Category Archives: Sonar-Collecttors

Economic Optimization and Evaluation

First the economic assumptions in a conservative approach will be described before presenting the results of the LEC calculation. At last there will be an analysis under the economic conditions and the legal framework for renewable energies in Spain.

Assumptions

The economic assumptions are given in the following table: Table 1: Economic assumptions

Investment costs:

Specific Powerblock Investment 1

2’241 €/kW„l, net

Total Solar field investment 2

SF_Invest = 130€/m2 x 437’639m2 x (A / 437’639m2)093 ^ 127 €/m2 (617’000 m2) to 137 €/m2 (210’000 m2)

Annual costs:

Insurance

1% of total investment costs

Operation&Maintenance Power Block

6% of Power Block Investment

O&M solar field

O&M_SF = 3 €/(m2a) x 437.639 m2 x (A / 437’639 m2)072 ^ 2.7 €/(m2a) (617’000 m2) to 3.7 €/(m2a) (210’000 m2)

Biomass (fuel cost)

0.5 ct/kWh

Base load, 24h/d, 3 weeks revision in Jan.

Financial boundary conditions:

Interest rate

8%

Lifetime

25 years

Compensation (Spain):

Electricity (www. omel. es [4], average price March 03 — February 04)

3.74 ct/kWh

Bonus electricity Biomass (RD2818) [5]

3.05 ct/kWh

Bonus solar thermal elec’y (RD2818) [3]

12.02 ct/kWh

Cost assumptions apply for the second or third plant to be built, having under control the unexpected difficulties related to new technologies. The first demonstration plant will have considerably higher solar field costs.

SHAPE * MERGEFORMAT

Results

Solar Field [m2]

Figure 4: Average annual earnings (beyond the required 8%) as a function of the solar field size.

Provided that the bonus tariffs in Spain will be valid for hybrid operation, it is economically very attractive to integrate a solar field into a biomass plant. The solar field should ideally have a mirror surface of 68’000 m2 for a 20 MW biomass plant. The additional earnings between 0 and 120’000 m2 (see figure 4) indicate, that the solar field in a hybrid plant is profitable with the assumed bonus. If the bonus will decrease, the additional earnings will decrease until the additional solar costs equal the additional bonus. If the bonus increases above the assumed value of 12.02 ct/kWh — as being discussed these days by political decision makers in Spain — the maximum will shift to higher surface areas.

The resulting levelised electricity costs depending on the solar field size are given in Figure 3:

Solar field size [m2]

Figure 3: Levelised electricity costs of a 20 MW biomass solar hybrid plant, as a function of the solar field size [m2]

Due to high costs of the solar field, the levelised electricity costs of a biomass plant can apparently not be reduced by coupling it with a solar field.

In Spain the legal framework for renewable energies is defined in the so called »Real Decreto 2818/1998«. For biomass and solar thermal electricity a bonus on top of the market price is being paid to cover the additional electricity generating costs. The bonus as well as the average electricity price of the Spanish electricity exchange market (March 03 — February 04) are given in table 1. For the calculations it was assumed that the corresponding tariffs could be applied according to the solar and the biomass share. The criteria for evaluating the plant investment is the annuity method, that is: In case the realised cash flow leads to an internal rate of return higher than the required 8% (see table 1), the annuity is positive, otherwise negative.

Thermodynamic Model

For describing the thermodynamic behavior of the collector, a semi stationary model, based on an energy balance, is used. With equation 4 the reachable massflux M of a collector segment is calculated via the absorbed radiation Iabs = r? optIb, the heat of in- and outflow.

referred to direct horizontal irradi — ance Ibh

%

losses qloss and the enthalpy-difference zih

(0opt(0zCr) lb-q!

M

) Ac

4hi

The whole collector-field can only reach the lowest massflux of the three sections:

7в = arcsin(cos(7)sin(0z))

(a) 5 x 104 rays (b) 5 x 105 rays

M = min^, M2, M3) (5)

This way matching losses between the sections are taken into account. To make sure, that the collector is in operating conditions to produce its corresponding output, a dynamic thermal node at each end of collector-stage is used as shown in equation 6.

(mcp)l dt — (Ubs^loss) Wap (6)

The thermodynamic model is implemented in the simulation environment Co/S/m[5] which was developed at the Fraunhofer ISE to simulate solar-collector systems.

Power Block

(a) flow sheet

(b) part load of a simp/e fresh water coo/ed process

Figure 6: Powerblock Cost Model

The cost model is based on a first estimation for a starting configuration with N = 34,

H = 7.5 m, D = 0.075 m and an absorber tube with a diameter of 15 cm. The specific direct cost8 of this collector would be Cc = 90 €/m2 for the mentioned configuration. This figure corresponds to cost estimations of the Solarmundo collector. The cost estimations were evaluated and seem reasonable for a third plant. All changes in cost due to mutations of the geometry are assumed to be linear. The specific direct collector-cost Cc is expressed by equation 7.

Cm N + Ch (4m + H) + Cd (N-1) D + Ca

Cc ^ NB (7)

The whole investment Бр of the solar field, power block, infrastructure, land and engineering can be calculated with:

The power b/ock is assumed to be a simple process with only the fresh water tank as a preheater (see figure 6). The condenser is cooled by fresh water. The part load behavior is integrated into simulation via look-up-table.

TE — (CcAc + TO) x (1 + «e) + C|Ac(1 + -^^-21 + 2pb The LEC is calculated via annuity «a and the annual electricity yield.

(8)

LEC =

(«a + K. + ^Mt1 + «c)TE

Ja Eeldt

Table 1: 50 MW Faro DNI = 2247 kWtlm2a

Cc

90 €/m2

specifi c direct collector-cost (N = 34, H = 7.5 m, D = 0.075 m)

Cm

30.5 €/m

specifi c cost of a primary mirror (B = 0.5 m), incl. structure, tracking etc

Ch

13.8 €/m2

specifi c cost of the absorber tower

Cd

11.5 €/m2

specifi c cost of gap

Ca

304.0 €/m

specifi c cost of the absorber

Cl

3.0 €/m2

land and preparation

To

4002 t€

others, piping steam-separator

T

640.0 t€

Infrastructure

Tpb

33600 t€

powerblock 672 €/kW

a

9.368 %

annuity 25 a rate of interest 8%

«e

22.5 %

engineering, commissioning, project managing & license

«O&M

2 %

operation and maintenance

«i

1 %

insurance

c

5 %

additional mark-on for contingencies

The assumptions of the cost model are shown in table 1.

Solar Only Plant and Gas Co-firing

From the starting point of a 50 MWei Solar Only steam plant, it will be analysed how natural gas co-firing influences the electrical yield, the solar share and the costs of the plant. For this analysis 240 plant configurations with different solar fields (210’000 m2 — 617’000 m2) and boilers (0 MWth — 150 MWth) were examined.

2.1 Technical Description

Power Cycle

The 50 MWel power cycle is equipped with sea water cooling and the feed water storage tank as single preheater (see figure 5). Its net efficiency is 32.8% (at a water temperature of 14°C, for warmer water temperatures and at part load the efficiency drops). [4]

The steam is produced by the solar field. If it does not reach the maximum turbine load it is supported by a parallel gas boiler. As opposed to the biomass variant, it was taken into consideration that the solar share should remain high. The assumed operation mode is that gas will be co-fired, once the solar collector can provide more than one kg/s steam.[5] An exemplary day (July, 13) is given in figure 6. The boiler’s thermal energy production is limited either by its thermal capacity or by the nominal mass flow of the turbine. For technical reasons the boiler operates between 20% and 100% of its nominal capacity.

time

Figure 6: thermal energy to power block by solar field (453600 m2) and gas burner (Pth, n=70 MW), july, 13

Analysis and Optimization

The main parameters which influence the optical performance and solarfield investment are the hight H of the receiver, the gap D between primary mirrors and their number N. The influence of variation of each parameter on the LEC is shown in figure 7a-c. The calculation was made for three different optical errors. It is obvious that higher optical errors decrease the performance of the collector and increase the LEC. For small optical errors the optimal receiver height is displaced to higher values. The optimum gap between primary mirrors, which is assumed to be constant, is less dependent on the optical errors. The ground coverage is about 80%. Additional primary mirrors reduce the specific collector-cost but also decrease the specific performance.

As mentioned above the primary-mirrors are curved elastically, hence they have a distinct focal length f. The relative focal length f is defined as the ratio of the focal length and the distance from the mirror to the absorber. The influence of the relative focal length f on the LEC is shown in figure 7d[11]. The optimum of f is a bit higher than one, with less dependence to higher than to minor values.

H[m]

(a) variation of height

Figure 7: Variation of geometric parameters (D = 0.075 m, N = 34, H = 7.5 m)

gap [m]

(b) variation of gap

(c) variation of primary mirrors (d) variation of the focal length

An optimization of the three parameters corresponding to different optical errors leads to lower LEC shown in table 2. By reaching a high optical accuracy, a higher placed receiver enables more primary mirrors and hence the cost reduction potential is very high.

Table 2: LEC of the configuration opti — [mrad] 2.32 4.65 6.98

mized on the optical errors LEC 11.3 12.1 13.2

It is also possible that the gaps between primary mirrors are increased linearly rather than constantly. A linear increasing gap effectuates an optimum for lower receiver heights, because the blocking at high zenith angles is reduced. The difference at the boundary conditions presented here is very low. The LEC of a collector with constant gaps is about 3-8 0/00 higher. The decision whether to use linear or constant gaps depends on the specific cost of the receiver hight Ch and the expense of the linear increasing gap. With respect of simplicity a constant gap might be more favorable.

Conclusion

The linear Fresnel-concept has the potential of low electricity cost prices. Considering

the numerous possibilities of variation in geometry an optimization for a distinct purpose

in respect of reachable accuracy and specific cost factors is important. With the method

presented it is possible to evaluate intended improvements regarding the LEC.

Figure 5: 50 MWei, net power cycle with sea water cooling, efficiency (steam -> el, net): 32.8%. Size of Solar Field and Gas Boiler

The gas share depending on solar field size and boiler size is given in figure 7. The operation mode of the boiler described above is assumed.

65%

60%

55%

50%

45%

40%

35%

30%

25%

20%

15%

10%

5%

0%

12%

11%

10%

9%

8%

7%

Solar Field Size [m2]

□ 11%-12% □ 10%-11%

□ 9%-10%

□ 8%-9%

□ 7%-8%

<Gas boiler [MW. h]

Figure 8: Mean annual efficiency DNI -> net solar electricity depending on solar field size and gas boiler capacity

Solar Field >
Size [m2]

Gas boiler [MWth]

Figure 7: Gas share depending on gas boiler size [MWth] and solar field size [m2]

3500

3000

2500

2000

1500

1000

500

Solar Field Size

□ 3000-3500

□ 2500-3000

□ 2000-2500

□ 1500-2000

□ 1000-1500

■ 500-1000

■ 0-500

Gas boiler [MWth]

Figure 9: Full load hours

00 50

0 (solar only)

[m2]

Although the efficiency is not necessarily the decisive criteria to judge a power technology, figure 8 still shows that the primary solar energy DNI can be converted into electricity with higher efficiency in hybrid operation. On the one hand this is attributable to higher steam cycle efficiency due to lower part load losses, on the other hand the so-called »lower dumping« due to a necessary minimal mass flow for the turbine (20% of nominal mass flow assumed) is reduced as well.

Design of a 240 MWe Solar Thermal Power Plant

D. Mills*, G. L. Morrison**, and P. Le Lievre***

*School of Physics
University of Sydney
Sydney Australia.

E-mail: d. mills@physics. usyd. edu. au

**School of Mechanical and Manufacturing Engineering
University of New South Wales
Sydney Australia 2052
E-mail: g. morrison@unsw. edu. au

***Solar Heat and Power Pty. Ltd. (SHP)

2 Chifley Square, Sydney NSW 2000, Australia
E-mail: peter@solarheatpower. com

In this paper, the general design philosophy for a large 240 MWe pure solar storage plant is discussed. The proposed stand alone plant design will use the same low cost Compact Linear Fresnel Reflector (CLFR) array system previously reported (Mills et al, 2003; Hu et al, 2003) and currently being constructed for a coal fired plant preheating project. In the stand-alone solar plant, the costs of hybrisation with fossil fuel are found to be high, and lower temperature operation seems more cost-effective. The advantage gained by low temperature operation derives from an unusual combination of large low cost low temperature turbines developed for the nuclear industry, and an inexpensive storage concept which suits that particular temperature range. Should both options be applicable, then this may be the most cost-effective solar thermal electricity development path. Comparison of solar electricity cost against a typical 400 MWe coal fired plant in the USA suggests similar cost/performance without green incentives.

Introduction

There has been much emphasis placed in the past on the adaptation of high temperature fossil fuel turbines to solar energy, with an attendant ability to utilise fossil fuel for backup energy. However, there has been a recent shift of interest to 100% solar plants because of the strict incentives that have been set up in countries like Spain, and Germany. Fully renewable operation is also advantageous in tradeable renewables certificates programmes like that of Australia, because the investment in the power block can be repaid at a higher rate.

In the past, it has been usually presumed that primary fossil fuel in large quantities is cheaper than solar heat. We think of solar energy as expensive. Perhaps we should be thinking that the handling of fossil fuel is also expensive. Recent results of a tender in Cyprus for a 120 MW oil fired fossil fuel plant were Turbines: 42.7%;

Boilers: 31.6%; Flue Gas Desulpherisation: 14.1%; Transformers: 11.6%. Boilers and fossil fuel treatment are about 45% of the cost. The cost of 20 years of oil is very similar to the avoided fossil fuel equipment. Perhaps 2/3 of the lifecycle cost of this plant is directly related to either fossil fuel handling or fossil fuel price.

Hybridisation with fossil fuel is used to give solar more reliability in the absence of storage. However, the price paid by a solar system for hybridisation is high, because the solar system must be made compatible in output temperature with the fossil fuel system, and because the actual cost of equipment to handle, combust and dispose of fossil fuel waste is also surprisingly high. A turbine system and storage unit optimally designed for pure solar heat may be very different from that which is designed for a solar/fossil hybrid.

Economic Optimization and Evaluation Assumptions

Table 2: economic assumptions for the 50 MW gas / solar hybrid plant

Investment costs:

Specific Powerblock Investment 6

671 €/kWel, net

Gas burner

Burner Invest = 80 €/kWth x 120 MWth x 1’000 kW/MW x (P/120 MWth)07

^ 75 €/kWth (150 MWth) — 169 €/kWth (10 MWth)

Annual costs:

Operation&Maintenance Power Block

5.5% of Power Block Investment

O&M_Gas Boiler

5.2% of Gas Boiler Investment

Natural Gas (fuel cost)

1.4 ct/kWh

Gas Boiler Efficiency

95%

If not otherwise defined the assumptions of table 1 apply.

Results

In figure 10 the levelised electricity costs are plotted as a function of solar field and burner size.

Levelised

Electricity

Costs

[ct/kWh]

Solar Field Size [m2]

Figure 10: Levelised electricity costs dependent on boiler [MWth] and solar field size [m2]

For all observed burner sizes an optimal solar field size exists resulting in a minimal LEC (convex shape of the surface).

It was taken into account that the gas fraction of the produced thermal energy should not exceed a certain amount for legal, respectively ecological reasons. The Californian SEGS plants are allowed to use 25% gas. In Spain it is being discussed at present to allow small amounts of co-firing but probably only in combination with a thermal storage.

without boiler

Table 3: Optimal plant configurations for Solar Only, 15% and 25% gas co-firing

Optimal configurations

Solar Only

15%

25%

gas share

gas share

Plant Design

Solar field [m2]

490’000

450’000

450’000

Boiler size [MW]

0

30

70

economic results

LEC [ct/kWh]

13.2

12.1

11.3

cost red. due to gas hybrid

8%

14%

Investment [Mio. €]

97

96

99

Full load hours

2’019

2’325

2’716

O&M [ct/kWhel]

3.2

2.9

2.6

O&M [% of total invest]

3.4

3.5

3.6

The results for the examined plant configurations are given in the next table.

Due to more full load hours and comparably low gas prices the levelised electricity costs can be reduced by 8% respectively 14% with increasing gas share in comparison with the Solar Only plant. A further and important advantage of hybrid mode is more reliable operation. The investment costs of all three variants are approximately the same (around 100 M€ for 50 MWel).

Conservative assumptions for O&M-costs have been taken into account and vary between 2.6 and 3.2 ct/kWh (depending on the solar field size). These values are slightly higher than the values of the trough plants in California (2.5 ct/kWh) [6].

An important issue is how efficiently precious natural gas is used in such a hybrid steam plant compared to a high efficiency combined cycle (CC) plant. To answer the question corresponding efficiencies have to be defined:

Table 4: Efficiencies of converting gas into electricity, plant configurations see table 3.

Gas-co-firing:

15% 25%

n1 = Eel, total / Egas

212% 126%

n 2 = (Eel, hybrid — Eel, SolarOnly) / Egas

28% 32%

Пі gives the ratio of plant electricity output and fuel input. r|2 is defined as the ratio of the supplementary electricity yield due to hybrid operation (in excess of a Solar Only plant) divided by the gas input. For p2 it was assumed that the plants are designed optimally according to the LEC (see plant variants in table 3). That means that the hybrid plants have smaller solar fields than the Solar Only plant. In case the optimally designed Solar Only plant was equipped with a gas burner providing for 15 resp. 25% co-firing, the gas converting efficiency would be higher for both variants. For further interpretation of the efficiencies see summary and outlook.

Low cost solar array design

In this paper, the general design philosophy for a large pure solar storage plant is discussed. The proposed stand alone plant design will use the same low cost Compact Linear Fresnel Reflector (CLFR) array system previously reported (Mills et al, 2003; Hu et al, 2003) as is being constructed for a coal fired plant preheating project of 35 MWe integrated with a coal-fired plant. This current coal saver project has been now been re­estimated to be 40 MWe. The project, being built for Macquarie Generation, is composed of three stages; a proving array of 1100 m2, an intermediate array of 20236 m2, and a final array of 134909 m2. After stage 3 is built, it will be the largest solar electricity plant built since the last LS3 parabolic trough field built in California in 1990, and will provide a solar electricity capacity about 3 times the current PV capacity of Australia. The kWh cost of the first plant is expected to be similar to, or below, current

wind technology in Australia.

The array system is linear like a parabolic trough collector, but it has many advantages over troughs which allow significant cost reductions, such as a long focal length with allows elastically bent flat standard glass reflector to be used.

Fig. 1. The Stage 1 array and tower line produced by SHP at the Liddell power plant site.

The array technology used in this project is of the Linear Fresnel type and was originally developed at the University of Sydney (Mills and Morrison,1999). It is called the Compact Linear Fresnel Reflector (CLFR) technology. In this approach, ground level reflector rows aim solar beam radiation at a downward facing receiver mounted on multiple elevated parallel tower lines. The technology is innovative in that it allows reflectors to have choice of two receivers so that a configuration can be chosen which offers minimal mutual blocking of adjacent reflectors and minimum ground usage. However, there are also many
supporting engineering innovations in the commercial product, including highly rigid space frame mirror supports with 360° roatation capability, long horizontal direct steam generation cavity receivers, and array fine tracking control electronics. The design of the CLFR array design incorporates high volume production elements to reduce engineering cost.

The authors have previously described some of the cost advantages of the CLFR array system (Mills et al, 2003) of the current trough technology, but have not discussed the general issue of overall stand-alone solar plant design. The traditional approach to the design of a line focus solar plant is to use a parabolic trough system to the supply of heat at between 320°C and 400°C to the main boiler and superheater of a conventional turbogenerator (NREL, 2003). Some higher cost trough designs utilise fossil fuel in off — solar hours, not only to increase the plant capacity factor, but to lower the overall cost of delivered energy. The present CLFR design can also be straightforwardly adapted in this direction. However, in trough and CLFR systems, thermal losses can rise rapidly with array operating temperature, partially cancelling out improvements in thermal conversion efficiency. In addition, the traditional path of using a superheated turbine requires more highly efficient and durable selective coatings, thicker-walled tubing for steam pressure containment, and the use of oil instead of water as a heat transfer fluid if operating above the water triple point.