UPTEC ES 10 020

Examensarbete 30 hpJune 2010

Evaluation of a Potential Site for a Small Hydropower Plant Located in the BioBio North Irrigation System, Chile

Sofie Gunnar

Teknisk- naturvetenskaplig fakultet UTH-enheten Besöksadress: Ångströmlaboratoriet Lägerhyddsvägen 1 Hus 4, Plan 0 Postadress: Box 536 751 21 Uppsala Telefon: 018 – 471 30 03 Telefax: 018 – 471 30 00 Hemsida: http://www.teknat.uu.se/student

Abstract

Evaluation of a Potential Site for a Small HydropowerPlant Located in the BioBio North Irrigation System

Sofie Gunnar

This project considers an evaluation of a potential site for a small hydropower plantlocated in the BioBio north irrigation system, Chile. The purpose was to analyze thepotential and constraints in harnessing the energy of an existing infrastructure ofirrigation canals for electrical production. The site was analyzed technically,economically and managerially. Before this project nothing was done and thereforethe investigations are a main part of the project. A preliminary design for the plantwas proposed and the project was named the Minicentral Quillaileo-Mininco.

Investigations showed a flow variation of 1.62-2.2 m3 per second and a gross head of44.3 meters. Evaluation gave a possible capacity of 840 kW producing 5 800 MWhannually. Appropriate electromechanical equipment is a Francis turbine with adiameter of 0.5 meter directly coupled to a 1000 rpm synchronous generator. Thepenstock recommended is a DN 1200 Flowtite GRP. The station is to be fullyautomatic and connected to the national grid.

The revenue is based on analysis of the past three year’s electrical market. The costsare based on budget proposals, statistical values and local comparisons. Theeconomical analysis, based on a discount rate of 12% and life span of 35 years, gives apositive cash flow within eight years and a simple payback period of 5 years. Theproject will have a NPV value of 444 900 USD, IRR 14.70% and B/C of 1.2. Cost perkW will be 2 980 USD. The project is recommended to be further developed.

Keywords: hydropower, irrigation system, electromechanical equipment, energyproduction, economical potential

Sponsor: ÅForsk and A.W. Bergstens, Kungliga Skogs- och LantbruksakademinISSN: 1650-8300, UPTEC ES 10 020Examinator: Kjell Pernestål, Uppsala UniversityÄmnesgranskare: Urban Lundin, Uppsala UniversityHandledare: Bo Pettersson, Vattenfall Power Consultant

Sammanfattning Detta projektarbete är ett uppdrag tillsatt av bevattningsorganisationen BioBio North Irrigation

System. Uppdraget var att utvärdera den tekniska, produktionsmässiga och ekonomiska potentialen i

att uppföra en vattenkraftsanläggning i organisationens befintliga bevattningssystem. En potentiell

plats var lokaliserad och gavs namnet Minicentral Quillaileo-Mininco. Innan detta projektarbete hade

inget arbete tidigare utförts. Röjning av plats, fältundersökningar, litteratursökning och diskussioner

med organisation och lokalbefolkning var därför en stor del av projektet.

Minicentral Quillaileo-Mininco ligger 18 kilometer öst om Santa Bárbara och två kilometer norr om

BioBio floden i Chiles VIII region, BioBio regionen. Området har kartlagts topografiskt med

laserbaserade mätningar som sedan bearbetats i AutoCAD. Bruttofallhöjden är därigenom satt till

44,3 meter och längden på tilloppstuben till 170,3 meter med två nödvändiga krökar anpassade efter

terräng. Hydrologiskt finns juridiska avtal till 2,2 m3 per sekund i systemet under hela året. Under

sommartidens sex månader skall cirka 0,58 m3 av denna volym kringledas till bevattningssystemets

användare medan resterande 1,62 m3 kan användas för elproduktion. För att verifiera flödets

rimlighet utfördes även mätningar i fält. Vidare analyserades jordarten ner till 2,5 meters djup,

områdets klimat, erforderliga miljöhänsynstagande samt liknande projekt. Landägare och användare

av bevattningssystemet har kontaktats och ställer sig positiva till projektet.

För att avgöra tillloppstubens dimension utvärderades kostnad mot den fallförlust som orsakats av

tuben. Rekommenderad tilloppstub är en Flowtite GRP med DN 1200, PN 6 och SN 5000. Verifiering

mot diagram, beräkningar, ekonomiska jämförelser och statistik ger rekommendationen Francis

turbin med 520 millimeter i diameter och 0.5 meters sughöjd. Vidare rekommenderas en

synkrongenerator med sex poler och ett varvtal på 1000 rpm. Stationen skall drivas fullt automatiskt

och kopplas till det nationella nätet.

Fallhöjdsförlusten beräknas genom hänsyn till friktion i tilloppstuben, turbulens vid krökar, intag och

utlopp. Verkningsgraden hos den elektromekaniska utrustningen baseras på diagram, statistik och

givna rekommendationer. Märkeffekten beräknas till 840 kW med den årliga produktionen 5 828

MWh. Systemet kommer inte att lagra vatten för att möta topp priserna utan produktionen kommer

att vara kontinuerlig.

Kostnaderna är baserade på budgetpriser, statistik och lokala antaganden. Den totala

investeringskostnaden antas bli 2,3 miljoner USD. Intäkten, 0,085 USD per kWh, är baserad på ett

medelvärde av prisutvecklingen i SIC systemet de senaste tre åren. För att behålla en viss marginal

vid prisvariation sätts intäkten till 0,076 USD per kWh i den ekonomiska analysen. Kostnaden per

kilowatt är 2 840 USD och återbetalningstiden 5,4 år. Med hjälp av ett ackumulerat kassaflöde,

baserat på diskonteringsräntan 12 % och 35 års livstid, ges tiden åtta år till positivt kassaflöde, ett

avkastningsvärde på 444 900 USD, internränta 14,7 % samt en nyttoanalysmetod på 1,18. Den

ekonomiska analysen genomförs även med avvikelser ifrån antagen intäkt, kostnad och

diskonteringsränta.

Validering sker genom jämförelse med tillverkares förslag på utrustning, statistiska värden, givna

rekommendationer i litteratur samt diskussion med erfarna kollegor. Projektet avslutas med en

rekommendation på fortsatta studier och en förteckning över de kontaktade återförsäljarna.

Resumen Del consumo mundial de electricidad, más de una sexta parte, 2500 TWh, corresponde a energía

hidroeléctrica. Pero con la creciente población mundial y el aumento del nivel de vida aumentará la

demanda de electricidad. Investigaciones muestran que a nivel mundial, existe potencial para otros

200.000 TWh de energía hidroeléctrica y que la tecnología actual sería capaz de extraer 20.000 TWh

[2]. Uno de los sitios potenciales se encuentra entre dos ríos: Mininco y Quillaileo en la Región de

Biobío, en el sur de Chile. Entre estos ríos hay un sistema de riego artificial propiedad de Canal BioBio

Norte.

Este proyecto fue encomendado por la cooperativa Canal BioBio Norte. La tarea consistía en evaluar

la técnica, la producción y el potencial económico de una planta hidroeléctrica ubicada en el sitio. El

proyecto fue nombrado Minicentral Quillaileo-Mininco. Ningún trabajo se había hecho con

anterioridad a la llegada de la estudiante. El despeje de sitio, estudios de campo, búsqueda en la

literatura y discusiones con la organización y la población local eran, por lo tanto, una gran parte del

proyecto.

El sitio se encuentra a 18 km al este de Santa Bárbara y 2 km al norte del río BioBio en la VIII Región

de Chile, Región del BioBio. La organización desea conectar la central a la red nacional, que en la

región es de propiedad de Frontel. La posible ubicación de la conexión se encuentra a dos kilómetros

al sur del río Biobío, donde también Angostura, una próxima hidroeléctrica en la misma región, se

conectará. Los propietarios de los terrenos y usuarios del sistema de riego han sido contactados y

están a favor del proyecto. Se ha hecho un levantamiento topográfico de la zona con las mediciones

realizadas luego procesadas en AutoCAD.

La altura de caída es de 44,3 metros y la longitud de la tubería de carga es de 170,3 metros, con dos

curvas necesarias para adaptarse al terreno. Desde el punto de vista hidrológico, hay una decisión

jurídica que establece que la organización tiene derecho a 2,2 m3 por segundo de este sistema

durante todo el año. En verano, seis meses, aproximadamente 0,58 m3 de este volumen se redirige a

los usuarios mientras que los restantes 1,62 m3 se pueden utilizar para la generación de electricidad.

Para verificar la probabilidad de los flujos también se realizaron mediciones en terreno. Otros

aspectos estudiados fueron el tipo de suelo hasta 2,5 metros de profundidad, el clima de la zona y las

necesarias consideraciones medioambientales. El proyecto también fue comparado con otros

proyectos similares.

Para determinar la dimensión de la tubería de carga se llevó a cabo una evaluación comparando su

costo versus la pérdida causada por el tubo. Como resultado de la evaluación se recomienda una

tubería de carga Flowtite GRP con DN 1200, PN 6 y SN 5000. A través de diagramas, cálculos,

comparaciones financieras y estadísticas se recomienda una turbina Francis de 520 mm de diámetro

con un cabezal de aspiración 0,5 metros. Desde el punto de vista eléctrico se recomienda un

generador síncrono con ocho polos y una velocidad de rotación de 1000 rpm. La estación será

operada de forma totalmente automática.

La pérdida de caída vertical se calculará teniendo en cuenta la fricción de la tubería de carga, la

turbulencia en las curvas, en la entrada y en la salida. La eficacia se basa en los gráficos, estadísticas y

recomendaciones. La producción de energía se calcula sobre la base de parámetros específicos y los

diagramas de flujo, la potencia es de 840 kW y se espera que la central produzca 5.828 MWh al año.

El sistema no tendrá capacidad para almacenar agua y enfrentar los precios de punta, sino que la

producirá en forma continua.

Los costos se basan en precios presupuestados, estadísticas y supuestos locales que resultan en una

inversión total de 2.3 milliones USD. Los ingresos se basan en un valor promedio de los ingresos por

kWh para los generadores de electricidad en el sistema de SIC en los últimos tres años, lo que

corresponde a 0,085 USD por kWh. A fin de mantener un cierto margen ante variaciones de precio,

se utilizó un ingreso de 0,076 USD por kWh en la evaluación. El análisis económico determinó que el

costo por kW es 2.840 USD y el período de amortización es 5,4 años. Mediante un flujo de caja

acumulado con la base de la tasa de descuento del 12 % se determinó que el plazo para tener flujos

positivos es de ocho años, el valor presente neto es 444.900 USD, TIR de 14,7 % y una razón

beneficio-costo de 1,18. El análisis económico se realizó considerando incluso desviaciones en los

supuestos de ingresos, costos y tasa de descuento.

La validación de los valores se llevó a cabo contra las propuestas de los fabricantes de equipos,

estadísticas, literatura y la discusión con colegas experimentados. El proyecto termina con una

recomendación de continuar los estudios y una lista de distribuidores de equipos que fueron

contactados

Acknowledgments The project was performed part time at BioBio North Irrigation System in Santa Bárbara, Chile, and

part time at Vattenfall Power Consultant in Stockholm, Sweden.

Rodrigo Romero Jara, Managing Engineer at BioBio North Irrigation System, has been the project

owner and customer. Mr. Romero has been a great help during the planning and execution of the

field trips and for installation at the office in Santa Bárbara.

Bo Pettersson, Vattenfall Power Consultant- Hydro Power, has been technical supervisor for the

project. Mr. Pettersson has been very helpful and has amazed with his competence within the fields

of hydropower and international affairs. To be mentioned is that Vattenfall Power Consultant had no

gain in the project or the BioBio North Irrigation System.

Urban Lundin, lecturer at the Department of Engineering Science at Uppsala University, has been the

reviewer as well as a great support during the whole project.

Peter Bergsten, Vattenfall Power Consultant- Hydro Power, made this project possible.

Anders Ramberg, E.ON Nordic Hydropower, has been a great support in taking the project forward

when reaching a dead end.

Pablo Giaconi, Vattenfall Power Consultant- Power Networks, has been a great inspiration and

personal support before travelling to Chile.

Berry Pettersson was a lifeline through harsh conditions experienced in Chile.

Ruben, Claudia and Joaquin Romero provided a great stay in Chile and brought a lot of joy.

Tomas Bergsten was a huge support and brought a lot of valuable views to the project.

ÅForsk and Stiftelsen A.W. Bergstens donation, Kungliga Skogs- och Lantbruksakademin, made this

project possible by monetary means.

Contents Abstract ................................................................................................................................................ i

Sammanfattning ...................................................................................................................................ii

Resumen .............................................................................................................................................. iii

Acknowledgments ............................................................................................................................... iv

1. Introduction ..................................................................................................................................... 1

1.1 Background ................................................................................................................................ 1

1.2 Objectives of the Study ............................................................................................................. 1

1.3 Demarcation .............................................................................................................................. 2

1.4 Method ...................................................................................................................................... 2

1.5 Report ........................................................................................................................................ 2

2. Theory .............................................................................................................................................. 3

2.1 Small Hydropower Plants .......................................................................................................... 3

2.2 Measurement Methods for Head and Discharge ...................................................................... 3

2.3 Turbines ..................................................................................................................................... 5

2.4 Generators ............................................................................................................................... 12

2.5 Gear box .................................................................................................................................. 13

2.6 Automatic Control ................................................................................................................... 13

2.7 Transformer ............................................................................................................................. 13

2.8 Penstock .................................................................................................................................. 13

2.9 Energy Production ................................................................................................................... 18

2.10 Economical Analysis .............................................................................................................. 19

3. Investigation .................................................................................................................................. 21

3.1 Background .............................................................................................................................. 21

3.2 Location ................................................................................................................................... 22

3.3 Topography .............................................................................................................................. 25

3.4 Hydrology ................................................................................................................................ 27

3.5 Geology .................................................................................................................................... 29

3.6 Environmental Aspects ............................................................................................................ 30

3.7 Civil Work ................................................................................................................................. 31

3.8 Economical Investigation ......................................................................................................... 32

3.9 Similar Hydropower Projects ................................................................................................... 33

4. Evaluation ...................................................................................................................................... 34

4.1 Equipment ............................................................................................................................... 34

4.2 Energy Production ................................................................................................................... 38

4.3 Economical Analysis ................................................................................................................ 40

5. Validation ...................................................................................................................................... 45

5.1 Sources of Error ....................................................................................................................... 45

5.2 Local Variations ....................................................................................................................... 45

5.3 Stated Recommendations ....................................................................................................... 45

6. Recommendation .......................................................................................................................... 47

6.1 Further Investigation ............................................................................................................... 47

6.2 Contacted Suppliers................................................................................................................. 47

7. Conclusion ..................................................................................................................................... 48

8. References ..................................................................................................................................... 49

9. Appendix ........................................................................................................................................ 52

List of Figures Figure 1.1 Chile with the BioBio region in focus...................................................................................... 1

Figure 2.1 Francis turbine ....................................................................................................................... 5

Figure 2.2 Kaplan turbine ....................................................................................................................... 5

Figure 2.3 Cross flow turbine .................................................................................................................. 6

Figure 2.4 Turgo turbine ......................................................................................................................... 6

Figure 2.5 Efficiency diagram for different turbines. .............................................................................. 7

Figure 2.6 Cavitation limits as a function of the specific speed. ............................................................. 8

Figure 2.7 Cross section of a Francis turbine........................................................................................... 9

Figure 2.8 Cross section of a draft tube ................................................................................................ 10

Figure 2.9 Sketch up of equation (2.8) .................................................................................................. 10

Figure 2.10 Turbine governor ............................................................................................................... 11

Figure 2.11 The hydropower scheme .................................................................................................... 15

Figure 3.1 The specific area ................................................................................................................... 22

Figure 3.2 Projected area ...................................................................................................................... 22

Figure 3.3 The irrigation system ............................................................................................................ 22

Figure 3.4 Minicentral Quiallileo-Mininco, national grid, current and projected road ........................ 23

Figure 3.5 Topographic map for the Minicentral Quillaileo-Mininco.................................................... 25

Figure 3.6 Topographic cross section .................................................................................................... 26

Figure 3.7 Flow duration curve .............................................................................................................. 27

Figure 3.8 The revenue per kWh ........................................................................................................... 32

Figure 4.1 The range of turbines ........................................................................................................... 35

Figure 4.2 Cumulated cash flow ............................................................................................................ 43

Figure 9.1 Apposite turbine design layout ............................................................................................ 55

List of Tables Table 2.1 Head range normally applied for different turbines. .............................................................. 6

Table 2.2 Discharge range normally applied for different turbines. ....................................................... 7

Table 2.3 Highest possible efficiency for different turbines ................................................................... 8

Table 2.4 Rotational speed for different generators............................................................................. 12

Table 2.5 Manning coefficient for different materials .......................................................................... 14

Table 2.6 Loss coefficient due to bends for different angles. ............................................................... 17

Table 3.1 Users of the irrigation system and their demanded volume ................................................. 27

Table 3.2 Field investigation of the flow.. ............................................................................................. 28

Table 3.3 Regional climate .................................................................................................................... 29

Table 4.1 Percentage loss for different penstock diameters ................................................................ 34

Table 4.2 Cost comparison for different penstock diameters ............................................................... 35

Table 4.3 Head losses ............................................................................................................................ 38

Table 4.4 Total head loss ....................................................................................................................... 38

Table 4.5 Turbine efficiencys ................................................................................................................. 38

Table 4.6 Energy production ................................................................................................................. 39

Table 4.7 Cost estimation ...................................................................................................................... 41

Table 4.8 Revenue estimation ............................................................................................................... 41

Table 4.9 Cumulated cash flow. ............................................................................................................ 43

Table 4.10 NPV for different discount rates .......................................................................................... 44

Table 4.11 Economic analysis for difference in revenue. ...................................................................... 44

Table 4.12 Economical analysis for different investment costs ............................................................ 44

Table 9.1 Energy production with a DN 1000 ....................................................................................... 52

Table 9.2 Energy production for a single regulated Kaplan turbine ..................................................... 53

Table 9.3 Energy production for a double regulated Kaplan turbine.................................................... 53

Table 9.4 Economical comparison between Kaplan and Francis turbines ............................................ 54

Table 9.5 Calculation of losses .............................................................................................................. 55

1

1. Introduction Hydropower is a well established technology which has been producing electricity for about a

century. It provides about a sixth of the world’s annual electricity usage and account for 90 % of the

renewable electricity production [1]. Globally there are still potential sites with a total technical

possibility of producing 20 000 TWh annually [2]. This report handles one of them.

1.1 Background

The Chilean government recently gave all the irrigation systems a recommendation of investigating

their potential for electricity production. One of those systems is called the BioBio North Irrigation

System (BBINS). BBNIS had located a possible site for a small hydropower plant and sent a request to

evaluate the potential of it. Before this project nothing was done by the organization. The plant was

named the Minicentral Quillaileo-Mininco since the site is located in between those two rivers. The

project was performed in the municipality of Santa Bárbara located in the southeast part in the VIII

region of Chile, the BioBio region.

1.2 Objectives of the Study

The objective of the study was to investigate the conditions of the site and with the results evaluate

its potential for hydropower. The investigation included hydrological, topographical, geological and

environmental surveying as well as mapping, comparison to other similar projects and financial

conditions. The evaluation considered production rate, suitable electromechanical equipment and

financial analysis.

Figure 1.1 Chile with the BioBio region in focus, number 1 is the municipality of Santa Bárbara [4]

2

1.3 Demarcation

The evaluation considered the project of the Minicentral Quillaileo-Mininco in the BioBio North

Irrigation System. The demarcation was set to survey the area topographically and hydrologically and

gather enough background information to make a probable evaluation of the site. It was assumed

that the site can be connected to the national grid and given permission to deliver its power in every

moment.

1.4 Method

The result of the project is based on research conducted in Sweden and Chile.

1.4.1 Research in Sweden

Preparations were done in Sweden in order to more easily find information and in an efficient way

have discussions with supervisors. The preparations were based upon research, studies and

discussions within the hydropower- and irrigation discipline. Contacts with similar projects were

made and a turbine manufacturer was visited. Upon return from Chile the result was verified and the

report was written.

1.4.2 Research in Chile

After preparations a fieldtrip to Chile was made in order to understand the organization and its

circumstances. The site was visited and clearance of the area was organized and managed. The site

was investigated by field- and literature studies as well as by topographical and hydrological

surveying. Furthermore existing maps, previous measurements and juridical provisions were studied

and evaluated. Contacts were made with suppliers, manufacturers, users of the irrigation system,

grid owner, similar projects in the area and national authorities. Ongoing calculations were

performed as parameters were determined. The whole project was performed in consensus with the

organizations’ management as well as locally responsible to ensure that the project was going in the

desirable direction.

1.5 Report

Totally this report evaluates the potential of the Minicentral Quillaileo-Mininco, the evaluation is

divided into four main parts. In Chapter 2 the bases in hydropower theory and the economical

analysis considered are explained. Chapter 3 states the investigations performed, Chapter 4 declares

the evaluation which later is validated in Chapter 5.

Note that the report is written with the assumption that the Minicentral Quillaileo-Mininco is to be

constructed.

3

2. Theory The theory chapter is delimited to the main fractions which the investigation and evaluation are

based upon. The chapter includes previous research, measuring methods and for the project relevant

formulas, graphs and definitions. Technical and economical theories within the field of hydropower

are addressed.

2.1 Small Hydropower Plants

The definition of small hydropower plants differs between countries. In Sweden the definition is

below 1.5 MW, in Germany below 5 MW and the EU has set the joint limit at 10 MW [6]. In the same

way the Chilean Energy National Commission has classified the hydropower plants according to their

capacity [7]:

Large Rated power > 5 MW

Small 1 MW < Rated power > 5 MW

Mini 100 kW < Rated power > 1 MW

Micro 1.5 kW < Rated power > 100 kW

2.2 Measurement Methods for Head and Discharge

2.2.1 Head

The gross head is the maximum vertical distance between the upstream and downstream water level

for reaction turbines and from the upstream water level to the nozzle axis level for impulse turbines.

For field measurements the most common method is to use digital instruments such as laser levels.

The most accurate and easily performed method is to use GSM or GPS receivers who also give a

rough mapping. In developing countries measurements are still sometimes performed by leveling

and yardstick [8]. Pressure gauge measurements are also possible [9]. When having estimated the

gross head it is necessary to take losses into account, i.e. calculate the net head, see Chapter 4.2.1.

2.2.2 Discharge

The discharge is the quantity of water passing through a fixed point at a given time. In a specific area

considered for hydropower but without any records of the discharge, regular measurements for at

least a year is recommended before installation. One single measurement is of little use.

There are four main methods of measuring the discharge:

- Velocity area method

A method preferable for medium to large rivers performed by measuring the cross sectional area and

the velocity of the water passing through it. The cross sectional area is computed by an integral over

a series of trapezoids describing the depths and shapes of different regions. The velocity is measured

at a number of points and then calculated into an average, this because the velocity varies both

across and along the river or canal. It can be measured either by timing a floating object, by a

mechanical current meter, by an electro-mechanical current meter or by pouring chemicals upstream

and measure the expenditure of time until the conductivity rises downstream [8][9]. The velocity

area method is the one used in this project, see Chapter 3.4.

4

- Weir method For small discharges a temporary weir can be constructed and placed across the flow. The water is then channeled through a notch. The linear measurement of the difference in upper and bottom water level gives a sufficient quantity of the discharge [8]. - Slope area method

The slope area method is an option for high flows with the possibility and allowance to place

temporary marks in the surface level. By the marks the slope, cross sectional area and radius is

estimated. The discharge is computed by:

(2.1)

Where A= cross sectional area [m2]

R= radius [m]

S= slope [m]

n= the Manning constant for watercourses varying between 0.03-0.06 depending on

the natural conditions in the river [8].

- For a small flow, the discharge can be measured by observing the time it takes for a bucket or

similar to be filled.

When the samples have been recorded they are normally compiled in a hydrograph or a flow

duration curve. In a hydrograph the flow is shown against time in chronological order while a flow

duration curve organizes the data by appearance in percentage.

5

2.3 Turbines

The four turbine types to be considered for this project are mentioned in 2.3.1-4. Left out among the

main turbines are the Pelton turbine since it normally works in a head range of 350 to 1800 meters

and the Bulb turbine since it has a head range of 3.5-25 meters [10].

2.3.1 Francis

The Francis turbine is a reaction turbine i.e. it is contained and uses the pressure energy. There are

two types of Francis turbines, horizontal and vertical depending on the direction of the shaft. Vertical

shaft may require more space but are more reliable and therefore horizontal shafts are only used for

small head schemes. The Francis turbine normally has 9-19 runner blades depending on the design

and rotational speed. Some manufacturers also add an extra shorter blade to each normal, so called

splitter blades. The aim is to provide a better path through the runner to increase the efficiency.

The water is flowing from the inlet to the spiral casing which creates a large vortex and distributes

the water around the circumference. The water is then guided by the stay vanes towards the guide

vanes. The guide vanes are adjustable and the angle is operated by the governor to fit the desired

load. After transferring its energy to the runner the flow is led through the draft tube to the outlet

tunnel. The runner torque is transferred to the turbine shaft which rotation leads to induction of

electricity in the generator.

2.3.2 Kaplan

The Kaplan is a further development of the Francis turbine. Single regulated Kaplan uses adjustable

guide vanes and fixed runner blades, while a double regulated Kaplan can adjust both. Non regulated

Kaplan turbines are used at sites with practically constant flow and head but are then normally called

propeller turbines. Depending on the site characteristics constructive variants such as open flume,

siphon, horizontal or vertical placements are available.

A pure propeller turbine has a narrow efficiency peak, but due to the possibility of regulation the

double regulated Kaplan is well suited for a wide flow range with a maintained high efficiency.

The number of blades varies from four to seven, higher heads than 50 meters may require eight

blades. The water path until the guide vanes is basically the same as for a Francis turbine see 2.3.1. In

the Kaplan turbine the flow is going through the guide vane in radial direction and then makes a right

turn to enter the runner in an axial direction.

Figure 2.1 Francis turbine [31] Figure 2.2 Kaplan turbine [31]

6

2.3.3 Cross flow/Banki/Ossberger

The Cross flow turbine, also known as Banki or Ossberger, is an impulse turbine i.e. the pressure

remains constant at the runner and the absorbed energy is kinetic. The Cross flow turbine has a wide

range of suitable heads which overlaps Kaplan, Francis and Pelton [8]. The discharge is directed with

one or several guide vanes to enter the runner from above at an angle of 45°. The flow then crosses

the runner twice before leaving at the opposite side. Two third of the energy is transferred in the first

pass and one third in the second pass. The turbine has up to 37 blades arranged tangentially and

radially. It is common to construct two or more Cross flow turbines on the same shaft. The design is

easy to understand, build and repair but it has a low efficiency. Low head schemes should carefully

consider the head loss caused by the vertical design and high head schemes might have trouble with

mechanical stress due to the one spot of entry. This turbine is a possibility when dealing with high

flows, limited power demand and low investment possibilities such as rural electrification programs.

Figure 2.4 Turgo turbine [11]

2.3.4 Turgo

The Turgo turbine is a compact impulse turbine which uses kinetic energy by forcing the water

through nozzles. It is similar to a Pelton turbine but its buckets are shaped a bit differently and the

water jet strikes the plane of the runner at an angle of 20°. The combination deflects and reverses

the discharge with a resulting impulse spinning the runner. The efficiency is lower than a Francis or

Pelton turbine but it can operate in a wider flow range. The Turgo can be an alternative to Francis

when the flow varies strongly or in case of long penstock due to the designs’ reduced risk of water

hammer appearance.

2.3.5 Classification of Turbines

The selection for turbine type is based on four criteria’s’:

- Net head

The net head is defined in Chapter 4.2.1.

Table 2.1 Head range normally applied for different turbines [8]

Turbine type Head range [m] Kaplan 2 < Hn > 50 Francis 25 < Hn > 350 Cross flow 5 < Hn > 200 Turgo 50 < Hn > 250

Figure 2.3 Cross flow turbine [21]

7

- Range of discharge

Table 2.2 Discharge range normally applied for different turbines [8]

Turbine type Acceptance of flow variation Acceptance of head variation Kaplan double regulated high, 30-100 % High Kaplan single regulated high, 30-100 % Medium Francis medium, 50-100 % Low Cross flow high, 30-100 % High Turgo high, 20-100 % High

- Rotational speed

The turbine type can be specified by looking at the specific speed, nQE, a dimensionless quantity.

Every turbine type has its own range where the Francis turbine has the range 0.05 ≤ nQE ≥ 0.33 and a

Kaplan 0.19 ≤ nQE ≥ 1.55 [8]. A large number of statistical studies have established a correlation

between the specific speed and the net head for each turbine, those formulas can be used to get an

estimated value. Where Hn is the net head in meters.

Francis

(2.2)

Kaplan

(2.3)

- Cost

To decide which turbine to use, a cost versus income estimation could be done. The Kaplan turbine

has a greater span of high efficiency than the Francis turbine but is in general 30-50 % more

expensive. The Kaplan turbine has smaller dimensions than the Francis turbine for the same capacity

resulting in higher rotational speeds and lower settings, the generator and civil work may therefore

be cheaper [10].

2.3.5 Efficiency

The turbine efficiency varies between different manufacturers but Table 2.3 and Figure 2.5 indicate

the typical guarantees given.

Figure 2.5 Efficiency diagram for different turbines [8]

8

Table 2.3 Highest possible efficiency for different small capacity turbines [8]

Turbine type Highest efficiency [%]

Kaplan double regulated 93 %

Kaplan single regulated 91 %

Francis 94 %

Cross flow 60 %

Turgo 85 %

2.3.6 Runner Dimensions and Specific Speed

The following description for turbine design is based upon data from a large number of built and

projected turbines compiled during a period of 20 years. Many factors affect the final design of a

plant but this is an appropriate method to get a good start value. Note that the method given should

only be used for preliminary studies as only manufactures can give the real dimensions for their

turbines. The method is specific for dimensioning a Francis turbine [12].

With the nQE given by equation (2.2) and (2.3) the cavitation limit can be read in the Figure 2.6.

Figure 2.6 Cavitation limits as a function of the specific speed [8]

To calculate the specific speed, the actual rotational speed of the turbine:

[rpm] (2.4)

The unit speed, n11, is defined by a correlation with the net head. The unit speed is the rotational

speed of a uniform turbine with a runner diameter of one meter and a head of one meter and is used

as a design parameter by manufacturers.

(2.5)

9

The inner runner diameter, D1, is calculated by

[m] (2.6)

The unit flow, Q11, is the discharge of a uniform turbine with a runner diameter of one meter and a

head of one meter and is used as a design parameter by manufacturers. With the suction head, Hs,

given in equation (2.10) the unit flow is obtained:

(2.7)

The formulas need to be calculated and recalculated in a loop until reasonable and standardized

values occur.

2.3.7 Spiral casing, Stay vanes and Guide vanes

The spiral creates a large vortex distributing the flow to the stay ring. The spiral casing may either be

fabricated in concrete or steel plates. The concrete alternative is the least expensive but for high

heads, above 40 meters, the hydraulic pressure will be too large for the concrete design to

withstand. The turbine manufacturer designs the spiral to keep the tangential velocity constant along

the consecutive sections and distributes the flow peripherally.

The stay vanes are fixed and lead the water from the spiral towards the guide vanes as well as

carrying the spiral casing ceiling. The stay vanes are normally made of welded steel plates filled with

concrete [10].

The guide vanes are located within the stay vanes just next to the runner. Their function is to control

the discharge and adapt the inlet angle to achieve maximum efficiency. The guide vanes rotate

around their axis by connected rods attached to a large ring that synchronizes the movement of all

vanes. They can also be used to shut off the flow to the runner but their presence should not exclude

a butterfly valve at the entrance of the turbine. There are normally between 18 and 28 adjustable

guide vanes.

2.3.8 Draft tube

The draft tube is a part of the reaction turbine and its aim is to recover the remaining kinetic energy

in the discharge by reducing its velocity just after the runner. The draft tube consists of a steel plated

cone and a concrete or steel plate lining, if the angle between those is too large flow separation will

occur. The optimum angle is 7° but since greater angles will reduce the length and thereby cost,

angles up to 15° do exist [8]. The pressure recovery is obtained by an increasing cross section area in

the flow direction. The lowered outlet velocity gives a lowered hydraulic pressure at the runner

which maximizes the torque.

Figure 2.7 Cross section of a Francis turbine [8]

10

The phenomenon of the draft tube is described by the Bernoulli formula.

(2.8)

Where Q= discharge [m3/s]

A= cross sectional area [m2]

ρ= water density [kg/m3]

p= pressure [Pa]

1, 2= different reference sections see Figure 2.9

The draft tube also forms the water conduit from the runner to the outlet tunnel.

2.3.9 Suction Head and Cavitation

For a reaction turbine the suction head is defined as the vertical distance between the turbine center

and the tail water level. The turbine center for a Francis is the level at the guide vanes center and for

a Kaplan at the runner blade center. The suction head can be either positive or negative but most

common is to strive for a positive setting to have the machinery above the tail water level to

minimize the risk of inundation and to facilitate maintenance. The suction head is dictated by the

cavitations’ limit. The cavitation occurs at the runner outlet when the hydraulic pressure falls below

vapor pressure i.e. formation of vapor occurs. When the vapor bubbles reach a higher pressure area

they collapse often with a substantial noise and if close to the runner blades or hub also pitting the

surface.

Cavitation is characterized by the cavitation coefficient, Thoma’s coefficient, σ, defined according to

IEC 60193 standards as:

(2.9)

Where NPSH=Net Positive Suction Head

Hn= net head i.e. gross head-losses [m]

Patm= atmospheric pressure [Pa]

Pv= water vapor pressure [Pa]

ρ= water density [kg/m3]

v= mean outlet velocity [m/s2]

g= acceleration due to gravity [m/s2]

Hs= suction head [m]

Figure 2.8 Cross section of a draft tube [8] Figure 2.9 Sketch up of equation (2.8) [19]

11

To avoid cavitation the turbine center should be installed with a suction head of:

[m] (2.10)

The cavitation limit is obtained by model tests. Studies of statistical values have given a correlation

between the cavitation coefficient, specific speed, outlet velocity and the net head for Francis and

Kaplan turbines:

Francis

(2.11)

Kaplan

(2.12)

2.3.10 Turbine Governor

The turbine is designed for a specific head and discharge. Any deviation must be compensated for by

opening or closing the control systems such as guide vanes, valves or gates. The load will be

fluctuating and thereby also the frequency, the turbine governor regulates the flow to change the

rotational speed and meet the new specifics. If there is a load rejection the unit will overspeed and

will have to be shut down not to cause negative impact and damaging the plant. The governor also

handles the starting sequence to accelerate the turbine to 50 Hz and keep it there. The governor

input is the rotational speed and the grids’ frequency and the most common output is a command

signal in order to increase or reduce the angle of the guide vanes. Several types of governors are

available from purely mechanical using a flyball mass to purely digital which is the most common

today. A governor based on digital techniques is in most cases either a PLC or a PC [10]. The main

modules in the PLC or PC are power supply, speed measuring module, input and output modules,

servo interface and operator interface [10].

Figure 2.10 Turbine governor [10]

12

2.4 Generators

There are two main types of AC generators, synchronous and asynchronous. Their variation in

construction makes them differ in investment and delivered quality of electricity. The plant can be

coupled to run island operation or deliver to the national grid which set different requirements. The

generator is governed by the required load. The generator design is determined by the turbines’

rotational speed, available space and whether a gearbox is installed or not.

Table 2.4 is considered for a region with 50 Hz and is based on

(2.13)

Where f= frequency [Hz]

p= number of pole pairs

n= rotational speed [rpm]

Table 2.4 Relation between poles and rotational speed

Number of poles Rotational speed [rpm] Number of poles Rotational speed [rpm] 2 3000 16 375 4 1500 18 333 6 1000 20 300 8 750 22 272 10 600 24 250 12 500 26 231 14 428 28 214

2.4.1 Synchronous

The synchronous generators are fixed on the specified rotational speed and thereby meet and

stabilize the 50 or 60 Hz of the grid in every moment. The generator is equipped with a DC or a

permanent magnet excitation system. Since the synchronous generator can produce reactive power

it is not depending on the grid for its excitation and can, with a suitable turbine governor run on an

isolated grid. It can also deliver energy directly to the station.

2.4.2 Asynchronous

The asynchronous generator has no possibility to provide its own excitation current. It is thereby

totally depending on a grid connection to consume reactive power for its magnetization. It is used

when the grid is strong and the plant is small. The voltage reduction it causes while magnetizing may

disturb the grid. To compensate for the consumed reactive power capacitors can be installed. When

the generator becomes disconnected it may, together with the capacitors, cause overvoltage.

Asynchronous generators are slightly cheaper but are not recommended for plants over one

megawatt [8].

2.4.3 Efficiency

The efficiency differs between each specific generator, every manufacturer base their guaranteed

efficiency upon model tests. In general higher rated generators have better efficiencies. For example

generators around 100 kVA normally has 95 % efficiency while 2 MVA has 97 %. Synchronous

generators have a slightly higher efficiency than asynchronous [8]. The efficiency 95 % is the most

common for generators below 1 MVA and should be used in calculations while designing [13].

13

2.5 Gear box

When a turbine and a generator operate at the same rotational speed they can be directly coupled

by one single shaft, in that way power losses and maintenance is minimized. In some cases for low

head schemes the turbine run in less than 400 rpm. A generator designed for that speed is very

expensive and demands a lot of space, for that reason a gear box is coupled in between to meet the

750-1000 rpm of standard generators. There are different types of gear boxes, the most common is

parallel shaft using helical gears set on parallel axes. Other alternatives are using bevel gears for a 90°

drive or a belt speed increaser. If the rotational speed is low at the turbine it can be an investment

benefit to have a gearbox instead of a low rotational generator. The gear box increase the noise in

the power house, require regular maintenance, increases the risk of oil leakage and can increase the

power losses up to 2 % [8]. The gear box often cause problems and should be avoided if possible [14].

2.6 Automatic Control

Small hydropower plants are often run unattended and fully automatic. Every plant needs to

carefully investigate their specifications but some rather general considerations are [8]:

- relays and devices to have the plant shut down if unpredictable faults is predicted

- storage of and access to operational conditions to evaluate the plant performance

- access the control system manually from another location

- turbine governor to regulate the production to the load

- a counter module for the produced kWh

2.7 Transformer

The transformer increases the voltage from the level of the generator to the level of the grid. There

are several different designs with different performance and technical characteristics such as the

traditional oil-filled transformer as well as oil-free exposit transformers. The specified transformer for

the site is often recommended and provided by the grid owner. The transformers efficiency is

normally between 98 % and 99 % with 99 % as recommendation for calculations [13].

2.8 Penstock

The penstock leads the water from the intake to the turbine. The penstock is constructed in a way to

create as high head with as short distance as possible to reduce losses and investment cost. The

penstock can be installed above or under ground depending on the climate, requirements of visual

impact, material and ground conditions. The penstock is characterized by material, diameter, wall

thickness and type of joint.

2.8.1 Material

The material is selected according to ground conditions, availability, maintenance routines and

capital. Most used materials are wood, steel and fibrereinforced plastic. The plastic pipes are often

cheaper, lighter and more easily handled and do not need protection against corrosion. The plastic is

often sensitive to UV radiation and should be installed underground or have the surface painted,

coated or wrapped. Concrete and steel are heavy materials which make the transportation and

handling cost high. The wood is easily available, easy to handle, do not need much preparation, no

need for corrosion protection and it is cheap but the disadvantage is high risk of leakage and

considerable maintenance such as regular spray coating.

14

From a maintenance point of view the plastic is preferable [15]. For smaller diameters it is often a

choice between standardized steel pipes or plastic pipes [8]. If the penstock is to be installed above

ground it is important to consider the variation in temperature and sun intensity to protect the

material from corrosion by paint and wrapping.

The characteristics of the material are expressed in:

DN= pipe diameter [mm]

PN= pressure class [bar]

SN= stiffness class [N/m2]

2.8.2 Diameter

The diameter is selected to reduce frictional losses within the penstock to acceptable level. The

diameter is set as a trade-off between losses and cost. To make a decision either each diameter’s

costs and caused losses can be compared or a fixed criterion can be used, 4 % losses of the gross

head is recommended to accept [8]. For calculation of the appropriate diameter the Manning’s

equation is recommended:

[m] (2.14)

Where n= Manning roughness coefficient for commercial pipes see Table2.5

Q= flow [m3/s]

L= length of the penstock [m]

Hg= gross head [m]

y= the percent loss of the total gross head due to friction [%]

Table 2.5 Manning coefficient for different materials [8]

Surface material Manning roughness coefficient, n Welded steel 0.012 Polyethylene 0.009 PVC 0.009 Concrete 0.015 Wood 0.013 GRP 0.011

15

2.8.4 Losses

Losses due to the penstock can be divided into friction losses, losses due to trash rack, entrance,

bends, expansions, contraction and valves.

Figure 2.11 The hydropower scheme [8]

The main cause of head loss is due to friction and occurs in the penstock. Frictional losses are seen as

a drop in pressure, p1-p2=Δp=losses. If a pipe with rough surface is considered the losses will be

proportional to the length of the tube, the inner perimeter and velocity i.e.

where

is depending on the surface characteristics. The losses will cause a reduction of the head according to

the relation .

Other losses occur once along the way. In a bend the flow is forced to change direction which will

cause turbulence, in valves there is a change in area which will increase or decrease the speed of

water and lead to losses [17].

2.8.4.1 Frictional Losses

For incompressible and steady flows through pipes the caused frictional loss is:

[m] (2.17)

Where f= friction factor

L= length of pipe [m]

D= the pipe diameter [m]

v= the average velocity [m/s]

g= gravitational acceleration [m/s2]

For laminar flow the friction factor is calculated by

(2.18)

where Re is the Reynolds number, when Re is below 2000 the flow is considered to be laminar.

This gives that the friction losses for laminar flow is

[m] (2.19)

When the flow is turbulent the friction factor becomes less dependent on the Reynolds number and

more dependent on the material roughness. To calculate the friction factor for turbulent areas

different methods can be used but the Colebrook-White devise is the most common:

16

(2.20)

To solve equation (2.20) a Moody diagram is often used and their combination solves the problem to

compute hf knowing the flow, pipe diameter and the material roughness height.

Another way for approximating the frictional losses is by the method developed by Manning:

(2.21)

Where hf= frictional loss [m]

L= length of the pipe [m]

Q= discharge [m3/s]

D= pipe diameter [m]

n= Manning coefficient for different kind of pipes, see Table 2.5

An third way of approximation is the Hazen-Williams formula often used in North America for pipes

larger than 50 millimeters in diameter and with a flow velocity under 3 m/s [8].

2.8.4.2 Losses due to Trash Rack The trash rack is a grid placed in the entrance of the penstock and is necessary to avoid floating

debris reaching the turbine. The loss caused by the water turbulence is described as:

[m] (2.22)

Where ht= local loss due to trash rack [m]

K = factor describing the shape of the rakes

t= bar thickness [mm]

b= width between bars [mm]

v0= entrance velocity [m/s]

g= gravitational constant [kg/m2]

= angle between the grid and horizontal reference.

If the grid is not perpendicular to the water flow the result computed must have an additional

correction factor k according to Mosonyi [8].

2.8.4.3 Losses due to Area Compression or Expansion

In some positions of the pipe it is necessary to have contractions or expansions due to the

surroundings, this will cause a head loss due to increased or decreased velocity and turbulence

generated by the change. The loss is estimated by multiplying the kinetic energy in the smaller part

with the coefficient K which varies with varied dimensions of diameters.

For compression the head loss is estimated by:

[m] (2.23)

17

Where

d= the smaller diameter [m]

D= the larger diameter [m]

v2= water velocity after the compression [m/s]

Equation (2.23) can be used for a pipe with a ratio of less than d/D=0.76.

For expansion the head loss is calculated by:

[m] (2.24)

Where v1 [m/s] is the velocity for the smaller pipe section. Those head losses can be reduced by using

a gradual pipe transition, confuser for contraction and diffuser for expansion.

2.8.4.3 Losses due to Bends

When the flow passes a bend the pressure will increase along the outer wall and decrease along the

inner wall, this causes an unbalance in pressure which will result in a spiral flow. The spiral will last

for about 100 diameters of length and be dissipated by viscous friction. The value of hb depends on

the radius of the bend and the diameter of the pipe. The problem is extremely complex when

successive bends are placed after one another, close enough to prevent the flow from becoming

stabilized at the end of the bend. Fortunately, this is hardly ever the case in a small hydropower

plant. The loss due to bends is calculated by:

[m] (2.25)

Where the loss coefficient due to bends, kb is:

Table 2.6 Loss coefficients due to bends for different angles [18]

Angle Kb

90 0.5

60 0.5

45 0.3

30 0.2

25 0.17

20 0.13

15 0.1

11 0.07

8 0.05 2.8.4.3 Loss in Outlet Loss in outlet, also called velocity height, is calculated by:

(2.26)

Where v= velocity in tube [m/s]

g = acceleration due to gravity [m/s2]

18

2.9 Energy Production

The runner converts the kinetic and pressure energy from the water into the mechanical energy

which spins the shaft. The total energy is described by the Bernoulli equation:

(2.27)

Where m= mass unit [kg]

c= water velocity [m/s]

g= acceleration due to gravity [m/s2]

z= height above reference level [m]

p= pressure [Pa]

ρ= specific density of the water [kg/m3]

By looking at a hydropower station with reference level 1 at upstream water level and reference level

2 after the runner the hydraulic energy available for the machine is:

(2.28)

Potential energy is held by a mass at a specific height:

[J] (2.29)

The energy is released when the object holding the mass is dropped. The energy stored in the water

at the upstream water level can be liberated by lowering the water in a controlled way, the power is

related to the mass flow rate:

[J/s] (2.30)

Substituting energy over time by power and expressing mass over time in water volume per time unit

and its density, the hydraulic power at disposition of the turbine is obtained:

[W] (2.31)

Where ρ= specific density of the water [kg/m3]

Q= discharge [m3/s]

g= acceleration due to gravity [m/s2]

Hn= net head i.e. gross head-losses [m]

The mechanical output of the turbine is given by:

[W] (2.32)

Where ɳ= turbine efficiency [%]

Ph= hydraulic power [W]

19

2.10 Economical Analysis

The economical analysis is a comparison between benefits and costs to be able to make an informed

decision whether to continue with the project or not. It also serves as a base for the investor to

compare different projects and to make a economical risk analysis.

2.10.1 Simple Payback Method

By the simple pay back method it is meant to divide the total investment with the annual revenue.

[years] (2.33)

To consider a hydropower project to be viable the repayment period should not exceed eight years

[8].

2.10.2 Year to Positive Cash Flow

Year to positive cash flow is read from the accumulated cash flow. In the cash flow the investment,

revenues, maintenance and operational costs, discount rate, lifetime and inflation rate is taken into

account. Less than eight years is normally considered to be a viable project [13].

2.10.3 Net Present Value, NPV

Net present value is a method to rank different investment alternatives, the alternative with the

highest NPV will give the highest net return in monetary means. The NPV is the present value of a

future return.

[monetary means] (2.34)

Where Ii= investment in period i

Ri= revenues in period i

Oi= operating costs in period i

Mi= maintenance costs in period i

r= periodic discount rate

n= number of lifetime periods

Vr= residual value of the investment over its lifetime

The discount rate is depending of the inflation rate and usually varies between five and twelve

percent. The discount rate highly affects the outcome of NPV and should be chosen carefully or a

comparison between several can be done. The NPV do not tell whether the return is high or low in

comparison to the investment.

2.10.4 Internal Rate of Return, IRR

The internal rate of return is an analysis method to consider the time value of money. It gives the

interest rate equality to the return expected from the project. The IRR is computed by iterative

calculation with different discount rates finding the one resulting in a NPV equal to zero. The IRR

should be several percent higher than the lending or interest rate in order to compensate for the risk,

time and problems associated with the project [8].

20

2.10.5 Benefit Cost Ratio, B/C

The benefit cost ratio compares the revenue and expenses flow.

(2.35)

Where Rn= revenues in period n

In= investment in period n

On= operating costs in period n

Mn= maintenance costs in period n

r= periodic discount rate

Projects with a B/C ratio less than one are generally discarded.

21

3. Investigation The investigation chapter states the performed investigation and the result given by field

measurements, interviews and literature research.

3.1 Background

3.1.1 Chilean Electrical Divisions

The electrical market in Chile is mainly based on thermal- and hydropower generation. In April 2010

the total installed production capacity reached 15.94 GW [3]. In 2007 57.2 TWh were consumed

which corresponds to 3.33 MWh per capita [4]. This number is rather low but the consumption is

increasing rapidly, 6 % per annum [5].

In 1982 the market was reformed to only be served by private interests in production, transmission

and distribution. Beside the private sector the market is regulated for long term strategies by the

National Energy Commission, CNE, the technical standards is set by the Energy Superintendence, SEC

and the Minister of Energy imposes the regulated tariffs to avoid problems during drought. The

system is divided into four separated power systems. The largest is named Sistema Interconectado

Central, SIC, and stretches around 2 700 km from Taltal in the north to Chiloé in the south. The SIC

system has 75.8 % of the total production capacity and serves 93 % of the population [3]. The SIC

system is also where the Minicentral Quillaileo-Mininco will be located. The other three systems are

the Sistema Interconectado del Norte Grande, SING, which serves the population and the mining

industry in the north and possesses 23.3 % of the total production capacity. Aysen and Magallanes in

the south have 0.3 % and 0.6 % respectively of the total production capacity [3].

3.1.2 Santa Bárbara

The municipality of Santa Bárbara covers an area of 3 356 km2 and has around 3 400 inhabitants. The

level of education is very low where only 2.3 % has a higher education and 16.9 % never even

attended class. There is an increased access to primary education but among the population above

60 years, analphabetic are widespread. For living the most common occupation is agriculture,

hunting, forestry, mining or fishing [20]. For electric production hydropower is dominating having

huge plants as Ralco, Pangue and soon Angostura in the area. In 1992 only 44 % of the inhabitants

had access to electricity [20]. There are no newer specific investigations for Santa Bárbara but

investigations from 2006 in the BioBio region avowed that 99.8 % in the urban area and 94 % in the

rural area had access to electricity [21].

3.1.3 BioBio North Irrigation System

The BioBio North Irrigation System was built by the Department of Irrigation in 1934 in order to

provide irrigated water in the municipalities of Santa Bárbara and Los Angeles. The system is in

operation and is owned by a cooperative of 240 farmers who all also use the system. The

organizations’ ten full time employees manage a network of 200 kilometers canals irrigating 20 000

hectares. In the winter season reparations and maintenance is performed which often involves 80-

100 persons. Within the network of canals there are several points where it is necessary to discharge

water from a higher to a lower canal, one of those sites is evaluated in this report.

3.1.4 Requirements given from the Organization

Due to the irrigation system being the main priority, the organization required that there would not

be a dam construction, the hydropower plant has to be operated to fit the system not the other way

22

around. Therefore the station will work in a constant flow as stated in 3.4.1. The organization has no

possibility to monitor the system, it has to be fully automatic. The license duration is set to 35 years

and the discount rate to 12 %.

3.2 Location

The potential site is located 18 km east of Santa Bárbara and 2 km north of the BioBio river. The

coordinates for the site is in latitude south 37.693° and longitude west 71.802°, in UTM coordinate

north 58 245 000 and east 252 500.

3.2.1 Irrigation System

The water is taken from the Quillaileo river and lead by the Canal Matriz into Derivado 1 where the

site is located. Derivado 1 has a total length of 17.9 km and the site is situated in the middle of it,

16.75 km from the intake at Quillaileo.

Figure 3.3 The irrigation system with the Minicentral Quillaileo-Mininco marked with and arrow [20]

Figure 3.2 Chile with the project area marked with an arrow [4]

Figure 3.1 The specific area with the site marked with an arrow [4]

23

3.2.2 Infrastructure

The infrastructure to the site is rather good, only the last two kilometers has to be driven on gravel

road and if the suppliers want to ship the equipment the port city of Conception is only 200 km away.

In the BioBio river a new hydropower plant called Angostura will be constructed and in 2012 have the

capacity of 309 MW. The plant will be located two kilometers south of the Minicentral Quillaileo-

Mininco which is a great advantage for this project. Due to Angostura the road will be changed more

to the north i.e. closer to the site, see Figure 3.4.

3.2.3 Grid Connection

The possibility of grid connection is crucial for the overall project. The plant is requested by the

BBNIS organization to be connected to the national grid. If the plant was to be run island operational

then aspects such as load conditions, load duration curve, peak load, load factor and energy demand

must be taken into account but this is not the case.

Contact has been made with Frontel, the company of the transmission lines in south of Chile.

Connection of the Minicentral Quillaileo-Mininco to their lines would be possible in their 13.2 kV line

going along the south side of the BioBio river [22]. Upon request for the load duration curve of the

area the answer given was to assume possibility of delivery when producing and in a later stage of

design return for more proper values. The national frequency in Chile is 50 Hz.

There is one point possible for connection to the transmission line located two kilometers south of

the BioBio river, i.e. four kilometers from the site [22]. There is also a line located 5.5 km to the

northwest from the site but the first option is preferable, not only because it is closer but also

because the southern option only has one landowner from site to the grid connection, Mr. Guillerna

Aravena. The Angostura project will simplify the possibility of connection since modification in the

transmission will be done in that area.

Figure 3.4 Minicentral Quillaileo-Mininco, national grid, current and projected [22][23][24]

24

Contact has been made with the Angostura project and Frontel in order to get the official new layout

for the infrastructure and transmission line but both without permission to publish, Figure 3.4 is

therefore an estimation from local knowledge acknowledged by Luis Villaroel [24].

3.2.4 Land Characteristics

The specific area is not unused, north of the upstream level there is a plantage of eucalyptus trees

and south of the downstream level is a cornfield but in between it is only a slope of natural

vegetation. The landowner is Mr. Roberto Aravena and the water right belongs to the BBNIS

organization. The area needed for the plant including intake and penstock is approx 0.5 hectares.

Chile is a country with a high risk of earthquake which has to be taken into consideration when

ordering and installing the equipment.

25

3.3 Topography

For surveying the area a total station Leica TCR407 Power was used. A point of reference was set in X,

Y and Z coordinates and then laser based measurements on several points in the specific area were

taken and referred. The coordinates were then processed in AutoCAD and a map was generated.

Figure 3.5 Topographic map for the Minicentral Quillaileo-Mininco

26

In the map two alternatives are projected. The organization had alternative one in mind for the

penstock and power house but while working with the measurements in AutoCAD another

placement was defined. In alternative one there is already a cleared path and the measurements are

more accurate. In constructing, the same amount of civil work will probably have to be done in both

cases but alternative two has a greater gross head and a slightly shorter penstock. In Figure 3.5 it is

hard to distinguish but when visiting the area it is clear that less excavation has to be done for the

power house in alternative two since it is a rather flat area close to the downstream water level.

Alternative two is also closer to the infrastructure and the outlet will be in an already turbulent area

of the system which will result in minimal environmental impact and less need of sheet piles.

The drawback for alternative two is that the penstock will have sharper bends but this will not cause

higher losses than what is gained in the shorter length and the higher head.

Alternative two is the recommended layout and is what has been considered in the following

analysis.

Figure 3.6 Topographic cross section

Alternative two has a gross head of 44.27 m, a penstock length of 170.29 m and has two bends of 20°

and 25° respectively. The upstream water level is located at 450 m above sea level [25].

27

3.4 Hydrology

Since the site is located in an irrigation system the flow is regulated and is kept at a specific value.

Estimation of runoff area and periods was therefore not needed. There is a juridical decision from

1977 stating that the BioBio North Irrigation System has the right to lead 2.2 m3/s to Derivado 1 from

the Quillaileo river [26].

During the summer season the users of the original system have the water right given by the BBNIS

organization as stated;

Table 3.1 Users of the irrigation system and their demanded volume

Name Volume [l/s]

Dolores Barrueto Barking 60

Javier Hermosilla Nef 45

María Chávez Ormeno 15

Inmobiliaria Santa Bárbara Ltda. 10

Endesa 121

Renoval 22.5 + 80

Saforai 230

Total 583.5

In this period the flow is thereby reduced from2.2 m3/s to 1.62 m3/s, those levels are the only ones

requested by the BBNIS organization to occur in a range of six months each.

From those statements this rather strange flow duration curve is obtained.

Figure 3.7 Flow duration curve based on juridical agreements of the site

Residual flow is the flow that must be left in the river throughout the year to not affect the

environment. In this case the system is artificial and no need to keep a residual flow, i.e. it is set to

zero.

The production will be all year round with the maintenance period as an exception.

To verify the magnitude of the flow, reliability of literature and by interest in the measurement

method the flow was measured the 25th of February. The water speed was measured by a current

0

0,5

1

1,5

2

2,5

0 20 40 60 80 100 120

Flo

w[m

3/s

]

Duration [%]

Flow Duration Curve

28

meter, a Gurley Precision Instruments No 622 ser 955777, and the area was measured with a

yardstick. For further details about the method see Chapter 2.2.2 -velocity area method.

Table 3.2 Field investigation of the flow

Upstream level Location [m] Width [m] Depth [m] Average velocity [m/s] Area [m2] Flow [m3/s]

0 0.2 0.65 0.89 0.13 0.116 0.2 0.2 0.68 0.89 0.136 0.121 0.4 0.2 0.74 0.97 0.148 0.144 0.6 0.2 0.84 0.89 0.168 0.150 0.8 0.2 0.84 0.81 0.168 0.136 1 0.2 0.82 0.72 0.164 0.118 1.2 0.2 0.73 0.72 0.146 0.105 1.4 0.2 0.64 0.72 0.128 0.092 1.6 0.5 0.64 0.56 0.32 0.179

Total flow [m3/s] 1.160

Downstream level Location [m] Width [m] Depth [m] Average velocity [m/s] Area [m2] Flow [m3/s]

0 0.25 0.58 0.89 0.145 0.129 0.25 0.25 0.58 0.81 0.145 0.117 0.5 0.25 0.58 0.97 0.145 0.141 0.75 0.25 0.58 0.89 0.145 0.129 1 0.25 0.58 0.56 0.145 0.081 1.25 0.25 0.58 0.72 0.145 0.104 1.5 0.25 0.58 0.81 0.145 0.117 1.75 0.25 0.58 0.97 0.145 0.141 2 0.25 0.58 0.64 0.145 0.093 2.25 0.15 0.58 0.32 0.087 0.028

Total flow [m3/s] 1.081

Two days earlier from the date of measurement it had been raining, the system was therefore not

fully used and the values are misleading. Furthermore only one measurement gives an uncertain

result. But what can be seen is that the difference in flow between up- and downstream is very low.

This is due to the land being irrigated naturally and thereby no need for irrigated water. This means

that during the summer season there will be days with no need of the flow going to the users. The

water can then instead be led through the power station which will give a higher electricity

production. In this report that fact will only be mentioned and seen as an additional benefit when

installed, the assumption that the flow varies only within a range of six months will be made.

In the future there is a concern that the Quillaileo river will have a lower flow. This is of course a risk

for the project but the juridical statement giving the system 2.2 m3/s is fixed and has no date of

expiration [26].

The water quality could not be measured due to the only laboratory in town being closed for

renovation. But by interviews it was declared that there has never been any need of cleaning this

part of the system and there have never been any complaints from the users having problems with

sediment in their systems. Visually the water is very clear. In this head range the turbines will not be

particularly prone to sand erosion. The canals are built in concrete.

29

3.5 Geology

3.5.1 Soil type

In 2004 the Chilean government carried out geological investigations in the region of Quillaileo due

to a dam reparation being performed. In that investigation the soil characteristics was determined by

taken samples of the cross sections from the ground level to a total depth of 2.5 meters. For the site

of Minicentral Quillaileo-Mininco following is stated:

0-0.2 m ground vegetation cover

0.2-1 m silty clay, light brown, medium humidity, medium consistency

1-2.5 m sandy loam, light brown, medium humidity, medium consistence

The area has a low permeability and workability category A. Category A can be handled by backhoe

or by hand [25].

3.5.2 Climate

In 1993 the University of Chile identified the climate in the region by placing measurements at

different specific sites, one of those was the district 89.7 which is the area of the Minicentral

Quillaileo-Mininco [27].

Table 3.3 Regional climate [27]

From Table 3.3 it can be read that the minimum temperature in 1993 in the district 89.7 was 3.9°C.

Horas frío in the table refers to the amount of hours when the temperature was below 7°C. If a

hydropower plant is to be constructed in cold climate it will cost more due to the increased difficulty

in construction and higher requirements in the equipment. The term cold climate often refers to

locations that experience at least 180 days of frost in a year, this is clearly not the case.

30

3.6 Environmental Aspects

The system is artificial and the trash rack at the intake of the Quillaileo is to prevent fish going into

the canal. Fish are therefore rare, there are no leisure activities in relation to the system and since

the plant will be built in an unused area the visual impact will be small. The penstock is

recommended to be buried and will therefore not be an obstacle for the animals crossing this area.

The construction will cause noise and movement which can disturb the fauna and existing flora in the

area will be cut down which will cause a change of the wildlife. In addition to the plant it could be

necessary to improve the infrastructure but by using existing roads reduces the destruction.

3.6.1 Juridical Aspect

General rules on environment impact are stated in the law 19.300 which is an addition to law 20.173,

updated by the Comisión Nacional del Medio Ambiente in 2007. Article 10 file c) states the

restriction that if a power generating plant larger than 3 MW is to be constructed, an environmental

impact assessment must be performed and approved by the juridical division of the Comsión

Nacional del Medio Ambiente. The Minicentral Quillaileo-Mininco is designed to have the rated

power of 840 kW i.e. it will be smaller than 3 MW and therefore no assessment is required.

In article 10 file a) it is stated that projects which affect water resources subjected to article 294

always need to have an environmental impact assessment approved before construction. The project

of Minicentral Quillaileo-Mininco is not included in this article due to article 294 only concerning

natural water resources.

3.6.2 Surrounding Area

The most noticeable impact will be on the users connected to the irrigation system in this area.

Discussions have taken place with all involved parts by a meeting to inform the users about the

project. All parts have a positive approach due to the system then being better equipped and

controlled. In Chapter 3.4 the amount of water for each user is given, when the hydropower station

is in operation no higher volume than stated will be allowed and no new users can be connected.

The landowner Gabriel Aravena is informed but there has been no negotiation of compensation for

future land use. The specific land is unused but the surrounding area is plantations owned by Mr.

Aravena, therefore a better infrastructure could be part of the compensation.

31

3.7 Civil Work

Normally the greatest cost and workload for a hydropower plant is the dam construction. Since no

dam is needed for the Minicentral Quillaileo-Mininco this is a great advantage. The main features in

this case are the water passages, penstock, tailrace, power house, modification of the canal system

and an improvement of the road.

At the intake, preparations to fit the canal into the penstock and still letting 0.58 m3 pass in

summertime must be built. At the intake trash racks must be installed to avoid material going into

the turbine.

The penstock is calculated to be 1200 millimeters in diameter, of the type Flowtite GRP see Chapter

4.1.1. Suggestion is to bury the penstock to make as little visual and obstacle impact as possible. If

buried, the penstock will last longer due to relatively constant moisture and temperature as well as

no sunlight exposure. In forested areas there can be problems with hunters shooting at the penstock

if located above ground. The length of the penstock is calculated to 170 meters and will need two

bends of 25° and 20° respectively to follow the terrain.

The entrance and exit of the turbine will have suitable valves and gates to make it possible to shut off

the flow for maintenance or in emergency situations. The valves are normally made of steel or iron,

wood is considered a possibility on the downstream side. After the turbine the draft tube for

occurrence of pressure recovery is installed and the water is then carried to the tailrace and further

to the downstream water level.

The power house should be built as small as possible to reduce cost and since the plant is to be run

fully automatically there is no need for permanent workspace. The house will be built in locally

available material such as concrete and wood. At the outlet stabilization of the ground will be

needed to avoid erosion.

There is an existing road to the upstream area which only will have to be stabilized with filling, to the

power house a new road will have to be constructed of approximately 500 meters. The quality of the

infrastructure is mainly set by the demands given by the suppliers of the electro mechanical

equipment.

The machine house will be located as in Figure 3.5. The ground needs to be leveled out and stabilized

at a distance of 170.3 meters from the intake.

The national grid is located four kilometers from the machine house, i.e. the same length of

transmission lines is required.

No specific spillway is needed since the system will be constructed in a way that will have the

possibility to lead the water the original way.

32

3.8 Economical Investigation

The economical investigations in feasibility studies are in general uncertain with the purpose to get a

rough idea of the profitability. When offers have been given from suppliers the economical analysis

should be recalculated.

3.8.1 Currency

In Chile the currency Pesos, CLP, is being used but for this analysis the organization requested the use

of US dollars since it will facilitate the search for and discussions with investors and suppliers.

1 CLP 0.00189 USD

1 SEK 0.139 USD

1 NOK 0.169 USD

The currency conversion is based on the average value of the period 2nd of February to 3rd of May

2010 [28].

3.8.2 Cost Estimations

Because of the difference in salaries for workers, fuel costs, administration and manufacturing the

construction cost of a hydropower plant varies widely in different countries and regions. The cost

estimation has been based on a project in the same region called Reca. Reca is projected and is to be

constructed in 2010, it has a flow of 2.5 m3/s and a gross head of 50 meters and is located in an

irrigation system i.e. very much alike the Minicentral Quillaileo-Mininco [29]. The cost has also been

compared and based on statistical values from year 2005 [30]. To adjust the price level of 2005 to the

current level a percentage value specified for each product has been used [31]. The

electromechanical cost is based on a budget price given by Turab AB [32].

3.8.3 Revenue Estimation

It is always a risk to invest in an energy project since the revenue given in electrical sales is very

fluctuating and complex.

Figure 3.8 The revenue per kWh for electrical production in the SIC system between November 2006 to February 2010 [33]

The revenue has increased during the last two years but is now on the downhill, for that reason the

average income per kWh for this period was calculated and used as a base and resulted in 44.87 CLP

i.e. 0.085 USD. For some safety marginal the base in the economical analysis is set a bit lower, 40 CLP

i.e. 0.076 USD.

0,000

10,000

20,000

30,000

40,000

50,000

60,000

70,000

no

v-0

6

feb

-07

maj

-07

aug-

07

no

v-0

7

feb

-08

maj

-08

aug-

08

no

v-0

8

feb

-09

maj

-09

aug-

09

no

v-0

9

feb

-10

Revenue per kWh [CLP]

33

3.8.4 Clean Developing Mechanism, CDM

If a renewable energy production plant is to be constructed in a developing country, countries

regulated by the Kyoto protocol can invest in the project and thereby earn the carbon credits given

to it. The system is called Clean Developing Mechanism and the carbon credits are called Certified

Emission Reductions, CERs.

The Minicentral Quillaileo-Mininco is too small to be profitable for CDM. The amount of CERs would

not cover the cost of registration and administration [34].

3.9 Similar Hydropower Projects

To evaluate if the design and chosen equipment are reasonable a method is to compare with similar

projects.

3.9.1 Huesna

The hydropower plant Huesna was built in 1997 and is located in the Sevilla region in Spain. It is

owned by Confederación Hidrográfica del Guadalquivir and is a multipurpose plant for electrical

production, irrigation and improvement of water quality. The flow is 1.61 m3/s and the head is 55

meters, the penstock is 240 meters long and has a diameter of 1300 mm. Sited is a horizontal Francis

turbine connected to a synchronous generator with 1000 rpm. The plant produces 4.35 GWh

annually [15].

3.9.2 Skinnsjön

The Skinnsjön plant was constructed in 1980 and is located in the municipality of Ånge, Sweden. The

plant has a head of 36.5 meters, the station has two vertical Francis turbines with the total rated

power of 760 kW. The inner diameters are 425 mm with the rotational speeds 1008 rpm. The plant

has an annually production of 3.3 GWh. The plant is owned by Härjeåns Kraft AB [35].

3.9.3 Kniva

The Kniva plant is located between two lakes with different altitudes in the municipality of Falun,

Sweden. It was constructed in 1936 and renovated in 1993. The flow is 2 m3/s and it has a head of 49

meters, the penstock is 650 meters long and the plant has a horizontal Francis turbine. Rated power

is 750 kW and the annually production is 800 MWh. It is owned by Falu Energi & Vatten AB [36].

3.9.4 Bruket

Bruket is a small hydropower plant located in the municipality of Sollefteå, Sweden. The head is 44

meters. It was constructed in 1984 with a vertical Francis turbine with a rated power of 850 kW and

annually produces 3.25 GWh. The inner diameter is 670 mm and the rotational speed 500 rpm. The

plant is owned by Tunsjöns Karft AB [35].

3.9.5 Similar Projects in the BioBio Region

Study visits to similar projects in the area was scheduled for the latter half of the investigation period

but the earthquake the 27th of February hindered this opportunity, other activities were prioritized

by the organizations.

34

4. Evaluation The evaluation chapter handles recommendation of electromechanical equipment, the assumed

energy production and the results of the economical analysis.

4.1 Equipment

4.1.1 Penstock

4.1.1.1 Material

Pros and cons with different materials can be read in 2.6.3. Recommended is a penstock of the

material Flowtite GRP. Flowtite GRP is a bit more expensive but has the advantage of a long lifetime,

no need of maintenance and a flexibility that reduces the impact of water hammer by half compared

to steel. The material handles the specifications for totally negative pressure, vacuum, and has been

tested to cope with earthquakes.

The gross head of 44.3 meter demands a material which can handle 4.4 bar + ΔHwater hammer, 44 mVp +

ΔHwater hammer. A normal water hammer occurs when the turbine is shut down under governor control,

in this case the overpressure can reach to 25 % of the gross head [8]. For emergency water hammer

it is the wall thickness that will have to be adjusted. ΔHwater hammer is calculated to 1.1 bar i.e. the

penstock should be able to handle 5.5 bar. The closest commercial pressure class is PN 6. To resist

external, positive and negative pressures stiffness class SN 5000 is suggested [18]. If the pipe

stiffness is insufficient the pipe will buckle under the negative pressures.

4.1.1.2 Dimension

To estimate a suitable penstock dimension a calculation of percentage losses due to friction was

done by using Equation (2.14).

Characteristic material coefficient for Flowtite GRP is 0.011, length of penstock 170.3 meter, flow 2.2

m3/s and gross head 44.3 meter. The maximum flow is used, when the flow decreases also the loss

will decrease.

Table 4.1 Percentage loss for different penstock diameters

Loss [%] Head loss [m] Diameter [mm] 0.5 0.2 1333 1 0.4 1171 1.5 0.7 1085 2 0.9 1028 2.5 1.1 986 3 1.3 953 3.5 1.6 926 4 1.8 903

Table 4.1 shows that the diameter should be between 1300 mm and 900 mm, looking at standard

diameters there are the commercial sizes of 1200 mm and 1000 mm. The difference in loss between

the diameters is 1.4 %. To make a decision the head loss and thereby reduction of production is

compared with the difference in cost of penstock and installation. The needed volume to bury the

DN 1000 penstock is 4.5 m3 per length meter, DN 1200 needs 5.8 m3 per length meter.

35

Table 4.2 Cost comparison for different penstock diameters [30]

Diameter [mm]

Penstock [NOK/m]

Installation [NOK/m]

Total cost [NOK/m]

Length [m]

Total investment cost [NOK]

Total investment cost [USD]

1000 kr 1 819 kr 945 kr 2 764 171 kr 472 644 $79 877 1200 kr 2 461 kr 1 218 kr 3 679 171 kr 629 109 $106 319 Difference kr 642 kr 273 kr 915 0 kr 156 465 $26 443

See Appendix 9.1 for comparison of the difference in energy production due to different losses i.e.

different net heads.

Difference in annual production [kWh] 109089

Extra annual revenue with DN 1200 [USD] $8 291

The payback time for the extra investment of DN 1200 is then 3.2 years, DN 1200 is therefore highly

recommended.

4.1.1.3 Recommendation

A penstock Flowtite GRP DN 1200, PN 6, SN 5000 is recommended.

4.1.2 Mechanical

4.1.2.1 Turbine type

Stated in 2.3.5 the Minicentral Quillaileo-Mininco site is in the range of a Francis or a Kaplan turbine

due to its head and flow. From supplier’s graphs showing the application range for their different

turbines can be obtained, one example is Figure 4.1. It clearly shows that if a turbine is to be ordered

from [37] they will deliver a Francis turbine.

Figure 4.1 The range of turbines with a marked spot for the Minicentral Quillaileo-Mininco [37]

36

Graphs from three more suppliers have been studied which all show a recommendation of a Francis

turbine [8] [10] [15]. The Francis turbine also has the advantage of normally demanding less

maintenance compared to a Kaplan turbine.

The type of turbine can also be determined by looking at the specific speed. The combination of the

method given in Chapter 2.3.6 and the net head of 43.6 meter, see Chapter 4.3.1, gives nQE=0.278 for

Francis and nQE=0.366 for Kaplan. But by suppliers there are standardized values for the rotational

speed. By equation (2.2) those nQE correspond to nFrancis=1059 rpm and nKaplan=1393 rpm. The closest

standard speeds are 1000 and 1500 rpm. With the new standardized values the specific speed is

recalculated which gives a new n and then the new nQE of 0.157 for both turbines is obtained. By the

ranges stated in Chapter 2.3.5 the conclusion is that by verification of the specific speed a Francis

turbine should be installed.

The advantage of a Kaplan is the maintained high efficiency over a wide flow range and thereby a

greater production but a Kaplan turbine is often 30-50 % more expensive. Calculations to evaluate if

the extra investment would pay off were performed, see Appendix 9.2. By the simple pay-back

method the Kaplan in comparison to a Francis would pay off in 65 years. The economical evaluation

thereby also states that a Francis is recommended.

The choice of a Francis turbine also corresponds to similar hydropower projects studied in Chapter

3.9.

For this site a vertical setting would be the cheapest and easiest construction option [32].

4.1.2.2 Turbine Dimensions and Suction Head

To calculate the precise dimensions of one specific turbine knowledge about the production capacity

and model tests are needed. The base for this is a hill diagram developed by the manufacturer. In this

stage there is no chosen supplier, the calculation was therefore performed only to get a grip of

reasonable dimensions.

The calculations performed are shown in Appendix 9.3. With a rotational speed of 1000 rpm the

diameter would be 520 mm and have a suction head of 0.54 meters, with a rotational speed of 750

rpm the diameter would be 690 mm and the suction head seven meters. A suction head of seven

meters is not reasonable and the smaller dimension of the 1000 rpm design is normally cheaper.

If the turbine diameter is less than 700 mm it simplifies the transport since it is small enough to be

transported by truck to rural areas in one set together with the generator [8].

For an apposite turbine design layout see Appendix 9.4.

4.1.2.3 Recommendation

A vertical Francis turbine is recommended with a diameter of 520 mm and a suction head of 0.5

meter positive.

37

4.1.3 Electrical

4.1.3.1 Generator type

As stated in 2.4 both a synchronous and an asynchronous generator could be suitable for the

Minicentral Quillaileo-Mininco but the synchronous generator is recommended because of its

advantage in voltage regulation and production of reactive power. Furthermore to drive voltage

directly to the station would be possible. The asynchronous is somewhat cheaper but at the rated

power of 840 kW not cheap enough to compensate for the disadvantages. By Frontel, the grid owner,

it was requested to install a synchronous generator.

4.2.3.2 Generator Dimensions

The dimensions of the generator are based on chosen turbine and its rotational speed. The two

options is 1000 rpm and 750 rpm which results in a generator with six respectively eight poles. The

generator must stand the top production at 840 kW, the closest standard is 900 kVA which fits.

4.1.3.3 Control System

Since the Minicentral Quillaileo-Mininco is a small scale station there is no need or economical gain

in having daily personal supervision, the control system is therefore highly recommended to be fully

automatically.

4.1.3.4 Transformer and Grid Connection

The grid owner, Frontel, will install and choose the transformer. The grid connection will be made

four kilometers from the site to the 13.2 kV national grid.

4.1.3.5 Recommendation

Recommended is a 900 kVA synchronous generator with six poles, 1000 rpm. The electrical system

should be fully automatic and the connection to the national grid should be two kilometers to the

south of the BioBio river.

38

4.2 Energy Production

The rated power is 840 kW and the annual production 5 830 MWh.

4.2.1 Head loss

The cause of head loss and its calculation methods is stated in 2.6.4. The variation in gross head is

neglected due to the head being above 30 meters and the occasional variance will be small in

comparison. From the topographical investigation the gross head is set to 44.27 meters.

Hn=Hg-hf1-hf2

Where Hn=net head, Hg=gross head, hf1=flow losses in intake due to gates and friction, hf2=flow losses

in outlet i.e. the height velocity.

The losses ht, hf, hc and hb are then calculated see Appendix 9.5 and their total is hf1.

Table 4.3 Head losses

Flow [m3/s] 2.2 1.62

Head loss i trash rack, ht [m] 0.006 0.003

Head loss according to friction losses, hf [m] 0.388 0.210

Head loss at inlet due to comparison, hc [m] 0.032 0.017

Head loss due to bends first bend, 20°, hb1 [m] 0.026 0.014

second bend, 25°, hb2 [m] 0.032 0.017

Total head loss hf1 [m] 0.483 0.261

hf2 is calculated by equation (2.26)

Flow [m3/s] 2.2 1.62

hf2 [m] 0.193 0.104 Table 4.4 Total head loss

4.2.2 Efficiency

The turbine efficiency for the Francis turbine is stated in Table 4.5.

Table 4.5 Efficiency based on figure 2.6

Flow [m3/s] 2.2 1.62

Q/Qmax 1 0.73

n/nmax 1 0.95

nmax 0.94 0.94

n 94.0 % 89.3 %

The generator efficiency is set to 95 % and transformer efficiency to 99 % [13].

Flow [m3/s] 2.2 1.618 hf1 [m] 0.483 0.261 hf2 [m] 0.193 0.104

Total head loss [m] 0.676 0.365 % of gross head 1.5 % 0.8 %

39

Some of the energy produced by the plant is used by the plant itself for auxiliary equipment such as

shut-off valves, gates, control system, lightning etc. For a small plant those parasteristic losses are

minimal and an estimation of 2 % of the total capacity is suitable, the parasteristic loss is considered

to be constant [13].

Maintenance will be performed during the summer period when the flow to the plant and the

activity in the organization is low. A good approximation for maintenance is two weeks annually and

four weeks every fifth year [14]. The calculated time for maintenance is in percent 4.6 % and average

amount of hours annually is 403.2 h.

4.2.3 Energy Production

Table 4.6 Energy production

Flow, Q, [m3/s] 1.62 2.2 Days 182.5 182.5 Gross head, Hg, [m] 44.27 44.27 Losses, hf1+hf2, [m] 0.365 0.676 Net head, Hn, [m] 43.90 43.59 Turbine efficiency [%] 89.3 % 94.0 % Generator efficiency [%] 95 % 95 % Installed power [kW] 591 840 Parastistic losses [kW] 17 17 Power [kW] 574 823 Transformer efficiency [%] 99 % 99 % Net power [kW] 568 815 Brutto energy [kWh] 2 487 692 3 569 439 Loss due to maintenance etc 4.6% [kWh] 229 004 - Net energy delivered [kWh] 2 258 688 3 569 439

Annual sum delivered [MWh] 5 828

There will not be any possibility of storage to peak hours in price level, the production will be

continuous.

40

4.3 Economical Analysis

4.3.1 Costs

The cost for canal refurbishing is an average estimate for refurnishing an old existing canal and make

adjustment to fit the flow for a penstock as well as leading some of the flow the original way. The

BBNIS organization has made the estimation that this will concern 1.5 km of the canal.

The cost for intake is based on the Reca project, included is a gate, close valve and trash rack.

The penstock is a Flowtite GRP tube with a diameter of 1200 mm and pressure classified PN6, from

2005 price level 7 % is added to reach the current price level [30].

For the penstock installation the price is set by cubic meter needed to excavate, with a diameter of

1200 mm this is estimated to 5.8 m3 per length meter. The area is cleared, excavated and fitted with

foundations for 160 NOK/m3 and then to the penstock is jointed and buried for 50 NOK/m3, the total

cost per length meter is therefore 1 218 NOK/m.

The machine house will be constructed at a flat but silty, lose ground and therefore 10 % is added for

ground preparation and fundament. Material and construction costs are included as well as air-

conditioning system, tailrace, spiral and drainage system with a pump pit. No account is taken to

daily supervision. From 2005 price level a percentage of 20 % is added to reach the current price

level.

Road refurbishment is estimated by the cheapest option range since the already existing road only

needs improvement, the length of one kilometer is estimated by the BBNIS organization. Currently

there is no road going from the upstream level to the downstream where the station will be located,

this is a rather difficult terrain and will therefore generate a higher cost as a length 200 meters is

estimated by the BBNIS organization. In the later road estimation it is also included a cleared and

adjusted area next to the machine house.

Turbine, generator, etc. is a budget price given by Turab AB. The cost includes delivery, installation

and commissioning of a vertical Francis turbine with a diameter of 600 mm, a synchronous generator

900 kVA, turbine governor and a butterfly valve.

The electrical governor covers generator control and protection, water level control, remote

supervisor system (SCADA), battery and battery charging. 20 % was added to reach the current price

level [30].

The cost for grid connection is based on the Reca project and includes line, transformers, protection,

agreements and connection. The connection point is located four kilometers from the plant as stated

in 3.2.3.

In hydro mechanical equipment a crane for the machine house, wicket gates, cooling water and

tailrace grid is included. 10 % is added to reach the current price level.

15 % of the total cost is budgeted to contractors, administration, ordering, consulting, management,

designing, investigation etc. [30].

41

For an installation in Chile it is recommended to calculate with 10 % for negotiations, boarder taxes,

VAT and investment expenses [38].

Unforeseen costs with 10 % are widely accepted when budgeting [30].

Table 4.7 Cost estimation

Civil Work [USD/m] [m]

Cost [USD] canal refurbishing $180 1 500

$270 000 [29]

Intake

$80 000 [29]

[NOK/m] [m] Cost [NOK]

penstock installation kr 1 218 171 kr 208 278 $35 199 [30]

Cost [NOK] add. 10 % Cost [NOK]

machine house kr 1 080 000 kr 108 000 kr 1 188 000 $200 772 [30]

[NOK/m] [m] Cost [NOK] road refurbishing, to the site kr 200 1 000 kr 200 000 $33 800 [30]

road refurbishing, to the station kr 500 200 kr 100 000 $16 900 [30]

total Civil Work $636 671 temporary constructions, 5 % of Civil Work

$31 834 [29]

Electro Mechanical Equipment [SEK]

Cost [USD] turbine, generator, etc. 4 900 000 kr

$681 100 [38]

Cost [NOK]

electrical governor

kr 540 000 $91 260 [30]

[NOK/m] [m] Cost [NOK]

Penstock kr 2 461 171 kr 420 831 $71 120 [30]

[NOK/kW] [kW] Cost [NOK]

hydro mechanical equipment kr 382 840 kr 320 628 $54 186 [30]

[USD/km] [km]

grid connection $50 000 4

$200 000 [29]

total Electro Mechanical Equipment $1 097 667

total Electro Mechanical and Civil Work $1 766 171

Other

Cost [USD] contractors, administration, ordering, etc. 15 %

$265 022 [30]

VAT, border taxes, investment expenses 10 %

$176 682 [38] unforeseen 10 %

$176 682 [30]

Total $2 384 331

4.3.2 Revenue

The revenue is assumed to be constant, see Chapter 3.7.3. To make an economical evaluation with

marginal the income is set to 40 CLP/kWh i.e. 0.076 USD/kWh.

Table 4.8 Revenue estimation

Annual energy delivered [kWh] 5828127

Revenue [USD/Kwh] $0.076

Annual revenue [USD] $440 606

42

4.3.3 Simple Payback and Cost/kW

Total cost [USD] $2 384 331

Annual revenue [USD] $440 606

Payback time [years] 5.4

To consider a hydropower project to be viable the repayment period should not exceed eight years

[8].

Total cost [USD] $2 384 331

Rated power [kW] 840

Cost/kW [USD/kW] $2 838

The normal investment cost in hydropower is between 2 000 USD/kW and 4 000 USD/kW [1].

4.3.4 Cash Flow

To calculate the cash flow the annual cost for maintenance and operation, M&O, needs to be taken

into account. The rule of thumb is that the annual cost is 1-4 % of the initial investment [13]. Included

in M&O is land lease, property taxes, water rental, insurance, spare parts and labor. This system will

be fully automatically and the organization always has staff on standby for its normal operation who

also can be educated to perform simple checks of the station. Further is water rental and land lease

requested to be neglected by the BBNIS organization. Through discussions with the organization and

similar hydropower plants in the area the assumption is 2 %.

Total investment [USD] $2 384 331

Annual M&O cost [USD] $47 687

The project is assumed to be developed in two years with following cost allocation:

Year one: half civil work, half investment expenses, VAT and boarder taxes, and half administration,

ordering and contractors. Year two: half civil work, half investment expenses, all electro mechanical

equipment, unforeseen, half investment expenses, VAT and border taxes and half administration,

ordering and contractors.

The life span is set to 35 years and the discount rate of 12 % by request from the BBNIS organization.

To have a safety marginal the electricity price is assumed to increase by one percent point less than

the inflation.

43

Table 4.9 Cumulated cash flow

Year Investment Revenues M & O Cash flow Cumulated cash flow

-2 $555 023,65

-$555 023,65 -$555 023,65 -1 $1 829 307,33

-$1 829 307,33 -$2 384 330,99

0

$440 606,40 $47 686,62 $392 919,78 -$1 991 411,21 1

$436 200,34 $47 686,62 $388 513,72 -$1 602 897,49

2

$431 838,33 $47 686,62 $384 151,71 -$1 218 745,77 3

$427 519,95 $47 686,62 $379 833,33 -$838 912,44

4

$423 244,75 $47 686,62 $375 558,13 -$463 354,31 5

$419 012,30 $47 686,62 $371 325,68 -$92 028,63

6

$414 822,18 $47 686,62 $367 135,56 $275 106,93 7

$410 673,96 $47 686,62 $362 987,34 $638 094,27

8

$406 567,22 $47 686,62 $358 880,60 $996 974,87 9

$402 501,55 $47 686,62 $354 814,93 $1 351 789,80

10

$398 476,53 $47 686,62 $350 789,91 $1 702 579,71 11

$394 491,77 $47 686,62 $346 805,15 $2 049 384,85

12

$390 546,85 $47 686,62 $342 860,23 $2 392 245,08 13

$386 641,38 $47 686,62 $338 954,76 $2 731 199,84

14

$382 774,97 $47 686,62 $335 088,35 $3 066 288,19 15

$378 947,22 $47 686,62 $331 260,60 $3 397 548,79

16

$375 157,74 $47 686,62 $327 471,12 $3 725 019,91 17

$371 406,17 $47 686,62 $323 719,55 $4 048 739,46

18

$367 692,11 $47 686,62 $320 005,49 $4 368 744,94 19

$364 015,18 $47 686,62 $316 328,56 $4 685 073,51

20

$360 375,03 $47 686,62 $312 688,41 $4 997 761,92 21

$356 771,28 $47 686,62 $309 084,66 $5 306 846,58

22

$353 203,57 $47 686,62 $305 516,95 $5 612 363,53 23

$349 671,53 $47 686,62 $301 984,91 $5 914 348,45

24

$346 174,82 $47 686,62 $298 488,20 $6 212 836,64 25

$342 713,07 $47 686,62 $295 026,45 $6 507 863,09

26

$339 285,94 $47 686,62 $291 599,32 $6 799 462,41 27

$335 893,08 $47 686,62 $288 206,46 $7 087 668,87

28

$332 534,15 $47 686,62 $284 847,53 $7 372 516,40 29

$329 208,81 $47 686,62 $281 522,19 $7 654 038,59

30

$325 916,72 $47 686,62 $278 230,10 $7 932 268,69 31

$322 657,55 $47 686,62 $274 970,93 $8 207 239,62

32

$319 430,98 $47 686,62 $271 744,36 $8 478 983,98 33

$316 236,67 $47 686,62 $268 550,05 $8 747 534,03

Figure 4.2 Cumulated cash flow

-4000000

-2000000

0

2000000

4000000

6000000

8000000

10000000

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37

Cu

mu

lati

ve c

ash

flo

w [

USD

]

Year

44

4.3.5 Year to Positive Cash Flow

Year to positive income is eight years. Less than eight years is normally considered to be a viable

project [13].

4.3.6 NPV

The net present value for this project is 444 913 USD. If comparison to other investments the NPV

value should be as high as possible. In Table 4.10 NPV is calculated with different discount rates.

Table 4.10 NPV with different discount rates

Discount rate [%] 6 % 8 % 10 % 12 % 14 %

NPV [USD] $2 429 027 $1 537 274 $905 522 $444 913 $100 374

4.3.7 IRR

The internal rate is 14.70 %. The IRR should be several percentages higher than the lending or

interest rate in order to compensate for the risk, time and problems associated with the project.

4.3.8 B/C

The benefit cost ratio for this project is 1.18, b/c below 1 is normally classified as a bad investment.

4.3.9 Economic Analysis for Different Revenues

Since the economical analysis is strongly depending on the revenue Table 4.11 gives simple payback,

year to positive income, NPV, IRR and B/C for different tariffs, -25 %, 0 % and +25 % compared to

0.076 USD/kWh.

Table 4.11 Economic analysis for difference in revenue

Difference in tariff [%] 75 % 100 % 125 %

Simple payback [years] 7.2 5.4 4.3

Year to positive income [years] 10 8 6

NPV [USD] -$300 220 $444 913 $1 752 585

IRR [%] 10.11 % 14.70 % 19.05 %

B/C 0.88 1.18 1.47

4.3.10 Economic Analysis for Different Investment Cost

Since the economical analysis is strongly depending on total investment Table 4.12 gives simple

payback, cost/kW, year to positive income, NPV, IRR and B/C for different tariffs, -25 %, 0 % and +25

% from 2 348 331 USD.

Table 4.12 Economical analysis for different investment costs

Difference in investment cost [%] 75 % 100 % 125 %

Simple payback [years] 3.8 5.4 7.2

Cost/kW [USD/kW] $2 090 $2 980 $3 967

Year to positive income [years] 6 8 10

NPV [USD] $1 203 621 $444 913 -$396 998

IRR [%] 22.10 % 14.70 % 10.12 %

B/C 1.68 1.18 0.88

45

5. Validation The validation chapter handles the reliability of the results stated in this project.

5.1 Sources of Error

The reader has to understand that this report is a prefeasibility study to be used as a base for the

consideration of whether to continue exploring this site or not. If it is decided to continue

responsible for the project will have to evaluate some of the figures and take some new

measurements. For that reason every source and calculation is well defined to facilitate further

evaluation to be based upon this study.

The topographical measurements were mainly taken at, what has been called, alternative one since

this was the original layout. Alternative two which is recommended for the plant may therefore need

further topographical measurements to base the design on.

The flow duration curve is uncertain, there will be variations but small in comparison to a normal

hydro power plant. From the measurement taken the conclusion is that 2.2 m3/s can be an

overestimation, the system has not been exposed to that value for a long time and the need of canal

refurbishment can therefore be higher than assumed.

The geological measurements were taken in 2004 and it is possible that some changes have

occurred.

The suggested civil work is only a suggestion and need further investigation and design evaluation.

The uncertainty in cost evaluation is always high in a prefeasibility study. More evaluation has to be

done and more budget prices from suppliers will have to be gathered. But for this prefeasibility the

figures are well based from reliable sources. The revenue has to be evaluated and negotiated with

the grid owner, Frontel. Also the load demand will have to be discussed and taken into account since

this reports’ energy production is based upon a guaranteed delivery option.

5.2 Local Variations

The specific results of this prefeasibility study are reprehensive for the surveyed area only. On the

other hand can the different disciplines, survey- and calculation methods be applied to any locations

believed to be a potential site for a hydropower plant.

5.3 Stated Recommendations

Turbine: Turab AB recommended a vertical Francis turbine. Turab AB recalculated from one of their

existing turbines, Monowai, and suggests a diameter of 600 mm with a rotational speed of 750 rpm

and a suction head of 2 meters [32]. By this project a vertical Francis turbine with 1000 rpm, a

diameter of 520 mm and a suction head of 0.5 meter positive was suggested.

Generator: BEVI recommended a synchronous generator 900 kVA for this project [32] which is

consistent with the recommendation given in this report.

Losses due friction in penstock: APS stated that the head loss due to friction in their pipes, Flowtite

GRP, would be 0.33 meter for 2.2 m3/s and 0.18 meter for 1.62 m3/s for DN 1200 with a length of

170.3 meters [18]. By the calculations in this project the corresponding figures is 0.39 meters for 2.2

m3/s and 0.21 meters for 1.62 m3/s for a DN 1200 Flowtite GRP.

46

Head loss: A total gross head loss of 1-4 % is stated to be acceptable [8]. In this project there is a 1.5

% gross head loss for 2.2 m3/s and 0.8 % for 1.62 m3/s.

Revenue estimation: According to the hydropower division at AMEC the revenue range in Chile is

normally between 35-50 CLP [38]. For this project 40 CLP has been used.

Cost estimation: A small hydropower plant between 250 and 1 000 kW should have an investment

cost of 2 240 USD/kW according to Thermie and 2 720 USD/kW according to ESTIR [8]. Normal

investment cost in hydropower is between 2 000 USD/kW and 4 000 USD/kW [1]. The investment

cost for this project is 2 838 USD/kW.

Maintenance: when approximating the energy production 4 % of the total time is recommended to

set aside for maintenance [13]. In this project 4.6 % is set aside for maintenance.

47

6. Recommendation In the recommendation chapter further research is suggested and contacted suppliers are listed.

6.1 Further Investigation

First step after receiving this report is to evaluate whether to continue with the project or not. If it is

decided to be continued the next step is to identify the investor. The investor will then outsource the

project to a consulting firm or handle the development themselves.

A recommendation is to evaluate the project profitability once more after offers has been collected

and then make another decision whether to continue or not. Furthermore it is also important to have

an agreement with Frontel, the grid owner, for probable revenue per delivered kWh and possibly tie

guaranteed revenue over a certain period to reduce the investment risk.

In January 2006 a new reform, Ley Corta I and II, was provided to make exceptions in transmission

charges for new renewable energy sources below 20 MW of capacity. The reform also simplified the

legal aspects of constructing electricity plants below 9 MW [38]. This reform has not been taken into

account in this report but is recommended to study further upon construction.

More specified geological investigations are needed to project the required civil work. Depth to

bedrock is one aspect to know whether the powerhouse foundation will need pooling or not which

could have a great impact of the total investment. Upon eventual request by the turbine

manufacturer investigate the amount and size of sediment in the discharge.

6.2 Contacted Suppliers

Which suppliers to use is a further evaluation after offers has been gathered and contacts have been

made. Listed below are the suppliers contacted during this evaluation:

Turab AB, a turbine and regulation design and manufacture company located in Nässjö, Sweden. The

company has shown interest in delivering and arranges the mechanical part of the set up to the

Minicentral Quillaileo-Mininco.

BEVI International AB, producers of electrical machines who have shown interest in delivering the

generator and transformer to this project. Located in Blomstermåla, Sweden. The company has a

close cooperation with Turab AB.

APS Norway AS is Scandinavia’s largest GRP pipe company. The company has the possibility to deliver

the recommended penstock. The company has a local office in Buenos Aires, Argentina.

Vattenfall Power Consultant and AMEC, both consultancy firms with a great experience and competence of every step within hydropower projects.

48

7. Conclusion In this early stage of the project it is hard to draw other conclusions than that the work with this

project should continue. The project will definitely be technically possible and economically viable

according to the assumptions made in this evaluation.

It is a small hydropower plant so the investment cost will be kept rather low but for the same reason

the financial return will be small. For that reason maybe the largest question for the investor is

whether the gain will be worth the time and risk spent on the project.

A great advantage with the project is the BBNIS organization behind it possessing a great

competence and knowledge of the area as well as good relations with all involved interests. The

recommendation is to have a local investor alternatively an investor being used to the area and

possibly is handling other projects in the district. The reason for this is the knowledge about the

specific regulations in Chile but mostly because of the project being so small with no possibility of

costly travelling.

Beside the monetary means there are several pros and cons with the project. The plant being located

in an artificial system means that there is no need of a dam construction, the small flow range

facilitates the equipment and if there is compromising in production the total flow can be led in the

original canal. The organization has competent on-call staff for its ordinary activities and persons

knowing the specific area thoroughly which will facilitate the construction. The prospective area is

unused, readily accessed and has a good terrain for construction with no need of rock blasting. The

affected users are informed and have reacted favorably to the project. Furthermore there is no need

of environmental considerations and the flow is juridical decided and will not lessen. The

disadvantage is that there is no possibility of storage and therefore no ability to meet the top hours

of revenue, the production will be constant. The Angostura project benefits the Minicentral

Quillaileo-Mininco in facilitation of grid connection and the redirection of the road closer to the site.

49

8. References [1] Boyle, G., 2004, Renewable Energy Power for a Sustainable Future, Oxford University

[2] Dahlbäck, N., History and layout of a Hydropower Station, Lecture, Hydropower- Technique and

System at Uppsala University (2009-09-01)

[3] Central Energía, Centrales, up to date information about installed capacity in Chile,

homepage; http://centralenergia.cl/centrales/ (2010-04-16)

[4] Central Energía, Ranking de países por consume per cápita de electricidad,

homepage; http://centralenergia.cl/estadisticas-de-energia-en-chile/ranking-de-paises/ranking-de-

paises-por-consumo-per-capita-de-electricidad/ (2010-04-16)

[5] Pollitt, M., 2004, Electricity Reform in Chile Lessons for Developing Countries, Center for Energy

and Environmental Policy Research, University of Cambridge

[6] Småskalig vattenkraft Projektering Konstruktion Drift, 2005, Småkraftverkens riksförbund,

Reklamtryckeriet i Köping AB

[7] Romero, R., 2009, How to determine the best way to develop a hydropower project in a net of

irrigation canals, BioBio North Irrigation System

[8] Guide on How to Develop a Small Hydropower Plant, 2004, European Small Hydropower

Association- ESHA

[9] Kristoferson L.A. & Bokladers U., 1991, Renewable energy technologies: their applications in

developing countries, Beijer institute

[10] Elstad, I. & Vinogg V., 2003, Mechanical Equipment, Hydropower Development Volume NO 12,

Norwegian University of Science and Technology

[11] A Guide to UK Mini Hydro Developments, British Hydro Association,

homepage; http://www.british-hydro.co.uk/infopage.asp?infoid=363 (2010-05-05)

[12] E. Holmén, 1984, Turbindimensionering

[13] RETScreen Software Online User Manual Small Hydro Project Model, 2004, Minister of Natural

Resources Canada

[14] Pettersson, B., Vattenfall Power Consultant- Hydropower, interviews and e-mail contact, Jan-

May 2010

[15] Mini power stations small hydropower 100-1500 kW, 1980, VAST Swedish Power Association

Development Section

[16] Ghidaoui, M., Zhao, M., Mclnnis, D. & Axworthy, D., 2005, A Review of Water Hammer Theory

and Practice, ASME

[17] Lundin, U., Hydraulics, turbine calculations, forces on blades, Lecture, Hydropower- Technique

and System at Uppsala University (2009-09-16)

50

[18] Jansson, M., Sales Manager Sweden, APS Norway AS, interviews and e-mail contact, March-April

2010

[19] Lundin, U., Turbine and Draft tube, Lecture, for Hydropower- Technique and System at Uppsala

University (2009-09-25)

[20] Santander, M., 2004, Reparación canal Quillaileo VIII Región, Gobierno de Chile

[21] Resultados de la última Encuesta Casen, Gobierno de Chile, 2006

homepage; http://www.mideplan.cl/casen/publicaciones/2006/Resultados_Energia_Casen_2006.pdf

[22] Cerra, C. Office manager in Santa Bárbara for Frontel, interview 2010-03-15

[23] Proyecto Central Hidroeléctrica Angostura, 2007, Reuniones Informativas de Proyecto, Colbún

[24] Luis Villaroe, Local Manager of Derivado 1 and 2 in the BioBio North Irrigation System, interviews

Feb-April 2010

[25] Consultría Reparación Canal Quillaileo VIII Región Tomo II Informe Final Anexos A al D, 2004,

Gobierno de Chile

[26] Santander, M. 2004, Consultoría Reparación canal Quillaileo VIII Región, Gobierno de Chile

[27] Santibañez, F. and Uribe, J.M, 1993, Atlas Agroclimático de Chile Regiones Sexta, Séptima,

Octava y Novena, Universidad de Chile

[28] Oanda, internet based forex trading and currency information,

homepage: www.oanda.com (2010-03-10)

[29] Oettinger, F. Project Engineer at Enerbosch in Temuco, Chile, interviews and e-mail contact

March 2010

[30] Kostnadsgrunnlag for små vannkraftanlegg opp til 10 000 kW, 2005, SWECO Grøner AS, Norges

vassdrags- og energidirektorat

[31] Traagstad, I.M. Administrator at the NVE library, e-mail contact March 2010

[32] Christer Abrahamsson, Managing Director and Head of Turbine Sales, Turab AB, interview and e-

mail contact Jan-April 2010

[33] Gobierno de Chile, Serio Precio Medio de Mercado Sistema Interconectado Central (PMM SIC),

hompage; http://www.cne.cl/cnewww/opencms/12_Utiles/ (2010-02-12)

[34] Tedgren, C., Vattenfall Power Consultant- Climate Department, e-mail contact (2010-03-15)

[35] Hydropower in Sweden, database of specifications of different hydropower plants,

homepage: http://www.kuhlins.com/sok.php (2010-03-06)

[36] Kniva Kraftstation, Falu Energi & Vatten,

homepage: http://www.fev.se/default.asp?id=2338&ptid= (2010-03-06)

51

[37] Castro, A., 2006, Minicentrales hidroeléctricas, Instituto para la Diversificación y Ahorra de la

Energía

[38] Videla, S., Economical consult at AMEC in Santiago, interviews and e-mail contact Feb-April 2010

52

9. Appendix

9.1 Difference in Energy Production due to Different Penstock Diameter

There is a difference in caused loss between different diameters of the penstock. The loss will reduce the gross head and thereby the energy production. The loss in production causes lost revenue which

can be calculated and compared with the extra investment of a larger diameter.

For the energy production of DN 1200 see Table 4.6. The energy production for a DN 1000 is stated in

Table 9.1, note that the difference lies in the losses i.e. the net head.

Difference in revenue then becomes

Difference in investment cost is 26 443 USD, see Table 4.2.

The payback time for the extra investment then becomes

Table 9.1 Energy production with a penstock diameter of 1000 millimeters

Flow, Q, [m3/s] 1.62 2.20 Days 182.5 44.3 Gross head, Hg, [m] 44.27 44.27 Losses, hf1+hf2, [m] 1.65 0.89 Net head, Hn, [m] 43.4 42.6 Turbine efficiency [%] 89.3 % 94 % Generator efficiency [%] 95 % 95 % Installed power [kW] 591 840 Parastistic losses [kW] 17 17 Power [kW] 585 796 Transformer efficiency [%] 99 % 99 % Net power [kW] 561 796 Brutto energy [kWh] 2 510 833 3 569 439

Loss due to maintenance etc 4.6 % [kWh] 229004 - Net energy delivered [kWh] 2279699 3488189

Annual sum delivered [MWh] 5 698

53

9.2 Francis versus Kaplan Economic Calculations

To economically compare Francis and Kaplan turbines their difference in efficiency is taken into

account to calculate the resulting energy productions. For the energy production of the Francis

turbine see Table 4.6. For all turbines a penstock with DN 1200 has been used. Note that the

difference lies in the turbine efficiency.

Table 9.2 Energy production for a single regulated Kaplan turbine

Flow, Q, [m3/s] 1.62 2.20 Days 182.5 44.3 Gross head, Hg, [m] 44.27 44.27 Losses, hf1+hf2, [m] 0.37 0.68 Net head, Hn, [m] 43.9 43.6 Turbine efficiency [%] 91 % 91 % Generator efficiency [%] 95 % 95 %

Installed power [kW] 602 813 Parastistic losses [kW] 17 17 Power [kW] 585 796 Transformer efficiency [%] 99 % 99 % Net power [kW] 579 788 Brutto energy [kWh] 2 536 454 3 453 168

Loss due to maintenance etc 4.6 % [kWh] 233493 -

Net energy delivered [kWh] 2302961 3453168

Annual sum delivered [MWh] 5 756

Table 9.3 Energy production for a double regulated Kaplan turbine

Flow, Q, [m3/s] 1.62 2.20 Days 182.5 44.3 Gross head, Hg, [m] 44.27 44.27 Losses, hf1+hf2, [m] 0.37 0.68 Net head, Hn, [m] 43.9 43.6 Turbine efficiency [%] 93 % 93 % Generator efficiency [%] 95 % 95 %

Installed power [kW] 615 813 Parastistic losses [kW] 17 17 Power [kW] 615 831 Transformer efficiency [%] 99 % 99 % Net power [kW] 598 814 Brutto energy [kWh] 2 593 820 3 530 682

Loss due to maintenance etc 4.6 % [kWh] 238774 - Net energy delivered [kWh] 2355046 3530682

Annual sum delivered [MWh] 5 886

According to Table 4.6 the Francis turbine produces 5 828 MWh annually i.e. the single regulated

would produce less and is abandon as an option. The double regulated would produce 57.6 MWh

more than the Francis.

54

Table 9.4 Economical comparison between Kaplan and Francis turbines

Amount higher production with a double reg. Kaplan [kWh] 57 601

Increased annually revenue with a double reg. Kaplan [USD] $4 378

Cost Francis turbine with rated power 840 kW [USD] [30] $422 204

Cost Kaplan turbine with rated power 840 kW [USD] [30] $707 215

Difference in cost [USD] $285 011

Payback time for a Kaplan [years] 65

A Kaplan turbine normally costs 30-50 % more than a Francis [10], with the calculations in Table 9.4

that figure is 40 % which corresponds.

9.3 Calculations of Turbine Dimensions

To start with the speed unit, n11, is calculated by equation (2.5) and set to 78.35.

The specific speed nqe is calculated by equation (2.2) to 0.278, with the specific speed the cavitation

limit can be read to be 0.2 in Figure 2.6.

The Suction head is calculated by equation (2.10) to 1.09 meters.

The unit flow, Q11, is calculated by equation (2.7) to 1.208.

The diameter can then be calculated by equation (2.6) to 0.525 meters.

By equation (2.4) the specific speed, n, is 985 rpm. Closest standardized speed is 1000 rpm. With the

value of 1000 rpm the diameter is recalculated by equation (2.6) and with the result of 0.52 meters.

The diameter is also calculated for the option of the rotational speed being 750 rpm and results in

the diameter of 0.69 meters.

The new diameter values gives the new unit flows of 1.24 and 0.70 which gives the new suction

heads 0.54 meter and 7 meters both positive.

9.4 Suggested Design Layout

The figure is missing in the electric edition for copyright reasons.

9.5 Head Loss Calculations

To calculate hf1 and hf2 the velocity in the tube is needed.

(9.1)

With the diameter 1.2 meter the velocities is calculated to be:

To calculate hf1 it is assumed that the intake grid has an inclination of α=60° to the horizontal, the

racks are made of stainless steel and is flat bars with a thickness of t=12 mm and located at a

distance b=70 mm from one another and that the total grid area is S=5 m2. The assumptions equity

was verified against [8]. Furthermore the penstock diameter is assumed to be evenly 1200 mm and

flow [m3/s] velocity in tube [m/s]

1.62 1.429

2.2 1.945

55

that there is an automatic cleaner for the trash rack, which gives K1=1. Those assumptions give the

possibility of calculating the velocity at the entrance:

(9.2)

flow [m3/s] velocity at entrance [m/s]

1.62 0.74

2.2 0.55

The losses ht, hf, hc and hb are then calculated by the methods in Chapter 2.8.4, their total is hf1.

Table 9.5 Calculation of losses

Flow [m3/s] 2.2 1.62 Head loss i trash rack

correction factor 2.25 equation (2.22) gives ht [m] 0.0060 0.0033

Head loss according to friction losses specific coefficient for Flowtite GPG 0.011 total length penstock [m] 170.29 equation (2.21) gives hf [m] 0.388 0.210

Head loss at inlet due to comparison diameter, penstock [m] 1.2 diameter, canal [m] 1.53 Kc 0.163 equation (2.23) gives hc [m] 0.0315 0.0170

Head loss due to bends first bend, 20°, k 0.133

equation (2.25) gives, hb1 [m] 0.0257 0.0139 second bend, 25°, k 0.166

equation (2.25) gives hb2 [m] 0.0320 0.0173

Total head loss hf1 [m] 0.483 0.261

hf2 is calculated by equation (2.26):

Flow [m3/s] 2.2 1.62

hf2 [m] 0.193 0.104

Total head loss is then:

Flow [m3/s] 2.2 1.618

hf1 0.483 0.261

hf2 0.193 0.104

Total 0.676 0.365

% of gross head 1.5 % 0.8 %