JUHO REKOLA ADVANTAGES OF VARIABLE SPEED DRIVE IN PUMP APPLICATIONS MASTER OF SCIENCE THESIS

Examiner: Professor Teuvo Suntio Examiner and topic approved in the Computing and Electrical Engineering Faculty Council Meeting on 09 September 2014

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ABSTRACT Juho Rekola: Advantages of variable speed drive in pump applications Tampere University of Technology Master of Science Thesis, 62 pages, 2 Appendix pages September 2015 Master’s Degree Programme in Electrical Engineering Major: Power Electronic Electric Drives Examiner: Professor Teuvo Suntio Keywords: frequency converter, variable speed drive, centrifugal pump, energy saving, payback time The thesis is studying centrifugal pump’s variable speed drive’s advantages in Alfa Laval Aalborg’s steam boiler applications. Thesis consists of two main parts. First part examines requirements set for variable frequency drives in standards, regulations and classification societies’ rules. This part can be divided into two parts, requirements for industrial applications and requirements for use in marine applications. Second main part of the thesis is to compare different pump system configurations for Alfa Laval Aalborg’s steam system’s feed water pumping system. This part consists of investment cost analysis for different pump system configurations and from operational cost calculations for these pumping systems. Investment cost analysis includes procurement costs of parts needed in the pumping systems and pump unit assembly costs. Operational cost analysis studies pump systems’ energy consumption and costs derived from the energy consumption. These two parts combined together form cost analysis for the system. Cost analysis is done for two different types of steam generation systems. First analysis is done for diesel power plant’s waste heat recovery system and second analysis is carried out for ship’s steam production system. The analyses are carried out separately because systems’ operation profiles are different and therefore operational cost analysis needs to be carried out separately. Cost analysis show how cost effective variable speed drive can be in this applications. Operational cost calculations are done according centrifugal pump theory. This theory is introduced in the thesis and is been used to explain why variable speed drive in centrifugal pump application is able to save significant amounts of energy compared to direct drive application.

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TIIVISTELMÄ Juho Rekola: Muuttuvanopeuksisen käytön etuja pumppusovelluksissa Tampereen teknillinen yliopisto Diplomityö, 62 sivua, 2 liitesivu Syyskuu 2015 Sähkötekniikan diplomi-insinöörin tutkinto-ohjelma Pääaine: Tehoelektroniikan Sähkökäytöt Tarkastaja: professori Teuvo Suntio Avainsanat: taajuusmuuttaja, muuttuvanopeuksinen käyttö, keskipakopumppu, energian säästö, takaisinmaksuaika

Työssä tutkitaan pumppujen muuttuvanopeuksisten sähkökäyttöjen hyötyjä Alfa Laval Aalborgin höyrykattilajärjestelmässä. Työ koostuu kahdesta osiosta. Ensimmäinen osa tutkii stantandardien, sääntöjen ja luokituslaitosten esittämiä vaatimuksia taajuusmuuttajille Alfa Laval Aalborgin valtmistamien laitteiden käyttöympäristöihin ja sovelluksiin. Määritystarkastelu voidaan jakaa teollisuus- ja laivasovelluksiin asetettuihin vaatimuksiin, stantardeihin ja sääntöihin. Toisessa osiossa tutkitaan Alfa Laval Aalborgin höyryjärjestelmän syöttövesipumppujärjestelmän erilaisia kokoonpanoja ja verrataan niiden hintarakennetta toisiinsa. Erilaisille pumppujärjestemille tehdään hinta analyysi. Tämä koostuu pumppukoneikkojen komponenttien investointikustannusten vertailusta ja kyseisten pumppukoneikkojen käytönaikaisesta energiakulutuksesta. Energian kulutuksen pohjalta eri pumppausjärjestelmien kätökustannuksia on mahdollista tutkia. Investointikustannusten tutkinta ja käyttökustannusten laskenta yhdistettynä muodostaa pumppausjärjestelmille hinta-analyysin, jonka avulla pumppausjärjestelille voidaan määrittää takaisinmaksu ajat. Analysoimalla takaisinmaksuaikoja voidaan tutkia muuttuvanopeuksisten pumpppukäyttöjen hintatehokkuutta verrattuna kiinteänopeuksisiin käyttöihin. Analyysi suoritetaan sekä voimalaitosten yhteyteen rakennettaviin hukkalämmön talteenottojärjestelmiin että laivoihin rakennettaviin höyryjärjestelmiin. Tarkastelut suoritetaan erikseen niiden erilaisen ajofilosofian vuoksi, jonka tähden näiden ajoprofiilit eroavat toisistaan. Käyttökustannusten pohjana olleet energiankulutuslaskenta on toteutettu keskipakopumppujen teorian mukaisesti. Tätä teoriaa on käyty läpi työssä ja tämän yhteydessä on esitetty teoreettiset perusteet miksi muuttuvanopeuksisella pumppukäytöllä voidaan säästää merkittävät määrät energiaa.

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FOREWORD This thesis has been done in company Alfa Laval Aalborg as a part of company’s product development process. I would like to thank the company management for the opportunity to do my thesis for the company. I would like to thank my colleagues in Alfa Laval Aalborg for guidance in the process leading up to this final version of the thesis. Gratitude goes towards my colleague Mr. Janne Kallioniemi for giving me time to finish my thesis by covering me on my daily work tasks. Especially I would like to thank Mr. Pasi Aaltonen for the technical and theoretical insight for the application studied, also thank you Mr. Taneli Ruohola for having the patience to answer my countless questions regarding the topic and interrupting your own work. Our suppliers have taken time to answer my questions and support requests and I would like them as well for enabling me to this study at this extent, it would not have been possible without you.

Rauma 29th of September 2015

Juho Rekola

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TABLE OF CONTENTS 1. 2.

INTRODUCTION .................................................................................................... 1 REQUIREMENTS FOR FREQUENCY CONVERTERS ....................................... 3 2.1 Ambient conditions ........................................................................................ 3 2.1.1 Temperature ..................................................................................... 3 2.1.2 Vibration .......................................................................................... 4 2.1.3 Exposure to elements ....................................................................... 5 2.1.4 Regulations....................................................................................... 6 2.1.5 Device comparison against demands ............................................... 7 3. SPECIAL REQUIREMENTS FOR INSTALLATIONS IN VFD SYSTEMS ........ 9 3.1 Human and machine safety ............................................................................ 9 3.2 EMC ............................................................................................................. 10 4. THEORY OF FLUID TRANSFER ........................................................................ 12 4.1 Pump theory ................................................................................................. 12 4.2 Pump Characteristics .................................................................................... 13 4.3 Control Principles......................................................................................... 15 4.3.1 Flow resistance manipulation......................................................... 15 4.3.2 Changing static head ...................................................................... 16 4.3.3 Variable speed drive....................................................................... 16 4.3.4 Parallel pumps ................................................................................ 17 4.3.5 Bypass control ................................................................................ 18 5. ENERGY SAVING POTENTIAL WITH DIFFERENT CONTROL METHODS19 5.1 Throttling control ......................................................................................... 19 5.2 Variable speed control .................................................................................. 20 5.3 Parallel pumps .............................................................................................. 20 5.4 By-pass control ............................................................................................. 21 6. COST ANALYSIS FOR DIFFERENT PUMP SYSTEM CONFIGURATIONS FOR INDUSTRIAL APPLICATION ............................................................................. 22 Common pump unit...................................................................................... 22 Common multi pump unit ............................................................................ 23 Boiler specific pump system ........................................................................ 24 6.1 Assembly & Procurement ............................................................................ 25 6.1.1 Common pump............................................................................... 25 6.1.2 Common multi pump set up ........................................................... 26 6.1.3 Boiler specific pump ...................................................................... 27 6.1.4 Comparison between assembly and procurement prices ............... 28 6.2 Operation ...................................................................................................... 28 6.2.1 Common pump............................................................................... 30 6.2.2 Common multi pump unit .............................................................. 31 6.2.3 Boiler specific pump ...................................................................... 32

v 6.2.4 Summary of operation costs ........................................................... 33 6.3 Total cost calculations and determine payback time .................................... 35 7. COST ANALYSIS FOR PUMP SYSTEM CONFIGURATIONS IN MARINE APPLICATION .............................................................................................................. 37 Common pump unit...................................................................................... 38 Boiler specific pump unit ............................................................................. 38 7.1 Assembly & Procurement ............................................................................ 39 7.1.1 Common pump............................................................................... 39 7.1.2 Boiler specific pump ...................................................................... 41 7.1.3 Comparison between pump units’ assembly and procurement prices 42 7.2 Operation ...................................................................................................... 42 7.2.1 Common pump............................................................................... 43 7.2.2 Boiler specific pump ...................................................................... 44 7.2.3 Summary of operation costs ........................................................... 46 7.3 Total cost calculations and determine payback time .................................... 47 8. CONCLUSION ....................................................................................................... 49 BIBLIOGRAPHY ........................................................................................................... 51 APPENDIX A ................................................................................................................. 53 APPENDIX B ................................................................................................................. 54

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LIST OF FIGURES Figure 1. 360° grounding done with EMC cable gland (ABB, 2011). ......................... 10 11 Figure 2. 360° grounding done with conductive sleeve (ABB, 2011). ......................... 11 Figure 3. Centrifugal pump characteristic curve (KSB, 2005). ................................... 13 Figure 4. Centrifugal pump system configurations with positive inlet pressure (KSB, 2005). ................................................................................................. 14 Figure 5. System head characteristic curve. Curve illustrates the systems head 𝐻𝑠𝑦𝑠 as a function of flow rate Q (KSB, 2005). .......................................... 15 Figure 6. Flow control with throttling valve (KSB, 2005). .......................................... 16 Figure 7. Flow control with variable pump rotation speeds (KSB, 2005). .................. 17 Figure 8. Flow control with parallel pumps (KSB, 2005). .......................................... 17 Figure 9. Flow control using bypass valve (KSB, 2005). ............................................ 18 Figure 10. Throttling control’s H-Q-diagram and power needed to run the pump at different operation points (KSB, 2005). ................................................... 19 Figure 11. Pumps different H-Q-curves and required power to run the pump showed as a function of flow rate (KSB, 2005). ........................................... 20 Figure 12. Parallel pump configurations H-Q-curve (KSB, 2005). .............................. 21 Figure 13. Bypass controls H-Q-diagram and required power to run the pumps as a function of flow rate (KSB, 2005). ........................................................ 21 Figure 14. Process & Instrument diagram of feed water common pump unit system. .......................................................................................................... 23 Figure 15. Process & Instrument diagram of common feed water multi pump unit system. .......................................................................................................... 24 Figure 16. Process & Instrument diagram of boiler specific feed water pump unit system. .......................................................................................................... 24 Figure 17. Common pump units consumed energy in Megawatt hours per year for direct and variable frequency fed units ........................................................ 30 Figure 18. Common multi pump units consumed energy in Megawatt hours per year for direct and variable frequency fed units. Direct and variable frequency driven common pump units’ energy consumption for reference. ...................................................................................................... 31 Figure 19. Boiler specific pump units consumed energy in Megawatt hours per year. Variable frequency fed common pump units energy consumption for reference. ................................................................................................ 33 Figure 20. Principle of marine application’s steam system. ......................................... 37 Figure 21. Marine application’s common pump unit process & instrument diagram. ....................................................................................................... 38 Figure 22. Process and instrument diagram for marine application’s Boiler specific pump unit......................................................................................... 39

vii Figure 23. Direct and variable frequency driven common feed water pump systems energy consumption in megawatt hours in a year in marine application.................................................................................................... 44 Figure 24. Boiler specific pump units’ individual and combiner energy consumption in megawatt hours in a year compared against direct driven common pump unit’s energy consumption. ....................................... 46

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LIST OF TABLES Table 1.

Table 2.

Table 3. Table 4. Table 5. Table 6. Table 7. Table 8. Table 9. Table 10. Table 11.

Table 12. Table 13. Table 14. Table 15. Table 16. Table 17. Table 18. Table 19. Table 20.

Ambient temperatures according classification societies’ rules (DNV, 2013;Lloyd’s Register, 2013; Russian Maritime Register of Shipping, 2014; Russian River Register, 2009). ........................................... 4 Allowed vibration levels in machinery space onboard ships (DNV, 2013;Lloyd’s Register, 2013; Russian Maritime Register of Shipping, 2014; Russian River Register, 2009). ........................................... 4 IP-classifications coding explained according to standard IEC-60529 (IEC, 1999; RS Components Pty ltd, 2015) ................................................... 6 Frequency converters ambient conditions according manufacturers’ manuals (ABB, 2015; Vacon 2015; Siemens 2015; Schneider2015). ............ 8 Common pump systems devices for direct fed Engines. ............................... 25 Common pump system devices variable frequency fed Engines. ................. 26 Devices for boiler specific feed water pump. ............................................... 27 Comparison between different feed water pump system configurations. ..... 28 Diesel engine power plant load curves. ....................................................... 29 Operational cost differences for different pump system configurations compared to Direct driven common pump system. ...................................... 34 Payback times in years for different feed water pump systems compared to direct driven Common Pump unit in different Cases and engine loads.................................................................................................. 35 Marine applications engine room’s variable frequency fed common pumps unit’s devices..................................................................................... 40 Marine applications engine room’s variable frequency fed common pumps unit’s devices..................................................................................... 40 Marine applications boiler specific pump systems devices. ......................... 41 Different feed water pump unit prices for marine application. ................... 42 Boiler steam production capacity in ferry and cruise vessel operations for common pump unit.................................................................................. 43 Auxiliary Boiler’s load curve in ferry and cruise vessel operations. ........... 45 Exhaust gas boiler’s load curve in ferry and cruise vessel operations. ....... 45 Operation costs for a year for boiler feed water pumps in ferry and cruise vessel operations for different pump systems. ................................... 47 Payback times for the upgrade investment for the pumping systems for marine application. ...................................................................................... 48

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ABBREVATIONS AND MARKINGS EMC IP THD VFD NPSH 𝐻𝑔𝑒𝑜 𝐻𝐿 𝐻𝑠𝑦𝑠 𝑔 𝜉

= = = = = = = = = =

Electromagnetic Compatibility Ingress Protection Total Harmonic Distortion Variable Frequency Drive Net Total Suction Head Geodetic head Head Loss System head Gravitational Velocity Presure loss coefficient

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1. INTRODUCTION

This master’s thesis addresses on advantages of variable frequency drive in centrifugal pump applications. Thesis is done for waste heat recovery system designed for diesel power plant’s overall efficiency improvement supplied Alfa Laval Aalborg Oy. The thesis has two different focus points. The first one studies different rules, regulations and standards regarding frequency converter use in industrial or marine applications. In rules and regulation different maritime classification societies’ rules for ships are studied in order to determine requirements for variable frequency drive system for boiler feed water pumping system. Also ambient conditions are taken into consideration. The second focus point is to determine investment costs for different feed water pumping system configurations. Feed water pumps are used for feeding water into steam boilers which are developing steam for steam turbine. Three different pumping systems configurations are compared against each other on investment costs and operational costs. Analysis is widened by applying variable frequency drive into the pump systems. Variable frequency drive enables new control methods and therefore possibilities for energy saving during operation. Improvement of energy efficiency by using variable frequency drive is well proven concept in many applications and a lot of research is done in this field of study so there is no shortage for base knowledge for this study. The purpose of this study is to take a closer look on the companies system and determine system characteristics in order to be able to calculate energy saving potential for different pump system configurations. Cost calculations are done to two different steam system applications. First application is steam boilers installed into diesel engine power plant to harvest waste heat from diesel’s exhaust gases. The other application is steam generation system to be installed into a ship. This system consists of oil or gas fuelled auxiliary boiler and from exhaust gas boilers harvesting waste heat from ship’s main engines’ exhaust gases. The goal of the analysis is to be able to determine payback times for different pump systems configurations in these two applications so that decision between different pump system to be used can be done based on facts rather than what has been done before. In chapter two requirements set by the application related rules and regulations and ambient conditions for the frequency converters are studied. These requirements are listed and compared against few devices that were initially meant to use in these applications. Third chapter introduces special requirements for electrical installations including frequency converters. Especially electromagnetic compatibility is addressed. After this focus is moved to second part of the thesis feed water pump analysis. Fourth chapter introduces theory of fluid handling. Centrifugal pump’s theory is explained with equa-

2 tions and with pumps performance curves which are essential part of pump dimensioning process. Also system characteristic curve is introduced. After knowledge of different characteristic for pump and system curve is established different forms of controlling the water flow in the system are introduced. Every control system has different effect on pumps energy consumption. That is why next part explains energy saving potential for different control methods. In chapter 6 cost analysis for power plant applications steam generation systems feed water pumping is carried out. In the beginning different pump systems are introduced with process and instrument diagram as well as with written explanations. After different pump systems are familiar procurement and assembly cost for these pumping systems are determined. Operational costs are calculated for the different pump systems before pay back times can be calculated for these systems. After establishing payback times analysis is done for the pay back times to establish understanding which pump units are feasible to use. Chapter seven does the same analysis for ship’s steam system’s feed water pumping configurations as was done in chapter six for power plant application. Chapter eight concludes the findings done in the thesis and answers the questions asked in this introduction.

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2. REQUIREMENTS VERTERS

FOR

FREQUENCY

CON-

Requirements for frequency converters in the company’s applications are studied in the following paragraphs. First ambient condition in which converters are installed are studied, then rules and regulations of different classification societies and standards regarding semiconductor devices are studied.

2.1

Ambient conditions

Frequency converters are suspected to harsh ambient conditions and therefore those conditions need to be studied to be able to choose correct frequency converter for the system. Different elements of ambient conditions are considered in following paragraphs.

2.1.1 Temperature Systems are usually built in countries which have tropical conditions for example Philippines. Systems are planned usually with assumption of ambient temperature of 40 °C. This is the ambient temperature outside the temperature inside auxiliary container is higher because it is only ventilated not cooled and therefore equipment installed inside the container needs to be able to withstand approximately 45-50 °C temperatures. This includes frequency converters because electrical control cabinet and pumps are installed inside the container and converters will be installed there as well. In marine applications ambient temperature in engine rooms are stated to be maximum 45 °C according classification societies’ rules (DNV 2013). The rules also state that if equipment is assumed to suffer sudden failure if critical temperature is exceeded the temperature shouldn’t be less than 10 °C above the mentioned 40 °C. In other words stated maximum ambient temperature for equipment used in the marine application should be at least 55 °C. Different classification societies’ temperature limits for machinery spaces are shown in Table 1.

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Table 1. Ambient temperatures according classification societies’ rules (DNV, 2013;Lloyd’s Register, 2013; Russian Maritime Register of Shipping, 2014; Russian River Register, 2009). Classification Society Det Norske Veritas GL

Temperature[°C] 0-+55

Lloyd’s Register

0-+45

Russian Maritime Register of Shipping

0-+45

Russian River Register

-10-+40

Temperatures in Table 1 are really close to each other. When choosing equipment based on classification societies’ rules it is the best to choose the strictest ambient temperature so you are able to use the same equipment in all projects regardless the classification society used in the project. When using this philosophy it is best to use Det Norske Veritas GL as a bench marker for temperature withstanding for the equipment because it has the highest grading for ambient temperature.

2.1.2 Vibration Marine applications bring vibration withstanding in to the picture. Steam systems and its components are installed to engine rooms of ships and vibration is constantly present in this kind of environment. Vibration levels are stated in Classification societies’ rules. The vibrations levels that equipment need to withstand are shown in Table 2. Table 2. Allowed vibration levels in machinery space onboard ships (DNV, 2013;Lloyd’s Register, 2013; Russian Maritime Register of Shipping, 2014; Russian River Register, 2009). Classification Society

Det Norske Veritas & GL Lloyd’s Register

Russian Maritime Register of Shipping Russian River Register

Frequency [Hz]

Velocity plitude [mm/s]

Am- Amplitude [mm]

5-50

20

N/A

N/A

N/A

N/A

2-80

N/A

±1

5-30

N/A

±1

5 Lloyd’s Register doesn’t state any specific vibration level for electrical equipment to withstand. Also three other classification societies have different methods for describing the levels of vibration. Because of this it is difficult to compare them to each other and define one value with which to choose equipment. When choosing equipment different regulations need to be compared with equipment’s features separately and try to find equipment that fulfills all the regulations so the same equipment could be used in all projects.

2.1.3 Exposure to elements When installing equipment outside of closed enclosures as frequency converters in company’s applications are usually installed they are directly exposed to elements and need to be able withstand in that environment for their whole working life. This gives requirements for the IP-classification for the converter so it is protected from the elements. Dust and other impurities in air can be very common in site locations near deserts and in power plants located near cement factories. Equipment needs to be protected from these impurities because they can cover the cooling surfaces of components and therefore cause overheating and equipment malfunctions or breakdowns. This can be achieved with filtration of cooling air. Filters need to be monitored for filter blockage in order to prevent overheating. Second element from which the equipment needs to be protected is water. Rain water shouldn’t be a cause of damage done by water because equipment is installed in a manner that it is protected from rain. System that the equipment is running opposes the threat of water entering the equipment. Frequency converters are used to run water pumps and the pressurized water in case of leakage in the pipes could enter the device. Because of this the equipment needs to be installed in a way that the leakage water shouldn’t enter the equipment and secondly the equipment itself should have high enough protection against water entering the device. Taking in consideration the requirements set by conditions stated in the previous paragraphs the IP-classification should at least IP54 (IEC, 1999). This can be seen from Table 3 in which the IP-classification’s coding is explained.

6 Table 3.

IP-classifications coding explained according to standard IEC-60529 (IEC, 1999; RS Components Pty ltd, 2015)

. As seen in Table 3 first number in IP-classification states the solid particle protection level of the enclosure. Level 5 is protected from dust so it is considered as sufficient level of protection against dusty environments. Second number indicates the liquid ingress protection level. In this category the level 4 device is protected from splashing water, this is sufficient level of protection because possibly leaking water is usually dripping from pipes and supporting frames not spraying.

2.1.4 Regulations Several standards and classification rules give regulations for the frequency converters and for their use in industrial and marine application. Most of these standards concern converters electrical “ambient climate” and converters withstanding of that climate and its impact on that climate. Two most important aspects the regulations are regarding are electromagnetic compatibility (EMC) and Total Harmonic Distortion (THD).

7 All of the classification societies don’t have regulations on regarding electromagnetic compatibility. Det Norske Veritas GL has stated that IEC standards IEC-60533, IEC6100-6-2 and IEC-6100-6-4 are used as benchmark on assuring electromagnetic compatibility (DNV, 2013). Russian Maritime Register of Shipping has stated specific characteristics that equipment need to fulfill in order to comply with the rules(Russian Maritime Register of Shipping, 2014). These characteristics comply with standards that were stated in Det Norske Veritas GL rules so it is sufficient to evaluates equipment’s suitability for the application. Lloyd’s Register and Russian River Register don’t have any regulations regarding electromagnetic compatibility so it is assumed that standards stated in Det Norske Veritas GL rules are can be used in these cases as well and the equipment can be used in these applications as well. THD Total Harmonic Distortion level is limited in standards and classification societies’ rules. Russian maritime register of Shipping has the highest stated THD level, 10% (Russian Maritime Register of Shipping, 2014), Det Norske Veritas GL and Lloyd’s Register have the same allower THD level, 8%. Det Norske Veritas GL also states that THD level needs to comply with standard IEC-6100-2-4 for Class 2 in which any single order harmonic isn’t allowed to be more than 5% of fundamental supply voltage (DNV, 2013; Lloyd’s Register, 2013).

2.1.5 Device comparison against demands Next four different manufacturers’ frequency converters will be compared against demands for the devices. The devices used for the comparison are ABB ACS880, Vacon 100 Flow, Siemens G120 and Schneider ATV600.These four frequency converters were chosen to be compared against each other by retailer recommendations and by customer specification of certain devices to be used in their systems.

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Table 4.

Frequency converters ambient conditions according manufacturers’ manuals (ABB, 2015; Vacon 2015; Siemens 2015; Schneider2015).

Device Temperature

IP

Vibration

EN 618003:2004

ABB ACS880

Vacon 100 Flow Siemens G120

Schneider ATV600

EMC

Marine Approvals DNV GL, Bureau Veritas, Lloyd’s Register

-15-55 ºC

55

IEC 60068-2

-10-50 ºC

54

EN/IEC 60068-2-6

EN/IEC 61800-3

0-60 ºC

55

EN 60721-33

EN 618003

-

0-50 ºC

54

N/A

EN 618003

-

-

Only ABB ACS880 has Marine Approvals from various classification societies. This means that only ABB is able to be used in marine applications from these frequency converters. The Marine Approval is a confirmation from classification society that the device fulfils the requirements specified for the specific equipment. When used in the industrial applications all four devices can withstand the maximum ambient temperatures defined in the customers’ requests for quotations. Also higher ingress of protection is available for all frequency converters and enables installations in harsh environments. In industrial application vibrations do not have that much significance as in marine applications as the installation surfaces are stable. EMC issues have been increasing problem in industrial environments. Devices are all built according to standard IEC 31800-3 and therefore give good platform for building a electromagnetically compliant system but installation of the devices still need to be done properly. EMC matters to take into account during installations are addresses in the following paragraph.

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3. SPECIAL REQUIREMENTS FOR INSTALLATIONS IN VFD SYSTEMS

Use of frequency converters in application arise new aspects that need to be taken into consideration when doing the electrical design for the variable speed application. Three different aspects are studied in the following paragraphs, practice has shown that these aspects need to be addressed if the system is going to operate as planned and also function its whole designed life time (Sähköala, 2014).

3.1

Human and machine safety

Standards and classification rules have regulations regarding human and machine safety. Purpose of these regulations is to ensure safe operation and maintenance of the machinery. In this paragraph safety of machinery standard, SFS-EN 60204-1, is studied from perspective of company’s application. Also classification societies’ rules regarding human and machine safety are studied. First thing machinery safety standard requires is supply isolation device. Machines supply has to be able to be disconnected in reliable manner and also be lockable for ensuring safe working environment during maintenance (SFS, 2010). Also location of the isolation device needs to be easily accessible and the device needs to be clearly marked for positive identification according to machine safety standard. Machinery safety standard requires machinery protection in many levels, such as overcurrent protection and overload protection (SFS, 2010). These protections are integrated into the frequency converter and don’t need special arrangements to be implemented. Machinery safety standard also suggests over temperature protection for Engines that are installed in places where cooling can be impaired (SFS, 2010). This can happen in dusty environments, in which company’s machines are suspected to operate. For electric Engines protection can be arranged by thermistors installed inside Engines windings and by monitoring the temperature. For frequency converters the overheating protections is integrated in the control system of the drive. Protecting machinery from damages due to low voltage is also stated in the standard. Machinery that may be damaged by low voltage or which’s normal operation may be affected by low voltage need to be protected from low voltage. Automatic restart of the machinery needs to be prevented after stoppage because of low voltage protection (SFS, 2010).

10 Det Norske Veritas GL requires by-pass arrangement for essential consumers that are fed by frequency converters. Consumer is kept essential if malfunction of the equipment endangers the normal operation of the ship (DNV, 2013). By-pass arrangement consists of a manually operated device by which supply to the consumer is secured if converter is not in working order. By-pass switch doesn’t have to be installed if redundant device for essential consumer is installed. For example if there are two feed water pumps for steam boiler, which are regarded as essential equipment, no by-pass arrangement is needed because second pump can be used to operate the boiler if other pups converter breaks up and the broken converter be replaced without secondary supply for the first pump.

3.2

EMC

Achieving electromagnetic compatibility requires special attention during designing and installation of the system. Cabling is in major role on fulfilling EMC regulations. Frequency converter Engine’s cable becomes a transmitter of high frequency interference if unshielded cable is used (Dolderer, P., et al.). Solution for preventing cables become transmitters is use of screened power cables between Converter and Engine. The shielding needs to be grounded from both ends of the cable and the grounding needs to be done in a manner that maximizes the conductive surface in order to minimize the contact impedance (Novák, J. et al., 2008). Grounding method called 360° grounding is used to maximize the conductive surface of grounding connection. Two different styles of implementation of 360° grounding is showed in Figure 1and Figure 2.

Figure 1. 360° grounding done with EMC cable gland (ABB, 2011).

11 Figure 1 demonstrates how 360° grounding can be achieved by using EMC cable gland. Cable gland has compression seal inside it which makes the connection between the conductive shield of the cable and the gland and onwards with enclosures conductive parts. Dashed line in the figure represents the faraday cage formed by the cables shielding, EMC cable gland and the enclosure. This faradays cage confines the high frequency interferences inside the cable and the enclosure so it doesn’t cause harmful interference to the surroundings (ABB, 2011). In Figure 2 continuity of the faraday’s cage is ensured with conductive sleeve which is tightened around the conductive shield of the cable, dashed line in this figure shows the forming of the faraday’s cage. In order to keep the faradays cage uniform all the auxiliary equipment’s enclosures need to be compliant with 360° grounding and the enclosure itself needs to be EMC compliant. Also Engine’s junction box needs to be compliant with 360° grounding to make the whole installation compliant with EMC regulations (ABB, 2011).

Figure 2. 360° grounding done with conductive sleeve (ABB, 2011).

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4. THEORY OF FLUID TRANSFER

Centrifugal pump theory has significant importance when considering energy saving potential of variable speed drive control for flow control. The theory shows how power absorbed by the pump is relative to the operation point of the pump. Theory behind different control principles is also studied in order to find out pros and cons for these methods.

4.1

Pump theory

Centrifugal pump theory is based on so called Affinity Laws (KSB, 2005). These laws state the relativity of pumps operational point on its rotational speed. Different characteristics of the pump are either directly proportional, proportional to square or proportional to cube to the rotational speed as demonstrated in equations 1, 2 and 3. 𝑄1 𝑄2

𝑛

𝑑

= 𝑛1 = 𝑑1 , 2

(1)

2

in which Q is flow rate, n is rotational speed and d is impeller dimension. 𝑑𝑝1 𝑑𝑝2

2

𝑛

2

𝑑

= (𝑛1 ) = (𝑑1 ) , 2

2

(2)

in which dp is either head or pressure created by the pump. 𝑃1 𝑃2

𝑛

3

𝑑

3

= (𝑛1 ) = (𝑑1 ) , 2

2

(3)

in which P is power needed by the pump. Power needed to run the pump in different operational points can be calculated as shown in equation 4. 𝑃=

𝜌𝑔𝑄𝐻 𝜂

,

(4)

where 𝜌 is density of the fluid, g is gravitational constant, H is pump head and 𝜂 is operating efficiency of the pump or pump and motor combined.

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4.2

Pump Characteristics

Pumps performance is presented by characteristic curve. Curve normally states pump discharge head as a function of water flow. Discharge head is stated in meters and water flow in cubic meters in an hour. Figure 3 is an example of pump’s characteristic curve. Highest chart is used for choosing the pump and two lower charts are used in the system design. Middle chart shows the net positive suction head, NPSH. Lowest chart illustrates power consumption of the pump in different function points. Different curves in the chart have different size impeller wheels in the pump which has an effect on the pumps head, pumping volume and power consumption as show in the equations 1, 2 and 3.

Figure 3. Centrifugal pump characteristic curve (KSB, 2005). Counterpart for the pump curve is so called system curve. System curve is unique to all systems as every system has different statistics. A principle system curve is shown in Figure 5. The figure shows the parts that the curve consists of. Base point of the curve is defined by the static component of the curve. Static component consists of two different

14 parts. First part is 𝐻𝑔𝑒𝑜 , which is the height difference between fluid surface in suction vessel and the pipelines discharge point. Second part is pressure head difference 𝑝𝑎 −𝑝𝑒 𝜚∗𝑔

.

(5)

In which 𝑝𝑎 is pressure in discharge vessel and 𝑝𝑒 is pressure in suction vessel (KSB, 2005). Pressure head difference states pressure difference between suction and discharge vessels in meters of head so it is comparable with other factors contributing to system curve. Curve slope and characteristics are defined by the dynamic component of the system curve. Dynamic component also consist of two parts. First one is head loss, 𝐻𝐿 . Head loss increases as the square of the flow rate Q. Head loss for the system is calculated as a sum of head losses for different parts of the piping system. Head loss is caused by friction within the fluid and between the fluid and piping. Second part is velocity head difference 𝑣𝑎2 −𝑣𝑒2 2𝑔

,

(6)

in which 𝑣𝑎 is discharge velocity of the fluid and 𝑣𝑒 is suction velocity of the fluid. In velocity head difference change in fluid flow velocity is converted into head difference. Velocity heads 𝑣𝑎 and 𝑣𝑒 are negligible when vessels A, C, D and E, shown in Figure 4, are been used in the application. Application studied in this paper is configured with vessels with similar characteristics as vessels C and E in Figure 4 (KSB, 2005).

Figure 4. Centrifugal pump system configurations with positive inlet pressure (KSB, 2005).

15 Example of a system curve is shown in Figure 5. It shows how the curve is composed of two components, static and dynamic, introduced earlier. System curve illustrates clearly how head loss, 𝐻𝐿 , and therefore system head, 𝐻𝑠𝑦𝑠 , increases proportionally to square relative to flow rate Q.

Figure 5. System head characteristic curve. Curve illustrates the systems head 𝐻𝑠𝑦𝑠 as a function of flow rate Q (KSB, 2005).

4.3

Control Principles

Pump’s operation point is at the point where system curve 𝐻𝑠𝑦𝑠 intersects with pump characteristic H-Q-curve. Operation point is normally needed to adjust according to applications current state. Operation point control can be done with multiple methods. In order to change the operation point the pump’s characteristic H-Q-curve or system head 𝐻𝑠𝑦𝑠 needs to be changed. System’s characteristic curve can only be changed during operation by changing the flow resistance or changing the static head component. Changes to pump’s characteristic H-Q-curve can be done by changing the speed of rotation and/or starting or stopping pumps operated in series or parallel (KSB, 2005). These four flow control methods are introduces in the following sub paragraphs.

4.3.1 Flow resistance manipulation Flow resistance manipulation is usually done with throttling valve. Throttling valve is used to increase the flow resistance and move the operation point to the left in the H-Qcurve (KSB, 2005). Shift of the system curve by use of a throttling valve is shown in figure 6. It can be seen that steepness of the curve increases when valve is closed fur-

16 ther. Surplus head is the head loss over the throttling valve needed to restrain the flow to the wanted level.

Figure 6. Flow control with throttling valve (KSB, 2005).

4.3.2 Changing static head System curve 𝐻𝑠𝑦𝑠 can be manipulated by changing the system’s statics head. Static head can be changed by altering the suction vessels static pressure or by changing the water level in the tank. Two different static heads can be seen in Figure 7. If static pressure is high the suction vessel’s pressure is smaller than discharge vessel’s pressure and/or discharge vessel’s liquid level is on greater geological height than suction vessel’s. So by increasing suction vessels pressure or geological height the static component of the system curve can be decreased if discharge vessel’s pressure and level are kept constant. This allows greater flow rate to be pumped with same system characteristics than before.

4.3.3 Variable speed drive Pumps developed head, flow rate and therefore needed power can be changed according to affinity laws stated in equations 1, 2 and 3. By calculating new H-Q-curves for different rotational speeds for the pump can a family of curves be determined. An example of family of H-Q-curves for a pump is shown in Figure 7. From the figure it can be seen that different flow rates can be achieved by changing the rotational speed.

17

Figure 7. Flow control with variable pump rotation speeds (KSB, 2005).

4.3.4 Parallel pumps Flow rate in pipeline can be altered by using two or more pumps which are in parallel connection. Pump group’s flow rate can be changed by deciding how many pumps are used simultaneously. Difference in flow rate if one or two pumps are used can be seen from Figure 8. Characteristics of the system curve dictate that even if the parallel pumps are identical the flow rate does not double because head loss 𝐻𝐿 increases compared to square of flow rate. During parallel pump operation with identical pumps the flow rate is evenly distributed between pumps. These characteristics can be seen in also Figure 8, which illustrates parallel pump operation with pumps’ H-Q-curves and system curve.

Figure 8. Flow control with parallel pumps (KSB, 2005).

18

4.3.5 Bypass control In by pass control the flow through pumps is not controlled. The flow to the system is adjusted to the desired level by bypassing excess flow back to the suction vessel. Figure 9 illustrates principle system for by pass control and an example system curve how flow to the system is controlled by bypass (KSB, 2005). Instead of increasing the backpressure of the system excessive flow rate is lead back to the suction vessel.

Figure 9. Flow control using bypass valve (KSB, 2005).

19

5. ENERGY SAVING POTENTIAL WITH DIFFERENT CONTROL METHODS

Different control principles have different effects on the power needed to run the pump. Different control principles are compared in the following paragraphs from energy consumptions point of view.

5.1

Throttling control

Throttling control decreases the needed power to drive the pump when operation point is shifted from point 𝐵1 to 𝐵2. Shift of the operation point and change needed power is shown in Figure 10.

Figure 10.

Throttling control’s H-Q-diagram and power needed to run the pump at different operation points (KSB, 2005).

Same power saving potential can be seen from equation 4 where product of the operation points flow rate Q and developed head H is a factor on the equation while other factors remain constant. Product of Q and H decreases if flow rate decreases more rapidly than developed head increases and this is the case with centrifugal pump applications (KSB, 2005).

20

5.2

Variable speed control

Altering the pumps rotational speed has higher effect on pump’s required power than throttling control has. Pumps required power has same characteristic at this control principle as in throttling control when operational point changes while rotational speed is kept constant. When rotational speed is changed the pump’s H-Q-curve and power curve shift as shown in Figure 11. Pumps performance values H, Q and P change according affinity laws stated in equations 1, 2 and 3. As shown in equation 3 the pump’s required power changes relatively to cube of the change of the rotational speed (KSB, 2005). This can also be seen from Figure 11 where difference between power curves is greater with higher rotational speeds.

Figure 11.

5.3

Pumps different H-Q-curves and required power to run the pump showed as a function of flow rate (KSB, 2005).

Parallel pumps

With parallel pumps control by switching pumps on and off two different power consumption levels can be achieved. First one is when one pump is used and pump is operating at operation point in which flow rate is 𝐵𝑠𝑖𝑛𝑔𝑙𝑒 , as shown in Figure 12. When switching on second pump operational point is switched to point 𝐵𝑝𝑎𝑟𝑎𝑙𝑙𝑒𝑙 . When parallel pumps are operating as a unit at operation point 𝐵𝑝𝑎𝑟𝑎𝑙𝑙𝑒𝑙 , individual pumps are both working at operation point in which developed head H intersect with individual pump’s H-Q-curve. This point is different than in single pump operation because Head loss 𝐻𝐿 is greater because of greater combined volume flow in the system. When operation point shifts to right in the pump curve pumps required power decreases as already stated in the throttling control’s case (KSB, 2005). This leads to situation in which parallel

21 pumps combined required power is not double of single pump operations required power. Relation between required power in single or parallel operation is depending in system characteristic so it needs to be calculated to case-by-case.

Figure 12.

5.4

Parallel pump configurations H-Q-curve (KSB, 2005).

By-pass control

By-pass control does not decrease required power when decreasing flow to the system unless the power curve of the pump is downward sloping as shown in Figure 13. Normally centrifugal pump’s power curve is upward sloping so power consumption increases when system flow is increased. Even though power consumption is increased in by-pass control it is also needed to ensure minimum flow through the pump when flow rate into the system is under pump’s specified minimum flow (KSB, 2005). Minimum flow for a pump is normally defined in pump’s datasheet.

Figure 13.

Bypass controls H-Q-diagram and required power to run the pumps as a function of flow rate (KSB, 2005).

22

6. COST ANALYSIS FOR DIFFERENT PUMP SYSTEM CONFIGURATIONS FOR INDUSTRIAL APPLICATION

Cost analysis for the feed water pump system is carried out in following parts. First different system configurations are introduces. The cost analysis itself is started from procurement and assembly costs of the needed components for the system. Next component for the cost analysis is operation costs for different pump systems. Cost analysis is carried out for steam production system’s feed water pumping system. Generated steam is used in steam turbine which is running electric generator. Steam is generated from diesel engine’s exhaust gas’s waste heat. This kind of configuration is called combi cycle system. Combi cycle system is designed to improve total efficiency of diesel engine power plant. For diesel engine power plant efficiency for electricity production is from 45 to 47%. In combi cycle system efficiency can be improved with 6 to 8% (Alfa Laval Aalborg technology, 2015). Importance of energy efficiency in steam production system is easy to see as less the system uses electric energy more of the generated electricity can be sold to the grid. This is the reason to carry out cost analysis in which capital costs are compared to operational costs to establish low payback time and best possible energy efficiency. The cost analysis is done for a system which been designed for ongoing project. By using a real life system as a base for the analysis design criteria for the pumping system is already available and it is reliable basis for the analysis. Needed data and design values are introduces in the cost analysis section at points where the data is used. From previously in this thesis introduced frequency converters Vacon 100 Flow is used in this project as the customer is using the same devices in their system and has requested these converters to be used. Different pump systems that are compared against each other are introduced in the following sub paragraphs both in words and in diagram view.

Common pump unit In common pump unit system two identical pumps are used one at the time and the other pump is kept as a stand by pump. In other words both pumps have 100% capacity to supply feed water for the boilers. Common pump unit can be operated as direct drive or as variable frequency driven. With Variable frequency drive the pump’s rotational speed

23 can be altered depending on the operation point of the boiler system. Figure 14 illustrates common pump units process and instrument diagram. Pump’s rotational speeds control is done according differential pressure over the pump. The control principle is to keep discharge pressure of the pump as constant.

Figure 14.

Process & Instrument diagram of feed water common pump unit system.

Number of feed water control units installed in parallel depends on how many boilers there are on the system. In the base project for this thesis there are seven feed water control units.

Common multi pump unit In Common Multi Pump Unit two or more pumps are kept as normal operation pumps and one pump is kept as a stand by pump. Number of operational pumps depends on the feed water demand. Feed water regulation for individual boilers is handled with feed water control units same as in Common Pump Unit. Pumps in this system can be directly or frequency converter driven. Configuration of common multi pump system is shown in Figure 15.

24

Figure 15.

Process & Instrument diagram of common feed water multi pump unit system.

Boiler specific pump system Boiler specific pump system consists of pump pairs which are designated for individual boilers. Two pumps for each boiler are installed to meet reliability demands for feed water system. Both pumps have 100% capacity and are operated individually, not at the same time. In this system pumps are variable frequency driven and feed water regulation to the boiler is handled by altering pump’s rotational speed. If no feed water is required by the boiler the corresponding pump can be stopped. Control principle can be seen from Figure 16. Feed water control unit is removed from the system as well the differential pressure transmitters over individual pumps. Differential pressure transmitters are replaced by pressure transmitter in common discharge pipe line to monitor pumps performance.

Figure 16.

Process & Instrument diagram of boiler specific feed water pump unit system.

25

6.1

Assembly & Procurement

In this paragraph unit costs for the parts of different pump systems configurations are determined and pump unit assembly costs are estimated from previous tenders from commonly used subcontractors. With this data assembly and procurement cost for different pump system configurations can be compared against each other.

6.1.1 Common pump Common pump unit with direct driven motors is constructed from devices shown in Table 5. Both pumps in the unit need these parts in order to be able operate and commission the pump properly. Table 5.

Common pump systems devices for direct fed Engines.

Devices Mechanical Pump Suction side Closing Valve Non-return Valve Discharge Regulation Valve Drain Valve Strainer Feed Water Control Valve

Instrumentation Strainer Differential pressure gauge Discharge pressure gauge

Electrical Contactor Engine Protection Relay

The total price of the devices in the common pump unit is 21 564.70€. Assembly of the pumping unit is estimated to cost 8 820.00€ (Alfa Laval Aalborg internal database, 2015). With this the total procurement and assembly cost for direct driven Common Pump system is 30 384.70€. When pump Engines are driven with frequency converter differential pressure over pump is measured and transferred to pump’s control system. Motor protection relay and contactor are not needed as the frequency converter is able to perform both components’ tasks. Switch fuse is installed into the frequency converter supply to enable isolation of the device and to function as circuit breaker for the supply cable. Other devices in direct fed and variable frequency fed pump units are the same. Devices used for the variable frequency fed pump unit are listed in Table 6.

26

Table 6.

Common pump system devices variable frequency fed Engines.

Devices Mechanical Pump Suction side Closing Valve Non-return Valve Discharge Regulation Valve Drain Valve Strainer Feed Water Control Valve

Instrumentation Strainer Differential Pressure Gauge Discharge pressure gauge Pump Differential Pressure Transmitter

Electrical Switch Fuse Frequency Converter

Price for the devices in variable frequency driven pump unit is 24 529.76€ and the assembly is estimated to cost 9 198.00€ (Alfa Laval Aalborg internal database, 2015). Total price for the pump unit is therefore 33 727.76€. Pump’s used in common pump units have quite long delivery time, 12 weeks (KSB offer, 2015). This often causes the pump procurement process to be on the critical path in the project schedule. This sometimes causes the pump dimensioning process to be done with preliminary design data and it involves risk of the pump’s to be falsely dimensioned for the system. False dimensioning usually leads into pumps operation point in which it doesn’t work in the highest possible efficiency (Schneider, 2014).

6.1.2 Common multi pump set up In Common Multi Pump configuration the devices needed for the pump unit are the same as in common pump system. The difference in these systems is the quantity. In the multi pump system we are studying there are three pumps so three sets of devices listed in the Table 5 are needed. In these systems the valves and other devices are the same except for the pump itself, contactor and motor protection relay. This is caused by the lower volume flow needed for an individual pump and therefore lower power consumption. After these alterations the cost of the devices for direct driven common multi pump system is 34 217.07€. Assembly cost for this configuration is 9 450.00€ (Alfa Laval Aalborg internal database, 2015). Total procurement and assembly cost for the pump unit is then 43 721.07€ For the variable frequency driven pump system same changes for the devices are done than in common pump unit system, differential pressure transmitter is added and contac-

27 tor and motor protection relay are replaced with frequency converter and fuse switch. In this case total device price is 38 360.85€, while assembly cost is estimated to be 10 800.00€ (Alfa Laval Aalborg internal database, 2015). Total cost at this point then would be 48 440.85€. Pumps used in Common Multi Pump System are from the same product family as in common pump system and also have relatively long delivery time of 12 weeks (KSB offer, 2015). One pretty significant factor in the price difference besides of the pump is differential pressure transmitters. The three transmitters’ price is 53% percent of the price difference between direct driven or variable frequency driven pump unit.

6.1.3 Boiler specific pump Configuration for boiler specific feed water pump is listed in the Table 7. For boiler specific pump unit two sets of devices shown in Table 7 are required. Control systems feedback for the feed water pumps is derived from corresponding boilers water level transmitter. This eliminates the need for differential pressure transmitter over the pump. Pumps correct function is monitored with pressure transmitter which is much more cost effective. Because of the water level control is done directly with adjusting feed water pumps rotational speed instead of using a throttling valve the valve is not any more needed. Table 7. Devices Mechanical Pump Suction side Closing Valve Non-return Valve Discharge Regulation Valve Drain Valve Strainer

Devices for boiler specific feed water pump. Instrumentation Strainer Differential Pressure Gauge Discharge pressure gauge Pump Discharge Pressure Transmitter

Electrical Switch Fuse Frequency Converter

Parts for boiler specific pump unit cost 5 931.48€ assembly costs for the same unit are 4 662.00€.(Alfa Laval Aalborg internal database, 2015) Combined price for this unit comes to 10 593.48€. For the base project seven individual pump units are needed as there are seven exhaust gas boilers at the system. Price for all the needed pumping units is then 74 154.33€. Boiler Specific Pump System has an advantage over the Common Pump Systems as all the components are stock material. This enables short delivery times and possibility to mass purchases. Higher purchase quantities may also give economies of scale advantage

28 and higher leverage to negotiate unit prices of the pumps and other equipment. This advantage could not be taken into account at this study as total quantities per year couldn’t be determined and used prices are budget prices for the base project. In boiler specific pump’s case piping needed to be done for the feed water system is significantly more complex than for either Common Pump System. Boiler specific pumps either need to be installed side by side close to feed water tank to prevent cavitation or the suction pipe for the pumps needs to be dimensioned to large diameters. Both of these alternatives are not very cost effective so this limits boiler specific pump systems usability in large steam systems with long feed water transfer distances.

6.1.4 Comparison between assembly and procurement prices Costs for device procurement and pump unit assembling for different pump system configurations are collected to Table 8. From the table can be seen that the prices keep getting higher as the pumping systems complexity rises. Boiler specific pumping systems price tag is significantly higher than currently used direct driven Common Pumping System’s price. On the other hand price difference between variable frequency driven and direct driven Common Pump System is only 3 343.06€. Table 8.

Comparison between different feed water pump system configurations.

Common Pump System

Direct Fed

30 384.70€

Common Multi Pump System

Variable Fre- Direct Fed quency Fed 33 727.76€

43 721.07€

Boiler Specific pump system

Variable Frequency Fed 48 440.85€

71 570.0€

Even though price difference between too most economical pumping systems is reasonably low decision between systems based only on procurement and assembly cost would lead to direct fed common pump system. To have wider data to base the decision next step is to analyze operation costs for these different pumping systems.

6.2

Operation

Operation costs for different feed water pump system configurations are calculated and compared in the following sub paragraphs. Three different running engine configurations for the diesel engine power plant are used. These engine configurations are shown on Table 9. Different cases are determined so that all three cases would illustrate different characteristics of the varying pumping systems. Table shows how many percent’s of

29 a year any number of engines are running. Case 1 demonstrates situation in which power plant is used quite evenly on every stage of the possible output power. This kind of engine configuration is typical for peak power plant which is used to balance the grid and maintain steady frequency in grid. Case 2 is a typical engine configuration for power plant sourcing base power to the grid. In this case as many engines as possible are running simultaneously and output power is maximized. In the last case number 3 engine configuration is also fragmented as in case 1 but the total engine running hours per year is smaller as fewer engines are running simultaneously. Table 9.

Diesel engine power plant load curves.

Engines Running

[pcs]

1

2

3

4

5

6

7

Case 1

Utilization rate

[%]

10

10

10

10

30

10

20

Case 2

Utilization rate

[%]

0

10

5

5

10

5

65

Case 3

Utilization rate

[%]

30

20

10

5

10

5

0

In normal operation diesel engines desired load is 85% of the maximum power. At that load engines fuel efficiency is at its highest point. Even though desired operation point is at 85% power the nominal steam generation from the exhaust gas boilers is counted at 100% engine power. This is why the three different cases are divided in to three different engine load subcases 100%, 85% and 50% loads. 50% percent is taken into analysis to show how lower engine load has impact on energy consumption on different pumping systems. Operation cost calculations are carried out with Microsoft Excel. Selected pumps performance curves were modelled for nominal frequency in order to calculate operation points for different needed volume flow quantities and for altering static head. Equation 2 from paragraph 4.1is used to calculate needed frequency to obtain ideal operation point for the pump in different system operation points with certain volume flow and required developed head. Pumps required power in nominal frequency can be determined from its datasheet’s required power curve. After nominal required power on nominal frequency is determined used frequency’s required power can be calculated by using equation 3 from paragraph 4.1. Pump performance curve modelling for developed head and required power were done to three different pumps. Pumps were chosen for base projects design values with objective to have the most energy effective pump for every pump system. To determine operation point for the whole steam system bases on the operation of the steam consumer, in this case steam turbine. Steam turbine in this case is so called slid-

30 ing pressure turbine which is able to use lower steam pressure in lower volume flows and therefore able to maintain high efficiency. This leads to altering steam pressure in the system depending on steam production. Steam supply pressure into the steam turbine stays in 12bar(a) when steam mass flow is under 47tons per hour. With higher flow pressure increases with linear form to 15bar(a) when 100% steam production of 59 tons per hour is reached (SNM, 2015). When steam turbines required steam pressure is determined pumps developed head can also be determined. When pumping losses and needed geological lift 𝐻𝑔𝑒𝑜 are taken into consideration needed developed pump head H is known.

6.2.1 Common pump Common pump systems yearly energy consumption is shown for direct driven and variable frequency driven pumps in Figure 17. The Figure 17 shows energy consumption for the three different engine configuration cases explained previously and also show these cases with three different engine loads.

350 300 250 200 Common Pump Unit Direct

150

Common Pump Unit VFD 100 50 0 100% Engine Power Case 1

85% Engine Power Case 1

Figure 17.

50% Engine Power Case 1

100% Engine Power Case 2

85% Engine Power Case 2

50% Engine Power Case 2

100% Engine Power Case 3

85% Engine Power Case 3

50% Engine Power Case 3

Common pump units consumed energy in Megawatt hours per year for direct and variable frequency fed units

100% Engine power in Case 2 shows that when high utilisation of the system is achieved potential energy savings are quite small as the pumping system is working close to its dimensioned operation point for 100% steam production.Variable frequency drives benefits can be seen in Cases 1 and 3 in all three load situations and in Case 2

31 when load is either 85% or 50 %. Graph shows that variable frequency driven pumps consumed energy gets proportionally lower compared against direct driven pump when steam production is getting smaller. This happens when fewer engines are used and/or engine loads are lower. In Case 2 with 100% engine power variable frequency driven pumps energy saving is only 7% of the direct driven pumps energy consumption. When engine power is 85% the energy saving is 32% and with 50% engine power the saving is 49 %. So with lower engine power variable frequency driven pump system saves almost half of the energy compared to direct driven pump.

6.2.2 Common multi pump unit Common Multi Pump System’s energy consumption in a year is compared to common pump systems energy consumption in Figure 18. With higher steam consumption the direct drive Common Multi Pump System uses more energy than direct drive common pump unit system. On the other hand when steam system is functioning in lower capacities and only one pump is operational energy saving is possible with direct drive multi pump system compared to common pump system. 400 350 300 250 Common Pump Unit Direct

200

Common Multi Pump Unit Direct 150

Common Pump Unit VFD

100

Common Multi Pump Unit VFD

50 0 100% 85% 50% 100% 85% 50% 100% 85% 50% Engine Engine Engine Engine Engine Engine Engine Engine Engine Power Power Power Power Power Power Power Power Power Case 1 Case 1 Case 1 Case 2 Case 2 Case 2 Case 3 Case 3 Case 3

Figure 18. Common multi pump units consumed energy in Megawatt hours per year for direct and variable frequency fed units. Direct and variable frequency driven common pump units’ energy consumption for reference. Variable frequency drive enhances common multi pump systems energy efficiency significantly. Especially with lower steam production capacities the energy saving potential is significant. In Case three variable frequency driven Common Multi Pump System used 34% less energy than direct drive system would. The difference kept rising when

32 the engine load is 85% at that operation point energy consumption was 40% lower. With 50% Engine load the difference is already 45%. This shows that with lower engine loads and with partial operation of the total power plant significant energy saving potential is able to be used if variable frequency fed pump system is installed. Differences in energy consumption between variable frequency driven Common Pump Unit and Common Multi Pump Unit are marginal and lower energy consumption varies between common pump and common multi pump system in different cases and engine loads. Common Multi Pump System turns out still to be more energy efficient on the lower engine powers when steam production is low. Variable frequency driven Common Pump Unit and Common Multi Pump Unit are consuming almost the same energy in Case 2 with 100% engine power, the difference is only 2% for Multi Pump Systems advantage. With this low difference in consumed energy for these two systems at this operation point can be said to be the same. With 85% engine power the Common Pump System is 8% more energy efficient than Multi Pump System. With 50% engine load scales tip slightly back to Multi O Common Multi Pump System Pump System’s side as the difference is at this operation point 4% for Multi Pump System’s advantage.

6.2.3 Boiler specific pump Boiler specific pump’s energy consumption is compared against Common Pump Units energy consumption in Figure 19. Boiler specific pump is consuming energy in the same rate as variable frequency driven Common Pump Unit when power plant is running on high engine utilization rate and with high engine loads. Boiler Specific Pumping Systems benefits can be seen best in Case 3 where fewer engines are running simultaneously and corresponding exhaust gas boilers are not operational as well. In this situation boiler specific pump will be stopped and higher energy efficiency can be achieved. In Case 3 with 100% engine power energy savings are 21% compared to Common Pump Units energy consuming. When engine power is 85% the savings drop down to almost half of the 100% engine load scenario 10%. Highest energy savings with boiler specific pump are achieved in Case 3 with 50% engine power. At that operation point achievable savings are 33% compared to common pump unit equipped with variable frequency drive.

33

300

250

200

150 Common Pump Unit VFD Boiler specific pump VFD 100

50

0 100% Engine Power Case 1

85% Engine Power Case 1

50% Engine Power Case 1

100% Engine Power Case 2

85% Engine Power Case 2

50% Engine Power Case 2

100% Engine Power Case 3

85% Engine Power Case 3

50% Engine Power Case 3

Figure 19. Boiler specific pump units consumed energy in Megawatt hours per year. Variable frequency fed common pump units energy consumption for reference.

6.2.4 Summary of operation costs Energy consumption for all pump systems in all nine different operation points are shown in one table in appendix A. From the table it can be seen that direct driven Common Multi Pump System is in the most cases the most inefficient regarding the energy consumption. Same table shows as well that energy consumption for Common Pump Unit and Boiler Specific Pump Systems are the two most energy efficient pumping systems for this application. Operational costs for different pumping systems compared to Common Pump System are shown in Table 10. Electricity price is calculated according primary energy price from which electricity is produced. In our base project primary fuel used for the diesel engines is natural gas. In the price calculations natural gas price is assumed to be 630€/ton. Power plants total efficiency on electricity production is also assumed to be 45%. With these values electricity price is 100.8€/MWh. Prices shown in Table 10 are calculated based on this values.

34

Drive Type 100% Engine Power Case 1 85% Engine Power Case 1 50% Engine Power Case 1 100% Engine Power Case 2 85% Engine Power Case 2 50% Engine Power Case 2 100% Engine Power Case 3 85% Engine Power Case 3 50% Engine Power Case 3 Average

Boiler specific pump

Common Multi Pump Unit

Operational cost differences for different pump system configurations compared to Direct driven common pump system.

Common Pump Unit

Table 10.

VFD

VFD

Direct

VFD

-8 578,08 € -10 870,27 € -10 395,50 €

-7 833,17 € -9 799,78 € -11 870,21 €

2 716,56 € -390,10 € -4 995,65 €

-9 351,22 € -10 265,47 € -12 621,17 €

-2 355,70 € -9 355,25 € -11 207,95 €

-2 816,35 € -7 843,25 € -11 724,05 €

5 137,78 € 3 773,95 € -4 186,22 €

-3 473,57 € -7 473,31 € -11 653,49 €

-7 911,79 € -9 980,21 € -9 765,50 € -8 935,58 €

-8 220,24 € -9 817,92 € -10 986,19 € -8 990,13 €

269,14 € -843,70 € -4 165,06 € -298,14 €

-11 373,26 € -11 381,33 € -12 917,52 € -10 056,70 €

Table 10 shows that average potential amount of saved money is almost identical in Common Multi Pump and Common Pump Systems. Both systems have potential for savings worth almost 9 000€. Direct fed Common Multi Pump system has somewhat virtual saving potential as 300 euros fall into calculations error margins. Boiler specific pump system has the highest saving potential for the different pumping systems. 10 000€ could be saved on average with this pump system configuration in a year compared against direct driven Common Pump configuration. Average saving potential does not tell the whole truth about saving potential of different systems. High differences in the saving potential can be seen when comparing different cases and engine loads against each other. Because of high relativity between energy consumption and power plant load curve can be identified from the calculations feed water pumping system needs to decided based on power plants designed load curve. In the base project power plant is designed to be a base power plant and as stated previously Case 2 represents base power plant’s normal load curve. With desired 85% engine power variable frequency driven Common Pump System has the highest saving potential of all the compared pump systems, 9 335.25€.

35

6.3

Total cost calculations and determine payback time

To calculate total cost for the system we take into account previous paragraphs calculations on costs and determine total cost for each pumping system. After the cost has been calculated payback time for investments can be determined by using following equation: 𝐼

𝑇 = 𝐹,

(6)

in which T is payback time in year, I is the initial investment in the system and F is the cash flow created by the investment. In our case initial investment is caused by procurement and assembly prices differences between different pump systems. On the other hand cash flow is created from changes in operational costs. Table 11 shows the payback times for different systems in all nine different operation points. N/A in table means that cash flow in that specific case in negative, so the system in less energy efficient than the original system and system won’t return the investment. In the industrial field of diesel power plants three years is normally kept as a threshold limit for a reasonable payback time and investments with longer payback time are usually disregarded (Alfa Laval Aalborg technology, 2015).

Drive Type 100% Engine Power Case 1 85% Engine Power Case 1 50% Engine Power Case 1 100% Engine Power Case 2 85% Engine Power Case 2 50% Engine Power Case 2 100% Engine Power Case 3 85% Engine Power Case 3 50% Engine Power Case 3

VFD 0,39 0,31 0,32 1,42 0,36 0,30 0,42 0,33 0,34

VFD 2,31 1,84 1,52 6,41 2,30 1,54 2,20 1,84 1,64

Boiler specific pump

Common Multi Pump Unit

Payback times in years for different feed water pump systems compared to direct driven Common Pump unit in different Cases and engine loads.

Common Pump Unit

Table 11.

Direct N/A 34,19 2,67 N/A N/A 3,19 N/A 15,81 3,20

VFD 4,40 4,01 3,26 11,86 5,51 3,53 3,62 3,62 3,19

36 Analysis of payback times shows that Common Pump Systems upgrade to variable frequency driven version will pay back the investment in less than six months in all the other cases expect Case 2 with 100% engine power. Even the longest payback time for this system upgrade is less than 18 months. Another thing that was not taken into account in the analysis is that without variable frequency drive the pumps selection process always leads to over dimensioning of the pump. Usually decision process has some uncertainties and the risks involved in these uncertainties are minimized by selecting a bit oversized pump in order to make sure it will develop enough head for the system in the highest volume flow. This over sizing is not necessary in variable frequency driven application as the pump can be driven in higher frequency than the nominal frequency in the grid is as long as the pumps structural maximum rotational speed is not exceeded. Other system that shows reasonable payback times is Common Multi Pump System with variable frequency drive. This system has payback time more than three years only in Case 2 with 100% engine power. Direct driven Common Multi Pump System fails the three year payback limit in all nine cases. Systems payback time is significantly higher than the three year limit for couple cases almost 35 years in the worst case. Also boiler specific pumps high investment costs lead to too long payback times. The payback time for the best cases is not still much higher than the set three year limit. This gives good reasons to analyse Boiler Specific Pump Systems feasibility for different load curve facilities. These kinds of applications are cases that engines are run in lower power and not all engines are run at the same time. For example this kind of systems can be seen in marine applications and introducing Boiler Specific Pump Systems should be considered in those kinds of applications.

37

7. COST ANALYSIS FOR PUMP SYSTEM CONFIGURATIONS IN MARINE APPLICATION

Second pump system cost analysis is done for entity that is used in marine applications. Marine application in this case includes ferry and cruise vessels. Steam system in ferry and cruise vessels consists of oil or gas fired auxiliary boiler and from exhaust gas boilers connected to ship’s main engines. These boilers are traditionally fed by common pump which is dimensioned to be able to feed both of the boilers at the same time even though both boilers do not operate with full capacity at the same time (Alfa Laval Aalborg technology, 2015). This leads to situation in which the pump is operating at partial load and is not operating at point of the highest efficiency. Cost analysis for different pump system configurations is studying the feasibility of variable frequency driven common pump system and boiler specific pump system. Basis configuration for steam system and for feed water pumping system used in marine applications is shown in Figure 20. In this system feed water regulation is done with control valves and feed water pumps are running at all times with constant speed.

M

EG BOILER

HOTWELL

STEAM DRUM

EG BOILER

OIL FIRED BOILER

STEAM TO CONSUMERS

M

Figure 20.

Principle of marine application’s steam system.

38

Common pump unit Process and instrument diagram for common feed water pump unit is shown in Figure 21. The configuration for the pump unit is slightly lighter than in industrial power plants as the used feed water is cleaner and therefore strainers are not needed in this application. Figure 21 shows frequency converter driven pump unit which is not standard solution in marine applications.

Figure 21.

Marine application’s common pump unit process & instrument diagram.

Pump system configuration for direct driven pump unit is otherwise similar to shown in Figure 21but the differential pressure transmitters and frequency converters are removed and common pressure transmitter is added to the discharge pipe line to monitor pump performance.

Boiler specific pump unit Boiler specific pump systems process and instrumentation diagram is shown in Figure 22. Boiler specific pump system is missing the separate feed water control unit because it is integrated into the pumping unit as the pumps are variable frequency driven and feed water flow into the boiler is controlled by changing pumps rotational speed according control principle introduced in paragraph 4.3.3.

39

Figure 22.

7.1

Process and instrument diagram for marine application’s Boiler specific pump unit.

Assembly & Procurement

Assembly and procurement costs for the different pumping system are evaluated in the same manner as in industrial pumps case in paragraph 6.1. Unit costs for devices, parts and assembly job needed in the units are determined from previous tenders and realized purchases.

7.1.1 Common pump Needed devices and parts for a direct driven Common Pump unit are shown in Table 12. All the listed items are needed for each pump except the pressure transmitter which is installed in the common pipeline after regulation valves and the feed water control unit which’s quantity is determined by number of boilers. In our study number of boilers is two.

40 Table 12.

Marine applications engine room’s variable frequency fed common pumps unit’s devices.

Devices Mechanical Pump Suction side Closing Valve Non-return Valve Discharge Regulation Valve Drain Valve Feed Water Control Unit

Instrumentation Discharge pressure gauge Pressure Transmitter

Electrical Contactor Motor Protection Relay

Price of parts and devices for common pump unit for marine application is 4343.22€. On top of that assembly costs are 4662.00€ so total investment cost for the direct driven common pump unit is 9005.22€ Next the common pump drive is changed to variable frequency drive and list on needed materials for this pump system is shown in Table 13. Like in industrial application contactor and motor protection relay are replaced by switch fuse and frequency converter. Also pressure transmitter is replaced by two differential pressure transmitters which are used for pump control. Table 13.

Marine applications engine room’s variable frequency fed common pumps unit’s devices.

Devices Mechanical Pump Suction side Closing Valve Non-return Valve Discharge Regulation Valve Drain Valve Feed Water Control Unit

Instrumentation Discharge pressure gauge Pump Differential Pressure Transmitter

Electrical Switch Fuse Frequency Converter

Assembly costs for the variable frequency driven common pump unit are the same as for the direct driven pump unit, 4662.00€. Parts and devices listed in the Table 13 are costing 5210.55€ and the total cost sums up to 9872.55€. Pumps are the same in both direct and variable frequency fed pump units. Pumps developed head H needs to be dimensioned according steam drums operational pressure 𝑝𝑎 and geological height 𝐻𝑔𝑒𝑜 because both of these are higher than for auxiliary boiler. Auxiliary boiler is located in the ship’s engine room, in deck 1 and steam drum is installed in the exhaust stack above the exhaust gas boilers in order to enable natural cir-

41 culation occurring between the steam drum and exhaust gas boiler. Feed water pump is located in the ship’s bilge in order to arrange sufficient net positive suction head, NPSH, for the pump to operate without cavitation. This physical difference in the location of two separate discharge vessels give priority for the steam drum in the dimensioning of the pump as it needs higher developed head in order the feed water to have high enough pressure when it reaches steam drum. Steam drums working pressure 𝑝𝑎 is higher than auxiliary boiler’s working pressure in order to ensure energy efficient production of steam. Steam generated with exhaust gas boiler does not need additional energy as the auxiliary boiler uses oil or natural gas to heat up water and generate steam. Operational order between these boilers is handled by operating the exhaust gas boiler in higher pressure and if it is not able to sustain the pressure in desired level auxiliary boiler will assist maintains to pressure. This pressure gap gives the steam drum higher importance in dimensioning of the pump. Dimensioning according steam drums required developed head means that the pump is over dimensioned for auxiliary boiler operation during harbor time. Over dimensioned head H and earlier stated operation points flow Q dimensioning according both boilers maximum capacity give good base to evaluate use of independent pumps for both boilers. This system is examined in the next paragraph.

7.1.2 Boiler specific pump Boiler specific pump unit’s devices and parts are almost the same as on variable frequency driven common pump unit. Boiler specific pump unit does not need specific regulation valve in the discharge side of the pump as the needed regulation in the system can be achieved with other valves already in the system (Alfa Laval Aalborg technology, 2015). This is why it is missing from the Table 14 where necessary parts and devices for the pump unit are listed. Also feed water control unit is no longer needed as previously stated the water level control in the boiler is handled by altering pumps operation point. Table 14.

Marine applications boiler specific pump systems devices.

Devices Mechanical Pump Suction side Closing Valve Non-return Valve Drain Valve

Instrumentation Pump Discharge Pressure Transmitter Discharge pressure gauge

Electrical Switch Fuse Frequency Converter

Pump units for auxiliary boiler and for steam drum are not identical as previously explained the operation points for the two are not identical as well. Pumps are dimensioned for the both separately and the process gave two pumps that will be used. The

42 pumps had same pipe connection size and therefore same size valves and fittings can be used for the units. Because of same size piping only difference between the units is the pump and the frequency converter used because the pumps had different size motors. Auxiliary boiler’s feed water pump unit’s total price is 6745.49€ from which the parts and devices cost 2083.49€. Steam drum’s feed water pump unit’s parts and devices cost 2012.93€ and the total price for the unit is 6674.93€. Total cost for the feed water pumps units’ in one engine room sums up to 13 420.41€.

7.1.3 Comparison between pump units’ assembly and procurement prices Total investment prices for different feed water pump system configurations are listed in Table 15. Direct driven common pump system has the lowest investment price compared against other pump configurations. Total price for the boiler specific pump configurations is 4 415.19€ more expensive than the cheapest direct driven common pump unit. This is caused by the doubled quantity of pump units compared against common pump unit even though parts and devices for single pump unit cost less than half of the price of parts and devices for the common pump unit. Biggest price difference between the common pump unit and individual pump unit was achieved because the system does not need separate feed water control unit for the boilers. Table 15.

Different feed water pump unit prices for marine application.

Direct Drive Common Pump Unit

Variable Frequency Driven Common Pump Unit

9 005.22 €

9 872.55 €

Total price of Boiler Specific Pump Configuration

13 420.41€

Auxiliary Boiler

6 745.49 €

Steam Drum

6 674.93 €

Differential pressure transmitters and frequency converters raised the price of common pump unit by 867.33€. Direct drive common pump unit would be chosen as the feed water unit if only investment costs would be considered. Next operational costs for these different pump systems will be calculated to give more knowledge to which to base the investment decision on.

7.2

Operation

Common pump unit’s operation costs are calculated for both drive methods and also boiler specific pumps operation costs are calculated in this chapter. Operation costs for

43 the three different feed water pump configurations are calculated for ferry and cruise ship’s operation profiles.

7.2.1 Common pump Common pump is operational at all times. That leads to a point that operation percentage in both operation columns shown in Table 16 need to sum up to 100%. In ferry operation the operation profile mimics ferries operating between Helsinki and Tallinn (Tallink, 2015). Ferry operation assumes 12h spent at sea in a day and 1 hour for maneuvering in harbor. This gives 50% of time to be operated on 30% of maximum steam systems load. 30% load is the same as the exhaust gas boilers maximum steam production. Steam production at exhaust gas boiler during the voyage is at its maximum because engines are operated at 100% capacity (Alfa Laval Aalborg technology, 2015). 20% load for 20% of time is operation with auxiliary boiler with low capacity after voyage when energy bank is used. Energy bank is charged with excess steam during voyage and used in harbour (Alfa Laval Aalborg technology, 2015). Rest 30% of the time auxiliary boiler is operating at higher capacity of 50% of whole steam system’s capacity. Table 16.

Boiler steam production capacity in ferry and cruise vessel operations for common pump unit. Utilization Rate Load 10 % 20 % 30 % 40 % 50 % 60 % 70 % 80 % 90 % 100 %

Ferry Operation [%] 0 20 50 0 30 0 0 0 0 0

Cruise Vessel Operation [%] 0 0 40 0 60 0 0 0 0 0

Steam Production [ton/h] 774 1548 2322 3096 3870 4644 5418 6192 6966 7740

Cruise Vessel operation differs from ferry operation in time spent at sea. Cruise vessels are normally more at harbor and therefore auxiliary boiler is running at higher load of 50% of total steam system load for 60% of time. Cruise vessels steam consumption is also greater so no excess steam can be used to heat up energy bank during sea voyage and auxiliary boiler is also for that reason operating on higher load (Alfa Laval Aalborg technology, 2015). 40% of operation time the vessel is at sea on 100% load so full steam system capacity is at 30% (Norwegian Cruise Line, 2015).

44 Energy consumption for both drive type common feed water pump units is shown in Figure 23. Graph shows consumed energy in megawatt hours in a year. Variable frequency driven pump unit uses 24% less energy in both operation profiles.

30 25 20 Common Pump Direct

15

Common Pump VFD 10 5 0 Ferry operation

Cruise Vessel operation

Figure 23. Direct and variable frequency driven common feed water pump systems energy consumption in megawatt hours in a year in marine application. Cruise Vessel operation has higher energy consumption for feed water pumping which logical as steam demand is also higher and therefore more feed water needs to be pumped into the boilers. Higher energy consumption leads to higher possible energy saving with cruise vessel operation as the percentage difference between the pump systems consumed energy was the same in both operation profiles. In cruise vessel operation 6.4 megawatt hours of electricity could be saved with variable frequency drive when to same number on ferry operation would be 5.8 megawatt hours.

7.2.2 Boiler specific pump Auxiliary boiler’s steam production profiles for ferry and cruise vessel operations are shown in Table 17. Auxiliary boiler is operating when the vessel is at port because exhaust gas boilers are dimensioned to be able to produce enough steam for the vessels operation during voyage (Alfa Laval Aalborg technology, 2015). That is why boiler and therefore boiler specific feed water pump are operational during time spent on port.

45 Table 17.

Auxiliary Boiler’s load curve in ferry and cruise vessel operations. Utilization Rate Load

Ferry Operation [%]

10 % 20 % 30 % 40 % 50 % 60 % 70 % 80 % 90 % 100 %

0 20 0 0 0 0 30 0 0 0

Cruise Vessel Operation [%] 0 0 0 0 0 0 40 0 0 0

Steam Production [ton/h] 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

Auxiliary and exhaust gas boilers’ operating profiles combined is the same operating profile as shown for common pump unit in Table 16. Exhaust gas boiler’s operating profile is shown in Table 18. The operating profile shows that exhaust gas boiler is operated with maximum capacity when it is operational. Table 18.

Exhaust gas boiler’s load curve in ferry and cruise vessel operations. Utilization Rate Load

Ferry Operation [%]

Cruise Vessel Operation [%]

10 % 20 % 30 % 40 % 50 % 60 % 70 % 80 % 90 % 100 %

0 0 0 0 0 0 0 0 0 50

0 0 0 0 0 0 0 0 0 60

Steam Production [ton/h] 274 548 822 1096 1370 1644 1918 2192 2466 2740

Auxiliary and exhaust gas boilers’ energy consumption in a year in megawatt hours is shown in Figure 24. The figure also shows total energy consumed by the boiler specific pumps in ferry and cruise vessel operation profiles. Direct driven common pump units energy consumption in these operation profiles are also shown for comparison.

46

30 25 20

Common Pump Direct Boiler specific pump AXB

15

Boiler specific pump EGE 10

Boiler specific pump TOT

5 0 Ferry operation

Cruise Vessel operation

Figure 24. Boiler specific pump units’ individual and combiner energy consumption in megawatt hours in a year compared against direct driven common pump unit’s energy consumption. From Figure 24 difference in energy consumption between common and boiler specific pump systems can be seen clearly. In ferry operation total energy used by the boiler specific pumps is 54% less than by the common pump unit. The same figure for cruise vessel operation is 53%. These figures translate to 13.0 and 14.1 megawatt hours of energy that could be saved with boiler specific pump system in the revised operation profiles. Comparison between all different pump system configurations’ energy consumption can be seen in graph shown in appendix b.

7.2.3 Summary of operation costs Cost calculations for operating the different pump system in studied operation profiles is carried out next. Electricity in marine application is generated with diesel engines and generators. Energy price is for the pump units is then determined by oil or gas price depending on used fuel and from diesel engines and generators combined efficiency to transform the primary fuel’s chemical energy to electrical energy. The electricity price is calculated for liquid natural gas fuelled vessel. Used natural gas price is 630€/ton in this study. With combined efficiency of 45% for diesel engine and generator the electricity price used to run the pumps is 100.8€/MWh (Alfa Laval Aalborg technology, 2015). Operational costs based on energy consumption calculation done on previous chapter and established electricity price in marine application are displayed in Table 19. Price of operation is calculated for a year’s operational time.

47

Common Pump Unit

Boiler specific pump

Operation costs for a year for boiler feed water pumps in ferry and cruise vessel operations for different pump systems. Common Pump Unit

Table 19.

Drive Type

Direct

VFD

VFD

Ferry operation

2 449.84 €

1 865.00 €

1 138,33 €

Cruise Vessel operation

2 749.44 €

2 048.76 €

1 271.69 €

Same trend can be seen from the operation cost Table 19 as from figures presenting energy consumption for different pump configurations. Boiler specific pump system is the most cost effective pump system if only operational costs are taken into consideration. In cruise vessel operation boiler specific pump system could be able to save 1 477.75€ in one year compared to direct drive common pump unit. Even variable frequency driven common pump unit has saving potential of 584.84€ per year. Now we have two different outcomes for the decision process. Investment cost analysis showed the direct driven common pump unit to be the most economical pump unit configuration for this application. Operation costs analysis revealed that boiler specific pump unit to be the most cost effective feed water pump unit system for the same application. Boiler specific pump system had the highest investment cost and direct fed common pump unit has the highest operation costs. This contradiction between the analyses needs to be addressed more. That is done in next chapter where total cost analysis is carried out.

7.3

Total cost calculations and determine payback time

Total cost calculations and payback time determination is done in a same way as for industrial application. Differences in procurement and assembly costs are the investment costs for the system and cash flow is the potential saving potential for the specific pump unit. Payback time is calculated according equation six same as in industrial application. Table 20 shows payback times for the variable frequency driven pump unit and for boiler specific pump configuration for the both operation profiles. Thresh hold time for the payback time of three year is widely used in marine applications (Alfa Laval Aalborg technology, 2015). This same time is used in this study. .

48

Drive Type Ferry operation Cruise Vessel Operation

Boiler specific pump

Payback times for the upgrade investment for the pumping systems for marine application. Common Pump Unit

Table 20.

VFD 1.5

VFD 3.4

1.2

3.0

Pay back times for common pump unit with frequency converter are well under the three year thresh hold time. This is caused low additional investment cost compared to direct driven common pump unit and this combined with relatively high energy saving potential gives variable frequency drive common pump units short payback times. Boiler Specific pump systems payback time in ferry operation is almost five months longer than the three year thresh hold limit. The pay back time shortens to thresh hold time of three years in cruise vessel operation profile. Same pattern can be seen from common pump units pay back time. This gives an input that with higher steam production rates in marine application the pay back times are getting shorter as energy saving potential is getting greater. This was already seen from operational cost analysis which stated that energy saving potential with boiler specific pump systems rose with more than one megawatt hour per year compared between ferry and cruise vessel operation profiles. For this specific case the variable frequency driven common pump unit would be chosen as the pump system. Because the pay back time for boiler specific pump system is not much higher than the thresh hold time and with higher steam production rates the payback time is assumed to be shorter the common pump unit cannot be determined to be superior in all cases. Therefore the analysis between the pump units needs to be carried out case by case.

49

8. CONCLUSION

Studies on requirements for frequency converters given in rules and regulations in Alfa Laval Aalborg’s applications showed expected results. Requirements against environmental factors were met in all devices which were compared against the requirements in this thesis. EMC requirements in device level were addressed in all devices as they were built according EMC standards. But even if device level EMC was met the whole systems electromagnetic compatibility is only met if the installations are done properly. The installation of variable frequency drive to be according the standards starts during design process so that proper cables and installation accessories are selected. Also familiarization in EMC matters for installation crew is crucial for them to use provided material in proper way. Biggest finding in this part of thesis was that only one device had Marine Classification at all. This limited the use of other devices in industrial applications. Further analysis for other devices needs to be carried out to be able to compare frequency converters in marine applications. Cost analysis for industrial application’s direct and variable frequency driven Common Pump and Common Multi Pump Units and for variable frequency driven Boiler Specific Pump System revealed interesting data for energy consumption and payback times. Common multi pump systems limited energy saving potential was not an expected result for the energy consumption analysis. Higher energy savings were anticipated for this pump system before calculations. Further analysis proved this hypothesis to be false and showed large energy saving potential for variable frequency driven Common Pump System. Common Pump System’s investment costs with frequency converter were not significantly higher than without variable frequency drive. This combined with good energy saving potential gave variable frequency driven Common Pump System really low payback times and therefore good promises for future use. Boiler specific pump system had higher investment costs than in initial expectations. Even though Boiler Specific Pump System had almost the same energy efficiency than the variable frequency driven Common Pump System the payback time for the Boiler Specific Pump system is slightly over the threshold limit and is not feasible alternative for pump system for this application. But with suitable load curve for the steam system and in smaller scale systems Boiler Specific Pump System can have significant saving potential both in energy and monetary perspectives. Marine applications steam systems variable frequency driven common pump unit had higher energy saving potential than initially anticipated. Also the additional investment price turned out to be relatively low compared to direct driven pump unit. These two factors gave short pay back time for the variable frequency driven pump configuration.

50 Boiler specific pump configuration had higher additional investments costs compared to variable frequency driven common pump unit. This was anticipated as the total number of needed is then doubled from two to four and also quantity of all needed instruments and devices is doubled expect missing feed water and regulation valves. Energy saving potential for the boiler specific pump configuration was higher than in variable frequency driven pump unit. This is caused by smaller pumps that are driven only when needed and in the pumps ideal operation range where efficiency is near its maximum value. Even though energy saving potential is significant the payback time for the boiler specific pump system turned out to be little over normally specified required pay back time of three years. Although calculations showed that with higher steam production systems boiler specific pump system’s payback time will be shortened to more favourable figures. Because of this notification decision on the most suitable feed water system configuration needs to be done case by case as the system configuration and operation profile has significant effect on the feed water pumping systems energy consumption.

51

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52 from: http://radioeng.cz/fulltexts/2008/08_04a_101_105.pdf. [Accessed: 15TH October 2014] SCHNEIDER. (2015) Variable Speed Drives Altivar Process ATV600. Available from:http://download.schneiderelectric.com/files?p_Reference=DIA2ED2140502EN&p_EnDocType=Catalog&p_File_Id= 1023139629&p_File_Name=DIA2ED2140502EN+%28web%29%20.pdf. [Accessed: 17th August 2015] SIEMENS. (2015) Sinamics G120 low voltage converters. Available from:https://cache.industry.siemens.com/dl/files/827/109478827/att_854355/v1/G120_ CU230P2_BA5_0415_PI_eng.pdf. [Accessed: 17th August 2015] RS-COMPONENTS PTY LTS. (2015) Handy Reference table for I.P. ratings. Available from: http://au.rsonline.com/web/generalDisplay.html?id=centre/mro_techref_iprating. [Accessed: 17th August 2015] RUSSIAN MARITIME REGISTER OF SHIPPING. (2014). Rules for the Classification and Construction of Sea-Going Ships, Volume 2. RUSSIAN RIVER REGISTER. (2009) RULES FOR THE CLASSIFICATION AND CONSTRUCTION OF INLAND NAVIGATION SHIPS. SCHNEIDER ELECTRIC. (2014) Three steps for Reducing total cost of Ownership in Pumping Systems. SFS. (2010) SFS-EN 60204-1 Safety of machinery – Electrical equipment of machines. Suomen Standardoimisliitto, SFS. SNM. (2015) Expected Steam Consumption Curve. VUORENMAA, S. (2014) Taajuusmuuttajakäyttöjen moottorivauriot ovat estettävissä, pp. 40-42. Sähköala 10/2014. TALLINK, (2015) Timetables for ferries between Helsinki and Tallinn. Available from: http://www.tallinksilja.com/fi/web/fi/aikataulut-helsinki-tallinna. [Accessed: 3th September 2015] VACON OY. (2015) Vacon 100 Flow Brochure. Available from: http://vacon-100flow.vacon.com/pdf/vacon-100-flow-brochure.pdf. [Accessed: 17th August 2015]

53

APPENDIX A

54

APPENDIX B