnitude.

Cycle 1A has two steam turbines. Each turbine has the same inlet conditions, but a different 

outlet pressure that corresponds to the temperatures and pressures that would best match the 

high-pressure (L1) or low-pressure (L2) ORC isopentane closed-loops of the existing Raft River 

GBPP. In this scenario, the steam turbine coupled to the L1 loop extracts the majority of the 

work. For instance, with a solar heat input of 25 MWth at ambient conditions of 15°C, the HP 

steam turbine generates 4.2 MWe, and the LP turbine generates 1.0 MWe. The outlet flow of the 

HP turbine then adds 16.4 MWth to the heat exchangers with the binary plant, whereas the LP 

turbine adds 3.4 MWth.

Because the steam turbine feeding the L2 loop is relatively small and will increase the capital 

cost, a second configuration is considered that eliminates that steam turbine. The remaining 

steam-turbine outlet flow is split between the binary-plant L1 and L2 con/vaps depending on the 

requirements. For instance, restoring the binary plant to its design point requires 16.6 MWth in 

the L1 (HP) con/vap and 3.4 MWth to the L2 (LP) con/vap. The single steam turbine generates 

5.1 MWe.

The two-turbine solution is slightly more efficient (29.6%) than the single turbine (28.6%). 

However, the two-turbine system has a higher capital cost (12.7 M$ compared to 11.7 M$); so,

despite generating slightly more electricity annually (107.8 GWhe compared to 107.4 GWhe), the 

LCOE is also slightly lower for the single turbine (0.129 $/kWhe compared to 0.126 $/kWhe).

The one-turbine solution was further simplified in Case 1C, where the steam-turbine exhaust 

only delivers heat to the HP binary-cycle vaporizer. This system results in a small reduction in 
30

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capital cost and a corresponding increase in the LCOE. However, Case 1C was only considered 

late in the project and is not analyzed further in this report.

The above results are for a N-S solar-field orientation (i.e., the axis of the collectors trends N-S).

Results are also presented for E-W-oriented solar fields in Figure 14 and demonstrate the same 

trends as for N-S-oriented fields. However, E-W fields collect 18% less solar energy over the 

course of the year for the single-turbine case, which is consistent with the results of section 3.4. 

Furthermore, the E-W systems are less efficient at converting incident energy into thermal heat,

which leads to higher LCOEs.

In summary, it was found that a single steam-turbine topping cycle has high solar-conversion 

efficiency compared to brine preheating and was slightly simpler and less expensive to install 

than a two-turbine system. Solar fields oriented along a N-S axis generated more power and had 

lower LCOEs than E-W-oriented fields. The most promising solution is therefore a single steamturbine hybrid plant with a north-south-oriented solar field.

Influence of Geographical Location 

The results in the previous section were presented for the Raft River geothermal plant near 

Burley, Idaho. However, ageing geothermal binary power plants are also present in areas of the 

United States with better solar resources. In this section, a solar steam topping-cycle hybrid 

power plant is investigated in three locations—Burley, Idaho; Reno, Nevada; and Imperial, 

California—with average solar data presented in Table 8. 

Figure 14. The solar conversion efficiency ηη ,11 and LCOE of several hybrid-plant configurations.

In each case, the binary plant is assumed to have the same characteristics as the Raft River 

geothermal plant. No change is made to the size of the GBPP heat-rejection system (condenser, 

cooling water pumps, and cooling tower), which means that it is undersized for the other two 

warmer locations. The purpose of this part of the study was to investigate how locations with 

better solar resources would perform. In reality, those locations would also have larger heatrejection systems, sized to the location’s wet-bulb temperature, so the annual generation forecast

is probably lower than would actually occur were a solar field of the given size installed as a 

0.00

0.05

0.10

0.15

0.20

0.25

Brine

preheating

Two turbines One turbine

LCOE, $ / kWhe

North-South orientation

East-West orientation

0

5

10

15

20

25

30

35

Brine

preheating

Two turbines One turbine

Solar conversion efficiency, %

North-South orientation

East-West orientation
31

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GBPP retrofit at these locations. For Imperial, the smaller heat-rejection system of the Raft River 

plant may have an especially large effect on annual generation; hence, the results of this study 

likely indicate a much higher LCOE than would actually occur for a solar retrofit in Imperial.

Annual calculations were performed, and results are summarized in Figure 15. Ambient 

temperatures significantly affect the performance of the water-cooled geothermal plant, 

especially because it is undersized, as described above. Consequently, the hybrid plant has a 

lower solar conversion efficiency and produces less work from the geothermal field in Imperial

due to much higher temperatures. However, the improved solar resource leads to more available 

solar heat, thereby generating more power in the solar steam turbines, as shown in Figure 15.

Table 8. Typical solar properties at various geothermal plant locations in the USA

Annual average Burley, ID Reno, NV Imperial, CA

Direct normal irradiance kWh/m2/day 5.71 6.39 7.23

Global horizontal irradiance kWh/m2/day 4.63 5.06 5.77

Wet-bulb temperature °C 5.1 4.8 14.3

Wind speed m/s 3.8 2.8 3.3

Elevation m 1,267 1,341 -17

Latitude °N 42.533 39.500 32.833

Longitude °E -113.767 -119.783 -115.583

Despite the hybrid plant in California producing less electricity annually, it has the lowest LCOE 

as shown in Table 9. This is because the LCOE for the hybrid plant is calculated using the 

electricity generated in addition to the existing geothermal plant. 

Table 9 shows that the Californian plant has the highest percentage increase in work output, 

thereby leading to low LCOEs.

Note that the solar conversion efficiency shown here is ηηsol,1 and is a measure of the total 

increase in electricity divided by the solar thermal heat input to the hybrid plant. Another 

measure uses the total power incident on the solar collector and is referred to as ηηsol,2, as 

discussed in Section 1.1. The annual average solar-field performance (including optical and 

thermal efficiencies) for the solar field considered here is around 45%–48%, leading to values of 

ηηsol,2 in the range of 12.7%–13.7%, which are comparable with ηηsol,2 values proposed by other 

authors for hybrid plants with a solar topping cycle; see section 1.3 [18].
32

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Figure 15. The influence of location on the hybrid-plant performance. a) Higher average annual 

wet-bulb temperatures lead to lower solar conversion efficiencies. b) The geothermal power plant 

produces less electricity in warmer regions. However, more solar heat is generated.

Table 9. Electrical work output, solar conversion efficiencies, and LCOEs of hybrid plants in 

different geographical locations

Burley, ID Reno, NV Imperial, CA

Stand-alone geothermal work GWhe 95.4 95.7 82.4

Additional work GWhe 12.0 12.4 14.8

Total work GWhe 107.4 108.1 97.7

Percentage increase % 12.6 13.0 18.6

Solar conversion ηηsol,1 % 28.6 28.2 27.8

Solar conversion ηηsol,2 % 13.7 12.7 13.4

Solar field efficiency % 47.9 45.0 48.2

LCOE $/kWhe 0.126 0.122 0.118

Effect of Re-Routing Excess Solar Heat around the Steam Turbine and 

Adding to the Vaporizer

The steam turbine has a design thermal power of 25 MWth and it was assumed that it can be 

over-rated by 10% to 27.5 MWth, which is a common design margin. When the solar field 

generates heat above this value, the heat may be curtailed, probably through defocusing in the 

solar field. However, the heat could potentially be used in the GBPP instead. For example, the 

hot steam can be bypassed around the steam turbine and mixed with the steam-turbine outlet 

flow (requiring a large pressure drop through a valve). This option is illustrated with a dashed 

0

5

10

15

20.0

22.5

25.0

27.5

30.0

Burley, ID Reno, NV Imperial, CA

Ave. wet bulb temperature, °C

Solar conversion efficinecy, %

Solar efficiency

Average temperature

0

10

20

30

40

50

60

0

20

40

60

80

100

120

140

Burley, ID Reno, NV Imperial, CA

Annual solar heat, GWh-th

Annual energy, GWh-e

Solar work, GWh-e

Geothermal work, GWh-e

Solar heat, GWh-th

a. b.
33

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line in Figure 4. The hybrid-plant power output as a function of solar heat is shown in Figure 16, 

and a noticeable kink (at 27.5 MWth) indicates the point at which excess solar heat is diverted to 

the binary plant. At this point, the steam-turbine power output is fixed, but the binary-plant 

power increases as a result of higher mass flow rates through the ORC vaporizers. Extracting 

work in a steam turbine is more effective than in the lower-temperature binary plant, which 

explains the sudden decrease in solar conversion efficiency; but Figure 16 clearly indicates that it 

is better to use the excess solar heat in the binary plant than to curtail it. 

Figure 16. The hybrid-plant power output for several ambient temperatures as the solar thermal 

input varies. There is a noticeable kink at the point where excess solar heat is re-routed around 

the steam turbine.

Optimal Solar-Field Sizing

The solar field is sized to produce 25 MWth at a solar irradiance of 950 W/m2 and at these 

conditions will restore the design performance of the binary cycle. The solar field has a solar 

multiple of 1. These design conditions occur only some of the time during the year so that the 

system would operate below design conditions for much of the year. To improve the number of 

hours that the integrated GBPP operates at or above the design conditions of the hybrid plant, the 

solar-field area may therefore be increased, and the solar multiple increases proportionally.

Increasing the solar multiple increases the quantity of heat available to the hybrid plant, and the 

LCOE therefore initially reduces despite the increased capital cost. Curtailment of excess solar 

heat leads to an optimal solar-field size of around 1.25 according to Figure 17. When excess heat 

bypasses the steam turbine, the optimal solar multiple increases slightly, and the optimum LCOE 

is slightly reduced. 

Note that there is a limit to the quantity of solar heat that the binary plant can absorb before 

energy is curtailed. In this example, the maximum solar-field thermal power is 45 MWth

0

5000

10000

15000

20000

25000

0 10000 20000 30000 40000

Hybrid plant power output, kWe

Solar thermal input, kWth

Wet bulb temperature = 15 F

Wet bulb temperature = 45 F

Wet bulb temperature = 75 F
34

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compared to 27.5 MWth in the conventional case, and it occurs when both the solar and 

geothermal portions of the hybrid plant reach an arbitrary output of 110% of the design value. At 

a greenfield geothermal plant, the 10% limit could be raised. On an existing GBPP, it is possible 

that re-blading the turbine would also provide a means to raise the design limit. 

Figure 17. The effect of solar-field size on the LCOE. Curves are shown for a hybrid plant with one 

turbine with the solar field oriented north-south. Curves are shown for two locations and for 

configurations where the solar heat is either curtailed or re-routed directly into the geothermal 

plant vaporizers.

Integrating Thermal Storage with Solar-Field Sizing in the Geo–Solar 

Hybrid

As noted above, the solar conversion efficiency when excess solar heat directly enters the 

vaporizer is lower than extracting the energy in the steam turbine. Thermal energy storage 

provides a way to avoid curtailment while also converting solar heat at higher efficiencies. Figure 

18 shows the impact of TES on the LCOE of hybrid plants located in Burley, ID, and Imperial, 

CA, for different solar multiples. The TES is designed to deliver power at the design rate of 25 

MWth, and it absorbs solar energy whenever the solar steam turbine has reached 100% of its 

design value. The storage duration (either 4 or 8 hours in this example) determines the energy 

capacity of the TES. All excess solar heat enters the TES, and once the TES is full, the excess is 

curtailed. (Further research should consider combining thermal storage and re-routing excess 

heat into the vaporizer.) Whenever the solar heat decreases below 25 MWth, the stores are 

discharged until they are completely depleted.

The storage is in the form of two liquid tanks that contain the solar HTF. One of these tanks is 

used to store excess capacity of hot HTF whereas the second tank is used to manage the 

inventory of cooled HTF. This type of storage is comparatively straight-forward technologically 

and has been previously deployed at CSP plants. It is assumed that the tanks have been 

0.00

0.05

0.10

0.15

0.20

1.0 1.5 2.0 2.5 3.0

LCOE, $ / kWhe

Solar multiple

Burley - curtailment

Burley - no curtailment

Imperial - curtailment

Imperial - no curtailment
35

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sufficiently insulated so that heat leakage losses are negligible over the storage duration (several 

hours).

The figures indicate that thermal storage increases the optimal solar multiple to around 1.5 for 4 

hours of storage and to about 2.1 for 8 hours of storage. Furthermore, when storage has a capital 

cost of 25 $/kWhth, the optimal LCOE is slightly lower than the system without storage, although 

this configuration requires greater investment. 

Figure 18. Thermal storage increases the optimal solar multiple. a) Hybrid plant at Burley, ID. b) 

Hybrid plant at Imperial, CA. Results are for a hybrid plant with one steam turbine with the solar 

field oriented north-south.

Figure 19 illustrates the influence of storage costs on the LCOE and the optimal solar multiple 

for a hybrid plant with four hours of storage. The optimal solar multiple does not change 

considerably with increases in storage cost. This graph illustrates that if the storage costs more 

than 35 $/kWhth, then the optimum LCOE is higher than the system with no storage. It should be 

noted that 25 $/kWhth is quite an optimistic value. More realistic values for two-tank liquid 

storage fall in the range of 30–50 $/kWhth. 

Other thermal storage systems exist, such as packed beds. These are containment vessels filled 

with a packing material such as rocks or ceramic. Heat is transferred to the bed by the HTFs. 

Packed beds are more compact than two-tank systems because only one tank is required. The 

quantity of HTF is also reduced and thereby reduces system costs (HTF is the most expensive 

component in two-tank liquid storage). A previous study indicated that packed beds may be less 

than half the cost of two-tank liquid storage [11]. However, packed beds have complicated 

transient behavior and require detailed models to accurately assess the appropriate size and cost. 

Given the results of this section, this may be a worthwhile area for further study.

In this example, all electricity is sold at the same price. Thermal storage would allow the system 

to dispatch energy at the most profitable times and potentially increase the revenue.

0.08

0.10

0.12

0.14

0.16

1.0 1.5 2.0 2.5 3.0

LCOE, $ / kWhe

Solar multiple

Normal operation

Solar heat direct to

GT

0.08

0.10

0.12

0.14

0.16

1.0 1.5 2.0 2.5 3.0

LCOE, $ / kWhe

Solar multiple

Normal operation

Solar heat direct to

GT

4h TES - 25 $/kWh

a. Burley, ID b. Imperial, CA
36

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Figure 19. The effect of the cost of thermal storage on the LCOE of the hybrid plant for a) Burley, 

Idaho, and b) Imperial, California.

Effect of Tax Incentives on Economic Results 

The results presented so far have been for the full expected capital costs of the retrofit, without 

any tax incentives. A hybrid geothermal–solar plant may be eligible for subsidies such as the 

investment tax credit (ITC). The ITC was extended in 2016 and has a value of 30% for solar 

installations that have commenced construction before 2019 [35]. The value of the ITC then 

decreases to a value of 10% by 2022. The LCOE for hybrid plants with four hours of thermal 

storage that take advantage of the ITC are given in Table 10. The tax incentives are sufficiently 

large that the LCOE is quite competitive even when storage costs are high. 

Table 10. Tax incentives reduce LCOE significantly, even for high storage costs. Systems include 

four hours of storage.

LCOE ($ / kWhe)

Burley, ID Imperial, CA

Tax incentive:

TES 

Cost ($/kWhth)

0% 10% 30% 0% 10% 30%

25 0.113 0.104 0.085 0.088 0.081 0.067

35 0.118 0.108 0.088 0.091 0.084 0.069

50 0.125 0.114 0.093 0.097 0.089 0.073

Influence of Solar-Field Costs

The cost of the solar field dominates the capital cost of the hybrid plant. For instance, the solar 

field accounts for 75% of the total capital cost for a hybrid plant with a solar multiple of 1.5, 

with excess heat re-routed around the steam turbine, with no storage, at Burley, Idaho. With four 

hours of storage at 25 $/kWhe the solar field accounts for 64% of the cost, whereas the storage 

accounts for 14%. The current analysis has assumed a total solar-field cost of 185 $/m2

, which 

0.08

0.10

0.12

0.14

0.16

0.18

0.20

1.0 1.5 2.0 2.5 3.0

LCOE, $ / kWhe

Solar multiple

Normal operation

4h TES - 25 $/kWh

4h TES - 35 $/kWh

4h TES - 50 $/kWh

0.08

0.10

0.12

0.14

0.16

0.18

0.20

1.0 1.5 2.0 2.5 3.0

LCOE, $ / kWhe

Solar multiple

Normal operation

4h TES - 25

$/kWh

a. Burley, ID b. Imperial, CA
37

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includes the collectors, receivers, site improvements, and HTF system. Concentrating solar-field 

costs have reduced significantly in recent years, and further cost reductions may be possible. The 

effect of solar-field costs on the LCOE (without tax incentives) is investigated in Figure 20 for 

hybrid plants at Burley, ID, and Imperial, CA. The LCOE decreases below 0.10 $/kWhe when 

the solar field costs less than 135 $/m2, which may be a realistic target in the coming years. For 

instance, the DOE SunShot target is a solar-collector cost of 75 $/m2. Reducing the cost of site 

improvements and the HTF system proportionally (as in Table 11), Figure 20 indicates that these 

target low-cost solar fields could achieve LCOEs as low as 0.07 $/kWhe. 

Table 11. Current solar-field costs, and target costs based on the DOE SunShot target. (Costs 

without tax incentives.)

Current Target

Solar collector $/m2 125 75

Site improvements $/m2 20 12

HTF system $/m2 40 24

Total $/m2 185 111

Figure 20. The LCOE of a hybrid plant with no storage and a solar multiple of 1.5 at two locations. 

The grey lines indicate the LCOE that may be achieved using current solar-field costs (including 

collectors, site improvements, and HTF system), or target costs according to the DOE CSP 

COLLECTS Funding Opportunity Announcement. (Costs without tax incentives.)

Comparison with a Photovoltaic Array with Battery Energy Storage

Costs have so far been presented for a variety of solar-thermal geothermal hybrid configurations. 

In this section, the LCOE is evaluated for equivalently sized photovoltaic (PV) arrays with 

battery energy storage (BES). A wide range of economic assumptions and techniques are used in 

the literature, so this approach allows a fair comparison of technologies.

0.00

0.05

0.10

0.15

75 125 175 225

LCOE, $ / kWh-e

Solar field cost, $ / m2

Burley, ID

Imperial, CA
38

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The performance of the PV plant is assessed using SAM’s Photovoltaic (detailed) model with the 

default module (SunPower SPR-E19-310-COM) and inverter (SMA America: SC750CP-US 342 

V). The DC-to-AC ratio is set to 1.2 and a 1-axis tracking system is enabled. Shading losses are 

included and depend in part on the ground-coverage ratio (GCR), which is 0.4. The systemdesign DC power is varied until the annual energy generation is equal to a hybrid plant in the 

same geographical location. Two locations are considered: Burley, Idaho, and Imperial, 

California. 

The PV+BES system is compared to hybrid plants that have a solar multiple of 1.75 and a 

thermal storage duration of 4 hours because the above analysis indicated that these plants are the 

most economically viable. Plants with no storage are also considered. The BES system is rated 

with a power of 8.5 MWe because this is the additional electrical output of the hybrid plants 

when the 25-MWth thermal storage is discharged. It is assumed that all the electrical energy 

generated by the PV array is dispatched to the grid and that none is curtailed. The storage 

therefore provides dispatchability options and other energy storage services.

The PV cell capital costs are estimated from NREL’s Annual Technology Baseline [37]. Storage 

costs are obtained from Lazard’s Levelized Cost of Storage [38] report and are for lithium-ion 

(Li-ion) batteries operated in the “Peaker Replacement” market. Li-ion batteries have a lifetime 

of about 10 years, but the assumed lifetime of the power plant is 30 years. The batteries are 

therefore replaced in the 10th and 20th years, with the battery costs discounted appropriately. 

High, medium, and low capital costs are presented in Table 12, and the LCOE is calculated for 

each case. The average LCOE is then evaluated. Similarly, thermal storage is assumed to cost 

either 25 or 50 $/kWhth, and the average LCOE is calculated. The LCOE is calculated using the 

FCR method and uses the same economic assumptions detailed in Table 6.

Results are presented in Table 13 for Burley, ID, and Table 14 for Imperial, CA. For plants with 

no storage, the PV array is significantly cheaper than the hybrid system, with an LCOE of 0.074 

$/kWhe at Burley, ID, compared to the hybrid-plant value of 0.116 $/kWhe. The hybrid plant 

performs particularly poorly, in part because for a given plant size, the system produced less 

annual electricity than the PV array. This is due to curtailment of the thermal energy, whereas no 

PV electrical energy is curtailed (which may not be a realistic assumption).

Storage is an important component for the hybrid plant because it increases the electrical energy 

that is dispatched. Furthermore, it allows the plant to operate flexibly. This is also an important 

requirement for PV because the rapid deployment of PV in California has led to a surplus of 

power in the afternoon. This results in the so-called “duck-curve” whereby flexible power must 

be rapidly dispatched during the late-afternoon hours. PV should be installed with storage to help 

reduce this issue. However, as shown in Table 13 and Table 14, batteries significantly increase 

the LCOE of the PV system—primarily the result of the high cost of batteries, coupled with the 

requirement to replace them every 10 years. 

It is also notable that the PV system requires a smaller area of panels than the CSP system does 

of mirrors. However, the large spacing of PV cells that is required to reduce shading losses 

means that the PV system occupies significantly more land area.
39

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Table 12. Capital cost assumptions for photovoltaic cells and lithium-ion batteries

Low Medium High

PV capital cost $ / kWe 1000 1300 1700

Operations cost $ / kWe 14 14 14

Storage capital cost $ / kWhe 290 350 425

Table 13. Comparison of costs and LCOEs for a hybrid plant and a photovoltaic array with 

batteries. Both plants are located in Burley, Idaho (without tax incentives)

Hybrid Hybrid + TES PV PV + BES

Storage duration h 0 4 0 4

Annual electricity GWhe 18.3 22.1 22.0 22.0

Capital cost M$ 17.7 21.5 14.7 39.4

LCOE $/kWhe 0.116 0.118 0.074 0.187

Aperture/module area m2 73,690 73,690 57,835 57,835

Land area m2 103,165 103,165 144,473 144,473

Table 14. Comparison of costs and LCOEs for a hybrid plant and a photovoltaic array with 

batteries. Both plants are located in Imperial, California.

Hybrid Hybrid + TES PV PV +BES

Storage duration h 0 4 0 4

Annual electricity GWhe 24.0 28.9 28.9 28.9

Capital cost M$ 17.7 21.5 16.3 41.0

LCOE $/kWhe 0.092 0.091 0.063 0.148

Aperture/module area m2 73,690 73,690 64,353 64,353

Land area m2 103,165 103,165 161,066 161,066
40

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5 Further Work

In this report, we have demonstrated the technical and economic feasibility of hybridizing a 

geothermal plant with a solar-driven topping cycle. Several research activities may follow on 

from this work and include the following.

Generating steam/water directly in the solar collectors: The capital cost of the system is 

dominated by the solar-field cost. Reducing solar-field costs will make the plant more 

economically attractive. In this report, the solar HTF is a thermal oil, such as Therminol VP-1. 

Thermal oils are relatively expensive (especially if thermal storage is required) and require a heat 

exchanger between the solar field and the solar steam cycle. It is potentially more cost-effective 

to generate steam or pressurized water directly in the solar collectors. However, modeling these 

systems is not trivial because steam generation in the collectors is complicated by the influence 

of the varying solar resource that can affect the location of steam generation. Such systems may 

require sophisticated control strategies and transient modeling. Alternatively, pressurized water 

could be heated in the collectors, and then flashed to steam. However, such a system would be 

limited to lower temperatures than the design value used in this report, which is above the critical 

temperature of water (373.9°C). Even generating pressurized water at 300°C would require 

pressures of 85.9 bar, which would substantially increase the cost of the solar collectors. 

Comparison of hybrid plant to conventional technologies: Values of the LCOE have been 

presented in this report. Although this is informative about the potential of the hybrid system, it 

can be challenging to compare the economic feasibility with other systems that exist because of

the wide range of methodologies and assumptions used in the literature. Therefore, it would be

more appropriate to undertake further LCOE analysis of other conventional technologies (such as 

PV arrays with BES, and stand-alone CSP and geothermal plants) using the same assumptions 

and techniques, to evaluate how the proposed hybrid system compares. Recent work on a hybrid 

solar–geothermal plant (using double-flash) technology undertook such analysis and indicated 

that the hybrid system was preferable to PV+BES and to stand-alone CSP plants [11]. Similar 

conclusions were obtained by Zhou et al. for a binary cycle with a steam topping cycle [19]. 

However, the systems and locations are quite different and further analysis is required. 

More sophisticated modeling of thermal storage: In this report, we briefly consider the impact of 

including thermal storage in the hybrid plant and find that it can increase the electricity 

generation. However, the results are quite sensitive to the cost of the storage and imply that 

storage capital costs should be less than 30 $/kWhth. Further analysis is required to determine 

whether this cost is feasible. Previous research indicates that values in the range 30–50 $/kWhth

are realistic for two-tank liquid storage [11]. Costs could potentially be reduced by using 

alternative technologies, such as a single tank with a thermocline or solid baffle, or a packed bed.

Alternative heat-integration strategies: Several methods of hybridizing the geothermal plant with 

solar were considered in this report, including brine preheating, and topping cycles with either 

one or two turbines. However, a variety of other integration strategies could be investigated, and 

some of these have been proposed in the literature. For instance, rather than using the steamturbine exit flow to vaporize the binary-cycle working fluid, it could be added to the geothermal 

fluid as in [18], or elsewhere in the cycle. Another option is to modify the binary cycle to operate 

at supercritical conditions rather than subcritical conditions, in a similar way to [17]. For 
41

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example, a supercritical expander could be added to the binary cycle (or the existing turbines 

could be upgraded, if possible). The working fluid would be pumped to high pressures, then 

heated first by the geothermal fluid, then by the solar field. Heat exchange would occur directly 

between the solar field and the binary cycle, therefore reducing the number of heat exchangers in 

the system compared to the case with the steam topping cycle. 

Time-of-delivery scheduling: Thermal storage enables the plant to dispatch power at optimal 

times and take advantage of fluctuations in electricity prices. A further study could investigate 

the required control strategies and the economic benefit of a hybrid plant that reacted to market 

signals.

Performance of hybrid plants that use air-cooling: This analysis considered the retrofit of a 

geothermal binary cycle that uses evaporative cooling towers. Many geothermal binary cycles 

use air-cooling and their performance is highly influenced by changes in ambient temperature, 

with high ambient temperatures leading to lower power outputs. The solar-steam topping cycle 

could be particularly beneficial when coupled with air-cooled binary plants because the 

additional solar heat input would coincide with periods of the day in which ambient temperature 

is elevated and stand-alone geothermal power-plant output is decreased. Additional heat input 

into the binary cycle during these time periods is likely to significantly improve plant 

performance, with the additional power generation per unit solar heat input expected to be 

greater than in the case of a wet-cooled power plant. The addition of a solar-steam topping cycle 

to an air-cooled geothermal binary power plant may therefore provide increased power 

generation and a consequently lower LCOE relative to the wet-cooled power plant investigated 

in this analysis.

Evaluation of hybrid-plant performance for a range of resource design conditions (and the 

resulting power-plant designs/configurations): The geothermal resource temperature and ambient 

temperature have a significant impact on the design of a geothermal power plant, influencing 

major design choices such as the plant type, plant configuration, working-fluid selection, and 

cooling medium. In this analysis, the performance of a hybrid-plant retrofit of the Raft River 

power-plant design was considered; it is expected that the performance and costs of hybrid-plant 

retrofits of other geothermal power plants (with differing geothermal resource, solar resource, 

and ambient-temperature design points) would differ from Raft River. Further evaluation of the 

hybrid-plant performance for a range of geothermal resources, solar resources, and ambienttemperature design points would allow the geothermal power industry to more readily select

geothermal power plants that would most greatly benefit from solar topping-cycle hybridization.

Applicability of hybrid plant with various levels of geothermal-resource productivity decline: 

Geothermal power plants frequently encounter resource productivity decline, which may occur in 

the form of a brine temperature decrease, brine flow rate decrease, or both. In this analysis, the 

performance specification of one specific off-design geothermal resource condition was 

considered. For this analysis to be more broadly applicable to the geothermal power industry, it 

would be instructive to evaluate the performance and LCOE for a solar steam topping-cycle 

retrofit for a range of brine flow rates and temperatures that deviate from the design point by 

varying amounts.
42

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6 Conclusions

In this report, we have investigated retrofitting a geothermal binary cycle with a solar steam 

topping cycle. The waste heat from the steam cycle is used to return the binary cycle to its design 

point. We develop design and off-design models of the geothermal plant (and verify against 

operational data), solar field, and topping cycle. These models account for variations in ambient 

temperatures and solar resource. We undertake annual simulations to evaluate the additional 

electricity generated and levelized cost of electricity.

We compare three different methods of hybridization and find that a system with a single steam 

turbine that acts as a topping cycle to the geothermal plant has the best performance and 

simplicity. We find that solar fields with a north-south orientation outperform fields oriented 

east-west. The hybrid plant with a single steam turbine and a north-south-oriented solar field is 

then investigated in further detail. For example, we calculate the LCOE for a hybrid plant located 

in three locations: Burley, Idaho; Reno, Nevada; and Imperial, California. The annual average 

ambient temperature significantly affects the performance of the geothermal plant (which uses an 

evaporative cooling tower), with the Californian geothermal plant generating the least 

incremental electricity because of the higher wet-bulb temperature that the cooling tower 

experiences. However, the solar resource is greater in Imperial, CA, than at the other two 

locations, leading to a higher quantity of additional electricity produced due to the solar field by 

the hybrid plant. Consequently, the LCOE, without tax incentives, of a hybrid plant in California 

is lower (0.118 $/kWhe) than the other two locations (0.126 $/kWhe at Burley, ID).

An advantage of hybrid geothermal–solar power plants is the ability to use all the available solar 

energy. In a conventional CSP system, the solar field is typically oversized so that the plant can 

operate close to the design point for a greater proportion of the year. However, excess solar 

energy then has to be either curtailed or stored. In a hybrid system, this problem may be avoided. 

When the topping turbine reaches its maximum capacity, excess solar energy can be bypassed 

around the turbine and added directly to the geothermal plant. This reduces the quantity of 

energy that is curtailed. We find that this mode of operation increases the optimal solar multiple 

to be around 1.5 and slightly decreases the LCOE. 

However, this mode of operation is less efficient than extracting work at high temperatures in the 

solar field. Therefore, it is preferable to install thermal storage so that power can be extracted at 

higher efficiencies at later times. Thermal storage also improves the dispatchability of the plant 

and may enable it to take advantage of fluctuating prices. The solar multiple that minimizes the 

LCOE increases when thermal storage is added. Four hours of storage has an optimal solar 

multiple of 1.75, and eight hours has an optimal value of 2.0. We find that storage should cost 

less than 30 $/kWhth in order for the minimum LCOE to be lower than that of a hybrid plant with 

no storage.

We consider the impact of subsidies and future developments in solar technology on the LCOE. 

Tax incentives such as the ITC reduce the capital cost between 10% and 30%, significantly 

reducing the LCOE. For instance, for a hybrid plant with four hours of storage in Imperial, CA, a 

solar multiple of 1.75 and a tax incentive of 30% has an LCOE of 0.067 $/kWhe. Solar-field 

costs are also expected to decrease in coming years. The DOE SunShot target is for collectors to 

cost significantly less than those used in this report (75 $/m2 rather than 125 $/m2). The solar 
43

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field accounts for up to 75% of the total capital cost, and reducing solar-field costs by half leads 

to a 30% reduction in the LCOE.

The cost of the hybrid geothermal–solar power plant is compared to a photovoltaic array with 

battery energy storage. It is found that the hybrid plant is significantly less expensive than the 

PV+BES system due to the high cost and replacement rate of batteries. For instance, with four 

hours of storage, the LCOE of the hybrid plant is 0.091 $/kWhe compared to 0.148 $/kWhe for a 

plant in California (without subsidies). This suggests that a hybrid solar–geothermal power plant 

with storage may provide a path to provide inexpensive, dispatchable geothermal power. 

However, without energy storage, the PV plant has a lower LCOE than the geothermal–solar 

hybrid.
44

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47

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Appendix A

Funding for this study was provided with the specific intention to evaluate a hybrid cycle with a 

high-temperature (exergy) solar steam topping cycle to extract net electric power from the 

energy collected in the solar field, after which the steam would then be cascaded to add solar 

heat to the GBPP to fill the plant’s under-used turbine and heat-rejection system capacity. 

However, it was recognized that the proposed system was substantially more complex and 

expensive than some of the simple solar-heat addition cycles that had been studied and/or 

constructed. To get a feel for whether the project concept would yield a substantial improvement 

in economics, the initial work was a high-level screening evaluation at a single operating point 

using the HYSYS software package, calibrated to the original design PFD.

Throughout this project, various configurations have been considered. Some of these were 

evaluated in both a screening study and the detailed modeling work of this report, whereas some 

were only considered in this study. A full list of considered configurations are now given, as well 

as the study they appear in:

Case 1A: Schematic shown in Figure 3. A steam topping cycle rejects heat into the binary cycle 

and vaporizes the working fluid. There are two turbines operating with different condenser 

pressures to match the temperatures and properties of the two pressure levels in the binary cycle. 

Evaluated in screening study and detailed study.

Case 1B: Schematic shown in Figure 4. The steam topping cycle rejects heat into the binary 

cycle and vaporizes the working fluid. There is only one steam turbine, and the exit flow 

pressure corresponds to the high-pressure level in the binary cycle. The exit flow is split between 

the two pressure levels. Only considered in detailed study—see Table 7.

Case 1C: Schematic shown in Figure 5. The same as Case 1B except that the steam turbine exit 

only preheats the binary-cycle fluid in the high-pressure level. Only considered in detailed 

study—see Table 7.

Case 2: This is the simplest configuration, and a schematic is shown in Figure 21. The solar field 

directly heats the production fluids. There may be problems with mineral deposition in the heat 

exchanger. This is not an effective use of the high-exergy fluid produced in the solar field. 

Evaluated in screening study and detailed study.

Case 3: A fraction of the injection brine is heated directly by the solar field. It is then mixed with 

the production fluids. Only considered in detailed study—see Table 7—and found to have very 

low solar conversion efficiencies.

Case 4A: A steam topping cycle rejects heat into injection brine, which is recirculated and mixed 

with the production fluids—see Figure 22. Considered in screening study.

Case 4B: The heat exchange between the brine and the condensing steam in Case 4A is not 

effective due to large temperature differences that occur. Using a three-stage steam turbine and 

passing the brine through condensers operating at increasing pressures (and therefore increasing 

temperatures) improves the heat-transfer process—see Figure 23. Considered in screening study.
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Case 5A: Case 4 increases the binary-cycle performance by increasing the mass flow rate of 

brine, and therefore, the binary-cycle mass flow rate. Rather than heating injection brine, in Case 

5A, some brine is extracted earlier in the process—see Figure 24. Because this brine is hotter 

than the injection brine, the increase in mass flow rate for a given solar heat input is increased. 

This leads to a higher solar conversion efficiency. Considered in screening study.

Case 5B: The effectiveness of the topping-cycle heat rejection is improved by using a threestage steam turbine—see Figure 25. Considered in screening study.

Figure 21. Case 2—Geothermal production fluids are heated directly by the solar field.

Solar Collector G

HP Turbine LP Turbine LP Condenser

HP Condenser Circ Pump

Cooling

Tower

HP Pre-Heater

LP Pre-Heater

HP Vaporizer LP Vaporizer

Production Wells Injection Wells

HP Isopentane

LP Isopentane

Cooling water

Geothermal fluids

Solar heat transfer fluid

Legend

Brine heater
49

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Figure 22. Case 4A—Injection brine is heated in the condenser of a topping steam turbine. The hot 

brine is recirculated and mixed with the production fluids.

G

G

Solar Boiler Pump

Solar Collector

Solar Steam Turbine

Condenser

HP Turbine LP Turbine LP Condenser

HP Condenser Circ Pump

Cooling

Tower

HP Pre-Heater

LP Pre-Heater

HP Vaporizer LP Vaporizer

Production Wells Injection Wells

Existing 

Binary 

Power 

plant

New 

Solar 

Topping 

Cycle

HP Isopentane

LP Isopentane

Cooling water

Steam

Geothermal fluids

Solar heat transfer fluid

Legend

Economiser Boiler
50

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Figure 23. Case 4B—Injection brine is heated in the condensers of a three-stage topping steam 

turbine. The hot brine is recirculated and mixed with the production fluids.

G

G

Solar Boiler Pump

Solar Collector

Three stage steam 

Turbine

Condensers

HP Turbine LP Turbine LP Condenser

HP Condenser Circ Pump

Cooling

Tower

HP Pre-Heater

LP Pre-Heater

HP Vaporizer LP Vaporizer

Production Wells Injection Wells

Existing 

Binary 

Power 

plant

New 

Solar 

Topping 

Cycle

HP Isopentane

LP Isopentane

Cooling water

Steam

Geothermal fluids

Solar heat transfer fluid

Legend

Economiser Boiler
51

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Figure 24. Case 5A—Brine is extracted before the binary-cycle preheaters. It is then heated in the 

condenser of the steam topping cycle and then mixed with the production fluids.

G

G

Solar Boiler Pump

Solar Collector

Solar Steam Turbine

Condenser

HP Turbine LP Turbine LP Condenser

HP Condenser Circ Pump

Cooling

Tower

HP Pre-Heater

LP Pre-Heater

HP Vaporizer LP Vaporizer

Production Wells Injection Wells

Existing 

Binary 

Power 

plant

New 

Solar 

Topping 

Cycle

HP Isopentane

LP Isopentane

Cooling water

Steam

Geothermal fluids

Solar heat transfer fluid

Legend

Economiser Boiler
52

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Figure 25. Case 5B—Brine is extracted before the binary-cycle preheaters. It is then heated in the 

condensers of a three-stage steam topping cycle and then mixed with the production fluids.

G

G

Solar Boiler Pump

Solar Collector

Three stage steam 

Turbine

Condensers

HP Turbine LP Turbine LP Condenser

HP Condenser Circ Pump

Cooling

Tower

HP Pre-Heater

LP Pre-Heater

HP Vaporizer LP Vaporizer

Production Wells Injection Wells

Existing 

Binary 

Power 

plant

New 

Solar 

Topping 

Cycle

HP Isopentane

LP Isopentane

Cooling water

Steam

Geothermal fluids

Solar heat transfer fluid

Legend

Economiser Boiler
53

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Screening Study

The parameters of the screening study were to fix the brine flow and temperature at the current 

operating condition of 2,700 klbs/hr (kph) and 272°F (compared to the original design condition 

of 3,150 kph and 280°F). This resulted in a GBPP net generation of 10.69 MWe at the original 

design-point atmospheric wet-bulb temperature of 39.9°F. For each screening case, the size of 

the solar field was adjusted until the GBPP achieved an approximate design net output of 13.75 

MWe (excluding geothermal production and injection pump loads), which required the solar heat 

input to the plant to result in a net GBPP output increase of 3.06 MWe. The solar heat input was 

modeled as simply thermal input to the cycle, with no parasitic loads or losses to obtain the 

thermal heat, e.g., no solar-field fluid pumps, and no pipe or collector heat losses. 

With the net output of the GBPP fixed, the parameters that changed from case to case were the 

thermal input, the net electrical power generated by the cycle overall, and the incremental solar 

conversion efficiency. A summary of the screening study results is presented in Table 15. 

Because the solar collectors are the most expensive part of any solar energy system, the 

incremental solar efficiency and the ratio of thermal heat input to electrical power output are the 

most important metrics for this screening study. 

Preliminary results are presented in Table 15 and indicate that Case 1 is the most promising 

configuration.

Table 15. Preliminary results comparing several hybrid geothermal–solar configurations. These 

results are for the case where the solar-field heat input restores the geothermal plant to its design 

point.

Case

Steam mass 

flow, kg/s

Steam-cycle net 

power, MWe

Binary-cycle net 

power, MWe

Brine exit 

temperature, °C

Solar heat 

input, MWth

Efficiency, 

ηηsol,1, %

1A 7.72 3.84 13.76 65.6 19.74 35.0

1B Only considered in detailed study—see Table 7

1B Only considered in detailed study—see Table 7

2 — — 13.78 62.1 19.16 16.1

3 Only considered in detailed study—see Table 7

4A 11.9 3.59 13.74 65.6 27.53 24.1

4B 11.6 4.77 13.74 65.6 28.77 27.1

5A 9.37 2.83 13.76 61.8 21.72 27.1

5B 9.25 3.58 13.77 62.1 22.51 29.5

Several points are worth noting:

1. Cycles that raise the temperature of the injected brine are essentially using solar heat to 

do so. This is neither cost effective nor beneficial, even over the long run. Conversely, 

cycles that lower the brine temperature increase the energy extraction from the brine, 

making better use of the very large investment and expense of getting geothermal brine to 

and from the reservoir, and reducing the required size of the solar-field investment.
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2. For brine-heating options, Case 5A and 5B represent substantial improvements in 

performance over the other brine-heating options. Conceptually, the reason for this is 

two-fold: 1) the recirculated brine is not heated from as cold a temperature, and 2) there 

is a reduced flow in the preheaters; thus, the heat exchangers are “oversized” and able to 

extract more heat from the geothermal brine.

3. Cases 4B and 5B are more efficient because of a multi-step heating process. This may or 

may not be practical to implement in a real plant.

4. The cheapest and simplest system to implement is Case 2 (brine preheating). However, 

this makes inefficient use of the most expensive component in the plant—the solar field.

5. Including a topping steam turbine increases the cost and complexity but is cost-effective 

for the following reasons. The steam turbine is small as a result of both low mass flow 

rates and relatively high exhaust pressure, so inexpensive industrial steam turbines are 

viable. Any cycle that integrates solar and geothermal must have at least one heat 

exchanger. Although the Case 1A steam vaporizer has the disadvantage of high pressure, 

it also has the advantage of boiling heat-transfer coefficients. The steam condenser to 

isopentane vaporizer vessel is not an expensive heat exchanger: there is a condensing 

heat-transfer coefficient on one side, and a boiling heat-transfer coefficient on the other 

side. The con/vap heat exchanger also eliminates the need for large fouling factors, which 

is necessary to include on the brine heat exchanger(s) required with the other cycle 

options. Because there is clean fluid on both sides of the Case 1A heat exchangers, there 

is also the potential to use more cost-effective designs, such as all-welded plate-type.
55

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Appendix B: Component Cost Estimates

Table 16. List of equipment, equipment sizing, and installed capital costs for brine-preheating, 

dual-turbine topping-cycle, and single-turbine topping-cycle hybrid-plant configurations

Brine Preheating

Dual-Turbine Steam 

Topping Cycle

Single-Turbine Steam 

Topping Cycle

Equipment

Equipment 

Size

Installed 

Cost

Equipment 

Size

Installed 

Cost

Equipment 

Size

Installed 

Cost

Site Improvements 42,108 m2 $1,052,700 42,108 m2 $1,052,700 42,108 m2 $1,052,700

Solar Field 42,108 m2 $4,210,800 42,108 m2 $4,210,800 42,108 m2 $4,210,800

HTF System 42,108 m2 $2,526,500 42,108 m2 $2,526,500 42,108 m2 $2,526,500

HTF-Brine HX 467 m2 $208,400 – – – –

Economizer – – 115 m2 $386,600 115 m2 $386,600

Vaporizer – – 191 m2 $202,100 191 m2 $202,100

Superheater – – 70 m2 $280,900 70 m2 $280,900

L1 Condenser – – 1810 m2 $485,100 1,810 m2 $485,100

L2 Condenser – – 42 m2 $80,900 42 m2 $80,900

L1 Feed Pump – – 29 m3/h $127,100 29 m3/h $127,100

L2 Feed Pump – – 6 m3/h $109,600 6 m3/h $109,600

L1 Steam Turbine – – 4,222 kW $2,111,000 5,001 kW $2,400,000

L2 Steam Turbine – – 1,014 kW $1,115,400 – –

Total (USD)

Additional Capacity 

(kW) at Twb,design

3,080 kW 8,146 kW 7,910 kW

The installed costs reported by Aspen Process Economic Analyzer include allowances for the 

material and manpower contributions for the following factors: 

• Equipment and setting

• Piping

• Civil

• Structural steel

• Instrumentation

• Electrical

• Insulation

• Paint.

These allowances are included as installation factors for each equipment item. In general, the 

installation factors (direct cost divided by equipment cost) are at least 1.2, if not considerably 

above. The highest installation factor reported was for the economizer unit of the steam boiler, 

where the installation factor reported by Aspen was 7.3.