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IMPERIAL COLLEGE LONDON

Faculty of Engineering

MSc in Sustainable Energy Futures

COURSEWORK COVER SHEET - INDIVIDUAL REPORTS

Please complete Sections A and C below; for group projects, also complete Section B

Section A:

Name Coursework Title Module Supervised by Date

Submitted

Section B:

Names of other Group Members (if applicable)

Section C:

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incorporate your own ideas, judgement and work. Plagiarism - the presentation of another persons words,

ideas, judgement, figures, diagrams, software or work as though they are your own - is not permitted. The use

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will result in a reduced mark (or, in serious cases, zero marks) being awarded for your coursework. All cases of

plagiarism will be reported to the College; major offences can lead to additional disciplinary action being taken.

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If this individual report relates to a project which was carried out in a pair or group, indicate which aspects of

the report, if any, were done jointly (consult your tutor or supervisor if you are in any doubt about what is

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1. carrying out calculations manually yes/no

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4. other (specify)

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I have read the above note on plagiarism, am fully aware of what it means and hereby certify that this coursework is entirely my own, except where indicated in the report or in the table above.

Signature: _______________________________ Date: ________________________

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Feasibility study of solar electricity generation in North African

region and transmission to Europe via High Voltage Direct

Current transmission lines

Gutelman Benjamin

September 2008

Supervised by: Dr B. Chaudhuri

Dr N. Ekins-Daukes

A thesis submitted to Imperial College London in partial fulfilment of the requirements for

the degree of Master of Science in Sustainable Energy Futures and for the Diploma of

Imperial College

Faculty of Engineering

Imperial College London

London SW7 2AZ, UK

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Table of contents

Page

Abstract 5

Introduction 6

1. Concentrated Photovoltaic Technology 7

2. Solar Thermal Parabolic Trough Technology 23

3. High Voltage Direct Current Technology 36

4. Irradiance Database 48

5. Model Simulation and Results 50

6. Conclusion 104

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Abstract

This project studies the possibility of generating large amount of electricity in North African region and

transmitting this electricity to Europe. Two significantly different solar electricity generating technologies

will be evaluated; Large Scale Concentrated Photovoltaic and Large Scale Parabolic Trough Solar

Thermal. The purpose of this project is to estimate the benefit European electricity consumer would gain

from the use of solar electricity generated in location where the solar irradiance is high and therefore in

location where the solar generating technologies operate at their best level of performances. The electricity

transmission mean used in this project is high voltage direct current transmission which is the only

economical option for the transmission of electricity over long distances such as the ones discussed in the

project. The total cost of generating and transmitting electricity is calculated, considering different

generation locations in North Africa and the optimal location from where to generate electricity is

established. The optimal location being the one that gives the lowest cost of electricity. From the result of

the simulation executed in this project it is shown that important benefit can be gained for this distant

generation of electricity. It has been calculated that generation of electricity from concentrated

photovoltaic system using Silicon modules at specific location in Africa could lead to a lower cost of

electricity than the cost of electricity resulting from the use of different renewable sources of energy. At

the actual price of the highly efficient multijunction cell, a large scale CPV power plant using MJ modules

gives a higher cost of electricity than large scale CPV power plant using Silicon modules. Considering the

performances and costs of the operating Solar Energy Generating System (SEGS) Solar thermal parabolic

trough do not economically compete with large scale CPV systems as the cost of electricity is much

higher. But considering the progress in the parabolic trough technology made since SEGS was built, a

significant cost reduction is projected for this system and is described in this thesis.

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Introduction

In Europe, the solar share of the energy mix is low; this can be explained by the fact that the PV

market is dominated by distributed low scale building-integrated or rooftop applications. Because

of this distributed characteristic of the European PV market, the cost-reducing effect from the

economy of scales is low and the cost of solar electricity remains high in comparison to the cost of

electricity generated from fossil resources or even from renewable such as from wind or

hydroelectric. There are many ways for reducing the cost of solar energy, one way is to centralise

the generation to benefit from the economy of scale another way is to increase the electrical

output of solar generating systems by improving the efficiency of solar electricity generation

technologies or by generating electricity at location where the suns radiation power is high. In

this project the effect on the cost of solar electricity of large scale solar electricity generation in

location with high irradiance will be studied. In this project the potential for generating electricity

from solar resources in North African region will be evaluated as well as the potential for this

electricity to be used in Europe. As it is going to be explained in the project high voltage direct

current transmission is the only economical way to transmit electricity over the distances

discussed in the project. The objective of the project is to find the total cost of electricity which

includes the cost of the transmission. Indeed the already existing UCTE grid and the existing

African-European interconnexions are already operated close to their limits of capacity therefore

new means of transmission would need to be erected in order to transfer large amount of electrical

energy from Africa to Europe, this is the reason why the transmission cost needs to be included in

the total electricity cost in order to allow comparison with other sources of energy used in Europe

which use the already existing UCTE grid to transmit the electricity generated. Two different

technologies for electricity generation will be evaluated; large scale concentrated photovoltaic and

large scale solar thermal parabolic trough. In this project the optimal location in Africa from

where to generate electricity using these two technologies will be found. The optimal generation

location being the one that gives the lower cost of electricity considering the differences in

irradiance from one location to another resulting in different annual electrical output of the

systems and considering the different length of HVDC transmission line required resulting in

different transmissions costs. The first three chapters of this project examine the advantages of the

generation and transmission technologies as well as their costs and efficiencies. In the fourth

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chapter of the project the model used for the assessment of the cost of electricity is described and

the results are exposed. In summary, this project evaluates the cost of generating electricity from

different technologies in Africa and transmitting this electricity to Europe, 3 optimal locations for

the establishment of a 5GW (5GWp for CPV and 5GWe for thermal) solar power plant are found.

The design for the three HVDC transmission lines used to transfer the electricity from the optimal

locations to Europe as well as their costs is described. Finally, assuming a discount rate of 5%, the

levelised cost of electricity for the different technologies placed at the three optimal locations is

calculated, this levelised cost of electricity includes the transmission costs. In the conclusion of

the project the levelised cost of electricity for different sources of energy assuming the same 5%

discount rate are shown and a brief comparison is made between the costs calculated in the project

and the costs of different sources of energy.

1. Concentrated photovoltaic technology (CPV)

1.1 Concept of concentrated photovoltaic dish system

In a concentrated photovoltaic dish system the sun radiations are collected onto a large area of

mirrors called collectors in order to reflect and concentrate these radiations onto a small area of

photovoltaic cells cluster together to form a module. The photovoltaic module is placed at the

focal zone of the parabolic dish and converts the concentrated suns radiations into direct current

electricity.

1.2 Rationale for use in desert, low latitude areas

The decision of investigating the option of CPV rather than traditional PV has been influenced by

key qualities CPV demonstrate when operating in low latitude desert conditions such as the one

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found in North Africa. Indeed, one characteristic of CPV dish system is that it can only use the

direct normal solar irradiation; the tracking system of the CPV unit ensures that the suns beam is

always directed into collectors field of view during the day, while traditional flat plate

photovoltaic system use the global horizontal solar irradiance which describe the solar radiation

that would strike a flat-plate collector oriented horizontally to the earths surface or the so called

flat-plate tilted irradiance whenever the flat-plate PV collector is orientated toward the equator

and tilted at an angle equal to the latitude of the site where the system is being operated. This

characteristic of CPV dish technology is a disadvantage when used in area where the global

horizontal irradiance (GHI) is higher than the direct normal irradiance (DNI). At location where

GHI is greater than DNI the expenses in tracking system are no longer justified as the system

would collect more energy in a definite period of time if left fixed and horizontal, reciprocally in

areas where the diffuse component of the global horizontal irradiance is minor, where the sky is

clear for example, and therefore in a location where the DNI is greater than the GHI, the cost of

tracking the sun become justified as it increases the electrical output of a tracking CPV dish

system. As it can be seen on the graph below, as the latitude decrease the DNI and GHI increase,

but the increase in DNI is more important than the increase in GHI (Muriel, 2001)

Figure 1

Figure 1 shows the increase in average annual direct normal irradiation and global horizontal

irradiation with variation in latitude in Europe and North Africa. The increase in direct normal

irradiation is greater than the increase of the global horizontal irradiation. As a result the output

and the profitability of a tracking dish CPV system in the south (North Africa) is much higher

than for fixed flat plate PV systems.

This brief analysis does not take into account the cost of tracking and the cost of the concentrative

solar cell (In order for the CPV system to be truly profitable, these costs must be offset by the

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increase in electrical production they would implied) .This analysis just demonstrates the quality

of the energy input a concentrative dish system would be able to use in north African region and it

also demonstrates the justification of using tracking and concentrative solar system in low latitude

areas.

1.3 General advantages of CPV systems

One principal advantage in term of cost per electricity produced of CPV system over traditional

PV come from its concentrative aspect. CPV dish system uses large areas of mirrors to focus the

sunlight on a small area of photovoltaic cell, cost reduction is achieved by replacing the more

expensive semiconductor area by the less expensive concentrative material; the primary attraction

of CPV systems is their reduced usage of semiconducting material which is expensive and

currently in short supply. This substitution may be achieved by collecting sunlight over an

equivalent area that required by conventional PV modules and then concentrating it on to a small

area of PV cells. Again the CPV dish system is more complex than simple flat static PV, and the

cost of this complexity would only make sense when used in areas with high direct normal

irradiance where the cost of building and operating the collecting and concentrating equipment

were to be more than offset by the saving that would result from using substantially less PV

material and the higher electrical output production. Another advantage of using two axis CPV

system comes from the fact that the hourly profile of direct beam radiation is rounder than the

profile for global radiation on a fixed surface meaning that the variation of the DNI throughout the

day is less important than the variation of the global horizontal irradiance, this results in a more

stable electrical output from CPV system dish that better match utility load requirements than that

of a static non-concentrator system. Finally another advantage of CPV is that, as mentioned

before, the active PV cell area constitutes an extremely small part of the system and, as such, is

easily replaceable. This means that the system can easily be repaired by replacing a damaged

active semi conductor area or be upgraded by replacing the active area by more efficient cell that

will be available in the market in a near future (Kurokawa, 2007).

1.4 CPV present market deployment

In 2004, less than a 1 MWp capacity of CPV was installed out of a total world PV market of 1200

MWp. Level of experience in CPV is therefore very low and as a result, cost reduction scenarios

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are hard to establish. Indeed, nowadays only a small number of companies are manufacturing

CPV module and concentrative cells. The main reasons why there is such a low deployment of

CPV technology are the following:

a. The PV market was dominated by low scale building-integrated or rooftop application whereas

CPV is more suited for mid to large scale generation; CPV units come in larger module sizes

(typically 20 to 35 kW) ,mainly because the added cost of complexity must be justified by a large

output which is often not required for domestic applications (Bett, 2005).

b. The efficiency of concentrator cell has only recently been improved; 10 years ago the best

concentrator cell had an efficiency of about 30%, compared with about 40% today (McConnell,

2006). As it is going to be shown in the simulation part of the project, the influence of cell

efficiency and more particularly the ratio cost of cell over efficiency has a very high influence on

the cost of electricity production of CPV systems when multijunction cells are used, in this case

the cost of the cell represent a significant portion of the overall CPV systems costs whereas when

silicon cells are used, their costs are almost neglectable in comparison to the whole system, and

the sensitivity of the cost of electricity production to the cell cost is very low.

c. In the last 10 years, the solar industry has expanded and the CPV industry is now growing rapidly.

The use of tracking system for generating solar electricity is more common now than in the past,

lowering the price of the equipment. As it is going to be demonstrated using high-efficiency

concentrator cells as well as traditional concentrator Silicon cell can lead to very low costs for

solar electricity production.

1.5 Concentrative cells

At the moment only a small number of companies are capable of manufacturing CPV cells, there

are no long-term performance data available, and no large units of the kind that is being envisaged

in the project have ever been built but some reports shows stable on-sun operation which is an

indication that rapid expansion could occur within the coming years.

At the concentrator photovoltaic summit 2008, Solar Systems reported on-sun operation of

concentrative cell on CPV dish system for 2 years with no measurable degradation. Similarly,

Emcore showed stable operation of a 2.5kW system for 8 months, and ISFOC (Instituto de

Sistemas Fotovoltaicos de Concentracin) noted only trivial issues for cells at its CPV test site.

ENTECH has been testing a 1kW triple-junction-cell concentrator array outdoors since July 2003

under a NASA-funded program, with no detectable performance degradation. Concerning

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efficiency of the cell Spectrolab and Emcore are currently shipping multijunction concentrator

cells to multiple CPV companies. In Spectrolab datasheet they are describing cell with minimum

average 36% efficiency cell under 500 suns. Emcore datasheet describes typical 35% cell

efficiency at 470 suns. But as no long term performance testing has been done, their reliability on

the long term is an area of discussion. Currently, a three-junction GaInP/GaInAs/Ge detains the

efficiency record of 40.7% (Kielich, 2006). The main technical reasons why multijunction

concentrator cells have achieved such high efficiency in comparison to other solar cell approach

are because:

a. Theoretically, if multiple semiconductor materials (with a range of bandgaps) are chosen to

better mach spectral distribution of the sun higher efficiencies may be achieved.

b. The compound semiconductors used in multijunction cells are direct gap materials and can be

grown with near perfect quality (Yamaguchi, 1999) .

Figure 2. Different solar cell efficiencies and the 40.7% record of triple junctions solar cell

1.5.1 Concentrative cell for the simulation

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In this project the cost of generating electricity with CPV dish system using two different CPV

cell modules will be evaluated (silicon and multijunction). The objective of this evaluation is to

verify the argument stating that , as the cell area requirement for CPV system is low, the use of

high efficiency , high cost cell is justified as the electricity output offset the high cost of the cell.

1.5.1.1 Silicon solar cell

SunPower HEDA 303 monocrystalline silicone concentrator cell

The first cell is the SunPower HEDA 303 monocrystalline silicon concentrator cell and the

specifications of the cell are shown on the table below (Kurokawa, 2007):

SunPower HEDA303

Cell dimensions 10mm*15mm

Active area dimensions 10mm*15mm

Active area 1500 cm2

Typical peak efficiency at 25W/m2 24%

Typical efficiency at 25W/m2 22%

Isc at 25W/m2 13.3 A

Vsc at 25W/m2 820 mV

FF at 25W/m2

Ipp at 25W/m2

Vpp at 25W/m2

0.76

12.4 A

670 mV

The cell used in the calculation is a modified version of the SunPower HEDA303. Indeed the

chosen parabolic dish configuration on which the module will be installed is reflecting light on a

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1m2 receiver. Thus the HEDA303 cell size specifications describe above need to be scale up to fit

in a m2 receiver in order to fit in the specific dish selected. The modified version of the SunPower

cell shows a tested efficiency of 23% when submitted to 400 times concentration. In a dish

concentrating at 400 suns, a 1m2 module equipped with the modified version of the cell would

have a typical peak power of 87.6 KWp and module efficiency equals to 20% at operating

conditions (cell temperature of 600C). A special design feature of these cells is that they have both

their positive and negative electrical contacts on the rear surface. Therefore, their active area is

essentially the same as their gross area, they can thus be densely packed so that 1m2 of cell area

should occupy approximately 1 m2 of space in the focal zone of the parabolic dish( with a cell to

module loss factor that is taken into account in the calculation) (Kurokawa, 2007).

1.5.1.2 Multijunction cell(MJ)

Multijunction solar cell Spectrolab MJ206 multijunction cell

The second cell for which the cost of generating electricity with a CPV dish will be estimated is a

multijunction cell manufactured by Spectrolab. It has been possible to collect a large amount of

data regarding the performance of concentrator dish fitted with a MJ206 module under various

conditions (Verlinden, 2007).

The table above shows the performance of a 0.2352m2 receiver fitted with a modules composed by

a cluster of 1500 MJ206 solar cell measuring 0.2304m2 in a CPV dish concentrating the sun

radiation 476 and 405 times. The table shows the performance under Standard Operating

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Condition (SOC) and under Normal Operating Condition (NOC). SOC are taken under a spectral

distribution of air mass 1.5 with a radiation power of 1000 W/m2 direct and a temperature of the

cell of 210C. A more realistic condition that would better match the condition encountered in

desert is the NOC defined by an incident power density of 850 W/m2 under a spectral distribution

of air mass 1.5 and a cell temperature of 450C .As it has been said before the configuration of the

CPV dish on which the modules will be placed to run the simulation focus the sunlight on a

receiver measuring 1m2, therefore the performance of the modules described above must be

scaled-up to match the performances the module would show if its size were to be increased to

1m2 . In the calculation it has been assumed that if a 0.2305m2 module equipped with MJ206 cells

produces 27.1 kW under NOC, a 1m2 module would produce electricity at the same receiver

efficiency and have an output power equal to 115.3kW. The receiver efficiency, when used in

desert condition, is assumed to be the same as the receiver efficiency under NOC condition.

1.6 Concentrated photovoltaic dish

In order to allow comparison in the cost of electricity for the two cells, utilization with similar

concentration materials and system equipment need to be performed. These materials and

equipments comprise the foundations, the base, the dish reflector, the actuators and hydraulic

controls, cables, flux receiver mount, cooling system, piping and inverter. The dish and other

equipment used for the simulation are based on the operation of PETAL (Photon Energy

Transformation & Astrophysics Laboratory) a fully-operative 400 m2 parabolic dish (22.5 m2

primary mirrors diameter) concentrator operating in the Negev desert in Israel with a focal length

close to 13 m, and variable concentration up to approximately 10,000 suns. PETALs paraboloidal

surface is constructed from 216 mirror panels with triangular perimeters. Because of its overall

hexagonal symmetry there are only 36 different mirror panels, each having 6 replications. Each of

the panels can be manually aligned so as to vary the achievable concentration. For the purpose of

the present project we shall consider a situation in which the 400m2 of incident solar irradiance is

redistributed over a 1m2 area of CPV cell, a situation in which PETAL is operated at 400X

concentration. The CPV module is placed in a box-shaped receiver having secondary reflectors on

the inner surface of its side walls, and sized so as to produce uniform illumination over all of the

cells. This would ensure illumination uniformity to within +- 5% of 400 KW/m2. PETAL is

equipped with a two-axis tracking system tracking and ensures that the sun direct normal radiation

is always directed into collectors field of view during the day. The cooling system in PETAL

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ensures that the cell temperature is kept at 600C throughout the day (Kurokawa, 2007). The

different losses occurring in these systems are known and a plant using CPV dish similar to

PETAL equipped with the 2 cells mentioned above would have the following efficiencies profile:

Silicon

Standard test condition (STC) cell efficiency 0.23

Cell module geometric factor 0.952

STC normal operation factor 0.913 (@ 60oC)

Soiling/shading factor 0.920

Mismatch, cabling, diodes 0.972

DC->AC inverter efficiency 0.950

Miscellaneous resistive losses 0.974

Total system efficiency 0.165

Concentration factor 400

Multijunction

Standard test conditions (STC) cell efficiency 0.33

Cell module geometric factor 0.952

STC normal operation factor 0.913 (@ 60oC)

Soiling/shading factor 0.920

Mismatch, cabling, diodes 0.972

DC->AC inverter efficiency 0.950

Miscellaneous resistive losses 0.974

Total plant efficiency 0.242

Concentration factor 400

As no large scale plant using CPV dish has ever been built, the sources of system efficiency were

assumed to be similar to the values of non-concentrator PV systems with one exception: a

soiling/shading factor of 0.92 was assumed for the mirrors including variation in reflectivity,

small amount of dirt and shading. Gordon and Wenger have studied the mutual shading problem

for 2 axis trackers mounted in either a square or rectangular array. Their conclusion is that a 7.8:1

ground to aperture ratio would result in annual shading losses of about 1%. This ground to

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aperture ratio is the one used to calculate the land requirement of the large scale CPV plant and

the shading losses factor resulting from the arrangement is taken into account in the

Soiling/Shading factor efficiency.

1.7 Cost of a 5GWp CPV power plant based on the costs of materials

and equipments used on PETAL

The costs involved in the materials and in the construction of large scale CPV power plant is

based on the cost estimation for large scale concentrator PV system described by Kurokawa in the

book: Energy from the desert (Kurokawa, 2007). The CPV unit used in the estimation is similar

to PETAL and the concentrative materials and other equipments costs are based on the costs

incurred in the operation and fabrication of PETAL. The construction costs are based on the costs

of edification of existing CPV system operating around the world.

Land requirements for 5GWe

Each CPV units have circular primary mirrors with a diameter of 22.5m (aperture of the mirror is

400m2) and they are arranged in a square array. A ground to aperture ration of 7.8:1 then requires

a spacing of 56m between the centres of adjacent units. When the silicon modules are used, we

consider the case of a CPV plant comprising 57078 individual 87.6 kW unit (5GWp). If the units

are arranged into a square area comprising 239 rows of 239 units each and each centre of unit are

spaced from each other by 56m, it results in a size of the CPV plant totalling a square area of

173km2. When the multijunctions modules are used, we consider the case of a CPV plant

comprising 43343individual 115.3 kW unit (5GWp). If the units are arrange into a square area

comprising 208 rows of 208 units each and each centre of unit are spaced from each other by 56m,

it results in a size of the CPV plant totalling a square area of 136km2.

The basic assumptions for the cost estimations are the following:

a. Installation of the 5GWp plant in one year

b. An effective workforce available for 250 days during the year

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c. The majority of the workforce is local

d. Availability of on-site grid electric power to commence installation ( or alternatively a small

PV plant)

e. Availability of on-site cranes, forklifts and portable elevated platforms

.

Workforce costs

Including site manager, chief engineer, electricians, cranes operators, cranes dogmen/riggers,

forklift trucks operators, installers, installer crew leaders, concrete foreman and concrete worker

including reinforcement fixers account for $ 4780 per CPV unit installed

Cost of material handling

Including elevated platforms, forklifts, mobile cranes account for $ 1450 per CPV unit installed

Cost of site preparation

The site is assumed to be levelled the plant has 239 north-south rows, each with 239 CPV units.

The rows are each 56m apart and the units are at 56m spacing, occupying a total land area of 173

km2. The cost of site preparation account to $ 4280 per CPV unit

Cost of material for the CPV units

A concentrating collector is configured as a mirrored concave steel shell mounted to rotate about a

horizontal axis on a fabricated steel base that rotates on a vertical axis at the centre of a concrete

foundation. The forces that are require for this two-axis tracking system are supplied by

electrohydraylic actuators and controlled by on-board electronic elements and positions sensors.

The power producing module of PV cells is mounted near the focus of the concave mirror and

intercepts the uniformly distributed concentrated radiation at the exit of a flux receiver. Coolant

fluid is pumped to a rotary joint at the centre of each CPV unit foundation, up the receiver mount,

into the flux receiver walls and the PV modules and back down again. The materials and

estimated costs can be allocated to number of clearly identifiable categories, as follows:

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Concentrator:

Foundation, base, dish reflector, actuators and hydraulics, controls and cables, and flux receiver

mount account for 45500$ per CPV unit

PV generator:

Flux receiver, cooling system and piping 8000$ per unit CPV

Inverter:

Electric output cables and power conditioning equipment 31500 $ per CPV unit

Additional costs

It has been estimated that there are many different factor increasing the total plant cost which are

difficult to estimated, it has to do with how the plant will be used and how far the plant is located

from the point of manufacture, what kind of profit margin may be assumed for designers and

contractors. The additional cost may therefore be regarded as being a possible rather than a

probable scenarios .The way this additional cost has been estimated should offer an insights into

the extent to which the above capital costs may have been underestimated. So considering the

design work required from the manufacturer due to the fact that the components for the CPV plant

are not off-the-shelf items, considering the project handling fee to the power engineering company

and considering a potential shipment of the components we end with a grand total estimate of

$136 000per unit (without the PV module)

Operation and maintenance

As there are no data available about the operation and maintenance of this kind of CPV plant,

because none has yet been built, the cost of O&M are based on the large solar thermal power

plants that have been constructed. Large scale CPV O&M shares same processes that large scale

solar thermal such as maintenance of tracking motors, fluid pumping, and mirrors cleaning. On

the other hand, the maintenance costs of a CPV receiver may be expected to be lower than those

of a turbine in a corresponding solar thermal plant. O&M for solar thermal power plant are often

estimated as being 1-2% of the capital cost, considering that the upper figure is being taken for the

estimates (Kurokawa, 2007).

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1.8 Cost of 5GWp CPV solar plant with Silicon cell

The cost of the Silicon cell is $500/m2 (Kurokawa, 2007), therefore the resulting total cost per unit

of a large scale CPV system is equal to $136500. For a 5GWe power plant the cost would then be

equal to 57078 units * 136000 = $7,791,147,000 and the distribution of the cost is as follow:

1.9 Cost of 5GWp solar plant with Multijunction cell

The cost of the multijunction cell is $10/cm2 (Olson, 2005) therefore the resulting cost per unit of

a large scale CPV system with multijunction modules is equal to $236000 per unit. For a 5 GWp

power plant the total cost would then be equal to 43343 units * 136000 = $10,228,948,000

Material

handling

1.08% Site

preparation

3.18%

Concentrator

33.77%

Cell module

0.37%

PV generator

5.94%

Inverter

23.38%

Additional

32.29%

Distribution of capital costs for

the 5GWp plant using Silicon modules

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As oppose to Silicon concentration cell, multijunctions cell cost represent a high proportion of the

total plant cost. While the cost of the PV module represented only 0.37% of the total cost of the

unit when silicon cells are used, the cost of PV module equipped with multijunction cell represent

42% of the total cost. Therefore the sensitivity of the cost of electricity production to the MJ cell

cost is much higher and any advanced in the technology or in the manufacturing processes of the

MJ cell would have an important effect in the cost of electricity. Cost of electricity is defined here

and throughout the project as the following equation:

Cost of electricity =

+

(It should be noted that the cost of electricity generation is not the levelised costs of electricity

(LCOE) as no depreciation rate are taken into account. The LCOE depends on the financing

scheme while the cost of electricity does not.)

Material

handling

1%

Site preparation

2%

Concentrator

19%

Cell module

43%PV generator

3%

Inverter

13%

Additional

19%

Distribution of capital costs for

the 5GWp plant using MJ modules

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The leader in CPV MJ cell production believes they can reduce their costs to a level of $5/cm2

through higher manufacturing efficiency and higher volume production. The potential reduction

of the cost in multijunction cell is described in the graph below and the reasons for the reduction

are explained (Sherif, 2005):

Figure 3. Projected MJ cell price at different volume

Case 1 , which is the upper line is the decrease in price resulting only from the economy of scale

factor, here no material or manufacturing process cost reduction are taken into account, just an

increase in volume production. In case 2 cost reduction is driven by a combination of economy of

scale and a reduction in the cost of Ge wafer which is one of the three element involved in the cost

of fabrication of an MJ cell with the cost of growing the device structure and the cost of cell

fabrication (including deposition of the anti-reflection coating and the metal pattern on the wafer,

saw dicing process to separate the cells from the wafer, and cell testing).

In case 3, cost reductions is achieved by a combination of economy of scale and reduction in the

cost of cell fabrication through higher manufacturing efficiency (the key element here is to replace

the saw dicing process by more cost effective processes). Case 4 combines all the above

scenarios: economy of scale, reduction in Ge wafer cost and lower cost, more efficiency

manufacturing processes. The effect of this reduction of cell cost on the total cost of electricity is

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shown in the model simulation part of the project. For the initial calculations of the cost of

electricity a $10/cm2 cell cost is used.

1.10 :ote about lifetime of CPV systems

As mentioned before, level of experience for large scale CPV is inexistent, therefore there is no

information on how well CPV module will deal with the long term effect of being exposed to 400

suns of being cycled on and off with each passing clouds. However, as the size of the cell area

required for CPV systems is physically small and therefore easy to substitute. It is not

unreasonable to think that the decrease in annual electrical output, thus the increase in cost of

electricity, from cell degradation would be more than offset by the replacement of new, more

efficient and cheaper PV modules over the lifetime of the plant. It has been estimated in the book

Energy from the desert that considering the potential future availability of cheaper and more

efficient cell, the presently unknown CPV cell degradation factor do not have a negative impact

on the cost of electricity, and that the total energy output over a 30 years lifetime may even be

under valuated in the calculations as this project do not take into account the replacement of cells

during the plant lifetime (Kurokawa, 2007). Considering these facts and following the reasoning

made in the book Energy from the desert, a 30 years lifetime of the plant operating at the same

efficiency for 30 years is a more than reasonable figure.

23

2. Solar thermal - Parabolic trough

2.1 Concept of parabolic trough

Parabolic Concentrating solar thermal power technologies are based on the concept of

concentrating solar radiation to be used for electricity generation within conventional power

cycles using steam turbines. For concentration, most systems use glass mirrors that continuously

track the position of the sun. In a trough system, the solar collector field consists of a large field of

single-axis tracking parabolic trough solar collector. The solar collectors are aligned on parallel

rows on a north-south axis in order to track the sun from east to west during the day. The

collectors have a parabolic shape so that it reflects the sun radiations onto a linear receiver located

at the focus of the parabola. A fluid flowing through the receiver takes the heat away towards the

power cycle, where high pressure, high temperature steam is generated to drive a turbine. Air,

water, oil and molten salt can be used as heat transfer fluids. The mix of steam-water left after the

generation of electricity is condensed and then feed back into the steam generator to complete the

water cycle. In order to produce electric output during overcast or night time periods; a backup

fossil-fired capability can be used to complement the solar output during periods of low solar

radiation (Sargent, 2003). A model of a parabolic trough system is shown on the diagram below:

24

2.2 Rationale for use in desert, low latitude areas

Solar thermal technology is another promising option for low cost large scale generation of

electricity in low latitude desert area such as in North Africa. This technology is substantially

different than CPV system in the sense that it converts the energy from suns radiation into heat

before transforming this thermal energy into electricity while CPV generates electricity from the

photoelectric effect. Despite this fundamental difference, the qualities that were attributed to CPV

when use in low latitude desert area are also valid with solar thermal technologies. Indeed solar

thermal technology use direct normal irradiance to generate electricity by the use of tracking

system, and solar thermal can only be used efficiently and at low cost in area where DNI is high.

In contrast to PV systems, the annual system efficiency of parabolic trough systems increases

significantly with the annual irradiation as the part load efficiency of a steam turbine cycle is

much lower than the nominal efficiency (Quaschning, 2004). The efficiency is also reduced

during days with fluctuating irradiance values due to the capacitive behaviour of the thermal

system. Furthermore, sites with lower irradiation values are situated at higher latitudes where the

solar altitude is also lower, thus increasing the optical losses of one-axis tracked trough collectors

and therefore reduces the efficiency. Lower ambient temperatures at sites with lower irradiations

increase the thermal losses of the collector and field and thus reduce the solar thermal collector

efficiency.

Figure 4. Variation of solar thermal system efficiency in function of global horizontal irradiance

25

2.3 Influence of thermal storage on the capacity factor of a parabolic

trough plant

One principal advantage of parabolic trough solar thermal over CPV is the technical ability to

store energy, thus increasing the ability of the generation system to match the load demand

requirement by displacing the output over more hours of the day. The increase economical

profitability of system with storage resulting from a flatter electrical output will not be evaluated

as this project focus on the cost of generating electricity rather than the actual state of the

European electricity market and the potential revenue from the sale of electricity. Spreading the

electrical output throughout the day and matching supply with demand to a certain extent is not

the only advantage of storage in solar thermal system. . The distinctive particularity of storing

heat in a solar thermal system is the ability of increasing the annual electrical output resulting

from higher system efficiency which is not the case for PV system; in CPV systems, there would

be no advantages in term of generation cost reduction if electrochemical storage were to be used,

it would simply displace the output and increase the profit resulting from the sale of electricity

.Storage in CPV system would only allow flexibility in operation by reducing the times of

mismatch between energy supply by the sun radiation and energy demand, thus allowing the

generators to make more profit as electricity could, in this case, be sold at higher price during

peak consumption period. In opposition to CPV system, adding thermal storage to solar thermal

systems increase the annual output of the plant mainly because the consequences of spreading the

output increase the total system efficiency of the plant and more particularly the turbine cycle

efficiency. Indeed, thermal storage allows the plant to operate the turbine more hours at full load

close to peak efficiency and reduces the numbers of hours the plant is operating at part load, the

number of turbine start-ups per MWh generated is also much lower than in system without storage

where start-ups are exclusively dependant on weather conditions As a result, the efficiency of the

turbine is improved and the annual electrical production is higher. The addition of thermal storage

is also expected to reduce parasitics by spreading the station load over increased annual

generation. Large high temperature thermal storage systems have been demonstrated at the Solar

Electricity Generation System (SEGS I) trough plant and Solar Two power tower in Mojave

Desert, California. In these systems, thermal losses have been shown to be minimal; thus the

storage thermal efficiency approaches 100%, and as it going to be shown in the simulation model

26

part of the project the added cost of thermal storage is largely offset by the resulting increase in

annual electricity generation it would cause.

2.4 Current Experience of parabolic trough system

Parabolic trough technology is currently the most proven of the solar thermal electric

technologies. The success of this technology is primarily indicated by the operation of nine large

commercial-scale solar power plants called SEGS (Solar Energy Generating Systems), the first of

which has been operating in the California Mojave Desert since 1984. These plants, which

continue to operate daily, range in size from 14 to 80 megawatts (MWe) and represent a total of

354 MWe of installed electric generating capacity. In the SEGS design, the curved solar collectors

focus sunlight onto a receiver pipe. Mechanical controls slowly rotate the collectors during the

day, keeping them aimed at the sun as it travels across the sky. The heat transfer fluid in SEGS

system is synthetic oil. The collectors concentrate sunlight 30 to 60 times the normal intensity on

the receiver, heating the oil as high as at 390C. The heated oil is routed through a heat exchanger

to generate steam that drives an electricity producing turbine. SEGS VIII (80MWe) and SEGS IX

(80MWe) are the largest solar power plants individually and collectively in the world.

2.5 Cost and performance of a 5GWe parabolic trough power plant

In the project, the data used to determine the cost of electricity production from large scale solar

thermal parabolic trough system are based on the costs and performances of the operating SEGS

VI 30MWe solar thermal power plant. SEGS VI was chosen as a reference because it was the last

plant built using the last generation of Luz collector technology. The last generation of the Luz

collector was, at the time of construction in 1989, working at the best level of performance in

comparison to other existing collector system technology, the cost and efficiencies of SEGS VI

are shown below and are taken from the paper Assessment of parabolic trough and power tower

solar technology cost and performance forecasts (Sargent, 2003) :

27

SEGS VI system efficiency:

Therefore for a scaled up 5GWe system using material similar to the one used for SEGS VI we

have a total plant cost equal to 2553*5,000,000 = $12,765,000,000.

As it is going to be seen further in this project, in the models result section, such figures do not

economically compete with large scale CPV system described before. The main reason is because

this plant is already 20 years old, and much progress have been made in different areas that would

reduce the cost of the plant per KWe installed and improve the system efficiency. A projection of

cost reduction and performance improvement for parabolic solar trough system is described

below.

Land requirement

The field aperture area of SEGS VI is 188,000m2 for a 30MWe turbine nominal capacity,

therefore if 167 plants would be installed to form a total of 5GWe of turbine nominal capacity, the

total field aperture area would be 32 km2

2.6 Area of improvement of parabolic trough system

The following information are based on SunLab projection described in the paper : Assessment

of parabolic trough and power tower solar technology cost and performance forecasts

Capital cost of SEGS VI:

Structure and Improvements $84/KWe

Solar collection system $1493/KWe

Thermal storage system $0/KWe

Steam generator or HX system $143/KWe

EPGS(electric power generation

system) $527/KWe

Balance of Plant $306/KWe

Total $2553/KWe

Solar Field optical efficiency 0.533

Receiver thermal losses 0.729

Piping thermal losses 0.961

Storage thermal losses NA

EPGS efficiency 0.35

Electric Parasitic load 0.827

Power plant availability 0.98

Annual Solar-to-Electric

efficiency 10.60%

28

2.6.1 Increase solar-to-electric annual efficiency

The system efficiency improvement of future parabolic trough plants is based on the well documented

efficiency data of the existing SEGS parabolic trough plants. SEGS VI is used as a reference plant to

estimate upcoming performance improvements. SunLab based their technical projection improvement and

cost reductions achievement on the following technical advancement and area of research.

2.6.1.1 Improvement in the solar field optical efficiency

The development of new SOLEL UVAC receiver which feature lower mean thermal emissivity, higher

absorptance ,higher transmitivity and increase net exposure to available radiation due to a low profile

radiation shield. These characteristics have led to a 20% increase in thermal performance when tested at

SEGS VI compared to original receiver tubes.

2.6.1.2 Research and implementation of thermal storage

Thermal storage systems which are not used in SEGS VI result in a higher capacity factor ,thus reduce the

cost of generation ($/KWh) by obtaining a higher annual electrical output of the plant(through higher

efficiency of the turbine cycle). The thermal losses from the thermal storage system are minimum. Large

high temperature thermal storage systems have been demonstrated and the storage thermal efficiency

comes close to 100%.

2.6.1.3 Turbine cycle improved efficiency

The turbine cycle efficiency accounts for the design turbine efficiency, start-up losses and losses due to

minimum turbine load requirement. The losses due to minimum turbine requirement are significant when

thermal storage is not used, therefore implementation of thermal storage increase the turbine cycle annual

efficiency (which is one of the causes that lead to a higher annual electrical output from installation of

storage systems).

The turbine cycle efficiency is also improved by using higher temperature heat transfer fluid (increase

Rankine cycle efficiency)

29

2.6.1.4 Reduction of electric Parasitic Load

Electric parasitic loads account for the heat transfer fluid pumps, condensate/feedwater pumps,

cooling water pumps, cooling tower fans, and boiler of heater forced draft fans.

A reduction in parasitic load is expected from the replacement of flex hoses with balljoint

assemblies in the solar field. These assemblies reduce the pressure drop across the solar field by

about 50%. Thermal storage will also reduce parasitic by spreading the load over increased annual

generation

In summary SunLab improved performance are based on:

1. Installation of new receiver with better optical and thermal features

2. Implementation of thermal storage leading to more efficient turbine cycle efficiency

3. A higher temperature heat transfer fluid to increase turbine efficiency

4. Replacement of flex hoses to reduce the pressure drop across the field thus reducing the parasitic

load

As it is going to be shown below, with the implementation of these existing technology a 17%

annual solar-to-electric efficiency is achievable in the long term. Though additional investigation

and development of storage systems, including the optimum heat transfer fluid temperature for

steam cycle efficiency and storage compatibility is required to achieve the 17% efficiency

projected by SunLab

2.6.2 Potential for cost reduction

The cost of actual SEGS VI has been estimated to be $2554/KWe (Turbine nominal capacity)

with a cost structure shown below (Sargent, 2003):

30

Capital cost of SEGS VI:

Structure and Improvements $84/Kwe

Solar collection system $1493/KWe

Thermal storage system $0/KWe

Steam generator or HX system $143/KWe

EPGS $527/KWe

Balance of Plant $306/KWe

Total $2553/KWe

The major cost component is the solar collection system with a cost breakdown as follow:

Solar collection system

Mirrors $40/m2

Receivers $43/m2

Concentrator structure $50/m2

Concentrator erection $17/m2

Drive $14/m2

Interconnection Piping $11/m2

3%

58%6%

21%

12%

Distribution of the capital cost of SEGS VI

Structure and

Improvements

Solar collection system

Steam generator or HX

system

EPGS

Balance of Plant

31

Electronics and control $16/m2

Header piping $8/m2

Foundation/Other Civil $21/m2

Other(Spares,freight,HTF) $17/m2

Contingency $12/m2

The plan for cost reduction per turbine capacity installed projected by SunLab is based on the cost

reduction of the following component of the cost structure:

2.6.2.1 Solar field collection element

As mentioned before changing the original receiver on SEGS VI to the UVAC receiver from

SOLEL constitute a major step in total system efficiency improvement through improved optical

and thermal properties.

The potential for cost reduction of the element, which contributes to a major portion of the direct

capital cost, is based on the announcement of different companies to provide this component.

Indeed, at the time where SEGS VI was built, the heat collection elements had only one supplier

(SOLEL) .The cost reduction for the receiver projected by SunLab is also based on the

investigation of using more robust and lower cost glass-to-metal seal design and on identifying

higher temperature coating with better optical and thermal properties (which reduce its cost in

term of cost per capacity)

2.6.2.2 Solar field support structure

Support structure consists of the metal support system of the collector consisting of the pylons and

reflector support elements. SunLab projection for the cost reduction of this element is based on

the future minimization of the number of required parts, less complex fabrication and reduction of

labor costs for field erection. The individual parts of the structure can technically be manufactured

by suppliers worldwide and the future competition for providing this element can lead to cost

reduction

2.6.2.3 Solar field mirrors

The reflector used in SEGS consists of a 4-mm low-iron float glass mirrors thermally sagged

during manufacturing into a parabolic shape. At the time of construction a single manufacturer

32

supplied the mirrors for the plant. And cost reduction projection for the mirrors is based on future

mass production and competition as well as technical improvements. Many alternatives glass

mirrors reflectors are in early stage of development and testing. Alternative such as the use of

thin-film reflector or laminate reflector material are being developed and should lower the cost of

the components in the future.

2.6.2.4 Power block

Power block cost include the steam turbines and generator as well as the condensate systems

There is a high potential for cost reduction per capacity installed when the power block size is

being increased. There is scale-up factor for increasing the plant size as it can be seen on the graph

below .Therefore a solar thermal power plant using higher temperature heat transfer fluid (higher

Rankine cycle efficiency) combined with higher turbine rating capacitiy decrease the cost of

generation per capacity. The scaling-up of the power block size is the major factor for SunLab

contributing to the reduction of the cost of electricity generated

33

SunLab cost reduction and improved performance is described in a roadmap for technology

updating based on the actual cost and performance of the operating SEGS VI. The SunLab

reviews on the assessment of parabolic trough technology cost and performance forecast was

made in 2003 and their roadmap towards improvement is described below:

1. SEGS VI 30MWe to SunLab Trough 100MWe-2004

In the first optimization of SEGS VI projection made by SunLab the power block size is being

increase from 30MWe to 100MWe taking advantage of the scaling-up of the turbine factor.(note

that for a 5GWe plant using the improvement described below, 50 individuals SunLab Trough

100MWe power plants would be needed)

The field aperture area is therefore being enlarged from 188,000 m2 to 1,120,480 m2 (56km2 for a

5GWe power plant if we assumed no spacing between the individual power plant)

A two-tank indirect thermal storage system using solar salt as a storage media is being

implemented increasing the capacity factor by

a. Increasing the part load steam cycle efficiency from 98% in SEGS to 99.5% in SunLab

trough 100MWe-2004

b. Increasing the he start-up efficiency from 96.9% to 99.2%

c. increasing the turbine minimum load requirement efficiency from 98.5% to 100%

The solar field optical efficiency is increased from 53.3% to 56.7% mainly due to the installation

of new SOLEL UVAC receiver. The parasitic losses are decrease from 17.6% in SEGS to 12.3%

through the conversion from flex hoses to ball joint assemblies (reducing the pressure drop in

collector loop)

These improvements result in an increased annual solar-to-electric efficiency from 10.6% with

SEGS VI to 14.3% with SunLab trough 100MWe-2004. The implementation of new technology

such as storage and new receiver results in an increase in the cost per KWe of the plant for the

first SunLab projection

34

2. SunLab trough 100MWe-2004 to SunLab trough 100MWe-2007

The second evolution of parabolic trough system projected by SunLab include the implementation

of a12 hours Thermocline Direct system storage increasing the turbine cycle efficiency. The

temperature of the heat transfer fluid is increased from 3910C to 4500C,this also results in an

increase steam cycle efficiency from 37% in SunLab trough 100MWe-2004 to 39% .

Parasitics are also reduced because of the elimination of need to run two sets of pumps in the

storage system .

These improvements result in an increased annual solar-to-electric efficiency from 14.3% with

SunLab trough 100MWe-2004 to 16.1% with SunLab trough 100MWe-2007

3. SunLab trough 100MWe-2007 to SunLab trough 150MWe 2010

In SunLab projection the 2015 version of the parabolic trough system has a power block nominal

capacity of 150MWe, thus reducing the cost through the effect of scaling-up factor. The field

aperture area is increased from 1,120,480 m2 to 1,477,680. The operating temperature is increase

from 4500C to 5000C increasing the gross steam cycle efficiency from 39% to 40%. The Solar

field optical efficiency is increased from 57.9% to 59.8% through a higher mirror reflectivity

factor based on use of front surface mirror with anti-soiling coating.

These improvements result in an increased annual solar-to-electric efficiency from 16.1% with

SunLab trough 100MWe-2007 to 17% with SunLab trough 150MWe-2010

4. SunLab trough 150MWe-2010 to SunLab trough 200MWe-2015

In the 2105 version of the parabolic trough projected by SunLab in their review the turbine

nominal capacity is increased from 150MWe to 200MWe. The field aperture area is increased

from 1,477,680 m2 to 1,955,200 m2 . The Solar field optical efficiency is improved through an

assumed anti-soiling treatment added to receiver envelope to improve cleanliness. The solar field

optical efficiency is increased from 59.8% to 60.2%.

These improvements result in an increased annual solar-to-electric efficiency from 17.0% with

SunLab trough 150MWe-2010 to 17.1% with SunLab trough 200MWe-2015

5. SunLab trough 200MWe-2015 to SunLab trough 400MWe-2020

In the last version of parabolic trough system projected by SunLab the turbine nominal capacitiy

in increased from 200MWe to 400MWe. The field aperture area is increased from to 1,955,200 m2

to 3,910,400 m2

35

These improvements result in an increased annual solar-to-electric efficiency from 17.1% with

SunLab trough 200MWe-20015 to 17.2% with SunLab trough 400MWe-2020

A summary of SunLab cost reduction and performance improvement is shown in the table below:

Annual solar-to-electric efficiency

Total plant

cost

SEGS VI 0.106 $2554/Kwe

SunLab trough 100MWe-2004 0.143 $4208/KWe

SunLab trough 100MWe-2007 0.161 $2949/KWe

SunLab trough 150MWe-2010 0.17 $2487/KWe

SunLab trough 200MWe-2015 0.171 $2198/KWe

SunLab trough 400MWe-2020 0.172 $1916/KWe

The effect of these improvements to the cost of electricity for large scale solar thermal parabolic

trough system is shown in the model simulation part of the project. For initial calculation,

performance and costs of SEGS VI are used to estimate the cost of electricity for a 5GWe

parabolic trough power plant. It should be noted that these costs do not include the operation and

maintenance costs. The O&M costs are estimated to be 1-2% of the total capital costs. The upper

figure is used in this project to estimate the levelised cost of electricity (same figure is used for

CPV systems)

36

3. High voltage direct current transmission

3.1 Advantage of high voltage direct current (HVDC) for bulk transmission of

electrical power over long distances

In order to transmit large amount of electricity over long distances high voltage direct current is

the best option. Indeed, the losses associated with transfer of large amount of energy using

alternative current transmission line are too important to be used on distances discussed in this

project. Indeed, the lengths of the transmission lines that are simulated in this project are longer

than a 1000 km long and have a submarine component. The main advantage of HVDC

transmission over AC is that no reactive power is transmitted, the transmission length is only

limited by ohmic resistance and there are no capacitive, inductive or dielectric losses which would

result in a drop of voltage along the line, while in AC transmission, as the current flow through

the line, a magnetic field is created around the cable and because the current is alternating, the

magnetic field changes periodically and induces a voltage. Therefore the power line behaves like a

coil and generates a resistance to the alternating current that in turn causes a decrease in current.

Alternating current may also be intensified in a cable because of the capacitive reactance causing

a problem of storage of electric charges within the cable, this problem especially occurs in

submarine cables as they act like a condenser due to their multi-layered structure. These

resistances generate an unusable reactive power and reduce this way the effective power capacity.

These resistances and the reactive power they generate are the reason why the maximum

transferable load and length of AC transmission line are limited. Indeed after a certain length the

losses of electrical energy and the cost of the compensation measures necessary to deal with the

reactive power produced are so important that it becomes economically inadequate to use AC

transmission lines. The graph below shows the losses in transmission capacity over distance for

three high voltages alternating current submarine cables with different peak voltages and one high

voltage direct current cable

37

Figure 5. Transmission capacity for different peak voltage cable

increasing distance. In the graph it is also shown that a lower voltage it is possible to transmit

over longer distances, but only transmitting less energy. Therefore compensational measures

would be required, which are not realizable with submarine cables in practice (ABB, 2005).

3.2 HVDC around the world

Worldwide HVDC transmission lines cumulate today to a total capacity of over 75 GW in more

than 90 projects. Many of them connect renewable power sources from hydropower or geothermal

power with distant centres of demand. Others are used to interconnect countries over sea (Schultz,

2000) .Below different HVDC projects running around the world are shown below:

38

Figure 6. HVDC projects around the world

3.3 HVDC costs

The transmission losses of HVAC overhead lines are roughly twice as high as those of HVDC.

The cost of overhead lines is similar for the lower voltage level, but at 800 kilovolt transmission

HVDC lines are much less expensive than comparable AC lines. On the other hand, rectifier

stations of HVDC links are considerably more expensive than the transformer stations of AC

systems. Therefore, for shorter distances and lower voltages AC is often the preferred choice,

while HVDC lines are applied at distances well over 500 km. The so-called Break-Even-

Distance terms the shortest distance where the investment costs of a direct current transmission

are identical with the costs of an alternating current transmission. It depends on the transmission

capacity and topography of the area. With an increasing transmission length the total costs of

HVAC are affected by the higher costs for conduction and network losses so that many

advantages result from the use of HVDC from the Break-Even-Point upward. In addition, the

maximum transferable loads are not restricted by the thermal limit of the conductors, but by the

guaranty of a stable voltage along the line. In contrast in case of HVAC, additional costs must be

added for compensational measures realized every 600 km (DLR, 2006).

39

Figure 7. Break-even distance for HVDC overhead transmission lines

.

The costs and losses of the 800kV HVDC transmission line are used in this project to evaluate the

cost of electricity generated in North Africa and transmitted to Europe with the cost of electricity

being equal to

+

The 800kV HVDC costs and losses from the table above are taken from different references and

calculation made by Trans-Mediterranean renewable energy cooperation(TREC) and the rated

transmission capacity of the 800kV HVDC line is calculated as being 5000MW (despite the fact

that there are no theoretical maximum transfer capacity for HVDC line; as the capacity transferred

increase the cost of the line increase as well as thicker cable are required, the cost of cables and

overhead lines above are therefore the cost of cables and lines which have the requirement for the

transfer of 5000MW of electrical power). It should be noted that in the calculation the highest

40

value for the overhead line and an average value for the terminal costs were used. These costs are

in Euros and were converted in dollar for the purpose of the calculation. It should also be noted

that the cost of transmission in the equation of the cost of electricity include two terminal (or

conversion station) costs.

.

3.4 HVDC transmission links design

HVDC design assumptions

In this project, the feasibility of using solar electricity in Europe generated in Africa is studied,

therefore the challenge of the project is to estimate the optimal location from were to generate

electricity (location that gives the lowest cost of electricity) and the optimal design for the HVDC

transmission line so that electricity can be provided to major centre of demand of electricity in

Europe. Three HVDC transmission lines will be envisaged and the choice of the design of the

optimal links are motivated by four reasons

1) The cost of undersea cables are about 6 times more expensive than overhead cable, therefore the

distance cover by the HVDC link through the Mediterranean sea must be minimized

2) A maximum of countries must be crossed by the HVDC line to be able to transmit electricity to a

maximum centre of demand of electricity, geographically speaking it means that the HVDC line

must be as straight as possible (minimise costs) and crossing as many centre of demand as

possible. The demand centres should have a high population density and therefore a high

electricity demand. Actually, the energy is fed into the high voltage network of the UCTE once

close to the centres of demand. Because this interconnected network is already operated until its

limits of capacity in many places, the solar electricity in this case is carried to the consumer as

close as possible. It should be noted that if centre of demand of electricity other than the location

at which the HVDC link ends were to use the electricity transmitted in the line, a conversion

station would be required to transform the direct current into alternative current in order for the

electrical energy to be fed in an already existing AC transmission line (otherwise 2 conversion

stations are required at the generation location and at the end of the line)

3) The area around the segment of the HVDC line between the point of generation and the coast of

Africa is assumed to be low populated and desertic, therefore no exclusion scenarios are being

41

envisaged concerning the design of the link; geographically speaking, straight HVDC line are

being envisaged for this portion of the transmission cable

4) In Europe, exclusions scenarios are being envisaged and the design of the links is based on the

work of Nadine May in her thesis Eco-balance of a Solar Electricity transmission from North

Africa to Europe , the exclusion criteria for the design of the HVDC links are protected areas

such as national park and reserves, industrial locations such as areas that are already occupied

with human activities facilities or meant for the extraction of raw materials are excluded,

populated areas are excluded as well (a minimum of 250m between populated places and the line

must be kept for reasons of electric and magnetic field) and finally geomorphologic feature where

certain areas and soil cannot be use as foundation for the pylons of the cable system. The excluded

locations for the construction of an HVDC line are shown in the graph below (May, 2005):

5) The starting point of the HVDC links must be the location from where electricity is generated at

the lowest cost considering that for different location in Africa there is a difference in the direct

normal irradiance and from every different region of Africa there is a different resulting capital

cost for the HVDC transmission line because of the different length of lines and cables involved

42

From these 5 assumptions, candidate regions can be derived from geographic and irradiances map

to narrow down the potential generating location in Africa.

On this map a few candidate regions for generation can be imagined considering the assumptions

mentioned above. A potential first HVDC transmission cable could have a starting point near

Morocco and the western Algerian region; this area would offer different qualities such as a

reduced undersea crossing through the Gibraltar Strait and a proximity to important Spanish cities.

A second link could start south to Italy somewhere in a location close to Tunisia, east Algeria and

Libya; this link would offer the advantage of a relatively short undersea HVDC portion trough the

Mediterranean Sea connecting north Algeria with the Italian island of Sardinia, this link would

allow the delivering of electricity to major centre of demand in Italy. A third link that can be

envisaged would provide electricity to the eastern part of Europe and Turkey with a starting point

in north Egyptian region.

These candidates for the generation location are logical options for the project, they show relative

proximity to the coast, in areas with high irradiance, these areas are low populated and desertic so

that minor exclusion scenarios would misrepresent the results of the model, and another advantage

43

is that the potential starting point of these 3 links are spread throughout the African coast from

west to east, each link would allow transmission to different major poles of demand in Europe.

The HVDC transmission links in Europe

As mentioned above, the design of the European portion of the HVDC transmission line is based

on the work of Nadine May. The objective of her PhD thesis was to derive, from European

electricity demand figures as well as exclusion elements, three optimal HVDC links from Africa

that would be more likely to satisfy the potential future electricity needs of major centre of

demand in Europe considering all the possible exclusion scenarios that would prevent the HVDC

lines to be built. In this project, the European portion of the three links developed in Nadine

Mays thesis will be used in order to find the cost of electricity (with transmission) of the two

solar electricity generating technologies .The length and design of the remaining portion of the

link (which is therefore the portion linking the generation location to Europe) is determined by the

simulation results of this project. The three lines are shown and described below (May, 2005):

44

1. The first line (referred in the project as Line 1) which is the one in the middle on the map

above starts in the northern coast of Tunisia and goes undersea for 220 km to the Italian island

Sardinia. On the island the line follows the course of the already existing overhead HVDC

line SACOI. The national park of Corsica forces the line to go easterly. Then a 130 km

submarine cable connects the Italian island to the Italian Mainland. The nation park

Arcipelago Toscano remains untouched. Afterwards the line has to pass the woodlands of the

Apennines and croplands in the Plain of the river Po until the destination Milano is reached.

The line pass close to many centre of demands such as Cagliari (40km away from the line),

Florence (104km from the line) and Genoa(62km away from the line)

2. The second line (referred in the project as Line 2) which is the one on the right on the graph

above starts at the Egyptian northern coast and follows the coastline until Israel is reached.

60km of the Israeli territory is reached and afterwards the line leads to Maan in Jordan after

280 km the border to Syria is reached. From there the line runs around 500 km through the

Syrian Desert. After a distance of 1300km the line leads further through the Anatolian part of

Turkey and then through the European part of Turkey. Bulgaria, Romania and Hungary are

passed in a north west direction until Vienna is reached after 1370 km, the line follows the

border of Slovakia to Czech Republic. After crossing the Czech Republic and Poland the line

end at Warszawa after a further 623 km. The line passes close to major centre of demand of

electricity such as Ankara(12km), Istanbul(19km), Sofia (99km) and Budapest(55km)

3. The third link (referred in the project as Line 3) starts in north Morocco and cross the Strait of

Gibraltar through a submarine cable on a length of 18km. Then the line has to pass the

Spanish wildlife sanctuaries Los Alcornocales and Sierra de Grazalema to the east and then

cross the country on a length of about 930km. On the latitude of the Pyrenees the French

border is passed. The line runs then almost straight in a north east direction as only a few

areas are excluded in France. The line crosses Belgium on a length of 164km and after a total

of 2011 km the destination Aachen in Germany is reached. The line passes close to major

centre of demand for electricity such as Seville(70km), Madrid (57km), Zaragoza(96km),

Toulouse (132km), Bordeaux(78km) and Paris (105km)

45

Summary distance and countries crossed by the 3 lines

LINE 1 LINE 2 LINE 3

Countries crossed(overhead) Length (km) Countries crossed(OH) Length(km) Countries crossed(OH) Length(km)

Sardinia/Italy 313 Egypt 138 Spain 932

Corsica/France 216 Israel 59 France 907

Italy 178 Jordan 378 Belgium 164

Syria 495

Overhead line = 707 Turkey 1324 Overhead line = 1193

Bulgaria 448

Submarine cable 373 Romania 361 Submarine line 18

Hungary 518

Total lenght 1080 Austria 40 Total length 2011

Overhead line = 3761

Submarine cable 0

Total lenght 3761

One of the purpose of this project is to evaluate how far away, in southern direction, from the start

of these HVDC links describe above, should the solar plant be installed in order to get a minimum

total cost of electricity, considering that the further away, the higher the cost of transmission is

but, often, the higher the irradiance is too so reducing the cost of generation through a higher

annual electricity output.

46

The black arrowed line being the portion of HVDC transmission line determined by the result of the

simulation of the model created in this thesis.

47

4. Irradiance database

The irradiance database used to estimate the direct normal irradiance that would fall on the

collector of the CPV and solar thermal plant is provided by The Solar and Wind Energy Resource

Assessment (SWERA). SWERA is government funded organization managed by the United

Nation Environment Program (UNEP). SWERA provide maps of the world renewable energy

resources and more particularly the solar irradiances for countries and region around the world.

As it can be seen in the African map below, the continent is divided into 74 regions, each of them

divided in cell of 40 km resolution. SWERA provide an excel sheet form in which a cell number

can be chosen, giving the direct normal irradiance, global horizontal irradiance, diffuse irradiance

and latitude tilt irradiance for every different cells of the continent at an accuracy of 40km

resolution.

48

49

5. Model simulation and results

The objectives of the simulation are the following:

1) Assessment of the optimal location from where to generate electricity, which is the location that

gives the minimum cost of electricity considering both generating cost and transmission costs.

2) Estimation of the cost of electricity for CPV plant operating at the optimal location using two

significantly different cells (Silicon and multijunction) but both placed in the same CPV unit to

allow comparison between the low efficient and cheap silicon cell and the high efficient and

expensive multijunction cell under the same conditions.

3) Estimation of the cost of electricity for a parabolic trough solar thermal plant based on the

performance of already operating SEGS VI, and determination of the future potential cost of

electricity based on the improvement projected by SunLab and described in the project.

The Model

50

From the information given throughout the thesis, the following data are input in the model

1. The capital cost of the 5GWe plants for both technologies

2. The efficiencies of the systems

3. The direct normal irradiance

4. The length and costs of the European portion of the HVDC link

5. The losses in transmission

Knowing these informations, it is possible to derive a cost of electricity including the transmission.

+

one portion of the transmission line being fixed (RED line on the map - European portion) and

described earlier (from Nadine Mays thesis), the other portion being the one starting at the optimal

location from where to generate and ending at the African coast (At the point where the black line

reach the red line) and derived from the simulation results. The addition of the black line and the red

line on the map below is therefore the final HVDC transmission line designs.

In this chapter Line 1 is referred to the one ending at Milano, Italy (middle line on the map), Line 2 is

referred to the one ending in Warsaw, Poland (right line on the map) and Line 3 is referred to the one

ending in Aachen, Germany ( left line on the map).

51

5.1 Sensitivity analysis

Before showing the total cost of electricity for different technologies generating at different

locations, a brief sensitivity analysis is performed The sensitivity analysis demonstrates which

factor are the most significant in the contribution to reduce the cost of electricity. The cost of

electricity here is the cost of generation of electricity using the CPV dish described earlier with a

concentration Silicon solar cell. (note that the costs in the sensitivity analysis are the cost of

generation only,no transmission costs are included)

52

5.1.1.Influence of cell efficiency on cost of electricity

On this graph it is shown that improvement in the efficiency of the cell is a major factor in the

future reduction of the cost of CPV system.Indeed, the actual efficiency of the concentration

Silicon cell is about 23% . If the efficiency of the cell is being increased from 23% to 35% the

cost is reduced from $0.029/KWh to $0.19/KWh which is a reduction of 35% in the cost of

generation. The purpose of this sensitivity analysis is to demonstrate the importance of cell

efficiency in resulting cost of generation, explaining why the use of high efficiency solar cell such

as multijunction cell has a high potential for cost of electrity reduction. On the graph the direct

normal irradiance level is assumed to be fixed and equal to 2320 KWh/m2/y1 , and the cost of the

cell is assumed to be the cost of the concentration Silicon cell which is $500/ m2

5.1.2 Influence of direct normal irradiance on cost of generation

0

0.01

0.02

0.03

0.04

0.25 0.27 0.29 0.31 0.33 0.35

Co

st o

f p

rod

uct

ion

($

/Kw

h)

cell efficiency

Sensitivity of cost of generation to cell efficiency

0

0.005

0.01

0.015

0.02

0.025

0.03

0.035

0.04

0.045

1600 1800 2000 2200 2400 2600 2800

Co

st o

f o

f g

en

era

tio

n (

$/K

wh

)

DNI (Kwh/m2)

sensitivity of cost of generation to DNI

53

This graph shows the influence of the level of irradiance on the cost of generation, the cost of the

cell and the efficiency are kept fixed and are respectively $500/m2 and 0.23. This graph

demonstrates the advantage of using CPV dish system in low latitude, high direct irradiance area

such as in Sahara desert. It also shows how generating electricity from CPV in more distant

southern area reduces the cost. Indeed, in North African region the DNI can increase by more than

400 KWh/m2/y1 on a distance of about 500km.

Meaning that the same plant installed in west Algeria would generate electricity at a cost of about

$0.03/KWh while this plant installed in north Morocco would generate electricity at a cost of

about $0.045/KWh which is a 50% increase in the cost of generation. Now the question this

project is going to answered through the results of the simulation is whether this reduction in cost

due to lower latitude higher irradiance location offset the cost of the 500km extra transmission

cable required to generate electricity in west Algeria rather than in north Marocco since the

electricity is meant to be used in European region.

DNI = 1527 KWh/m2/y

-1

DNI = 2190 KWh/m2/y

-1

54

5.1.3 Influence of cell cost on cost of generation

This graph demonstrates the low sensitivity of cost of generation to the cell cost. Indeed in a CPV

dish with silicon cell system, the cost of the cell is considered as a minor component of the total

cost; therefore even a 600% increase in cell cost would only increase the cost of production by

less than a $0.001/KWh. This low sensitivity to cost of production is another reason explaining

why the use of expensive concentration multijunction solar cell is profitable in CPV systems. This

is because the cost of generation is much more influenced by the efficiency of the cell than by the

cost of the cell. In this graph the cell efficiency and the DNI are kept constant and are respectively

0.23 and 2320 KWh/m2/y1.

0.026

0.027

0.028

0.029

0.03

0.031

0.032

0.033

0.034

0.035

500 1000 2000 3000 6000 12000 24000

Co

st o

f p

rod

uct

ion

($

/Kw

h)

Cell cost ($)

sensitivity of cost of generation to cell cost

55

5.2 Simulation of a large scale 5GWp CPV system using silicon

modules

5.2.1 Line 1

The model results will establish at what distance from the coast