Economic evaluation of a novel fuel-saver hybrid combining a solar receiver with a combustor for a solar power tower

Applied Energy 113 (2014) 1235–1243

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Economic evaluation of a novel fuel-saver hybrid combining a solar receiver with a combustor for a solar power tower G.J. Nathan a,⇑, D.L. Battye b, P.J. Ashman b a b

Centre for Energy Technology, Schools of Mechanical Engineering, University of Adelaide, SA 5005, Australia Centre for Energy Technology, Schools of Chemical Engineering, University of Adelaide, SA 5005, Australia

h i g h l i g h t s  A new concept is proposed, integrating a solar thermal receiver with a combustor.  Total infrastructure is reduced by eliminating the boiler as a separate device.  The levelized cost of electricity is reduced relative to the equivalent hybrid.  The hybrid offers continuous operation, reduced losses and reduced thermal shock.

a r t i c l e

i n f o

Article history: Received 1 January 2013 Received in revised form 22 August 2013 Accepted 28 August 2013 Available online 21 September 2013 Keywords: Solar-thermal power generation Hybrid receiver combustor Hybrid Levelized cost of electricity (LCE, LCOE)

a b s t r a c t The novel concept of a hybrid receiver–combustor, HRC, is presented, in which the functions of a solarreceiver and a combustor are combined into a single device. An economic assessment of this concept is then performed for a solar power tower electricity generating plant employing molten salt technology, to evaluate the conditions under which an economic benefit can be derived. The HRC is compared with an equivalent well-known concept of Solar Gas Hybrid, SGH, with otherwise of identical specifications, for both 1 h and 13 h of thermal storage capacity and also with an equivalent stand alone solar power tower, SPT, and a gas-only boiler. All hybrid configurations are designed to provide 100% of the electrical demand continuously, i.e. to operate in the fuel-saver mode. Costs of each configuration are compared for a constant size of power block and also for a constant size of heliostat field using a consistent and well established cost-estimating methodology. On the assumption that the HRC achieves the same combustion efficiency as the boiler for twice the capital cost of a solar receiver, the HRC is found to reduce both the overall capital cost and the levelized cost of generating electricity relative to the equivalent hybrid. The benefit is attributed to the increased sharing of infrastructure and to allowing a slightly smaller heliostat field size for the case of the same size of power block. The HRC has the additional benefit of reduced operation and maintenance due to reduced thermal cycling and of reduced thermal shock, although these are not included here owing to a lack of data with which to evaluate it reliably. Ó 2013 Elsevier Ltd. All rights reserved.

1. Introduction Hybrids of concentrated solar thermal energy and fossil-fuelled technologies are receiving growing attention owing to the complementary nature these two energy sources [1]. Solar thermal power offers low net greenhouse gas emissions but suffers from high cost, due largely to the intermittent nature of the resource, while the combustion of fossil fuels offers high availability and low fuel cost, but at the expense of high CO2 emissions. Kolb [2] was a pioneer in identifying economically beneficial configurations of hybrids between solar thermal and combustion processes in Rankine cycle boilers. Later, Ying and Hu [3] showed that the greatest ⇑ Corresponding author. Tel.: +61 8 8313 5822; fax: +61 8 8313 4367. E-mail address: [email protected] (G.J. Nathan). 0306-2619/$ - see front matter Ó 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.apenergy.2013.08.079

thermodynamic leverage for the solar energy in a Rankine cycle can be achieved when it is used to pre-heat the feed-water to a boiler, since the low grade solar heat can be used to displace high grade steam bled from the boiler. In a related approach, the thermodynamic benefits associated with displacing bled steam were identified by Mokhtar et al. [4], who proposed the use of low grade solar thermal heat to regenerate CO2 solvents, such as amine solutions, for application in the carbon capture and storage process. Hybrid concepts to drive a Brayton (gas turbine) cycle are also under development, using a solar-air receiver to preheat the combustion air [5–7]. These systems have achieved an instantaneous solar fraction of 60–70%, albeit at a relatively low thermodynamic efficiency of around 18%. In another recent concept, Gou et al. [8] proposed an alternative power cycle combining oxy-fuel combustion with solar thermal that claims a 95% conversion efficiency of fuel

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Nomenclature Ah total heliostat area (solar field size), km2 Capexoverall overall capital cost Capexsolar capital cost of solar component CPC compound parabolic concentrator CSR concentrated solar radiation EPGS Electrical Power Generating System GB gas-fired boiler plant HRC Hybrid Receiver–Combustor LCEgas levelized cost of electricity of gas-fired plants LCEoverall overall levelized cost of electricity of stand-alone or hybrid plants LCEsolar Effective levelized cost of solar electricity LCE levelized cost of electricity O&M operating and maintenance

to electricity. Notwithstanding the potential thermodynamic benefits that have been identified from these various types of hybrid, little further attention has been paid to the economic benefit of shared infrastructure since it was first identified by Kolb [2]. He demonstrated that the cost of the solar component of energy can be reduced by approximately 50% relative to a stand-alone plant through sharing infrastructure, notably the condenser and turbine, with the fossil-fuelled plant. However, a further step in the integration of infrastructure is possible by seeking to combine the infrastructure used to collect the heat from the solar radiation with that from the combustion processes. A step toward such integration was identified by Mehos et al. [9], who proposed a device in which the combustor is mounted to the back of the receiver cavity. Nevertheless, that device also uses separate chambers for the combustor and receiver. To our knowledge no previous report in the public domain has proposed the concept of a fully integrated hybrid receiver–combustor, although this concept has been under development at the University of Adelaide for several years [10,11]. Hence also, no assessment is available of the potential economic benefits of directly sharing the heat exchange surfaces used to collect the two energy sources. The primary aims of the present investigation are therefore to present such a concept and to evaluate the conditions under which it can be economically beneficial. It is also noteworthy that the hybrid solar-combustion systems proposed for boilers to date1, from which the heat is applicable to process heating as well as to power generation, achieve an economic benefit solely in the ‘‘power booster’’ mode2 [2,12]. In contrast, these same hybrid configurations actually increase the cost of power in the ‘‘fuel saver’’ mode3 [2,13]. The power-booster mode is more economically beneficial than the fuel save mode follows because it produces more revenue for essentially the same capital investment in solar collector plant. That is, this additional capital is difficult to recoup simply by displacing relatively low-cost fossil fuels, while there is typically more value in increasing the power output. Notwithstanding the acknowledged relevance of the power booster mode to grid-connected applications, there is also a need for a cost-effective

1 It should be noted that the hybrid solar-combustion gas turbine systems currently under development [5–7] also operate in the fuel saver mode. However, such concepts are not relevant to process heat and these programs do not obviate the need to also assess fuel-saver concepts for boilers. 2 ‘‘Power-Boosting’’ is the name coined to describe the case in which the solargenerated heat is used to intermittently increase the power output the turbine relative to the base-load output from combustion boiler. 3 ‘‘Fuel-Saving’’ describes the case where the solar-generated heat is used to intermittently displace some of the fuel fed to the boiler, while maintaining a constant power output from the turbine.

Pg PLE Qrec Qstm S SGH SPT xgas xsolar We

gross electrical power, MWe parasitic load efficiency receiver heat gain, MWth steam cycle thermal input, MWth thermal storage capacity, (MW h)th solar-gas hybrid solar power tower annual fraction of net electrical energy generated from natural gas in hybrids annual fraction of net electrical energy generated from solar radiation in hybrids work, electrical, MWe

configuration of fuel-saver hybrid heat generator. One such application is in the off-grid power market, which is an important target for solar thermal technology for three reasons [13]. Firstly, owing to the relatively small scale of off-grid sites, the benchmark price against which solar power must compete is typically that of diesel powered internal combustion engines, known as ‘‘Gen. Sets’’, whose average LCE is considerably higher than that of grid-connected power. (For example, in Australia, diesel generation is typically $450/MW h, while the average price of grid power is $60/MW h; [14]. Secondly, the scale of off-grid power systems is typically 5–150 MW, which is within the range where solar thermal technologies have been demonstrated. Finally, many of these off-grid markets are located in regions where the average solar insolation is typically higher than in major population centers, making it well suited to solar energy. A second important application for fuel saver hybrids is in process heating applications for chemical products, etc. [1]. The demand characteristics for most processing plant contrasts that of electrical generation in being steady, to maximize both the process stability and the economic utilization of the plant. Hence the need for fuel-saver solar-combustion hybrids is significant. The integration of solar receiver and a combustor is best achieved by adapting a solar power-tower solar receiver system, rather than by distributed systems such as parabolic troughs or linear Fresnel arrays. This is because the heat of combustion is best collected in a single central device, both to minimize heat losses (which scale with the surface area to volume ratio) and to capitalize on economies of scale. Solar power towers, in which a central receiver is mounted on a tower to harvest the concentrated solar radiation, CSR, from a heliostat field, have now been demonstrated in many projects around the world [15,16]. They are expected in the long term to offer a lower cost of electricity over parabolic trough systems because of their capacity to take better advantage of the economies of scale [12]. Nevertheless, the present levelized cost of electricity (LCE) from power towers is typically higher than that from parabolic trough systems, owing to their later development [17]. Furthermore, both types of power are presently significantly more expensive than conventional fossil-fuel and nuclear generation [13,17,18]. Hence there is also a need for further technological advances to reduce the cost of power-tower generation technologies, especially at small to medium scale, to facilitate their competitiveness in the longer term. For this reason, a further aim of the present investigation is to assess the potential of the hybrid receiver–combustor concept to lower the cost of solar power tower technologies. The high capital cost of solar thermal power is an additional barrier to their widespread implementation and hence leads to

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their high LCE. Wüstenhagen and Menichetti [19] demonstrate that the financial risk to investors increases with the capital cost, which constitutes a barrier to the implementation of renewable energy. Furthermore, subsidies for green energy generation such as renewable energy certificates, despite some advantages, fail to fully mitigate long term risks, since they are vulnerable to changes in government policy [20]. For this reason, a further aim of the paper is to assess the potential of the proposed HRC to lower the capital cost of the solar component of energy, and hence also to lower the commercial risk relative to previously known hybrid concepts. In light of the needs identified above, the first aim of the present paper is to present a novel concept for a Hybrid Receiver–Combustor (HRC), in which the functions of a solar receiver and a combustor are integrated into a single device. The second aim is to evaluate the economic benefit of this concept of fuel-saver hybrid. In particular it aims to identify the conditions under which the LCE and the capital cost can be reduced relative to a solar-only plant and a range of equivalent hybrid configurations based on existing receiver and boiler technology.

Solar Receiver Circulated Molten Salt

CPC

Hot Storage Tank Circulated steam

Steam Gen. Cold Storage Tank

It is readily apparent that different working fluids can be applied to both stand-alone solar and to hybrid systems. Hence, in seeking to evaluate the benefit of the HRC integration, it is necessary to choose two systems that are identical in all aspects except for this. We have chosen to do this with molten salt as the working fluid because the most complete performance data are available for this case. Fig. 1 presents the key components of the reference hybrid case of an established solar power tower system, here utilizing a cavity receiver combined with a gas boiler. This system employs molten salt technology and is similar to one of the hybrid configurations operated in the fuel-saver mode evaluated by Kolb [2]. Fig. 2 presents the equivalent HRC, in which the boiler has been removed and the combustion systems have been integrated within the HRC. That is, the flame burns within the same cavity used to collect the CSR. To allow a direct comparison between the two systems, both cases examined here employ the same molten salt technology. A moveable shutter has also been added to the HRC to cover the aperture and reduce losses when the solar insolation drops below a useful threshold. The integration of the cavity receiver and the combustor into a single unit reduces the number of components by one, and thus also the total infrastructure required to deliver 24-h dispatchable power. This integration can be expected to deliver the following qualitative benefits:  It eliminates the boiler as a separate component, thereby reducing the total heat-exchange area, heat losses, thermal cycling and maintenance costs. It can also be expected to reduce capital cost.  The integration of the boiler and receiver reduces energy losses. It eliminates energy wasted during warm-up of the boiler in a conventional solar-gas hybrid. Also, because the molten salt is continuously heated in the receiver–combustor, less energy is lost on parasitic loads for electrical heat tracing of pipes carrying molten salt than for the reference receiver.  The integration can be used to reduce the amount of thermal storage while still offering continuous supply. For the present assessment it is assumed conservatively that 30 min of storage is required to allow for contingencies in transitioning between the two energy sources due to, for example, difficulties in lighting the flame. The economic benefits will be even greater should no-storage be demonstrated to be technically realizable, as is expected;

Boiler

Fuel supply system

Heliostat Field

Fig. 1. Schematic diagram of the reference conventional Solar Gas Hybrid (SGH) for a solar power tower configuration with molten salt storage. Here EPGS is the Electrical Power Generating System and CPC is a compound parabolic concentrator.

Hybrid Receiver Combustor Circulated Molten Salt

Aperture Shutter

2. Concept description

EPGS

CPC Fuel supply line

Hot Storage Tank Steam

Steam Gen.

EPGS

Cold Storage Tank Fuel supply Heliostat Field

Fig. 2. Schematic diagram of the analogous solar power tower configuration of the novel Hybrid Receiver–Combustor (HRC), also with molten salt storage. Here EPGS is the Electrical Power Generating System and CPC is a compound parabolic concentrator.

 The simultaneous introduction of CSR and combustion into a single device allows for more CSR to be harvested near to the lower limits of the solar day. This is because, for the conventional receiver, the minimum threshold of intensity to usefully harvest CSR is set by the need to heat the tubes to a greater temperature than the design outlet temperature of the receiver. In contrast, for the integrated case, the solar component only needs to supplement the heat from the flame, so that a positive input can be obtained for lower solar fluxes, and hence longer solar hours;  The HRC concept allows the thermal input to the tubes to be maintained nominally constant despite any rapid variations in solar insolation due to cloud cover, since the thermal input from a flame can be controlled rapidly to compensate for such changes. This is expected to reduce thermal shock to the receiver, as compared with the SPT and SCH configurations, and in turn to reduce the capital and O&M costs. However, this potential benefit is conservatively ignored here, owing to a lack of data in the open literature with which to assess its economic value. Importantly, the proposed HRC receiver concept adapts existing technologies that are well established in either the 100% solar or 100% combustion modes, so that relatively modest changes to existing design methodologies are anticipated for these modes of operation. Nevertheless, new knowledge is required to optimize the integration of the two energy sources during the simultaneous

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introduction of CSR and combustion into the receiver cavity. The high flux of the solar radiation will result in complex and coupled heat transfer and reaction processes during the mode of simultaneous operation, that have only just begun to be explored. Indeed, to our knowledge, the first such investigation was reported by Medwell et al. [21]. They identified three mechanisms by which high intensity radiation can influence a flame, namely via direct molecular excitation of the fuel, via indirect excitation of H2O and CO2, and via broadband heating of soot. They further showed that these influences can be significant at fluxes of relevance to a HRC receiver. Hence the detailed design and optimization of the HRC receiver during operation with multiple energy sources requires new knowledge and modeling tools to be developed.

Table 1 The main characteristics of the different generating options considered for the case of a work output, We = 100 MWe. Plant Thermal storage Capacity factor (annual) Warm up period Solar extension Solar fraction

Efficiencies Heliostat/spillage (annual) Receiver/solar mode Boiler/combustion mode Steam cycle Parasitic load efficiency Solar-to-electric

3. Methodology The economic evaluation of various combinations of the systems shown in Figs. 1 and 2, either as a hybrid or as a stand-alone system, is performed by employing a consistent set of cost correlations for both capital and operating costs, predominantly adapted from [12]. The dominant assessment is based on the case of the same size of power block (i.e. electrical work), We, with a more limited comparison also reported for the case of constant total heliostat area, Ah, for each system. In both cases, the assessment is performed for a range of We or Ah. This is because commercial plant are typically specified to achieve a given total output. Nevertheless, the comparison based on Ah is also relevant since the heliostat field size has physical constraints for power towers (owing to the influences of beam expansion due to mirror imperfections and to vibration) and because it provides insight into the purchasing power of a given investment in solar infrastructure, which scales with Ah. A particular configuration of the HRC concept has been proposed by Nathan et al. [11], who note that it can be used with a range of heat transfer fluids, including water for direct steam generation. For the present assessment, molten salt has been chosen as the heat transfer fluid largely because more extensive information on its technical and economic performance is available [12] than for any other fluid. In addition, the use of a molten salt avoids the complications of direct steam generation associated with boiling in non-vertical tubes, which results from the axis of the HRC receiver being aligned with the focal line of the heliostat field (Fig. 2). The details of the six cases evaluated are summarized in Table 1, all for the case of a 100 MWe plant. The solar capacity factor without thermal storage is assumed to be 27%, while the overall capacity factor for each plant with a boiler is assumed to be 90%. All plants use a sub-critical steam cycle with double reheat and maximum pressure/temperature of 180 bar/540 °C. That is, the efficiency of the HRC during combustion-only mode is assumed to be identical to that of a boiler at 86%. This is reasonable because the aperture will be closed during this mode of operation, which occurs when the re-radiation losses exceed the net solar absorption (following Jafarian et al. [22]. Similarly, the efficiency of the HRC during the solar-only mode is assumed to be the same of the solar only receiver at 82%. This is reasonable since both are cavity receivers. The assumption that the solar aperture does not significantly increase losses over that from a stand-alone boiler during mixed-energy operation, (i.e. with both solar energy and combustion introduced simultaneously) is yet to be tested. However, this mode of operation is expected to be shorter than the other two, making its contribution relative small. Thermal losses from equipment surfaces are neglected. This assumption is justified for molten salt storage and piping as the thermal efficiency exceeds 99% [15]. The evaluation is also based on the use of natural gas as the sole fuel, owing to its comparative ease of utilization and wide availability. The use of any single fuel is sufficient for the

a

a

SPT13

GB

SGH13

SGH1

HRC0.5

HRC13

h/ day %

13

–

13

1

0.5

13

74

90

90

90

90

90

h/ day h/ day %

0

0

0.5

0.5

0

0

0

–

0

0

0.5

0.5

100

–

82

34

34.1

87.5

%

56

–

56

56

56

56

% %

82 –

– 86

82 86

82 86

82 86

82 86

% %

43 90

43 96

43 90

43 90

43 90

43 90

%

17.8

–

17.8

17.8

17.8

17.8

Solar energy generation as percentage of total annual energy generation.

comparative assessments sought here. Nevertheless, as with conventional boilers, the HRC receiver concept is not restricted to this fuel, although other fuels may require the consideration of other (complex) issues, which is beyond the scope of the present investigation. The reference solar-only case shown in Table 1 is the solar power tower with 13 h of thermal storage, here denoted SPT13. This storage capacity allows the capacity factor of the plant to be increased from 27% to 74%. To achieve a capacity factor of 90% (as per the stand-alone gas boiler, GB), a gas boiler of the same capacity is added to form the Solar Gas Hybrid SGH13, also with 13 h storage, configured as in Fig. 1a. This system achieves a low share of fossil contribution for continuous generation, with a total fraction of 82%, sometimes termed a ‘‘light hybrid’’. This has the same Ah as the SPT of 1.40 km2. The corresponding HRC, also with 13 h storage (HRC13) based on the configuration presented above with reference to Fig. 2, has the same size power block and a slightly larger solar fraction of 87.5%, owing to the longer solar hours and by avoiding the need for gas warm-up. The other limiting combination of established hybrid shown in Table 1 corresponds to the case with minimum thermal storage, here chosen to be one hour, denoted SGH1, also configured as per Fig. 1. The one hour of storage is assumed to be necessary to allow for the boiler to be started up and brought up to capacity in the event of an unexpected reduction in insolation. The reduction in thermal storage over the reference case results in a smaller heliostat field size of 0.580 km2 and a smaller solar fraction of 34%, so is sometimes termed a ‘‘heavy hybrid’’. The other reference case is the gas only boiler, GB, designed to deliver the same 100 MWe capacity on its own. The final two cases considered in Table 1 are the HRC configurations with 0.5 h and 13 h storage, HRC0.5, and HRC13, respectively. The HRC0.5 has the smallest thermal storage capacity, and so the smallest Ah of 0.546 km2 for We = 100 MWe. The HRC13 has the same Ah and amount of storage as the SGH13, to allow a direct comparison. Note that 30 min of storage is allowed for the low thermal storage case to provide some flexibility in maintaining full output in the event of any unforeseen difficulties in transitioning rapidly between the energy sources. The influence of avoiding the need to warm the boiler up each day is assessed by assuming 30 min fuel consumption is needed each day for the SGH cases but not for the HRC. The parasitic load efficiency (PLE) of the HRC and SGH configurations is assumed to be the same as the

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G.J. Nathan et al. / Applied Energy 113 (2014) 1235–1243 Table 2 Assumptions and correlations used in the cost estimations (2009 US dollars). Cost component

Correlation/value

Heliostats Salt-cooled receiver

216 3:52 Q 0:44 rec 0:0305 Q rec þ 0:961 0:0153S þ 0:502

Unit 2

Basis

$/m $M

[12] [12] [12] [12] [12]

Tower Thermal storage Steam generator

0:212 Q 0:7 stm

$M $M $M

EPGS

1:84 Q 0:7 stm

$M

[12]

Gas-fired boiler

1:69 Q 0:7 stm

$M

[23]

O&M Solar field Plant Natural gas cost

1:88Ah þ 0:189 0:0151P g þ 2:92 3

$M/yr $M/yr $/GJ

[12] [12]

Levelized cost calculation parameters Internal rate of return 10% Plant life 30 yrs

SPT configuration (90%). The net contribution to the PLE from operating the molten salt system (pumping and electrical trace heating of molten salt lines) is reduced by about two thirds for the HRC0.5 relative to the SPT because it avoids these losses when useful heat is not being supplied to the EPGS. At the same time, the HRC incurs the additional parasitic losses associated with running the combustion system when not operating in the solar-only mode. These losses, which are similar to that of a boiler, are dominated by the fan power needed to circulate air and combustion products. (Note that natural gas is supplied under pressure, so there is no energy penalty in delivering it to the tower). However, the PLE of the boiler is much higher (at 96%) than that of the SPT (90%). Hence the use of PLE of 90% throughout the 24 h cycle of the SPT more than compensates for the use of ancillary equipment to run the combustion system, and so provides an allowance for operating the fluidic seal and external shutter. Table 1 also shows that the HRC is assumed to harvest an additional 30 min of solar insolation per day over the SGH and SPT cases, because the HRC allows the CSR to supplement the energy from combustion, allowing a positive contribution to be received at lower solar fluxes. The combined effect of these changes is that the solar fraction for the HRC0.5 is maintained at 34%, the same as that of SGH1 despite having 0.5 h less thermal storage. Table 2 presents the assumptions and correlations used for the cost estimation. Correlations for the gas-fired boiler and EPGS are based on literature data to which we have applied a capacity scaling exponent of 0.7 based on thermal input. The cost of the HRC receiver is assumed to be twice that of the stand-alone receiver, to allow for fans, air heaters and combustion systems. This is considered to be a conservative estimate made on the basis that full cost data are not available due to the early stage of the technology development. This is consistent with the aim of the current study to provide a first-order assessment of economic feasibility. However, the assumed HRC receiver cost is less than that of a boiler owing to the use of a lower-pressure heat transfer fluid. The costs of the gas-fired boiler components are based on Bemis and DeAngelis [23]. All costs reported here are in 2009 US dollars. Literature cost data was adjusted for inflation using the Chemical Engineering Plant Cost Index. Cost correlations and values in Table 2 are inclusive of indirect costs. The economic merit of the various combinations of hybrid power plants are compared by considering four parameters, namely the levelized cost of electricity, calculated following the definition of the [24],

LCE ¼ Rt ððInv estmentt þ O&M t þ Fuelt þ Carbont 



þ Decommissioning t ð1 þ rÞt ÞðRt ðElectricityt ð1 þ rÞt ÞÞ

ð1Þ

Here (1 + r)t is the discount factor for year t, Investmentt is the investment costs in year t, O&Mt is the cost for operations and maintenance in year t, Fuelt is the cost of fuel costs in year t, Carbont is the cost of carbon in year t and Decommissioningt is the cost of decommissioning in year t. The denominator in Eq. (1) is the discounted electrical output of the plant over its economic life which is assumed to be 30 yrs. For the present comparison we conservatively ignore the cost of carbon and of decommissioning in both cases. Eq. (1) is then solved to give the LCE for a discount factor equivalent to the assumed internal rate of return (IRR) of 10% over the life of the project. The LCE is calculated both for the overall plant, LCEoverall, and that of the solar component, LCEsolar, as is the capital cost, Capexoverall and Capexsolar, respectively. Here the solar component is determined by assuming that solar energy replaces a fraction of fossil energy in a fossil-only plant without affecting the fossil energy cost. The steps involved in determining LCEsolar in hybrid plants HRC and SGH are: 1. Determine the overall levelized energy cost of the hybrid, LCEoverall, using Eq. (1). 2. Determine the levelized energy cost of a fossil-only plant of same capacity and capacity factor as the hybrid, LCEgas. 3. Solve Eq. (2) for LCEsolar:

LCEov erall ¼ xsolar LCEsolar þ xgas LCEgas

ð2Þ

where xsolar and xgas are the respective solar and gas electrical energy fractions in the hybrid. Analagous equations (to Eq. (2)) may be written for the solar fraction of the capital and operating costs. 4. Results Tables 3 and 4 presents the most important details from the cost estimation for the two cases of We = 100 MWe and Ah = 1 km2, respectively. In Table 3 it can be seen that, while the hybridizing at fixed storage capacity (for SGH13) adds to the capital cost of the SPT plant, the increase is at most 14.7%. However, for all of the other cases, hybridizing reduces the total capital cost by up to 41%, for the case of the HRC0.5. This trend is consistent with previous analyses of hybrid systems [2], although their comparisons were not presented in the same way. More details of the influence on capital cost normalized by energy generated ($M/GW h/yr) are presented both for the total plant (Fig. 3) and for the solar component (Fig. 4). Here the solar component of capital cost was calculated by incorporating all of the solar-only components (notably heliostat field, tower, receiver, storage and steam generator), and the solar share

Table 3 The estimated costs of the various system options for a power output, We = 100 MWe. Plant Field area Capital costs Heliostat field Receiver Tower(s) Thermal storage Steam generator EPGS Boiler Site improvements Total capital cost Fuel cost O&M cost LCEoverall LCEgas LCEsolar

SPT13

GB

SGH13

SGH1

HRC0.5

HRC13

km2

1.4

–

1.4

0.58

0.546

1.4

$M $M $M $M $M $M $M $M

302 63 23 52 10 90

85.9 78.9 14.3

302 63 23 52 10 90 83 15

125 43 10 4 10 90 83 15

118 83 9 2 10 90 15

302 126 23 52 10 90 15

$M $M/a $M/a $/MW h $/MW h $/MW h

555

637 5.1 7.42 77.0 52.0 82.4

380 17.4 5.82 64.8 52.0 89.7

328 16.9 5.81 59.0 53.9 68.9

618 3.2 7.42 72.8 59.1 74.7

15

7.42 77.2 77.2

179.9 45 5.9 51.5 51.5

G.J. Nathan et al. / Applied Energy 113 (2014) 1235–1243

Table 4 The estimated costs of the various system options for a solar field size of 1 km2. Plant Plant capacity Capital costs Heliostat field Receiver Tower(s) Thermal storage Steam generator EPGS Boiler Site improvements Total capital cost Fuel cost O&M cost LCEoverall LCEgas LCEsolar

MWe $M $M $M $M $M $M $M $M $M $M/a $M/a $/MW h $/MW h $/MW h

SPT13

GB

SGH13

SGH1

HRC0.5

HRC13

72

172

72

172

183

72

216 54 16 37 8 71 12 415 6.2 82.3

132 121 22 277 45 5.9 46.8 46.8

82.3

216 54 16 37 15 71 65 12 480 3.7 6.2 81.8 55.2 87.7

216 54 16 7 8 132 121 22 584 30 7.9 59.2 47.4 81.0

216 109 16 4 16 137 23 521 31 8 53.1 48.4 62.2

216 109 16 37 8 71 12 470 2 6 78.2 64.2 80.2

Capital cost, c $M per GW.hr/yr overall

0.8

Gas fired boiler EPGS

0.6

Steam generator Thermal storage Tower

0.4

Receiver Site improvements Heliostat field

0.2

0.0 SPT-13 SGH-13 SGH-1 HRC-13 HRC-0.5

Fig. 3. Overall capital costs of the various combinations of equivalent plant, all for a total power output of 100 MWe. Costs are normalized by annual total energy generation.

Solar capital cost, $M per GW.hr/yr solar

0.9 0.8 Gas fired boiler 0.7

EPGS

0.6

Steam generator Thermal storage

0.5

Tower

0.4

Receiver Site improvements

0.3

Heliostat field 0.2 0.1 0.0 SPT-13

SGH-13

SGH-1

HRC-13

HRC-0.5

Fig. 4. Solar component of capital costs of the various combinations of equivalent plant, all for a total power output of 100 MWe. Costs are normalized by annual solar energy generation.

both of the power and of the shared components (notably the boiler, EPGS and site improvements), determined from the product of the solar fraction and their capital cost. For the case of We = 100 MWe, it can be seen that, while both of the conventional hybrids (SGH13 and SGH1) reduce the overall

300

Overall levelized energy cost, $/MWh

1240

SPT-13 250

SGH-13 SGH-1

200 HRC-13 HRC-0.5

150

100

50

0 0

50

100

150

200

Capacity, MW e Fig. 5. A comparison of the overall levelized costs of electricity as a function of power-block capacity for all of the systems in Table 1. (Note that the data for SGH13 and SPT-13 are coincident for the scale of this figure).

normalized capital cost ($M/GW h/yr) relative to the power tower in the fuel-saver model (by 5.8% and 43%, respectively; Fig. 3), they increase the solar component of the capital cost (by 8.8% and 11.5%, respectively; Fig. 4). In contrast, the new hybrids (HRC13 and HRC0.5) reduce both the overall normalized capital cost ($M/ GW h/yr) relative to the power tower (by 8.7% and 52%, respectively; Fig. 3) and of the solar component of the capital cost (by 0.5% and 11.5%, respectively; Fig. 4). Perhaps more significantly, the HRC reduces the normalized capital costs significantly relative to the equivalent SGH. The low storage case, HRC0.5 reduces the normalized total and solar components of the capital cost ($M/ GW h/yr) relative to SGH1 by 13.6% and 20.6%, respectively. The high storage case, HRC13, reduces the normalized total and solar components of the capital cost ($M/GW h/yr) relative to SGH13 by 3.0% and 8.5%, respectively. The same trends are also found for the comparison based on Ah, as can be seen from Table 4. For example, on this basis the SGH13 reduces the total normalized capital cost by 24% relative to the SPT, while it increases the solar component of the capital cost by 11%. Also in contrast, the HRC0.5 reduces the normalized total capital cost in $M/GW h/yr, by about 60% relative to the SPT and by 16% relative to the SGH1. It is worth noting that the assumed cost multiplier of 2.0 for the HRC over a stand-alone receiver results in the HRC having a slightly lower cost than does the stand-alone boiler. This can be explained both because of the lower pressure of the working fluid and the simpler construction of a molten salt receiver relative to a steam boiler. However, it should also be noted that the costing methodologies for the receiver and boiler were obtained from different sources, which leads to some uncertainty in the relative comparison. Nevertheless, it is clear that the total capital cost of the combined infrastructure is reduced significantly by the novel hybridization process. A comparison of the levelized cost of electricity for the total plant, LCEoverall, and for the solar component, LCEsol, is shown as a function of electrical work output, We, for each case in Figs. 5 and 6, respectively. The power output for these data is limited to 180 MWe, which corresponds to the We for the maximum field size of 2.5 km2 for the SPT. A numerical comparison of relative changes for the case of We = 100 MWe is given in Table 5. It is important to note that these calculations under-estimate the benefit of the HRC in O&M costs, since the Sargent and Lundy correlations [12] correlations are based only the size of the heliostat array and the size of the EPGS. This analysis is conservative in making no account for differences in maintenance costs attributable to the specific design

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G.J. Nathan et al. / Applied Energy 113 (2014) 1235–1243 300

Overalll levelized energy cost, $/MWh

Levelize ed cost of solar energy $/MW.hr

250 SPT-13 200

SGH-13

150

HRC-13

SGH-1

HRC-0.5 100

50

SPT-13 SGH-13

250

SGH-1 200

HRC-13 HRC-0.5

150

100

50

0 0

0.5

1

0 0

50

100

150

Capacity, MWe Fig. 6. A comparison of the solar component of levelized costs of electricity as a function of plant capacity for all of the systems in Table 1.

1.5

2

2.5

3

Ah, km2

200

Fig. 7. A comparison of the overall levelized costs of electricity as a function of heliostat area for all of the systems in Table 1.

Plant

DLCEoverall re SPT13 DLCEsolar re SPT13 DLCEoverall re SGH13 DLCEsolar re SGH13 DLCEoverall re SGH1 DLCEsolar re SGH1 D$M/GW h/yroverall re SPT13 D$M/GW h/yrsolar re SPT13 D$M/GW h/yroverall re SGH13 D$M/GW h/yrsolar re SGH13 D$M/GW h/yroverall re SGH1 D$M/GW h/yrsolar re SGH1

SPT13

SGH13

SGH1

HRC13

HRC0.5

% % % % % % %

0.00 0.00 +0.36 6.31 +19.18 17.47 0.00

0.36 +6.74 0.00 0.00 +18.75 16.39 5.80

16.10 +16.12 15.79 +8.79 0.00 0.00 43.81

5.79 3.26 5.45 9.37 +12.28 18.35 8.67

23.59 10.83 23.31 16.46 8.93 22.35 51.47

%

0.00

8.79

11.50

0.48

11.51

%

6.16

0.00

40.35

3.04

48.48

Leveliz zed cost of solar energy $/MWh

250

Table 5 The estimated relative change in cost of each configurations against different reference configurations, for the case of We = 100 MWe. A negative change is a reduction in cost.

SPT-13 200

SGH-13

150

HRC-13

SGH-1

HRC-0.5 100

50

0 0

0.5

1

1.5

2

2.5

3

Ah, km2 %

8.08

0.00

2.49

8.52

18.67

%

77.97

67.64

0.00

62.54

13.62

%

10.32

2.43

0.00

10.75

20.64

of the HRC relative to the other cases. Reductions in the calculated O&M occur only due to economies of scale. Hence it does not account for anticipated reductions in O&M due to eliminating the boiler, which will incur annual inspections and overhaul (with tube replacements), nor does it account for the savings due to the reduction in thermal cycling or thermal shock, since the receiver boiler will operate at approximately steady state, whilst both the stand-alone receiver and boiler incur daily start-up to accommodate the cyclical solar input. At the same time, it does not allow the receiver to be shut-down separately from the rest of the plant, so implies that the receiver-boiler will need to reach comparable reliability with the rest of the plant to avoid additional shutdowns. Even on this basis, these results show that the new hybrid reduces both LCEoverall and LCEsol across the entire range of We, relative to both the SPT and the equivalent hybrid. As for the trend in capital cost, for case We = 100 MWe, while the standard hybrid reduces LCEoverall relative to the SPT (by 0.4% and 16% for the SGH13 and SGH1, respectively), it increases LCEsolar (by 6.7% and 16.1% for the SGH13 and SGH1, respectively). In contrast, the HRC reduces both LCEoverall (by 5.8% and 24% for the HRC13 and HRC0.5, respectively), and LCEsolar (by 3.3% and 10.8% for the SGH13 and SGH1, respectively) relative to the SPT. Figs. 5 and 6 also show that, relative to their equivalent hybrid, the HRC

Fig. 8. A comparison of the solar component of levelized costs of electricity as a function of heliostat area for all of the systems in Table 1.

reduces LCEoverall by 5.5% and 8.9% for the high and low storage case, respectively. The HRC also reduces LCEsol by 9.4% and 22.3%, respectively, for the high and low storage case, relative to their equivalent hybrid. That is, the heavy hybrid has a greater impact on LCE and capital cost than does the light hybrid, as is to be expected, although the trends are consistent. Interestingly, while the overall plant costs decrease with scale, the relative benefits do not vary greatly with scale, although they do show a small increase with scale. Hence, the concept is beneficial across a wide range of power block sizes. Also, the reduction in the solar component of LCE for the HRC is compensated by an increase in the gas component, LCEgas, which is only about 4.5% for the HRC0.5 relative to the SGH1 but is about 14% for the HRC13 relative to the SGH13 (Table 3). Nevertheless, this does not negate the net benefit in LCEoverall noted above. The comparison of LCEoverall and LCEsolar based on heliostat field size is shown in Figs. 7 and 8, respectively. The numerical values of the same comparisons is provided in Table 6 for the case of the maximum field size, Ah = 2.5 km2, which corresponds approximately to the present maximum field size, although this limit will increase with advances in technology. For these comparisons, a change in the amount of storage results in a different sized power block, owing to the constant Ah (see Table 4). Hence the low storage cases also achieve greater economies of scale in the power block at the limiting field size. Consequently, this method of comparison yields slightly different relative performance of the different hy-

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G.J. Nathan et al. / Applied Energy 113 (2014) 1235–1243

Table 6 The estimated relative change in cost of each configurations against different reference configurations, for the case of Ah = 2.5 km2. A negative change corresponds to a reduction in cost. Plant

DLCEoverall re SPT13 DLCEsolar re SPT13 DLCEoverall re SGH13 DLCEsolar re SGH13 DLCEoverall re SGH1 DLCEsolar re SGH1 D$M/GW h/yroverall re SPT13 D$M/GW h/yrsolar re SPT13 D$M/GW h/yroverall re SGH13 D$M/GW h/yrsolar re SGH13 D$M/GW h/yroverall re SGH1 D$M/GW h/yrsolar re SGH1

SGH1

HRC13

HRC0.5

% % % % % % %

SPT13 0.00 0.00 0.43 6.22 34.17 0.51 0.00

SGH13 0.43 6.63 0.00 0.00 33.60 6.08 7.03

25.47 0.52 25.15 5.74 0.00 0.00 54.91

6.96 4.28 6.56 10.23 24.83 4.77 10.79

32.75 20.69 32.46 25.63 9.77 21.10 62.48

%

0.00

7.91

4.52

2.07

21.21

%

7.56

0.00

51.50

4.04

59.64

%

7.33

0.00

11.52

9.25

26.98

%

121.80

106.21

0.00

97.88

16.77

%

4.74

13.02

0.00

2.57

17.48

brid systems, although the same trends are apparent as for the constant sized power block. Relative to the equivalent hybrid, the HRC reduces the overall normalized capital cost ($M/GW h/yr) by 4% and 17% for the high and low storage cases, respectively for Ah = 2.5 km2. It also reduces the solar component of normalized capital cost ($M/GW h/yr) by 9% and 18% for the high and low storage cases, respectively, again for Ah = 2.5 km2. Similarly, the HRC reduces the LCEoverall by 5.5% and 8.9% for the high and low storage cases, respectively for Ah = 2.5 km2, relative to the equivalent hybrid. It also reduces the LCEsolar by 9.4% and 22.3% for the high and low storage cases, respectively, again for Ah = 2.5 km2. 5. Discussion The economic benefit of integrating gas firing with the solar receiver can be explained as follows. In the fuel-saver mode, the conventional hybrid increases total plant infrastructure over both the stand-alone solar and gas plants, without increasing power output. This increases the solar components of cost relative to the SPT and the overall cost relative to the GB, despite the beneficial influences of hybrids, consistent with earlier findings of Kolb [2]. In contrast, the HRC reduces total infrastructure per MW h/yr relative to the equivalent SPT of the same We, (or increases We at the same Ah to achieve greater economies of scale in the power block), which leads to a reduction in both the LCE and capital cost. For the high storage cases, the HRC also provides a small reduction in fuel and O&M costs at the same We. The magnitude of the benefit is lower for the low-storage case, due to the smaller component of hybridization. Relative to the SPT, both of the low storage cases, namely SGH1 and the HRC0.5, reduce the LCE because they offer both better capital utilization and greater economies of scale for the shared infrastructure. For the case of constant We, they both reduce the size of the heliostat field, while for the same size heliostat field, both deliver an increase in both instantaneous power output and in total energy, since they deliver continuously. Hence, while all of these hybrids considered here offer the high availability necessary for off-grid markets by being able to operate in gas-only mode when necessary, only the HRC achieves an economic benefit for solar power in the fuel-saver mode. In addition, these benefits are reasonably independent of scale. It is also worth comparing the present hybrid concept with the solar gas turbine hybrid concept under development [5–7], which

also provides an economic benefit in the fuel saver mode. No attempt is made here to directly compare the economics of these two systems owing to the different methodologies and data bases employed in evaluating them. However, the technical challenges in heating high pressure air to a high temperature result in a trade-off between solar fraction and thermodynamic efficiency for such a solar gas turbine hybrid system. For example, the maximum receiver outlet temperature measured for the SOLGATE system, which employed air-cooled high pressure windows, was around 960 °C [5], while the more robust metallic receiver under development is presently limited to around 750 °C [7]. Both of these temperatures are very much less than the 1650 °C typical of a modern efficient gas turbine, so that it is necessary to either operate with a lower turbine efficiency or with a high proportion of combustion to achieve the same the turbine inlet temperature. For example, to achieve an instantaneous solar fraction of 60%, the gas turbine efficiency in the SOLGATE hybrid was about 18%, while this dropped to below 15% at a higher instantaneous solar fraction of 70% [5]. To match the 43% efficiency of the present boiler cycle would require either a combined cycle, with the associated increased in cost and/ or a very much lower solar fraction. In addition, the instantaneous solar fraction of 60% corresponds to an 18% solar fraction taken over a 24 h day, assuming the same 7.5 h solar day as used here. Hence substantial further developments in gas turbine receiver technology are required to achieve the same combination of solar fraction and efficiency as predicted for the HRC. The estimated solar fraction of 34% for both the HRC0.5 and SGH1, is also somewhat greater than the 12.3–19.8% estimated by Kolb [2], although their concept is quite similar to the present SGH concept. The difference is due partly to the use of a molten salt in the present system, with a higher temperature, over the thermal oils used by Kolb [2], and to other differences in conditions. It is also worth noting that, while the HRC cycles are less thermodynamically efficient than is achieved by pre-heating the feedwater to a boiler [3,25], the two concepts are not mutually exclusive. That is, the HRC delivers the high grade needed to superheat the steam, while feed-water heating utilizes low-grade heat. Hence a source of lower-grade heat, if available, could also be used to pre-heat the feed-water to either the SGH or the HRC, so displacing the higher cost and higher enthalpy stream provided by either the power tower or the boiler. Finally, it is also worth noting that the solar fractions calculated here are significantly larger than those of hybrids installed commercially to date. For example, the hybrid solar-coal plant currently under construction at Kogan Creek, which operates in the power-boost plant by heating feed-water with a Linear Fresnel array, is reportedly designed to achieve a peak solar fraction of only 5.9%.4 Likewise the Martin Next Generation Solar Energy hybrid plant, completed in 2010, is reported to provide 75-megawatt (MW) from a parabolic trough system into a 3705 MW combined cycle plant, comprising a solar fraction of about 2%.5 Hence, the proposed solar fraction of the HRC, which achieves 100% of peak power by combustion and 32% of total solar power, after accounting for capacity factors, represents a significant increase over current hybrid concepts.

6. Conclusions The novel concept of a solar Hybrid Receiver–Combustor (HRC) is found to offer significant potential advantages over equivalent configurations of both stand-alone solar and previously proposed 4 http://kogansolarboost.com.au/technology/areva-advantage/, accessed 30 August, 2011. 5 http://www.fpl.com/environment/solar/martin.shtml, accessed 30 August, 2011.

G.J. Nathan et al. / Applied Energy 113 (2014) 1235–1243

hybrid concepts in the fuel-saver mode, on the proviso that the assumed performance can be achieved (or approached) in practice. The HRC concept offers, relative to the stand-alone solar system, an increase in both the economic utilization and in the economy of scale of those components of the infrastructure that are shared with the gas boiler for the same size of power block. If the HRC can be demonstrated to achieve comparable combustion efficiency to the boiler for an increase in the cost of receiver by a factor of two, relative to the SPT the system will:  reduce the overall installed capital cost of generation ($M/GW h/yr) by 51% and its solar component by 12%,  reduce the overall LCE by 24% and the solar component by 11%. The benefit is comparable based on for the same size of heliostat field. These reductions are significant because existing hybrid-boiler concepts increase the cost of solar power in the fuel-saver mode. Under the same assumptions, the HRC is predicted to reduce both the capital cost and the levelized cost of electricity over the equivalent hybrid due to the combined effects of lower total infrastructure and to the lower net thermal losses from the single device relative to that from two separate items of equipment. Even when conservatively ignoring any of the anticipated reductions in O&M associated with reduced thermal cycling and thermal shock, due to lack of published data, the HRC is estimated to yield the following advantages over the equivalent SGH:  A reduction in the solar component of the capital cost of electrical generation ($M/GW h/yr) by 20.6% and 8.5% for the half-hour and 13 h storage cases, respectively, for plants of the same power block capacity. The equivalent reduction in overall capital costs are 13.2% and 3.4%, respectively;  A reduction in solar component of LCE (LCEsol) by 22.3% and 9.4% for the half-hour and 13 h storage cases, respectively, for plants of the same power block capacity. The equivalent reductions in overall LCE are 8.9% and 5.9%, respectively;  A reduction in solar component and overall of normalized capital cost ($M/GW h/yr) by 17.5% and 16.7%, respectively, for the half-hour storage case when compared for plants of the same sized heliostat field (2.5 km2). The equivalent reductions in LCEsol and LCEoverall were estimated to be 21.6% and 11.1%, respectively.

Acknowledgements The authors would like to thank CET members Associate Professors Bassam Dally and Eric Hu, Dr. Zeyad Alwahabi, Dr. Richard Craig and former Petratherm Business Manager, Mr. Jonathan Teubner, for their contributions to an earlier concept of solar-boiler hybrid. We also acknowledge the contributions to the development of the hybrid technology proposed here by CET Manager, Dr Jordan Parham. Finally, we wish to thank Petratherm Director, Mr. Terry Kallis, and KPMG personnel Mr. Matthew Herring and Dr. Michelle Zucker for their support of and commitment to the technology. We also thank CET members, Mr. Ashok Kaniyal, for performing some supporting calculations and, Mr. Mehdi Jafarian,

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