Hybridizing a geothermal power plant with concentrating solar power and thermal storage to increase power generation and dispatchability

Applied Energy 228 (2018) 1837–1852

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Applied Energy journal homepage: www.elsevier.com/locate/apenergy

Hybridizing a geothermal power plant with concentrating solar power and thermal storage to increase power generation and dispatchability

T

Joshua D. McTiguea, Jose Castrob, Greg Mungasc, Nick Kramerc, John Kingc, Craig Turchia, ⁎ Guangdong Zhua, a

National Renewable Energy Laboratory, 15013 Denver West Parkway, Golden, CO 80401, USA Coso Operating Company, CA, USA c Hyperlight Energy, Ltd., San Diego, CA, USA b

H I GH L IG H T S

power output of a geothermal plant is increased by 2 MW (9%) by using solar heat. • The hybrid plant’s solar thermal energy to electricity conversion efficiency is 24%. • The hybrid plant cost (LCOE) is 25–50% lower than a PV array with battery storage. • The cost is up to 15% lower than a concentrating solar plant with thermal storage. • The • Over-sizing the solar field and using storage improve flexibility and reduce cost. e

A R T I C LE I N FO

A B S T R A C T

Keywords: Concentrating solar power Thermal energy storage Geothermal power Retrofit Levelized cost of energy Hybrid power generation

Geothermal power plants often deploy less than their full power capacity due to declining geothermal resources. Integrating heat from a concentrating solar power (CSP) collector field increases the power output at low cost. This article considers five methods of solar heat addition in a double-flash geothermal plant. The most promising solution converts solar heat into electrical work with an efficiency of 24.3%. The economic feasibility and optimal sizing of the solar field and thermal stores are evaluated. A hybrid plant that increases power generation from 22 to 24 MWe has a Levelized Cost of Electricity (LCOE) of 0.07 ± 0.01 $/kWhe. Adding three hours of storage increases the LCOE to 0.08 ± 0.01 $/kWhe. Photovoltaic systems are considered to be a low-cost renewable technology, but an equivalent photovoltaic system with battery storage costs 0.15 ± 0.07 $/kWhe due to the high cost and replacement rate of batteries compared to thermal storage. The hybrid plant also has a lower LCOE than a conventional CSP plant. If the dispatchability that thermal storage provides is rewarded with higher electricity prices, calculations indicate storage becomes an attractive investment when discharged power receives 1.75 times the typical price of electricity.

1. Introduction and motivation A geothermal resource typically experiences a reduction in the temperature, pressure, or mass flow rate of its production fluids over time, leading to decreased power generation and underutilized equipment. If a Power Purchase Agreement exists plant operators may be subject to additional fees for not producing agreed quantities of power [1]. The extent of any resource decline is unique to that geothermal field. A survey of geothermal power plants in California and Nevada found that flash plants typically experienced a temperature decrease of 0.8% per year, while the value was 0.5% for binary plants [2].

⁎

Underperforming plants may be brought back to full capacity by the addition of thermal heat. The unused capacity of the geothermal plant provides an opportunity to install a concentrating solar plant at reduced cost since investment in a power unit and condenser are not required. Integrating thermal storage provides the plant with flexibility and dispatchability. Several novel contributions are made in this article. For instance, the technical performance of several plant configurations are compared. The solar field can be over-sized thereby allowing the hybrid plant to operate at its design point for a greater portion of the year, and the optimal solar field size is found. Excess heat can be sent to the geothermal plant or stored, thus reducing curtailment. The impact of

Corresponding author. E-mail address: [email protected] (G. Zhu).

https://doi.org/10.1016/j.apenergy.2018.07.064 Received 11 April 2018; Received in revised form 1 June 2018; Accepted 14 July 2018 0306-2619/ © 2018 Published by Elsevier Ltd.

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J.D. McTigue et al.

ηsol θ⊥, θ ρ ρf,s σ τ τd ϕ

Nomenclature Roman symbols cp Ccap E h ṁ M p P Q̇ s t T V Ẇ

specific heat capacity, kJ/kg·K capital cost, $ energy, kJ enthalpy, kJ/kg mass flow rate, kg/s annual operations cost, $ pressure, bar power, W heat, W entropy, kJ/kg·K time, s temperature, °C volume, m3 work, W

Abbreviations BES CSP DPO FCR HTF IAM IRR LCOE PV

Greek symbols α β γ ε η1 ηopt

solar efficiency, %, see Eq. (13) transversal and longitudinal incidence angles reflectance fluid or solid density, kg/m3 solar multiple transmittance discharging time of stores, s heat loss, W/m

average absorptance oversizing factor for storage tanks intercept factor packed bed void fraction first law efficiency, %, see Eq. (12) optical efficiency, %

battery energy storage concentrating solar power eutectic mixture of diphenyl oxide and biphenyl fixed charge rate heat transfer fluid incidence angle modifier internal rate of return levelized cost of electricity, see Eq. (14) photovoltaics

Subscripts and superscripts h, c in, out

hot and cold inlet and outlet flows

comprise 29% of US geothermal capacity, and notably 90% of US flash plant capacity is over 25 years old, indicating that many existing plants may be experiencing the effects of resource decline. The opportunity to explore resource decline mitigation currently exists in the US, and the results may have benefits internationally as flash plants make up 65% of the world’s total installed capacity of 11 929 MWe. The first 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 [4]. The plant also includes a 26 MWe photovoltaic solar array,

storage on system cost is investigated, and the conditions for storage to be economical are explored. Furthermore, the hybrid plant economics are compared to conventional systems, and are found to be competitive. This article concentrates on the integration of solar heat into a double-flash geothermal power plant: production fluids are flashed and the resulting steam powers a steam turbine. Hybrid plants require good solar and geothermal resources, and Fig. 1 indicates that the most suitable locations in the United States are in the West, and are primarily dependent on the geothermal resource location. The installed geothermal capacity in the USA is 3134 MWe, most of which is concentrated in California and Nevada, see Fig. 1. Flash plants

Fig. 1. Potential locations for geothermal-solar hybrid plants and design requirements. Map of the USA showing locations of high solar irradiance and geothermal temperatures at a depth of 3000 m. Data from National Solar Radiation Database [3]. 1838

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However, over-sizing can lead to the curtailment of excess solar heat if sufficient storage is not available. Retrofitting a geothermal plant with solar means that curtailment can be reduced as excess solar heat is sent to the geothermal plant. Storage can increase the quantity of energy dispatched, and the flexibility of power generation, and a two-tank liquid thermal energy storage is used here. In this article, the optimal sizing of the thermal storage and solar field is investigated, and the influence of these parameters on one another is discussed. In Section 6, the levelized cost of electricity of the hybrid plant is compared to an equivalent photovoltaic array with batteries, and a stand-alone CSP plant, and therefore assesses the relative economic feasibility of the hybrid system. In Section 7, the effect of the electricity price on optimal storage size is investigated. Alternative storage systems that are more compact and cost effective than two-tank liquid storage are discussed in Section 8.

which offsets the decrease in power generation that occurs at high ambient temperatures [5]. 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 [6]. Tests were conducted with a 200 kWth array of parabolic trough collectors in 2014. Other previous investigations have concentrated on either hybrid systems using binary plants [7–9] and single-/double-flash plants [10–13]. Heat generated by the solar field can be added at numerous points in the geothermal system. The optimal hybrid configuration depends on the location of components, the properties of the geothermal fluids, and the performance of the 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 [14]. 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. Lentz and Almanza [10] investigated using solar collectors to directly heat the geothermal fluids, thereby increasing its enthalpy and the steam generation. The fluids could either be heated before or after the first flash tank. However, the authors noted that this method was limited by silica deposition in the collectors, and is a more significant issue if the collectors are placed after the flash tank as the brine has a higher salt concentration. Four methods for adding solar heat to the Ahuachapán geothermal field in El Salvador to increase the power output by 2 MWe to 97 MWe have been considered [11,12]. Heating the brine directly from the production well was determined to require too large a heat exchanger. A method that was successfully tested involved heating brine from the first separator and directing the generated steam into the high-pressure turbine. The authors calculated that increasing power output by 2 MWe would require a solar field of 30 acres (121,405 m2) to heat the heat transfer fluid (HTF) to 225 °C. Cardemil et al. [13] compared two locations of solar-heat addition in single- and double-flash plants in the Atacama Desert, Chile. After the flash tank, the solar field could either superheat the steam, or evaporate the brine. Using 2nd Law analysis, it was concluded that superheating the steam was slightly more effective because the turbine operated more efficiently with dry steam. Doubleflash systems were also found to be preferable to single-flash plants. Hybridization of solar heat with binary geothermal plants typically involves different integration methods to flash plants, although preheating the geothermal fluids has also been investigated in this context [15]. Other strategies involve superheating the binary cycle working fluid [16] or using the solar heat to drive a topping cycle – either as part of the binary plant [7] or in a steam turbine [17], thereby making better use of relatively high-exergy solar heat. These studies find the LCOE to be relatively high, obtaining values such as 0.163 $/kWhe [17] and 0.22–0.43 $/kWhe [16]. However, estimated solar field costs in the range of 250–300 $/m2 are used, which are high compared to recent estimates which are closer to 150–200 $/m2. This is particularly relevant given that the solar field cost dominates the total capital cost.

2. Modeling of the hybrid system The geothermal plant is a double-flash power plant: steam produced from geothermal fluids in a flash tank is diverted to the high-pressure stage of a steam turbine. The brine enters a second flash tank, and the produced steam is injected into the low-pressure steam turbine stage. The power plant is based on the units at the Coso geothermal field, and was modelled in the IPSEpro heat balance software, developed by SimTech [18]. Design and off-design performance were validated against data provided by the Coso Operating Company who operate the double-flash geothermal plant in China Lake, California. The hybrid plant consists of a double-flash geothermal power plant, and array of mirrors to concentrate sunlight, and two liquid tanks that contain the heat transfer fluid (HTF) and are used as thermal storage.

2.1. Geothermal production fluids The geothermal well produces a fluid with a characteristic curve. The fluid pressure is inversely related to the mass flow rate, and is assumed to follow a choked flow correlation [19]. Data points are tabulated in Table 1. Intermediate points are evaluated with cubic spline interpolation. The values of pmax and ṁ max were set at pmax = 30 bar, ṁ max = 125 kg/s in order to obtain the design power output (30 MWe) of the geothermal plant, and to match the fluid properties around the cycle. The current operating point is 75% of the design output (22.5 MWe) and was obtained by reducing the maximum mass flow rate to ṁ max = 112 kg/s. The geothermal fluid was assumed to have a specific enthalpy of 1500 kJ/kg which is in line with typical enthalpies observed at Coso. The salt content of geothermal production fluids is low, and the fluid can therefore accurately be modelled using water properties.

1.1. Scope and novelty of the present work

Table 1 Pressure-mass flow characteristic for a geothermal well.

In this article, several methods of integrating solar heat into a geothermal power plant are investigated, and the cost of the novel system is compared to conventional renewable technologies. A thermodynamic model of the system is first described in Section 2. The geothermal power plant is based on the Coso geothermal plant, and the model has been validated against operational data. Several methods of integrating the solar heat with the geothermal plant are considered in Section 3 and annual calculations are undertaken in Section 4. Previous studies of hybrid systems typically do not include thermal storage or consider over-sizing of the solar field. ‘Over-sizing’ the solar field is commonplace in concentrating solar applications, otherwise the system operates below its design point for significant portions of the year. 1839

ṁ / ṁ max

p/ pmax

0.000 0.135 0.339 0.508 0.678 0.763 0.950 0.980 0.990 1.000

1.00 0.99 0.98 0.96 0.90 0.80 0.55 0.38 0.19 0.00

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at hourly intervals that is representative of long-term trends and the expected range of weather conditions for that location. Using this data therefore accounts for short-term and seasonal variations in solar irradiance. The solar field uses linear Fresnel reflector (LFR) technology to concentrate sunlight. The LFR arrays are based on those designed by Hyperlight Energy Ltd., and the optical and thermal efficiencies are based on Hyperlight Energy’s calculations and experiments. The optical efficiency ηopt of an LFR array may be written as

2.2. Steam turbine Off-design behavior of the steam turbine is modelled using Stodola’s ellipse which relates the mass flow rate, and the inlet and outlet pressures through [20]:

ṁ ( T01 )/ p01 = k [1−(p0e / p01 )2]1/2

(1)

where ṁ 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 relation [21]:

[1−(p0e / p01 )2]1/2 ṁ ⎛ T01 ⎞ p01, ref = ṁ ref ⎜ T01, ref ⎟ p01 [1−(p0e, ref / p01, ref )2]1/2 ⎝ ⎠

ηopt = γρτα·IAM(θ⊥, θ∥)

where γ is the intercept factor, ρ is the reflectance, τ is the transmittance, α is the average absorptance of the receiver surface, IAM is the incident angle modifier, and θ⊥, θ are the transversal and longitudinal incidence angles respectively. The incidence angles are calculated using the FirstOPTIC method developed in Ref. [28]. The IAM is a function of these angles and further details are provided in Ref. [29]. Heat transfer losses from the solar receiver are calculated using the empirical correlations similar to those in Ref. [30] and has the form:

(2)

A variety of physical mechanisms lead to entropy generation in the steam turbine, as described in Ref. [22]. Rather than undertaking detailed stage-by-stage calculations, stages are grouped into sections, and correlations of each section efficiency are used to predict turbine performance. These correlations are based on experimental results from turbine units, and from stage-by-stage calculations. The correlations were originally developed by Spencer-Cotton-Cannon [23,24], and computer code was developed in [25] and implemented by IPSEpro. The steam turbine is primarily operated with ‘sliding pressure’ control where the inlet pressure floats in response to the varying mass flow rate in accordance with Stodola’s ellipse to maintain a constant volumetric flow rate. It is assumed that the outlet pressure is fixed by the condenser pressure and is constant. The condenser is water cooled and its pressure therefore does not vary significantly with ambient temperature. This was found to be consistent with operational data from Coso power plant. The turbine is constrained to a maximum inlet pressure 10% greater than the design value. If more mass is available, a valve before the turbine is throttled to maintain the inlet pressure at its maximum value (which leads to larger losses). The excess steam is flashed in the second flash tank, and more steam enters the low-pressure turbine stage.

4 ϕ = 0.141Tabs + 6.48 × 10−9Tabs

(5)

where ϕ is the heat loss in W/m, and Tabs is the temperature in °C. However, the correlations have been updated to be more applicable to the LFRs developed by Hyperlight Ltd. Heat transfer fluid (HTF) fills the absorber pipe and surrounding pipework in the solar field. The volume of HTF per m2 of mirror area is calculated as 3.34 × 10−3 m3/m2 using dimensions of Hyperlight’s LFR array. There is a single absorber tube with a diameter of 90 mm for a pair of basins. The basin supports the mirrors. A basin has a length of 15.2 m and a mirror area of 72.5 m2. The HTF volume per m2 of mirror is therefore 6.67 × 10−4 m3/m2. This value is then multiplied by a factor of 5 to represent the additional HTF that is required to fill the pipelines. The solar field inlet and outlet temperatures are assumed to be kept constant by varying the HTF mass flow rate through the collectors. Therefore, as the solar irradiance increases, so does the mass flow rate. The size of the solar field is quantified using the ‘solar multiple’, σ. A CSP field with a solar multiple of one can provide the rated thermal capacity when the Direct Normal Irradiance (DNI) is at its maximum expected value (∼950 W/m2). Such a field will operate below its design point for much of the year, and it is conventional to oversize the solar field. Increasing the solar multiple proportionally increases the solar field size and its power output. A CSP field with a solar multiple of two will have double the area, for example. Typical values of solar irradiance and temperature for China Lake, California are shown in Table 2 and demonstrate a good solar resource.

2.3. Flash tanks The flash tanks are assumed to be isenthalpic and to separate the vapor and liquid with 100% efficiency. In practice, typical separation efficiencies are of the order of 99.9% [26]. 2.4. Heat exchanger Solar heat is transferred from a relatively hot heat transfer fluid (HTF) to the cooler geothermal fluid in a heat exchanger. The heat exchangers are modelled using a simple energy balance, such that

ṁ c (hc, out −hc, in ) = ṁ h (hh,in−hh,out )

(4)

2.6. Thermal storage model

(3)

The storage system comprises two tanks that contain the liquid HTF at different temperatures. In this analysis the cold store is at 190 °C and two different hot stores are compared. Depending on the maximum operating temperature of the HTF, hot stores at 300 °C and 400 °C are considered.

where h is the enthalpy and is a function of temperature and pressure. The geothermal fluid inlet temperature Tc, in is known (from the geothermal model), and its outlet temperature Tc, out and pressure are specified. The hot outlet temperature is given by assuming Th, out = Tc, in + ΔT, where ΔT = 25 °C. The hot inlet temperature is specified; two cases are examined in this paper, Th, in = 300 °C and Th, in = 400 °C. It is assumed that the solar field heats the HTF up to a constant temperature, Th, in which is achieved by varying the mass flow rate of fluid through the solar collectors.

Table 2 Typical solar properties at China Lake, California. Annual average Direct normal irradiance Global horizontal irradiance Temperature Wind speed Elevation Latitude Longitude

2.5. Solar field model The available solar resource was given by TMY3 (Typical Meteorological Year) data for China Lake, California, and was obtained from the System Advisor Model (SAM) [27]. TMY3 presents solar data 1840

China Lake, CA 2

kWh/m /day kWh/m2/day °C m/s m °N °E

7.75 5.75 18.2 3.5 677 35.68 −117.68

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where ṁ is the mass flow rate, h is the enthalpy, t is time, and in and out represent the flows into and out of the store, respectively. The volume of the containers required to store a quantity of energy E between two tanks at different temperatures is given by

Each store is governed by a mass and energy balance, given by:

dṁ = ṁ in−ṁ out dt

(6)

̇ ) d(mh = ṁ in h in−ṁ out hout dt

(7)

E = (βρf Vcp T )h−(βρf Vcp T )c

(8) COND

a T

PRE P FT1

Heat to geothermal plant

HS

HX

SF

CS

CND

To cooling tower

CW

FT1 FT2

Water Steam HTF

INJ

I

b

c 25

INJ INJ2 COND PRE FT1

17.5

Solar efficiency, %

1 st law efficiency, %

18.0

17.0

16.5

0

5

10

15

20

20

15

25

0

5

Solar heat addition, MWth

d

25

Net power, MW e

Net power, MW e

28

26

24

22

0

5

10

15

10

15

20

25

Solar heat addition, MWth

20

25

Solar heat addition, MWth

e

24

23

200

250

300

350

Temperature of heat addition,°C

Fig. 2. Solar heat can be added at different points in the geothermal power plant. (a) Schematic of hybrid power plant with solar heat added in five ways: INJ – injection brine is heated to saturation temperature; INJ2 – same as INJ, except fluid is heated until the vapor fraction is 50%; COND – The condensed water is heated; PRE – geothermal production fluids are preheated; FT1 – brine at the first flash tank exit is heated. (b) Variation of first-law thermal efficiency with the quantity of solar heat addition, Qsol. (c) Variation of solar-conversion efficiency with Qsol. (d) Variation of net power with Qsol. (e) Variation of net power with the temperature of solar heat addition. Key: SF – solar field; HS – hot storage; CS – cold storage; HX – heat exchanger; P – production well; I – injection well; FT1 – flash tank 1; FT2 – flash tank 2; T – turbine; CND – condenser; CW – cooling water. Valves, pumps etc. are not shown for clarity. In (b, c, and d) the solar field HTF is heated to 190 °C. The HTF cold temperature is set to be 25 °C greater than the geothermal inlet fluid. 1841

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30–40 injection wells. Each well has its own characteristics and fluid properties which can vary with time and the operation of other wells. There are nine 30-MWe turbine sets, and numerous pipelines, headers, separators and flash tanks. The simplified model contains one production well, one injection well, and one turbine set. Differences between the model results and the operational data may be attributed to these simplifications. Other factors that may cause errors are the age-related performance changes of the steam turbines, future changes in the behavior of the geothermal wells, changes in climate that affect the solar resource, and the impact of integrating solar heat into the geothermal plant. While these issues may cause problems with modelling the behavior specific to Coso, the results should still be representative of a typical double-flash geothermal plant.

Table 3 Design and off-design inputs and performance data used to model a two-stage steam turbine unit. Data provided by Coso Operating Company and is representative of the Coso geothermal power plant.

Mass flow Temperature Inlet pressure Gross power Net power Efficiency

kg s−1 °C bar MWe MWe %

Design conditions

Current operating conditions

High pressure

Low pressure

High pressure

Low pressure

48.0 169.2 6.3 29.6 29.4 19.7

25.0 132.5 1.4

43.8 159.8 5.7 22.5 22.2 16.9

7.1 98.3 0.95

3. Comparison of hybrid plant configurations where ρf is the fluid density, V is the volume, cp is the specific heat capacity, T is the temperature, and β is an additional factor which accounts for the fact that the tanks should be slightly oversized. The subscripts h and c represent the hot and cold store, respectively. The storage should deliver a power P for τd hours in order to have stored E. The energy is also given by

E = Pτ = ṁ (cp, h Th−cp, c Tc ) τd

Concentrating solar and thermal storage are added to a double-flash geothermal power plant which is assumed to be running at 75% of its design capacity. Fig. 2a indicates the layout of a double-flash geothermal power plant with a two-stage steam turbine, and the design point and current operating conditions are given in Table 3. The CSP field concentrates sunlight and heats a thermal oil which transfers its heat to the geothermal system. The thermal storage uses two liquidtanks which contain the same heat transfer fluid as used in the solar collectors. This is the most readily deployable storage solution available and has been used in several CSP installations previously [33]. Five methods of adding solar heat to the geothermal plant are considered, and a schematic diagram is presented in Fig. 2. In summary, these are:

(9)

The volume of each store is then given by:

̇ d mτ ρf

βV =

(10)

HTF thermal properties were collected from manufacturers and typically included specific heat capacity, density, vapor pressure, and viscosity. Properties vary smoothly with temperature, so intermediate values are evaluated with cubic spline interpolation. The enthalpy h and entropy s were evaluated using

h=

∫T

T2

1

cp dT ; s =

∫T

T2

1

cp T

dT

1. INJ: Add solar heat to brine that was going to be re-injected into the geothermal reservoir. 2. INJ2: Add solar heat to the re-injection brine until it is 50% vapor. 3. COND: Add solar heat to condenser water. 4. PRE: Add solar heat directly to the geothermal production fluids. 5. FT1: Add solar heat to brine that leaves the first flash tank.

(11)

A mineral oil and a synthetic oil are considered in this article, and thermal properties are provided in Appendix A. Water properties are calculated using CoolProp software [31].

The impact of adding solar heat Qsol on the power output and efficiency for these five configurations is presented in Fig. 2b–e. These figures indicate that Qsol increases power output and first-law efficiency η1, while the solar-conversion efficiency ηsol is fairly constant. Increasing Qsol increases the steam flow rate that is delivered to the highpressure turbine, thereby increasing the inlet pressure. However, the characteristic curve of the geothermal well has mass flow rate inversely related to pressure [19]. Increasing the turbine inlet pressure (and therefore the well pressure) requires a lower mass flow rate from the geothermal field, thereby potentially increasing the lifetime of the geothermal resource. The additional mass required by the turbine is supplied either by recirculating fluid or increasing steam generation. The turbine is operated with ‘sliding-pressure’ control, whereby the inlet pressure and mass vary in response to changes in the flow from the wells and the solar field. Above the maximum turbine inlet pressure, the turbine inlet is throttled, and a noticeable kink is apparent in the trendlines of Fig. 2b–e. The power continues to increase albeit at a slower rate, but ηsol drops significantly, as does η1. This is a unique advantage to retrofitting geothermal plants with solar. In a conventional CSP plant, once the turbine reaches its design point any excess solar heat has to be curtailed or stored. However, the hybrid plant has additional spare capacity in the turbine so that excess heat can be utilized – albeit at a lower efficiency. The five configurations are: INJ: In normal operation of the Coso geothermal plant, unflashed brine is pressurized to 15 bar and re-injected into the ground at ∼104 °C. In INJ, a fraction of this brine is heated by the solar field until becoming saturated liquid, and is then mixed with the production fluids. This configuration shows the poorest performance with the

2.7. Hybrid plant efficiencies The first-law thermodynamic efficiency of the hybrid system is given by:

η1 =

̇ Wnet ̇ ̇ Q + Qsol

(12)

̇ is the net work output, Q̇ is the heat addition across the where Wnet ̇ is the solar heat power block when no solar heat is added, and Qsol addition. Another useful metric is the solar thermal conversion efficiency which is defined as the net increase in electrical work divided by the solar heat input to the cycle:

ηsol =

̇ −Wȯ Wnet ̇ Qsol

(13)

where Wȯ is the work output when no solar heat is added. 2.8. Simplifying assumptions and sources of uncertainty The off-design performance of the geothermal plant was validated against operational data provided by Coso Operating Company for units at the Naval Air Weapons Base in China Lake, California [32], with model results agreeing with power plant data to within ± 5%. However, uncertainties exist for several reasons. The most substantial of these is the simplifications made to model the geothermal plant. For instance, Coso operates with between 80–90 production wells and 1842

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solar multiples of σ = 2 and 4, with the summer and winter solstices illustrating the extreme cases. At σ = 2 , the plant cannot deliver the target thermal power (8 MWth) in the winter solstice and stores are underutilized: over winter they discharge only 0.1% of the energy than if they were fully charged and discharged each day, see Table 5. The storage utilization can be used to evaluate whether the storage is appropriately sized, and is defined as the ratio of the actual energy discharged to the total quantity that could have been dispatched if the stores had been fully charged and discharged once per day. Solar multiples of 4 are large compared to most current installations. However, the stores are still used to only a small extent throughout the winter, with utilizations of 25% for an 8-h store. On the other hand, during the summer the stores are fully charged daily with utilizations over 99%. If the stores are full and the geothermal plant cannot accept all the available thermal power, then the power is curtailed, as shown in Fig. 3b, which indicates that the solar field is not cost efficient. There is an inherent trade-off in sizing the solar field and thermal stores: large solar fields are required to provide the required power in the winter. However, this leads to an oversupply of energy in the summer, requiring large stores to avoid curtailment. These large stores are then underutilized in the winter.

power input increasing 0.16 MWe per MWth heat addition. The 1st law efficiency η1 decreases as solar heat is added because the solar-conversion efficiency, ηsol is less than the 1st law efficiency when Qsol = 0 (proof in Appendix B). Increasing the re-heat brine temperature improves performance slightly, by increasing the specific enthalpy of the mixed fluid. INJ2: Evaporating the injection brine to a vapor fraction of 50% improves the performance compared to INJ. The solar-conversion efficiency increases to 22.5% from around 17% and η1 increases with heat addition. However, this approach may result in increased mineral deposition in the pipes and heat exchanger. Using a shell-and-tube heat exchanger, with the brine inside the tubes will make it easier to clean although phase change normally occurs on the shell-side. COND: Water leaves the condenser at ∼38 °C and 0.1 bar and can be evaporated without scaling issues. Saturated vapor is injected directly into the high-pressure turbine stage, and its temperature is set by the turbine inlet pressure. Alternatively, the turbine exhaust steam could be heated, which would increase the recirculated mass for the same heat addition since the exhaust is hotter (∼46 °C) than the condenser water. However, the exhaust is a low pressure (0.1 bar) two-phase mixture and compressing this fluid to the required turbine inlet pressure (6 bar) requires a considerable work input and a two-phase pump. Furthermore, an isentropic compression increases the fluid temperature to 550 °C thereby rendering the solar field redundant. PRE: The two-phase production fluids are heated directly, thereby increasing their vapor fraction. This method sees the highest increase in power output per unit heat addition, with ηsol = 25%. However, evaporation can lead to an increased rate of scaling [34] although the precipitation may be delayed by the introduction of H2SO4 [35]. A larger heat exchanger may also be required due to the larger flow rates and the lower heat transfer coefficients of two-phase flows. For instance, Qsol = 10 MWth heats 110.6 kg s−1 of production fluids compared to 24.6 kg s−1 for INJ and 62.0 kg s−1 for FT1. FT1: Brine leaves the first flash tank (FT1) at ∼165 °C compared the FT2 outlet which is 104 °C. Heating FT1 brine therefore recirculates more mass per unit heat addition. This approach has a comparable performance to PRE, with ηsol = 24.3%. Increasing the temperature that the fluid is heated to reduces net power by a small quantity – the increase in enthalpy of the mixed fluid is outweighed by the increased pumping power to keep the fluid saturated. This configuration has the best performance with the least risk of scaling and is investigated further below.

5. Levelized cost of electricity (LCOE) of the hybrid plant The levelized cost of electricity (LCOE) is calculated over a 30-year lifetime, for various sizes of solar field, storage durations, and HTF temperatures. The levelized cost of electricity is the cost that, if assigned to every unit of electrical energy produced over the lifetime of the plant, equals the total lifecycle costs when discounted back to the current year [36]. Here, the total lifecycle costs include capital costs and operational and maintenance costs, but other factors can also be included. For the hybrid plant where the power block and geothermal wells already exist, the annual electrical energy is given by the marginal increase in electrical energy above the base rate provided by the geothermal plant. The LCOE is calculated using the fixed charge rate (FCR) method:

LCOE =

Ccap FCR + M (14)

E

where Ccap is the capital cost, M is the annual operational and maintenance costs, 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. FCR calculation details may be found in Appendix C and Ref. [36]. The cost of each component is evaluated using correlations developed from the literature and industry representatives and are presented in Appendix C.

4. Annual simulations Variations in available solar resource affect the hybrid plant performance. The thermal power delivered by the solar collector is a function of the sun angle, the direct normal irradiance (DNI), the mirror properties and the temperature of the HTF. The design point of the hybrid plant has a net power generation of 24.2 MWe which is a 2 MWe increase in the electrical work output of the geothermal plant. This corresponds to a thermal power of 8 MWth for the FT1 configuration. Generating this thermal power requires a solar field with a mirror area of 14,159 m2 at the peak DNI on the summer solstice (973 W m−2). A solar field of this size has a solar multiple σ = 1. Increasing the solar multiple proportionally increases the solar field size and its power output. The operating point of the geothermal system with 8 MWth power addition is shown in Table 4. If the solar collectors provide more than 8 MWth, then the excess energy is stored. Once the thermal stores are full, the excess energy is dispatched to the geothermal plant, up to a maximum thermal input of 16 MWth, which corresponds to the point where the inlet pressure to the turbine can no longer be increased and the turbine must be throttled. Beyond this heat input, thermal energy from the solar field is curtailed. The hourly behavior of the hybrid system is illustrated in Fig. 3 for

Table 4 Operating point of hybrid plant using FT1 configuration.

Temperature Pressure Mass flow rate Recirculated temperature Recirculated pressure Recirculated mass flow rate Cold store temperature Hot store temperature* Solar thermal energy Gross power Net power 1st-law efficiency Solar thermal conversion efficiency

°C bar kg/s °C bar kg/s °C °C MWth MWe MWe % %

HP stage

LP stage

162.6 6.10 47.2 162.6 6.60 147.9 190.0 300.0/400.0 8.0 24.5 24.2 17.3 24.3

100.0 1.01 54.2

* The hot store temperature depends on the maximum operating temperature of the HTF. Two cases are investigated in this article. 1843

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a

b Collector thermal power Delivered thermal power Power delivered to/from stores Dumped

20

30

Power, MW th

Power, MW th

30

10 0 -10

20 10 0 -10

20-Jun 12 AM

21-Jun 12 AM

22-Jun 12 AM

23-Jun 12 AM

20-Jun 12 AM

Summer solstice

22-Jun 12 AM

23-Jun 12 AM

Summer solstice

c

15

10

Power, MW th

Power, MW th

15

21-Jun 12 AM

5 0 -5

d

10 5 0 -5

20-Dec 12 AM

21-Dec 12 AM

22-Dec 12 AM

23-Dec 12 AM

Winter solstice

20-Dec 12 AM

21-Dec 12 AM

22-Dec 12 AM

23-Dec 12 AM

Winter solstice

Fig. 3. Power flows in the hybrid power plant for the summer solstice and winter solstice. (a) Summer solstice, solar multiple = 2. (b), Summer solstice, solar multiple = 4. (c) Winter solstice, solar multiple = 2. (d), Winter solstice, solar multiple = 4.

increasing the storage duration, which explains why the lines begin to converge at large solar multiples. The choice of heat transfer fluid for the storage media significantly affects the LCOE. Fig. 4a illustrates the LCOE of a mineral oil (Xceltherm 600) which has low capital cost (2.5 $/kg), is non-toxic, and has low vapor pressures, so that the stores do not need to be pressurized. The maximum operating temperature of the mineral oil is 300 °C. On the other hand, a synthetic fluid with a maximum operating temperature of 400 °C is shown in Fig. 4b. This fluid is a eutectic mixture of diphenyl and biphenyl oxides (DPO) (marketed as Dowtherm A, Therminol VP1 etc.). DPO has more expensive upfront costs (3.1 $/kg) compared to mineral oils. Furthermore, operating at higher temperatures increases the vapor pressure (∼10 bar at 400 °C), requiring pressurized stores that are more expensive by a factor of ∼1.3. DPO is more toxic and less environmentally friendly than mineral oils. Operators may be cautious of storing large volumes of DPO after a fire at the SEGS1 CSP plant in 1999 destroyed 3400 m3 of DPO and caused considerable damage. Molten salts are another widely-used heat transfer fluid in solar applications. However, they are not appropriate for this application because the cold tank is close to the freezing point of most molten salts. Furthermore, the requirement for electric heaters in the thermal stores to keep the salts molten would increase the cost of the system. The cold tank in both cases has a temperature of 190 °C. Increasing the temperature difference between the stores increases the energy density, thereby reducing the storage volume and cost. Fig. 4 indicates that this outweighs the impact of using a more expensive HTF and a pressurized vessel. For instance, the LCOE of a system with DPO, σ = 2 , and 4 h of storage is 0.085 ± 0.011 $/kWh compared to an equivalent plant with mineral oil which costs 0.093 ± 0.011 $/kWh. Using DPO instead of mineral oil reduces the storage capital cost from 60 to 39 $/kWh. Note that the storage capital cost per unit energy can be calculated in two ways. The capital cost per unit energy capacity of the store is typically quoted. However, a more representative value is given by considering the utilization of the store—how much energy is discharged

Table 5 Performance of thermal stores in the hybrid plant.

Solar field mirror area Annual collector energy Annual increase in electrical energy Average electricity generateda Average first-law efficiency Capacity factorb

Total energy discharged Utilizationc Average energy discharged (May–Jul) Utilization (May–Jul) Average energy discharged (Nov–Jan) Utilization (Nov–Jan) Total energy curtailed

Solar multiple = 2

Solar multiple = 4

m GWhth

28,318 28.83

56,636 57.66

GWhe

6.97

11.37

MWhe

23.0

23.5

%

17.7

18.5

%

42.0

67.6

2

Storage 4h

8h

Storage 4h

8h

GWhth

6.1

7.0

9.7

17.4

% MWhth/day

52.4 30.0

30.0 37.7

83.2 31.8

74.6 63.4

% MWhth/day

93.4 0.1

59.0 0.1

99.3 14.9

99.0 15.7

% GWhth

0.2 0.0

0.1 0.0

46.5 10.7

24.6 6.7

a

The average electricity generated per day without solar is 22.2 MWe. The capacity factor is defined as the average additional electricity divided by the design value of additional electricity (2 MWe). c The storage utilization is defined as the total energy discharged divided by the total energy that would have been dispatched if the store had been fully charged and discharged once per day. b

Fig. 4 indicates that larger solar fields initially reduce the LCOE as more energy is delivered to the hybrid plant over the course of the year. However, increasing the solar multiple further leads to higher LCOEs because of increased curtailment. Curtailment can be reduced by 1844

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a

0.15

LCOE, $ / kWh

LCOE, $ / kWh

0.15

0.10

0.05

1

2

3

4

Fig. 4. Effect of solar field size and thermal storage sizing on the levelized cost of energy. (a) The hot thermal store is at 300 °C with Xceltherm 600 mineral oil for storage medium. (b) The hot thermal store is at 400 °C with DPO as the storage medium. The cold store is at 190 °C in both cases. The shaded bars indicate the mean LCOE plus/minus one standard deviation.

b Storage duration = 0.0 h Storage duration = 2.5 h Storage duration = 5.0 h Storage duration = 7.5 h Storage duration = 10.0 h

0.10

0.05

1

2

3

4

Solar multiple

Cost per discharged energy, $ / kWhdischarged

Solar multiple

over a typical cycle. Table 6 provides the capital cost per unit energy dispatched on average, which is significantly larger than the capital cost per unit energy capacity. For instance, the DPO store capital cost per unit energy dispatched is nearly double (72.5 $/kWh) the capital cost per unit capacity (41.3 $/kWh) because of a storage utilization of 57.0%. Larger thermal stores lead to higher LCOEs, as the total electricity generation remains roughly the same while the investment increases. The LCOE implies that the optimal storage size is zero as it does not reflect the value that storage provides to the plant or the grid by enabling the flexible dispatch of energy [37]. The ‘optimal’ storage size can be found by instead considering the capital cost per unit energy discharged on average, see Fig. 5. Large stores achieve economies of scale and have low capital costs per unit capacity. However, they are infrequently fully charged, so the capital cost per unit energy dispatch is high. Conversely, small stores are frequently utilized, but have higher capital costs per unit capacity. The ‘optimal’ storage duration is 3 h and 10 h for solar multiples of 2 and 3, respectively, when the storage fluid is DPO. This illustrates the inherent trade-off in sizing the thermal stores. Efficient use of the storage capacity requires small stores, but cost considerations indicate that larger stores are more cost-effective (from a storage perspective). Table 6 compares the economic cost of two solar field sizes with no storage and with the optimal duration of storage, according to the cost per kilowatt-hour dispatched for the DPO stores.

160 σ = 2.0 σ = 2.5 σ = 3.0 σ = 4.0

140 120 100 80 60 40

0

2

4

6

8

10

12

Storage duration, h

Fig. 5. Cost per unit energy dispatched of two-tank thermal storage using DPO. The hot store is at 400 °C and the cold store is at 190 °C, and the system discharges at 8 MWth.

6. Comparison with PV + storage and stand-alone CSP plants The economic feasibility of the hybrid plant is compared to a solar photovoltaic (PV) field with battery energy storage (BES) and a stand-

Table 6 Hybrid plant economics for different solar multiples, with and without optimally sized stores. Solar multiple = 2

Total energy Additional electricity Solar field cost Solar field HTF Pump cost HX cost HTF cost Storage cost Capital cost Storage cost Storage utilization LCOE

GWhth GWhe M$ M$ M$ M$ M$ M$ M$ $/kWh % $/kWh

Solar multiple = 3

0 h (mineral)

3 h (synthetic)

0 h (mineral)

10 h (synthetic)

28.8 6.98 4.25 0.230 0.211 0.060 0.0 0.0 4.750 0.0 0.0 0.069 ± 0.011

28.8 6.97 4.25 0.286 0.211 0.046 0.595 0.397 5.785 41.3 57.0 0.081 ± 0.011

43.2 9.34 6.37 0.345 0.211 0.060 0.0 0.0 6.986 0.0 0.0 0.076 ± 0.012

43.2 10.42 6.37 0.430 0.211 0.046 1.982 0.777 9.816 34.5 57.9 0.091 ± 0.011

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for systems including storage. Similarly to battery degradation, the HTF in the hybrid plant thermal stores degrades over time and has to be replaced. The above calculations assumed a replacement rate of 1% per year. However, if the plant is operated ineffectively then degradation rates could be higher. For a make-up rate of 10% per year (equivalent to replacing the fluid once every ten years) the LCOE is 0.089 ± 0.011 $/kWh for DPO with 3 h of storage and σ = 2 , and 0.109 ± 0.012 $/kWh for DPO with 10 h of storage and σ = 3, which is still more cost-effective than PV + BES. The LCOE of a stand-alone CSP plant is also evaluated for comparison. The same solar collectors and thermal storage are used as in the hybrid plant case. The system uses a synthetic oil that is operated between the same temperatures as the hybrid plant. The power block converts solar heat to electricity with a 35% efficiency and costs approximately 1500 $/kWe (this includes the turbine, generator and condenser) [38]. The solar multiple of the CSP plant is fixed at 2.5, and the power rating of the turbine is adjusted to produce an annual quantity of energy equivalent to the hybrid plant. The stand-alone CSP plant is affected more severely by curtailment than the hybrid plant. This is because the geothermal power plant can absorb a greater quantity of excess solar energy than an independent CSP field. As a result, the hybrid plant has a lower LCOE than the stand-alone CSP plant when storage is not included. When storage is included, the standalone CSP’s LCOE decreases since less energy is curtailed and more electricity is produced over the course of the year. However, the results in Table 8 demonstrate that the hybrid plant is still a more cost-effective option, due to the large capital cost of the power block and condenser in the stand-alone CSP plant. It is worth noting that the concentrating solar field has been assumed to have relatively conservative cost and performance parameters. For instance, the cost of the solar field is 150 $/m2 which is higher than costs proposed by some manufacturers. Furthermore, linear Fresnel reflectors typically have poorer optical performance than parabolic trough technologies, and thereby produce less energy over the course of a year. These results suggest that a hybrid geothermal-solar-storage system provides a relatively cost-effective way to add renewable, dispatchable power to the electricity grid compared to existing renewable alternatives.

alone CSP plant. PV systems have been widely deployed in recent years – particularly in California due to lower capital costs. For hybrid systems to be considered a worthwhile investment, they must achieve LCOEs competitive with conventional renewable technologies. The four hybrid plant systems described in Table 6 are compared to PV + BES and CSP systems that produce the equivalent annual energy. Photovoltaic and battery cost assumptions are summarized in Table 7. Photovoltaic cell capital costs are estimated from NREL’s Annual Technology Baseline [38]. Batteries are Lithium-ion batteries which have a lifetime of approximately 10 years [39]. Since the LCOE analysis occurs over a 30-year period it is assumed that the batteries are replaced at the 10th and 20th year of operation, and the total battery cost is discounted appropriately. Li-ion batteries are assumed to be operated to a maximum depth of discharge of 80% [40] – which effectively increases the required battery size capacity by 25%. The PV field energy output was modelling using the ‘System Advisor Model’ (SAM) [27]. The PV panels are assumed to be 1-axis tracking, with total system losses of 14.1%, an inverter efficiency of 96% and a DC-to-AC ratio of 1.2. (These are the default values in SAM). The PV field LCOE is evaluated with the FCR method and has the same economic assumptions as the hybrid LCOE calculations, so that the results are directly comparable. The nominal PV power capacity is 2 MWe which equals the nominal design point of the hybrid plant which generates an additional 2 MWe. The PV field is sized so that it produces the same annual quantity of energy as the equivalent hybrid plant. As a result, the PV field that corresponds to a hybrid plant with a solar multiple of 2 has a rated power of 3.225 MWe while the PV field that corresponds to a hybrid plant with a solar multiple of 3 has a rated power of 4.82 MWe. It is assumed that all the power produced by the PV field can be absorbed by the grid. Thus, no power is curtailed. When storage is not included PV arrays have similar costs to the hybrid-geothermal system, as shown in Table 8. However, batteries have higher capital costs (200–800 $/kWh) and shorter lifetimes (10 years) than thermal storage [40,41]. Consequently, the LCOE of the hybrid plant with storage is lower than the PV + BES system. For instance, the hybrid plant with σ = 2 and 3 h of storage has an LCOE of 0.081 ± 0.011 $/kWh, compared to the equivalent PV field value of 0.148 ± 0.066 $/kWh. Similarly, the hybrid plant with σ = 3 and 10 h of storage has an LCOE of 0.091 ± 0.01 $/kWh, compared to the equivalent PV field value of 0.254 ± 0.130 $/kWh. The wide variance in battery costs leads to a large spread of possible LCOEs, but it is worth noting that even the lowest cost batteries (200 $/kWhe) lead to systems with higher LCOEs than the hybrid system (0.0821 and 0.125 $/kWhe, for the 3 h and 10 h storage, respectively). For comparison, other studies have calculated the LCOE of PV-BES to be 0.082 $/kWh [42] for a 200 MWe solar field with 10 h of storage, and 0.16 ± 0.05 $/kWh and 0.19 ± 0.05 $/kWh [41] for a 100 MWe solar field with 3 and 9 h of storage, respectively. These results suggest there is a compelling economic argument to consider hybrid plants as a competitor to PV systems with batteries. A major factor in the high LCOE of the PV + BES system is the high cost of batteries, the requirement to replace them periodically, and the limited maximum depth of discharge. Furthermore, the above PV + BES analysis is somewhat optimistic for several additional reasons. The effects of battery degradation over time have been neglected, but this affects the lifetime and can reduce energy capacities over time [43]. The round-trip efficiency is assumed to be 100%, while current estimates place the value in the range of 85–95% for Li-ion batteries. In this simplified analysis it is assumed that all electricity generated by the PV field can be dispatched to the grid. Storage is employed to provide flexibility but would reduce the annual electricity dispatched. The LCOEs therefore represent a lower bound which would increase as the benefits of storage were taken advantage of and more accurate battery models were employed. Of course, the LCOE does not account for the price electricity is sold at and is not necessarily the most suitable metric

7. Flexible power generation Storage increases a plant’s flexibility as power can be dispatched during hours of greatest demand. Dispatchable power generation is increasingly important as renewable penetration increases. For instance, large quantities of solar power on the Californian grid has led to a surplus of power during the afternoon [44]. This results in the socalled “duck curve” [45] whereby firm capacity must be rapidly dispatched during the evening hours. The abundance of intermittent generation has led to volatile electricity prices, which can become negative [46]. Consequently, power generation units should be flexible; reducing power delivery during the afternoon and ramping at high rates during the evening. Combining baseload production (geothermal) with variable production (CSP) and thermal storage provides the flexibility to operate in such a marketplace. A hybrid system which includes Table 7 Cost assumptions for a photovoltaic solar array with Lithium-ion battery storage.

PV capital cost Operations cost Storage capital cost

1846

$/kWe $/kWe $/kWhe

Low

Medium

High

Reference

1000 14 200

1300 14 500

1700 14 800

[38] [27] [40,41]

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future years), as well as a control system for the optimal dispatch of storage. Such analyses may result in optimal storage sizes and utilizations that differ from the above results. The present analysis assumes that storage provides value to the grid in various ways that may not be directly quantifiable. Therefore, the price multipliers reflect the average price that stored energy must be dispatched at for the system to be viable.

Table 8 LCOE comparison of hybrid geothermal-solar-storage with photovoltaic cells with battery storage, and a stand-alone CSP plant with thermal storage. LCOE, $/kWhe

Annual energy generation, GWhe

Storage duration, h

Hybrid plant

PV + BES

Stand-alone CSP

6.98

0 3

0.067 ± 0.011 0.081 ± 0.011

0.062 ± 0.014 0.148 ± 0.066

0.102 ± 0.013 0.096 ± 0.011

9.34

0 10

0.076 ± 0.012 0.091 ± 0.011

0.062 ± 0.014 0.254 ± 0.130

0.102 ± 0.013 0.093 ± 0.011

8. Alternative storage systems Two-tank liquid stores are the most readily deployable storage system for CSP plants, but several other pre-commercial storage technologies exist that may be more compact and cost effective. Options include solid sensible storage, phase change materials (PCMs) or thermochemical storage [47]. Solid sensible storage is currently the most cost-effective option with the lowest technological complexity [48], and includes concrete blocks to which heat is transferred through pipes [49], or packed beds: a storage vessel filled with solid particles through which the HTF percolates [50]. For a packed bed, the energy stored is given by:

dispatchable storage can provide other benefits to the grid, such as frequency control. Since dispatchable power generation is a valuable commodity it should be priced accordingly. This section investigates the price that stored energy should be dispatched at for the hybrid system to be economically viable. The hybrid plant electricity is sold at a flat rate of 0.09 $/kWe. Electricity produced by discharging the stores is sold at a multiple of the flat rate, called a “price multiplier”. For a system with a given storage duration and solar multiple, the price multiplier required for the system to achieve an internal rate of return of 10% is calculated. (This value of IRR represents a scenario where a system looks profitable. The IRR is calculated using the methodology in [36] and described in Appendix C). Results are presented in Fig. 6. The curves indicate that there is an optimal storage size: as discussed above, small quantities of storage are expensive per kWh and therefore require high price multipliers. Increasing the storage size increases the economic return, although extremely large stores are underutilized and again require high price multipliers. For solar multiples of 2, the optimal storage size is around 3–4 h. Increasing the solar multiple increases the optimal storage duration to around 10 h, as thermal energy availability has increased. Using a synthetic fluid typically requires lower price multipliers to achieve a profitable IRR than mineral oils, which is consistent with the above analysis. Profitable IRRs can be achieved with price multipliers in the region of 1.5–1.75. This analysis assumes that all dispatched energy from storage receives the increased price. As such it is not a reflection of the current electricity market where prices vary throughout the day and across the year. In such a scenario, large storage systems may be of little use, since higher prices may only be available for one or two hours of the day (and may coincide with times of high solar availability). Analyzing this scenario requires time of delivery pricing (including estimates for

a

E = β (1−ε ) ρs V [(cs T )h−(cs T )c ]

where ρs is the solid density, cs is the solid heat capacity, and ε is the void fraction (the fraction of space not filled by particles), T is the temperature, V is the volume, and β is a simple factor that accounts for the fact that the thermal front in the store is not a step function but has a finite gradient. This means that the full storage is not utilized and should be oversized in order to store the required energy. Subscripts h and c refer to the hot and cold temperatures, respectively. The packing material is an iron oxide such as magnetite (Fe3O4) with an average cs = 800 kJ/kg K, ρs = 5000 kg/m3, ε = 0.4 and β = 0.75. The cost of the packing is estimated to be 500 $/m3 [51], and the pressure vessel cost is calculated with the correlations in Appendix C, and uses DPO as the HTF. Two-tank liquid storage with 4 h of discharge (32 MWh) operating between 400 °C and 190 °C requires each tank to have a volume of 330 m3, and a total capital cost of 39 $/kWh. However, a packed bed with the same energy capacity and operating temperatures would be 315 m3 and 14 $/kWh. Moreover, the HTF volume is reduced from 300 m3 to 126 m3, thereby reducing the severity of fire risk. However, the discharging temperature varies with time and the round-trip efficiency may be affected by irregular charge and discharge cycles [52]. Numerous schemes have been proposed to mitigate these problems, such as the inclusion of PCMs [53], the segmentation of the bed into layers [54,55], or mixing the discharging flow with a cooler fluid to

b

4.0

Synthetic oil, SM = 2 Synthetic oil, SM = 3

Price multiplier

Price multiplier

Mineral oil, SM = 2 Mineral oil, SM = 3

2.0

1.0

Fig. 6. Curves showing the price multiplier required for a hybrid system with a given storage duration to achieve an internal rate of return of 10%. The price multiplier is the increased price that stored energy is dispatched at. Shaded bands show the uncertainty. (a) Mineral oil storage, with the hot store at 300 °C. (b) Synthetic oil storage, with the hot store at 400 °C.

4.0

3.0

0

2

4

6

8

Storage duration, h

10

12

3.0

2.0

1.0

0

(15)

2

4

6

8

Storage duration, h 1847

10

12

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power at times of high electricity prices. Calculations indicate that the price needs to be roughly double the typical flat-rate price of 0.09 $/kWe for storage to provide internal rate of returns over 10%. These price points are small compared to the price fluctuations that are currently observed in the Californian energy market. However, exploiting price differentials may not be an option for some current geothermal plant operators if they are committed to an existing power purchase agreement which specifies a fixed electricity price. The results of this study suggest that hybridizing concentrating solar power with geothermal energy and thermal storage can be a cost-effective strategy to add dispatchable renewable energy to the grid. Numerous existing geothermal plants could potentially benefit from the addition of solar heat to increase power output. This article suggests an effective way to integrate the two systems without requiring the installation of a topping cycle. Future studies should consider more practical aspects – such as long-term trends in geothermal well performance, quantify the risk and mitigation of scaling in components, and the effect of electricity price fluctuations on operating strategies and plant design.

control the mixture’s temperature. Evaluating the influence of this transient behavior on the integrated plant performance will determine the true cost savings. 9. Conclusions In this article, an existing double-flash geothermal power plant is retrofitted with concentrating solar power to increase the power generation. Solar heat is added in five different configurations, and the most suitable approach involves reheating the brine after the first flash tank. The solar heat added to this brine is converted to electricity with an efficiency of 24.3%. This approach has a reduced risk of depositing minerals on the heat exchangers or pipework compared to other methods. Retrofitting in this way is cost effective since the existing power block, pipework, and condenser can be used. Various other approaches exist, such as using solar heat to power a high-temperature topping cycle. Heat could be rejected into the geothermal plant to improve generation. A topping cycle will increase the capital cost but will achieve higher efficiencies. Furthermore, storage systems at higher temperatures are likely to be more compact and cost effective. Incorporating two-tank liquid thermal storage into the hybrid plant increases the flexibility of the plant, at increased capital cost. Increasing the temperature difference between the tanks reduces the volume, and thus the cost. This is an effective approach even if more expensive storage fluids and pressurized vessels are required. The levelized cost of electricity (LCOE) was calculated for several storage durations and solar field sizes and was found to be significantly lower than equivalently sized photovoltaic arrays with battery storage because thermal stores are cheaper and have longer lifetimes than batteries. For instance, a system with 3 h of storage had an LCOE 28% lower, while a system with 10 h of storage was 47% lower. The hybrid plant also had a lower LCOE than a conventional stand-alone concentrating solar power (CSP) plant. Hybrid geothermal-solar-storage systems therefore provide a relatively cost-effective way to add renewable, dispatchable power to the electricity grid compared to existing renewable alternatives. Concrete stores and packed-beds are likely to provide cheaper, more compact storage than liquid tanks, albeit at increased complexity and risk. Storage provides numerous benefits to the grid and can dispatch

Acknowledgements This work was authored in part by Alliance for Sustainable Energy, LLC, the manager and operator of the National Renewable Energy Laboratory 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 and Solar Energy Technologies Office. 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. The authors gratefully acknowledge Dr. Mike Erbes for assisting with the off-design steam turbine modeling and the Naval Geothermal Program Office, including Dr. Andrew Sabin, Mr. David Meade, Mr. Michael Lazaro, and Ms. Kelly Blake, for their contributions.

Appendix A. Thermal properties of heat transfer fluids See Tables 9 and 10. Appendix B. Proof showing 1st law efficiency decreases as solar heat is added The first law efficiency of a system with no solar heat input is

η1, o =

Wo Q

The first law efficiency of the hybrid plant including a solar heat input is

η1 =

W Q + Qsol

The solar conversion efficiency is

Table 9 Thermal properties of mineral oil Xceltherm 600. Temperature

Vapor pressure kPa

Viscosity

°C

Heat capacity kJ/kg K

2

mm /s

kg/m

25 100 200 300 400

2.0 2.3 2.6 2.9 –

0.0 0.0 1.1 19.0 –

31.0 3.0 0.8 0.4 –

848.0 804.0 743.2 682.5 –

1848

Density 3

Thermal conductivity W/m K 0.14 0.13 0.12 0.11 –

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J.D. McTigue et al.

Table 10 Thermal properties of synthetic fluid, Therminol VP1 (DPO). Temperature

Vapor pressure kPa

Viscosity

°C

Heat capacity kJ/kg K

mm /s

kg/m

25 100 200 300 400

1.6 1.8 2.0 2.3 2.6

0.0 0.5 10.1 241.5 1086.0

3.6 1.0 0.4 0.3 0.2

1060.6 998.3 912.6 816.4 694.2

ηsol =

2

Density 3

Thermal conductivity W/m K 0.14 0.13 0.11 0.10 0.08

W −Wo Qsol

The first law may therefore be written as

η1 =

W + ηsol Qsol Q + Qsol

Differentiating with respect to Qsol leads to

η Q−Wo ∂η1 = sol (Q + Qsol )2 ∂Qsol In order for the first law efficiency to increase with solar heat addition, the first derivative must be greater than zero, this leads to the condition

ηsol >

Wo = η1, o Q

Appendix C. Cost correlations Cost correlations for storage vessels: The pressure vessel contains the storage media. Pressure vessel cost estimates were obtained from PCL Construction by Coso Operating Company and fitted well with a correlation derived from Peters and Timmerhaus [56] (when costs were inflated to current values) for unpressurised vessels. The cost of the vessel depends on its volume V and is given by:

Cves = 7351·V 0.557 Pressurizing the store significantly increases the cost, and the following correlation was obtained from EconExpert [57] (an online tool for capital cost estimation) for pressures over 7 bar:

Cpres = 0.922 + 0.0335P−0.0003P 2 + 1 × 10−6P 3 The total cost of the pressure vessel is therefore given by CPV = Cpres·Cves . Cost correlations for heat exchangers: Correlations from EconExpert for a floating-head, shell-and-tube heat exchanger constructed from carbon steel.

CHX = β (18944.44 + 280.71A−0.06601A2 ) β = 1 for P < 10 bar β = 1.0011 + 0.001P for P ⩾ 10 bar where P is the pressure, and A is the heat transfer area. A is calculated using the log-mean temperature difference method, where

A=

Q U ·LMTD

where Q is the heat transferred, U is the overall heat transfer coefficient (assumed to have a constant value of 1000 W/m2 K) and LMTD is the logmean temperature difference, given by

LMTD =

ΔTh−ΔTc log(ΔTh)−log(ΔTc )

where ΔTh is the temperature difference on the hot side of the heat exchanger, and ΔTc is the temperature difference on the cold side of the heat exchanger. Solar field costing: The solar field cost is assumed to be in the range of 100–200 $/m2 following discussions with solar collector manufacturers. HTF costing: Following contact with manufacturers and suppliers, Xceltherm 600 was priced at 2.5 $/kg and Therminol VP1 was priced at 3.1 $/kg for bulk quantities (over 19 m3 or 5000 gallons). The HTF degrades over time and is replaced at a rate of 1% per year over the lifetime of the plant. Pump costing: This correlation was derived from EconExpert for a centrifugal pump made from cast steel. P is the discharge pressure, and Ẇ is the rated power.

Cpump = 5648.8P 0.4305Ẇ 0.4121 Price of electricity: The price of electricity was set at 0.09 $/kWh following discussions with industrial partners. 1849

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Sensitivity analysis: The cost of each component was assumed to follow a normal distribution C ∼ N (μ, σ 2) , which was truncated to prevent negative costs. A Monte Carlo simulation with 10,000 runs was undertaken. For each run, each component normal distribution was sampled, and the economic metrics evaluated to develop a distribution of costs. The mean value of each distribution was that given by the equations above. The value of the standard deviations are given in Table 11. Economic assumptions: Economic parameters for calculating the LCOE and IRR are summarized in Table 12 and are the default values used in the System Advisor Model (SAM). The LCOE is calculated using the fixed charge rate (FCR), as in Eq. (14). This relatively simple method is used to reduce the number of uncertain variables in the economic calculations. SAM is also widely employed, so using the FCR method facilitates comparison with other studies. More detailed LCOE calculations are possible, such as those discussed in [58]. These advanced models can include details such as shadow pricing of capital costs, re-investments, and scrap values. C.1. Calculation of the fixed charge rate (FCR) The values in Table 12 are used to calculate the fixed charge rate, which is used to evaluate the LCOE from Eq. 14. The FCR is given by:

FCR = (PFF)(CRF) where PFF is the project financing factor, and CRF is the capital recovery factor. PFF is given by

PFF =

1−T (PVDEP) 1−T

where T is the tax rate and PVDEP is the present value of depreciation, which is given by: N

PVDEP =

∑ j=0

Dj (1+WACC) j (1 + i) j

where Dj is the depreciation rate in year j, i is the inflation rate, and WACC is the weighted average cost of capital, given by:

WACC =

1 + (1−d )((1 + RROE)(1 + i)−1) + d (1−T )((1 + RINT)(1 + i)−1) −1 1+i

where d is the project debt fraction, and RROE is the real return on investment, given by:

RROE =

1+IRR −1 1+i

where IRR is the internal rate of return. RINT is the real debt interest rate:

RINT =

1+NINT −1 1+i

where NINT is the nominal debt interest rate. The CRF is given by:

CRF =

WACC

(

1−

N 1 1 + WACC

)

where N is the lifetime of the plant in years, which is assumed to be 30 years. C.2. Internal rate of return The internal rate of return (IRR) of an investment that has a series of future cash flows Fi is the rate of return that sets the net present value (NPV) of the cash flows equal to zero. N

∑ i=0

Fi = NPV = 0 (1 + IRR)i

where the cash flow F in year i is given by

Fi = Ri−Ii−Mi−(Ri−Di−Mi ) T where R is the revenue, I is the investment, M is the O&M costs, D is the depreciation, and T is the tax rate. For the hybrid plant, the revenue is the marginal revenue above that which would have been produced by the geothermal power plant. Table 11 Parameters used in sensitivity analysis.

Solar field HTF Pressure vessel Heat exchanger Pump Electricity price

Mean value, $

Standard deviation

Upper limit

Lower limit

150 – – – – 0.09

0.20 µ 0.10 µ 0.25 µ 0.20µ 0.20 µ 0.20 µ

10 µ 5.0 µ 20 µ 10 µ 10 µ 1.50 µ

0.30 0.30 0.30 0.30 0.30 0.20

Dash indicates costs are calculated from correlations above. 1850

µ µ µ µ µ µ

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Table 12 Economic factors used in LCOE calculations. Economic parameters

Assumed values

Tax rate, T, % Inflation rate, i, % Project debt fraction, d, % Internal rate of return, IRR, % Nominal debt interest rate, NINT, % Depreciation rate, Dj, %

40 2.5 60 10 8 20, 32, 20, 14, 14; 0 thereafter

Note that the equation for IRR is a Laguerre polynomial with N roots. For the case of an initial cash investment followed by cash inflows, there is only one positive root, and the remainder are negative or imaginary.

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