CHP Thesis KTH

8/12/2019 CHP Thesis KTH

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DEVELOPMENT OF A TOOL FORSIMULATING PERFORMANCE OF SUBSYSTEMS OF A COMBINED

CYCLE POWER PLANT

PRABODHA JAYASINGHE

Master of Science Thesis

Stockholm, Sweden Year


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DEVELOPMENT OF A TOOL FOR SIMULATINGPERFORMANCE OF SUB SYSTEMS OF A COMBINED

CYCLE POWER PLANT

Prabodha Jayasinghe

MSc Thesis 2012

Department of Energy Technology

Division of Heat and Power Technology

Royal Institute of Technology

100 44 Stockholm, Sweden


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Master of Science Thesis

GI-2012-039 MSC EKV889

Development of a tool fo r simulatingperformance of sub systems of a combinedcycle power plant

Prabodha Jayasinghe Approved

Dr. Anders Nordstrand

Examiner


Supervisor

Professor R.A. Attalage

Dr. Anders Nordstrand Commissioner Contact person


Abstract

In Sri Lanka, around 50% of the electrical energy generation is done using thermal energy, and hencemaintaining generation efficiencies of thermal power plants at an acceptable level is very important from asocio-economic perspective for the economic development of the country. Efficiency monitoring alsoplays a vital role as it lays the foundation for maintaining and improving of generation efficiency.

Heat rate, which is the reciprocal of the efficiency, is used to measure the performance of thermal powerplants. In combined cycle power plants, heat rate depends on ambient conditions and efficiencies of sub-systems such as the gas turbine, Heat Recovery Steam Generator (HRSG), steam turbine, condenser,cooling tower etc. The heat rate provides only a macroscopic picture of the power plant, and hence it is

required to analyse the efficiency of each subsystem in order to get a microscopic picture. Computerbased modelling and simulation is an efficient method which can be used to analyse each subsystem of acombined cycle power plant. Objective of this research study is to develop a computer based tool whichsimulates the performance of each of the subsystems of a combined cycle power plant of rated capacity163MWe in Sri Lanka. At the time this research was commenced, analysis on the power plant was fo-cused only on the heat rate, but performances of subsystem were not investigated.

In this research analysis of the plant is divided into several main systems, in order to study them macro-scopically. Then, these main systems are further divided into subsystems in order to have a microscopicperspective. Engineering equation solver (EES) was used to develop the tool for modelling and simula-tion, and the final computer model was linked with Microsoft excel package for data communication. Fi-nal computer model is employed using both present and past operating data in order to compare present

and past performance of the power plant.


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In combined cycle power plants steam is injected into the gas turbine to reduce the NOx generation andthis steam flow is known as NOx flow. According to the result it was found that turbine efficiency dropsby 0.1% and power output increases by 1MW when NOx flow increases from 4.8 to 6.2kg/s.

Further it concluded that gas turbine efficiency drops by 0.1% when ambient temperature increases by 3oC; and gas turbine power output decreases by 2MW when ambient temperature increases from 27 to 31degrees.

Regarding the steam cycle efficiency it was found that steam turbine power output drops by 0.5MW when ambient temperature increases from 27 to 31 oC; and steam cycle efficiency increases by 1% whenNOx flow increases from 4.8 to 6.2kg/s. Further, the steam turbine power output decreases by 0.25MWe

When NOx flow increases from 4.8 to 6.2kg/s

Heat rate, which is the most important performance index of the power plant, increases by 10units(kJ/kWh) when ambient temperature increases by 3 oC.

Heat rate also increases with increase NOx flow which was 6.2kg/s in year 2007 and 4.2kg/s in year 2011.Hence, heat rate of the power plant has improved (decreased) by 10units (kJ/kWh) from year 2007 toyear 2011.

Other than above, following conclusions were also made during the study using model developed withthe perspective of study.

1) HRSG efficiency has not change during past 4 years

2) Significant waste heat recovery potential exists in the gas turbine ventilation system in theform of thermal energy


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List of Abbreviations

HRSG Heat recovery steam generatorFOSV Fuel oil stop valveIGV Inlet guide vanes

LLP Low Low pressureLP Low pressureHP High pressureHPBFP High pressure boiler feed pumpLPBFP Law pressure boiler feed pumpCEP Condensate extraction pumpIBD Intermittent blow downCBD Continues blow downHPSV High Pressure Steam ValveHPCV High Pressure Control ValveCST Condensate Storage Tank.SWAS Steam water analysis system

CW Cooling waterCT Cooling towerCWST Cooling water storage tank


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Development of a tool for simulating

Performance of sub systems of a combined cycle power plant

1 Introduction ............................................................................................................................12

1.1 Overview ............................ ............................. .............................. ............................. .................................. 12

1.2 Objective of the project........... ............................. .............................. ............................. ................................ 12 1.2.1 Present scenario ............................................................................................ ............................... .. 12 1.2.2 Proposed system.............................................................................................................................13

1.3 Data gathering ............................ ............................. .............................. ........................................ .............. 13

1.4 Methodology ............................ .............................. ............................. ....................................... ................... 13

2 Literature survey......................................................................................................................15

2.1 Gas turbine............................. .............................. ............................. ....................................... ................... 15

2.2 Brayton cycle.......... ............................. .............................. ............................. ..................................... .......... 15

2.3 Development of gas turbine ............................ .............................. ............................. .................................... 17

2.4 Applications of gas turbines .......................... .............................. ............................. ..................................... 17

2.5 Performance of gas turbine ............................. .............................. ............................. .................................... 18 2.5.1 Atmospheric temperature.. .................................................................................... ........................ 18 2.5.2 Atmospheric humidity .................................................................................. .................................. 18 2.5.3 Fuel type ............................................................................................ .................................. ........... 19 2.5.4 Steam or water injection .................................................................................... ............................ 20 2.5.5 Air extraction ...................................................................................... ................................. ........... 20

2.6 HRSG ............................. .............................. ............................. .............................. .................................. 20

2.7 Steam turbine... ............................. ............................ ............................. ........................................ .............. 21 2.7.1 Classification of steam turbine ................................................................................... .................... 21

2.7.1.1 Condensing and non condensing steam turbines..................................................................21 2.7.1.2 Single and double flow steam turbines..................................................................................22 2.7.1.3 Impulse and reaction steam turbines .................................................................................... 22

2.8 Condenser...................... ............................. .............................. ............................. ....................................... 23 2.8.1 Direct contact condensers.............................................................................. ................................ 23 2.8.2 Surface condensers.........................................................................................................................24

2.9 Cooling towers .......................... .............................. ............................. ...................................... ................... 25 2.9.1 Wet cooling towers.................................................................................................. ....................... 25 2.9.2 Dry cooling towers..........................................................................................................................26

3 Plant overview ........................................................................................................................ 27

3.1 Preface..........................................................................................................................................................27

3.2 Heat recovery steam generator (HRSG)........................................................................................................28

4 Fuel system ............................................................................................................................ 29

4.1 Fuel storage ............................ .............................. ............................. ........................................ ................... 29

4.2 Fuel centrifuge ............................ .............................. .............................. ....................................... ............... 30

4.3 Fuel forwarding system ........................... ............................. ............................ ......................................... .... 31


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4.4 Gas turbine fuel oil skid............................. .............................. ............................. ....................................... 32 4.4.1 Fuel flow meter...............................................................................................................................32 4.4.2 Fuel filter............................................................................ ............................................. ................ 32 4.4.3 Fuel accumulator .................................................................................... ...................................... .. 32

5 Gas Turbine............................................................................................................................ 33

5.1 Gas turbine building........................... ............................... .............................. .................................... ......... 33 5.1.1 Accessory compartment .................................................................................... ............................. 33 5.1.2 Turbine compartment.....................................................................................................................33 5.1.3 Exhaust compartment .......................................................................... .......................................... 35 5.1.4 Load compartment ..................................................................................... .................................. .. 35 5.1.5 Generator compartment ................................................................................................................35

5.2 Air intake system....... ............................. ............................ ............................ ........................................ ..... 36

..................................................................................................................................................................................36

5.3 Gas turbine auxiliary systems.......................................................................................................................36 5.3.1 Gas turbine accessory gearbox.......................................................................................................36 5.3.2 Fuel injection system .................................................................................... .................................. 36

5.3.2.1 Fuel pump ......................................................................................... .................................... . 37 5.3.2.2 High pressure fuel filter .........................................................................................................37

5.3.3 Lubrication oil system.....................................................................................................................37 5.3.4 Atomizing air system.......................................................................................................................37 5.3.5 Gas turbine cooling water system ........................................................................ .......................... 37

6 Heat recovery steam generator (HRSG)................................................................................ 39

6.1 Low low pressure (LLP) circuit....................................................................................................................39

6.2 Low pressure (LP) circuit.............................................................................................................................40

6.3 High pressure (HP) circuit ............................ ............................ ............................. ...................................... 41

7 Steam turbine ......................................................................................................................... 43

8 Condensate system................................................................................................................. 46

9 Cooling water system ............................................................................................................. 49

10 SWAS (Steam water analysis system) ......................................................................................51

11 System modelling ................................................................................................................... 52

11.1 Combined cycle heat rate ........................... ............................ ............................ ........................................ .... 52

11.2 Gas turbine efficiency .............................. ............................. .............................. ...................................... ..... 53 11.2.1 Gas turbine cooling water system........................ ...................................................................... 53 11.2.2 Gas turbine fuel energy................................................................................. ............................. 54 11.2.3 Gas turbine electrical power ............................................................................... ....................... 55 11.2.4 Gas turbine steam injection ................................................................................. ...................... 55 11.2.5 Gas turbine air intake and exhaust.............................................................................................55 11.2.6 Gas turbine compartment convective losses ............................................................................. 56 11.2.7 Gas turbine ventilation system...................................................................................................57

11.2.7.1 Turbine compartment ventilation system.........................................................................58 11.2.7.2 Exhaust compartment ventilation system.........................................................................58 11.2.7.3 Load compartment ventilation system..............................................................................59

11.2.8 Gas turbine efficiency.................................................................................................... ............. 59 11.2.9 Gas turbine compressor .......................................................................... ................................... 60 11.2.10 Heat recovery steam generator (HRSG) ....................................................................... .............. 61


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11.2.10.1 HRSG modules .................................................................................... ............................... 64 11.2.10.1.1 HP Economizer ............................................................................ ................................. 65 11.2.10.1.2 HP Economizer 1 ..........................................................................................................65 11.2.10.1.3 HP Economizer 3 ..........................................................................................................65 11.2.10.1.4 HP Super heater 2 ........................................................................................................66 11.2.10.1.5 HP Super heater 1 ........................................................................................................66 11.2.10.1.6 HP evaporator .............................................................................. ................................ 67 11.2.10.1.7 LP economizer......... .................................................................................... ................. 67 11.2.10.1.8 LP evaporator ............................................................................... ................................ 67 11.2.10.1.9 LP supper heater ........................................................................................... ............... 68 11.2.10.1.10 LLP evaporator ...........................................................................................................68

11.3 Steam Cycle................... ............................. ............................ ............................ .......................................... 69 11.3.1 Steam Turbine efficiency............................................................................................................70 11.3.2 Steam Turbine isentropic efficiency...........................................................................................71 11.3.3 Condenser efficiency................................................................................... ............................... 71

12 Software architecture.............................................................................................................. 72

12.1 Data processing ........................... ............................ ............................. .......................................... .............. 72 12.2 EES program structure ............................ ............................ ............................. ....................................... .... 74

13 Analysis and results................................................................................................................ 76

13.1 Performances comparison 2007 vs. 2011......................................................................................................76 13.1.1 Heat rate.....................................................................................................................................76 13.1.2 Gas turbine efficiency.................................................................................................... ............. 77 13.1.3 Compressor isentropic efficiency of gas turbine........................................................................77 13.1.4 Turbine isentropic efficiency of gas turbine...............................................................................78 13.1.5 HRSG efficiency ..........................................................................................................................79 13.1.6 Steam cycle efficiency ................................................................................... ............................. 79 13.1.7 Heat transfer in the HP economizer 1 at full load......................................................................80 13.1.8 Heat transfer in the HP super heater 1 at full load .................................................................... 81 13.1.9 Heat transfer in the HP super heater 2 at full load .................................................................... 81 13.1.10 Heat transfer in the HP evaporator ............................................................................................ 82 13.1.11 Heat transfer in the LP economizer............................................................................................82 13.1.12 Heat transfer in the LP evaporator.............................................................................................83 13.1.13 Heat transfer in the LP supper heater........................................................................................83 13.1.14 Heat transfer in the LLP evaporator .......................................................................... ................. 84

13.2 Effects of NOx flow ........................... ............................ ............................. ........................................ ......... 85 13.2.1 Heat input to GT from NOx steam.................................................................................. ............ 85 13.2.2 Gas turbine power output..........................................................................................................86 13.2.3 Gas turbine efficiency.................................................................................................... ............. 86 13.2.4 Steam turbine power out .......................................................................... ................................. 87 13.2.5 Steam cycle efficiency ................................................................................... ............................. 88 13.2.6 Heat transfer in Condenser .................................................................................. ...................... 88 13.2.7 Plant overall heat rate................................................................................................................89

14 Discussion and Conclusions .................................................................................................. 90

14.1 Heat Rate ............................ .............................. ............................. .............................. ............................... 90

14.2 Gas turbine............................. .............................. ............................. ....................................... ................... 90

14.3 HRSG ............................. .............................. ............................. .............................. .................................. 90

14.4 Steam cycle .......................... ............................. .............................. ............................. ................................. 90

14.5 Heat transfer in the condenser.......................................................................................................................91


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14.6 Waste heat recovery potential .............................. ............................. .............................. ............................... 91

15 Annexure ................................................................................................................................ 93

15.1 Enthalpy of air and gasses from light fuel oil combustion ............................ ............................ ....................... 93

15.2 Typical pretest stabilization period................................................................................................................95

15.3 Heat rejection form gas turbine ventilation system..........................................................................................96

16 Reference................................................................................................................................ 97


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1 Introduction

1 . 1 O v e r v i e w Total grid installed capacity of Sri Lanka is around 2818MW [1], and thermal and hydro power plants areproviding significant amount of electricity into the grid.

Installed capacityEnergysource 2009 2010

Hydro 1379 1383 Thermal 1290 1390Renewable 15 45

Total 2684 2818Installed capacities of Sri Lanka [1]

Electricity generation cost is directly associated with the generation efficiency, thus requiring the sustenanceof power generation efficiency at satisfactory level with the provision of financial as well as environmentalbenefits. Poor generation efficiency results from ageing of equipment, equipment malfunction or designfaults. Thus, it is necessary to monitor efficiency precisely and continuously because variations can be iden-tified and possible corrective action can be taken to bring back the efficiency to original level.

In a thermal power plant, a performance index called heat rate, which is the reciprocal of the efficiency, isused to measure the performance of the plant instead of thermal efficiency.

Heat Rate = Heat energy consumed during fuel combustion (kJ) / Electrical Energy produced (kWh)

1 . 2 O b j e c t i v e o f t h e p r o j e c t Thesis research was done in one of the combined cycle power plant, which is 163MW in capacity, in SriLanka.

1 . 2 . 1 P r e s e n t s c e n a r i oPresently, heat rate is calculated on a monthly basis using monthly fuel consumption and electrical energyproduction. But, this figure does not reflect a correct picture on the thermal performance of the plant dueto the following reasons.

According to the demand the plant load is controlled and, generally, during day time the plant runs at fullload whereas, at night, operates at part load or shut down. When the plant operates at part load, efficiencyis less and higher heat rate exists. Thus, when heat rate is calculated on using monthly fuel consumptionand monthly electrical energy production, only a generalized value can be obtained for the entire operatedload spectrum. Hence, above heat rate varies with the monthly plant load factor.

During plant start-ups significant amount of fuel consumption takes place affecting the heat rate in terms ofthe number of start-ups that take place during the month.

Due to above reasons heat rate, which is calculated using present method, fluctuates from month to month.

Thus, it is not possible to get a clear picture regarding the actual efficiency of the plant, hence not possible

to compare the present performance of the plant with the past figures. One objective of this project is todevelop a system which will calculate the heat rate excluding part load conditions and star-up.


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Thus, the system was modelled to record the indices related to macroscopic performances as well as micro-scopic performance of the power plant.

The system modelling was carried out using EES (Engineering equation solver) software. This software wasselected based on availability of the software, user friendliness, and the possibility to link the software withMicrosoft excel.


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2 Literature survey

2 . 1 G a s t u r b i n eBrayton cycle, which is the fundamental concept behind the gas turbine, was first proposed by GeorgeBrayton in 1870. The cycle consists of four reversible processes. [2]

Figure 2.1: Elements of gas turbine

2 . 2 B r a y t o n c y c l e

1-2 Isentropic compression (in a compressor) 2-3 Constant pressure heat addition 3-4 Isentropic expansion (in a turbine) 4-1 Constant pressure heat rejection

Figure 2.2: P-v and T-s diagrams of Brayton cycle

Work input in the compressor inW=

)1h2(hair minW = &

Work output from the turbine outW=


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)4h3(hair moutW = &

Heat input inQ=

)2T3(Tcpair m)2h3(hair minQ == &&

Heat rejection outQ=

)1T4(Tcpair m)1h4(hair moutQ == &&

Thermal efficiency of ideal Brayton cycleQin

inWoutW

= Brayton

Applying steady state steady flow equation to whole system

Qout-QinWW inout =

2T3T1T4T1

QinQout

1

==

Brayton

Process 1-2 and 3-4 isentropic

K 1-K

P1P2

T1T2 = K

1-K

P4P3

T4T3 = K - Specific heat ratio

P3P2 = P4P1 =

K 1-K

P1P2

11 = Brayton

Thus according to the ideal Brayton cycle, efficiency of a gas turbine depends on pressure ratio and the spe-cific heat ratio of air. When pressure ratio increases, cycle efficiency raises. But, it is necessary to maintaintemperature at point 3 below a certain value which is the maximum possible temperature that the turbineblade can withstand.

Net work output increases with increasing pressure ratio, and start decreasing after reaching a maximum value. Hence, it is necessary to compromise thermal efficiency and the net work output.

Performance indicator called heat rate is used in thermal power industry instead of thermal efficiency.

)()(

kWh produced Energy ElectricalkJ combustion fuelduringconsumed Energy Heat

Rate Heat =

Thus heat rate has units, and when thermal efficiency increases with decreasing heat rate.


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Figure 2.3: T-s diagrams of actual gas turbine cycle

1h2ah1h2sh

,

=

compressor iso 4sh3h4ah3h

,

=

turbineiso

Process of an actual gas turbine deviates from ideal Brayton cycle due to following two reasons.

Brayton cycle consists of four processes, but in reality constant pressure heat rejection does not take-place inside the gas turbine. Instead, flue gas coming from the turbine is exhausted to the atmosphere, andfresh air is inducted into the compressor from the atmosphere.

Second reason for the deviation is the presence of irreversibilities in an actual gas turbine. Actual work in-put of the compressor is higher than the ideal conditions, and the actual work output of the turbine is lessthan the ideal conditions. Deviation of the actual process from the ideal condition can be analysed using is-entropic efficiencies of the turbine and the compressor. Apart from above mentioned irreversibilities, pres-sure drops during heat addition and heat rejection also take place. [3]

2 . 3 D e v e l o p m e n t o f g a s t u r b i n eGas turbine started to evolve rapidly since 1930. Efficiencies of compressor and turbine of early gas tur-bines were relatively lower; and the turbine inlet temperature could not be increased due to metallurgicallimitations. Hence, efficiencies of early gas turbines were around 17 percent.

Many research works were done to improve the efficiency of gas turbine, and it was possible to increase theturbine inlet temperature due to the invention of new cooling techniques and materials. Today turbine inlettemperature of a gas turbine is around 1425 oC, and in 1940s this value was around 540oC. But, at highercombustion temperatures, NO x formation is significant, and hence steam injection was carried out intocombustion chamber to reduce the flame temperature; and thus NO x formation reduces.

Other than turbine inlet temperature, efficiencies of components of gas turbine were improved in order toincrease the overall efficiency of gas turbine.

Intercooling, regeneration, and reheating were also used to improve the overall efficiency of gas turbine [4].

2 . 4 A p p l i c a t i o n s o f g a s t u r b i n e sGas turbines are used in many industries such as power generation, aircraft, ships, helicopters, locomotives,and even in automobiles. Power to weight ratio of gas turbine is very high compared to reciprocation en-gines. At higher altitudes performance of gas turbine is much higher than a reciprocating engine, and hencegas turbines are very popular in aeronautical industry.

Gas turbines are generally more expensive than reciprocation engines, and efficiency of a gas turbine variesdrastically with varying shaft rpm. Hence gas turbines are not very attractive for automobile industry, andless popular. [5]


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2 . 5 P e r f o r m a n c e o f g a s t u r b i n e

2 . 5 . 1 A t m o s p h e r i c t e m p e r a t u r ePower output of a gas turbine varies with the mass flow rate, thus performance of a gas turbine significantlydepends on the density of atmospheric air which means ambient temperature plays a vital role regarding theperformance of gas turbine. When ambient temperature increases density drops; and this cause power out-

put and efficiency drop. Thus, it is not possible to compare heat rates, which were calculated in two differ-ent occasions, of a particular gas turbine, unless ambient temperatures are same for both occasions. But aconcept called corrected heat rate is used in thermal power industry as solution for the above problem.

Actual heat rate that is also called uncorrected heat rate is divided by a factor called ambient temperaturecorrection factor to obtain the corrected heat rate. This correction is only for ambient temperature.

retemperatuambient

forfactor Correction

rateheatActual

e)temperatur ambientforcorrected(rateheatCorrected =

This correction factor is function of ambient temperature, and it compensates the effects of ambient tem-perature from the heat rate. This correction factor depends on the type and the model of the gas turbineand manufacturer specify the correction factors. [6]

Figure 2.4: Effect of ambient temperature

2 . 5 . 2 A t m o s p h e r i c h u m i d i t ySimilarly relative humidity also affects the performance of the gas turbine. Since, density of humid air is lessthan the density of dry air, power out drops with increasing relative humidity. Heat rate also increases whenrelative humidity rises. It is possible to compensate the effects of relative humidity on dividing the actualheat rate by the relative humidity correction factor. [6]

humidityrelative

forfactor Correction rateheatActual

humidity)relativforcorrected(rateheatCorrected =


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Figure 2.5: Effect of relative humidity

2 . 5 . 3 F u e l t y p e Work output of a gas turbine depends on the specific heat capacity ( cp ) of the combusted gas.

)1T4(Tcpair m)1h4(hair moutQ == &&

This specific heat capacity of the combusted air depends on the fuel composition, and hence fuel type alsoone of the major factor that can vary the performance of the gas turbine. [7]

Figure 2.6: Effect of relative humidity


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2 . 5 . 4 S t e a m o r w a t e r i n j e c t i o nIn modern gas turbines water or steam injection is carried out into the combustion chamber in order to re-duce the NOx generation. Since, this is an additional mass flow; output of the gas turbine increases with thesteam (or water) injection. When water is injected, some amount of heat is absorbed by the water, in orderto raise the temperature to combustor condition. Thus, heat rate deteriorates when water is used for NOxreduction. When steam is used for NOx reduction, heat rate improves if the heat consumed to produce thesteam is neglected. But, in most of the applications this heat cant be neglected, and hence heat rate get

worse even when steam is used for NOx reduction. [8]

Figure 2.7: Effect of steam injection into gas turbine

2 . 5 . 5 A i r e x t r a c t i o nCompressor of the gas turbine consists of number of stages, and in each stage air pressure increases. Hence,pressure of the 1 st stage is at the lowest pressure and the pressure of the last stage is at highest. Hence, it ispossible to extract air from various stages of compressor; and extracted air can be used for applicationssuch as bearing sealing, turbine blade cooling, atomizing air for combustion etc. When air extraction in-creases, mass flow rate through the turbine decreases, and turbine out put power drop.[8]

2 . 6 H R S GHeat recovery steam generator (HRSG) can be considered as a heat exchanger which recovers heat fromhot gas in order to produce steam. In combined cycle power plants, heat recovery steam generators areused to recover heat from the gas turbine exhaust, and to generate steam that rotates the steam turbine.Cogeneration plants also use heat recovery steam generators to manage energy in an efficient manner.

HRSG consist of three main components called economizer, evaporator and supper heater. Water that is atsub cooled state enters the economizer, and the exit condition is very close to saturated liquid state. In theevaporator, saturated water becomes saturated steam that will be further heated inside the supper heater toproduce super heated steam.

Finally flue gas, from which, heat absorbed into the circulation fluid, goes to the atmosphere through theHRSG stack.

HRSGs can be classified into two types. HSRGs, in which, flue gas flows vertically, are called vertical typeHRSGs. Similarly in horizontal type, HRSG flue gas flow takes place horizontally.


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Figure 2.8: Vertical HRSG

The main advantage of the vertical HRSG is that it requires comparatively less land area. Some HRSGs areassociated with supplementary firing unit which supplies more heat into the HRSG, and thereby producemore steam. Some power plants often use supplementary firing to cater peak demand.

Some power plants have additional stacks to bypass the HRSG if required. In this type of a plant, a diverter valve is installed in the bypass stack entrance, to control the flue gas. This allows operating the gas turbine, with out HRSG in operation. [9]

Most of the HRSGs have drums which are used for several functions.

1) Acts as a water storage2) Helps to maintain the chemical balance of the working fluid3) Separate water and steam

2 . 7 S t e a m t u r b i n eSteam turbine is a device that absorbs energy from steam and coverts into mechanical work. Initially recip-rocation piston steam engines were used in the industry, and later rotary steam turbines became popular

due to its advantages over reciprocating type. Efficiency and power to weight ratio of rotary steam turbineare higher compared to reciprocation piston steam engines. [10]

2 . 7 . 1 C l a s s i f i c a t i o n o f s t e a m t u r b i n eSteam turbine can be classified in many different manners.

2 . 7 . 1 . 1 C o n d e n s i n g a n d n o n c o n d e n s i n g s t e a m t u r b i n e sIn condensing steam turbines exhaust pressure is maintained below atmospheric pressure. This type ofsteam turbines is commonly used in power plants, and steam quality of the exhaust is generally around90%. Exhaust pressure of non-condensing steam turbines is at higher pressure than the atmosphere, andthis type of steam turbines is commonly used in refineries, district heating units, pulp and paper plants, and

desalination facilities. In these steam turbines, exhaust is used in the process.


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2 . 7 . 1 . 2 S i n g l e a n d d o u b l e f l o w s t e a m t u r b i n e sSteam flow produces forces on both tangential and axial directions, and tangential force generates a torque

which rotates the turbine. The axial thrust is imparted onto the structure that holds the entire steam turbineassembly by mean of a thrust bearing, and this axial thrust increases with increasing turbine capacity. Indouble flow steam turbines, steam injection taken place at the center of the shaft and leaves at both ends.

Figure 2.9: Double flow steam turbine

The blades of a one half of the turbine face the opposite direction of the blades of the other half. Hence,tangential forces of both haves generate a torques on the same direction while the thrust force of one halfof the steam turbine compensates the thrust force of the other half of the steam turbine.

Figure 2.10: Double flow steam turbine [10]

2 . 7 . 1 . 3 I m p u l s e a n d r e a c t i o n s t e a m t u r b i n e sIn impulse turbines, velocity of steam increases as it flows through the nozzle. Hence, pressure drop takenplace across. Exit steam of the nozzle impinges upon the blade of the turbine and cause deflection. Thiscreates a momentum reduction in the steam jet, and hence momentum of the blade rises. Across the blade,no pressure drop take-place, and only velocity change exists.


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Figure 2.11: Impulse and reaction steam turbines [10]

In reaction turbines, velocity of steam increases and pressure drops in the nozzle similar to impulse turbine.But as the steam flows across the blade both velocity and pressure drops in the axial direction. This createsa pressure difference across the blade in the tangential direction, and hence a torque generates around theshaft. [11]

2 . 8 C o n d e n s e r The main objective of a condenser is to act as a heat exchanger on transferring heat from steam turbine ex-haust to cooling water. Due to heat transferring process, steam turbine exhaust get condensed in the con-denser. Condensers are mostly associated with a temporally condensate storage called hot well, into which,condensate flows from the condenser. [12]

Condensers can be categorized into two main types as follows.

a) Direct contact condensersb) Surface condensers

2 . 8 . 1 D i r e c t c o n t a c t c o n d e n s e r s

In this type of condensers, cooling water and condensate directly mix inside the condenser, and hence there

is only one out flow stream. This type of condensers can be categorized into three sub types as spray con-denser, barometric condenser and jet condenser.

In spray condensers, cooling water is sprayed into the steam. In the barometric condensers, cooling waterfalls down through baffles, and steam inlet is located underneath these baffles. Steam gets condensed, andthe mixture flows out through a tail pipe that is located at the bottom of the condenser. Only difference be-tween barometric condenser and jet condenser is that tail pipe is replaced with a diffuser in the jet condens-ers. This diffuser raise the inside pressure within short distance.


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Figure 2.12: Spray condenser [13]

Figure 2.13: Barometric condenser [14]

2 . 8 . 2 S u r f a c e c o n d e n s e r sIn contrast to direct contact type, mixing is not taken place in surface condensers, and there are separate

two inlets and separate two outlets. In power plants, these types of condensers are frequently encountered,and they are essentially shell and tube heat exchangers. Steam flow outside the tubes, and cooling waterflows inside the tubes.

Figure 2.14: Surface condenser [15]


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2 . 9 C o o l i n g t o w e r sCooling towers are used to cool the water that comes from the condenser, and cooling towers can be cate-gorized into two main types as wet type and dry type. [16]

2 . 9 . 1 We t c o o l i n g t o w e r s

Figure 2.14: Wet cooling tower [17]

In this type of cooling towers, hot water spreads over a net of slats or bars called packing, through which, water flows downwards. Atmospheric air enters into the cooling tower through louvers that are located atbottom of the cooling tower, and leaves from the top. Thus, air and water flows in counter directions, andthis will allow mixing water and air thoroughly. During the mixing process, water evaporates, and due toabsorption of latent heat water gets cooled. Other than due to evaporation, convection heat transfer takesplace from surfaces of the water droplets to the air. Cold water collects in a basin called cooling tower basin

at the bottom of the tower.It is possible to again categorized wet cooling tower into two sub types, forced draught (FD) and induceddraught (ID). Forced draught type cooling towers are associated with fans that creates the air flow.

Density of air that is in the cooling tower is less than the out side air, and this density difference creates aflow through the cooling tower, and in forced draught cooling towers this natural air flow is sufficient toprovide the cooling effects.

Water evaporation in wet cooling towers is significant, and hence considerable amount of make-up watermust be supplied into the cooling tower basin in order to maintain the water level. Dry type cooling towerare used when it difficult to maintain such a large amount of make-up water.


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2 . 9 . 2 D r y c o o l i n g t o w e r s

Figure 2.15: Wet cooling tower [18]

Dry cooling towers consist of finned tubes, in which, warm water flows, while air flow is taken place out-side of the tubes. Thus, heat transfers from warm water to air, through the finned tube walls. In dry coolingtowers air flow is maintained by means of fans.


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3 Plant overview

Figure 3.1: Plant overview

3 . 1 P r e f a c e The plant consists of one gas turbine, heat recovery steam generator (HRSG) and a stem turbine.

A water treatment plant, which is installed in the same premises, is fulfilling the water requirement of thepower plant, and effluent treatment is also carried out in this water treatment plant. Fuel oil purification iscarried out using centrifuges, and these centrifuges are also located in the premises of the water treatmentplant.

HRSG consists of three fluid circuits which are used to heat the working fluid (water); and three differentpressure levels are maintained in these circuits

Apart from HRSG, there are number of other sub systems which are associated with the power generationprocess.

1) Condenser - Exhausted steam, which are coming from the steam turbine, condense inside the con-denser.

2) Feed water pumping system Pumping system is used for water circulation3) Cooling towers Cooling water, which is used in the condenser, cools in cooling towers4) Cooling water pumping system High capacity cooling water pumps were installed in the power plant

to maintained cooling water circulation through condenser and the cooling towers.5) Lubrication oil system of gas turbine Turbine shaft is mounted on six journal bearings. Lubricating oilis pumped into these bearings and oil layer is maintained between shaft and the bearing metal surface.

A cooling system is placed to extract heat from the lubrication oil.


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6) Hydraulic oil system of gas turbine Hydraulic oil is in placed to drive some equipment of the gas tur-bine.

7) Fuel system Fuel system is installed to maintain fuel flow of the gas turbine.8) Lubrication oil system of steam turbine9) Hydraulic oil system of steam turbine

Gas turbine capacity of the plant is 110MW; where as the capacity of the steam turbine is 57MW, and netpower output at rated condition is 163MW. The flue gas coming from the gas turbine goes to the HRSG(Heat recovery steam generator) via a by pass damper which is a two way damper. Bypass damper can beused to divert the flue gas into bypass stack while blocking the flue gas path to HRSG. It can also be usedto send the flue gas into HRSG having blocked the bypass stack. During the plant start up, heat exchangermodules of HRSG may not filled with the water, and it is not be possible to heat the HRSG until the heatexchanger modules get filled with water. Therefore during the plant start up, flue gas is diverted through thebypass stack, until HRSG heat exchanger modules are filled. Another purpose of the by pass damper is tostop the heat input to the HRSG immediately, in case of an emergency shutdown.

3 . 2 H e a t r e c o v e r y s t e a m g e n e r a t o r ( H R S G )HRSG consists of three fluid circuits which are used to transfer working fluid (water); and three differentpressure levels are maintained in these circuits. Circuit, which maintains the highest pressure, is calledhigher pressure (HP) circuit, and the pressure inside this circuit is around 100bar. Circuit, which maintainthe lowest pressure, is called Low Low pressure (LLP) circuit and the pressure in side this circuit is around1.8bar. The other circuit is called low pressure (LP) circuit, and it maintains intermediate pressure around15.5bar. There are three drums that are associated with each circuit, and these drums are called HP drum,LP drum, and LLP drum.

Steam turbine exhaust is cooled using condenser, and the bottom part of the condenser is called hot well,and it contains condensate. This condensate is pumped back to the LLP drum by means of condensate ex-traction pumps (CEP). Separate demineralised water supply line is connected to hot well for makeup waterrequirement.

Water pumped from LLP drum to HP drum using high pressure boiler feed pumps (HPBFP), and similarly water is pumped from LLP drum to LP drum by low pressure boiler feed pumps (LPBFP). High pressureand low pressure steam, which are coming form HP and LP circuits, are injected into the gas turbine.

Steam, which is at 24bar, is extracted from the steam turbine, and injected into gas turbine in order to limitthe combustion temperature. This is because NO X generation is high at higher combustion temperature,and hence in normal operating conditions steam injection is carried out into gas turbine to achieve envi-ronmental standard.

Similarly, steam, which is at 5bar, is extracted from the steam turbine, and injected into LLP drum for preheating. Deration also taken place in the LLP drum due to steam injection.


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4 Fuel system

4 . 1 F u e l s t o r a g e

Figure 4.1: Fuel storage system

High speed diesel (HSD) is used as the fuel for power generation in the power plant, and this fuel is storedin storage facility which consists of two raw fuel tanks and two treated fuel tanks. Each tank is 6100m 3 incapacity.

Fuel that is taken from the fuel supplier is pumped into raw fuel tank through a filter which used to carryout preliminary filtering process. But this filtering process is not sufficient for combustion in the gas tur-bine. Hence, fuel, that is stored in raw fuel tanks, is pumped via centrifuges, where further purificationtaken place, into treated fuel tanks.

For every fuel delivery, fuel suppler provides a lab report regarding the fuel quality, and this report gives thehigher heating value of fuel. Usually when level of a raw fuel tank, goes below 5-10m, new fuel delivery isstarted. Hence, fuel from the new delivery mixed with fuel from the previous delivery in the raw fuel tanks.

Thus, mixture of fuel from different deliveries, are stored in the raw fuel tanks. Hence, higher heating valuegiven in the lab report is different from the actual heating value of fuel that is used in the gas turbine.

But for the analysis it is necessary to know the higher heating value of the fuel. Hence, it was started takingfuel samples from the fuel tanks, in order to measure the actual higher heating value of the fuel. Thesesamples are sent to an industrial laboratory to measure the higher heating value. Presently fuel sample istaken after every fuel tank change-over as an operational practice. This new practice was initiated due torecommendations raised after the project.


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Advantages of fuel centrifuge [19]

Reduce high temperature corrosion Reduce ash fouling deposits Remove trace metal contaminants Water Separation

Filtration of fuel to remove solid oxides, silicates and other harmful contaminants

4 . 3 F u e l f o r w a r d i n g s y s t e m

Figure 4.4: Fuel forwarding system

Centrifuged fuel that is stored in treated fuel tanks is pumped to gas turbine fuel oil skid. Two fuel forward-ing pumps, which are parallel, are used to pump fuel from treated fuel tanks to gas turbine fuel oil skid.

When the power plant is running, only one fuel forwarding pump is in operation, and the other one acts asthe standby pump. Return line is connected to pump discharge line, and fraction of fuel returns to treatedfuel tank. A control valve, which is located in this return line, controls the fuel supply pressure.


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Figure 4.5: Duplex fuel filter

Fuel filter, which is 40micron in filtration rating, is used in the suction side of the forwarding pumps. Thisfuel filter is duplex type which means two filters are connected in parallel, and one filter is in operation andthe other one acts as a standby filter. With time, particles accumulate inside the filter, and this cause higherdifferential pressure between the filter, and when this differential pressure rise beyond 0.5bars filter changeover must be done. This filter change over can be done without interrupting the fuel flow. Similar filter,

which is 20micron in filtration rating, is used in the discharge side of the forwarding pumps for further pu-rification.

4 . 4 G a s t u r b i n e f u e l o i l s k i dFuel forwarding system pumps fuel to gas turbine fuel oil skid, which consists of flow meter, fuel accumula-tor, and the duplex fuel filter.

4 . 4 . 1 F u e l f l o w m e t e rFuel flow meter is used to measure the fuel flow rate of the gas turbine. As far as energy analysis is concern,this meter is very important, since total energy input to the plant can be calculated using this flow meter.

4 . 4 . 2 F u e l f i l t e r After fuel flow meter, another duplex filter is located in the fuel line for the filtration, and it uses 5 micronpaper elements for filtration.

4 . 4 . 3 F u e l a c c u m u l a t o rIn case of an emergency shutdown of the plant, a valve called fuel oil stop valve (FOSV) which is in thedown stream of the gas turbine fuel oil skid, closed immediately in order to stop the fuel flow into gas tur-bine. When this happened, pressure inside the fuel line rises momentarily. This sudden pressure rise isdampened by the fuel accumulator which is connected to the outlet of the filter.


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5 Gas Turbine

5 . 1 G a s t u r b i n e b u i l d i n g All the equipments associated with the gas turbine are located in the gas turbine building, and equipmentcontained in several compartments called accessory compartment, turbine compartment, load compart-ment, and generator compartment.

5 . 1 . 1 A c c e s s o r y c o m p a r t m e n t There are several auxiliary systems such as fuel injection system, lubrication system, atomizing air system,hydraulic system, turning gear system, starting system, and these systems are necessary for the operation ofthe gas turbine. Most of the electrical and mechanical equipments of above auxiliary systems are contained

within the accessory compartment.

5 . 1 . 2 T u r b i n e c o m p a r t m e n tCompressor, turbine, combustion wrapper and some auxiliary equipment are contained within the turbinecompartment. Fuel is injected into compressor discharge through units called combustion cans, and thereare fourteen number of combustion cans in the turbine compartment. Main fuel supply line splits into four-teen numbers of sub lines, and provide fuel for combustion cans.

In order to combust, liquid fuel must be atomized, and this is done by injecting fuel and pressurized airthrough a nozzle at a high velocity. This pressurized air is called atomizing air, and a compressor, which isin the accessory compartment, provides atomizing air for combustion cans.

There are 17 numbers of compression stages in the compressor, and each stage consists of stationary bladeand a rotary blade. When air flows through these compression stages air get compressed, and compressordischarge pressure is around 10.5bar when plant is at full load. This compressed air then comes to a cham-ber called combustion wrapper.

Figure 5.1: Stationary blades of the compressor during maintenance work


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Figure 5.2: Rotary blades of the compressor during maintenance work

This combustion wrapper is the source, which provides the secondary air to the combustion cans. Atomiz-ing air, which is the primary air, and liquid fuel also enters into combustion cans, in which, combustion takeplace. Then heated air and combustion products are directed to the turbine.

There are three number of turbine stages exists in the turbine; each stage consists of stationary blade and arotary blade. This stationary blade, which is also known as turbine nozzle, changes the direction of air flow.Energy transfer takes places in the rotary blades which are also known as buckets.

Figure 5.3: Nozzles and buckets

First stage nozzles and buckets are exposed to very high temperature, and hence cooling air flow is main-tained through these nozzles and buckets.

Third stagebucket

Second stagebucket

First stagenozzle


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Figure 5.4: Nozzles and buckets

At high combustion temperatures NOx generation take place, and hence steam is injected onto the flame ofthe gas turbine to reduce NOx generation. This is called NOx steam, and a steam header that comes fromsteam cycle provides NOx to combustion cans of the gas turbine.

5 . 1 . 3 E x h a u s t c o m p a r t m e n tGas turbine exhaust goes into the HRSG through a duct that is right-angles to the axis of the gas turbine.

Thus, flow direction of flue gas must be changed by 90degree angle, and this is done by the exhaust plenum which is located inside duct close to the gas turbine outlet.

The segment of the duct, which contains the exhaust plenum, is enclosed by another compartment calledexhaust compartment.

5 . 1 . 4 L o a d c o m p a r t m e n tGas turbine shaft and the turbine shaft are connected by a coupling called load coupling, and it is located inthe load compartment.

5 . 1 . 5 G e n e r a t o r c o m p a r t m e n t The main item in the Generator compartment is the generator which is driven by the gas turbine. Since, thisgenerator is driven by the gas turbine it is called gas turbine generator.

First stage bucket Second stage bucket Third stage bucket

Second stage nozzle Third stage nozzle


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5 . 2 A i r i n t a k e s y s t e m

Figure 5.5: Filter house

Air, that is necessary for the gas turbine, is taken through a compartment, which is located outside the gasturbine building. This compartment is known as filter house, and there are two types of filter elements in-side the filter house. Initially air comes through pre filter elements, and then goes through fine filter ele-ments. Both pre and fine filters are 5microns in filtration rating. But some dust partial, which could not beblocked by the pre filter, are trapped in the fine filter. Differential pressures across both pre and fine filterelements are measured electronically, and recorded in the control room data base. When filter elements getchoked, this differential pressure rises, and 60mmWC is the alarm limit for filter replacement.

5 . 3 G a s t u r b i n e a u x i l i a r y s y s t e m s

5 . 3 . 1 G a s t u r b i n e a c c e s s o r y g e a r b o xSome equipment such as fuel pump, main oil pump, and atomizing air compressor are driven by the acces-sory gear box, and the input shaft of the gear box is coupled with the gas turbine shaft. Thus, accessory gearbox takes input power from the gas turbine shaft.

5 . 3 . 2 F u e l i n j e c t i o n s y s t e mFuel injection system is mainly consists of fuel stop valve, fuel pump, higher pressure fuel filter and theflow divider. All these equipment are in the accessory compartment.


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Temperature of turbine support legs are maintained around 40 oc. This is to limit the expansion whichcould cause misalignment. Hence, turbine support legs are surrounded by jackets, through which, cooling

water flow. Hence, heat transfers from turbine support legs to cooling water; and temperature of turbinesupport legs are maintained in an acceptable range.

There are four flame detectors that are used to measure the intensity of the flames inside the gas turbine. These flame detectors are also cooled using cooling water.

Fuel pump has inbuilt lubrication system which supplies lubrication oil to fuel pump.

Finally the heated cooling water is cooled using an off-base cooling water module witch comprise of radia-tor (heat exchanger) bank, fans, pumps, surge tank, valves and instrumentations. Radiator modules aremade of horizontal finned tubes that are fixed between two headers. Cooling air is blast across the radiatorbanks using six numbers of fans.

It was necessary to calculate the heat rejection from the gas turbine cooling water for analysis. For this cal-culation, inlet/outlet cooling water temperatures of the radiator, and the flow rate of cooling water are re-quired.

There was no flow meter installed in the system to measure the cooling water flow rate. But, there were twolocal pressure gauges to measure the suction and, discharge pressures of the cooling water pump. When theplant is in operation reading are taken every 8 hours by plant operators and recorded in log sheets. Thus,cooling water flow rate was obtained form the pump characteristic curve using differential pressure acrossthe pump.

Similarly there was a local temperature gauge to measure the temperature of the outlet cooling water tem-peratures of the radiator, and readings have been recorded in log sheets. But the local temperature gauge,

which was there to measure the inlet temperature, was not easily accessible. Hence, this temperature gaugehas not been calibrated for longer perid. Thus, inlet water temperature measurement was carried out using adigital thermometer.


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6 Heat recovery st eam generator(HRSG)

The exhaust flue gas temperature of the gas turbine is around 550 oc, and the flue gas flows through the a vertical HRSG. Energy that is available in the flue gas transfers into water, and production take place at theHRSG. As explain in the plant overview chapter the HRSG consist of three circuits (HP, LP and LLP cir-cuit), through which, working fluid (water or steam) flows.

6 . 1 L o w l o w p r e s s u r e ( L L P ) c i r c u i t

Figure 6.2: LLP circuit

Condensate pumped into the LLP circuit using condensate extraction pumps (CEP), and discharge line ofthese pumps terminates at a water storage tank called LLP drum. This drum acts as the storage, from

which, water is taken for HP and LP circuits. LLP flow control station, that is located in between LLPdrum and the CEP, is used to control the condensate flow. This control station consist of two control

valves that are driven by pneumatic supply and two isolation valves that are driven by electrical motors.

Steam lines that are coming from steam turbine, HP circuit, and LP circuit are connected to a commonheader; and this header terminates at LLP drum. This common header injects steam to the drum for pre-heating and dearation. When the plant is in normal operation, steam line, which is coming from steam tur-bine, fulfills the steam requirement for pre-heating and dearation. But, during the plant start-up, steamscoming from the HP and LP circuits are used for pre-heating and dearation. This is because steam cant beextracted from the steam turbine during plant start-up.

Blow-down line that connects the LLP drum and the IBD (intermittent blow down) tank is used to carry-out drum blow-down in order to maintain chemical balance in the drum.

Flow controlstation

Gas turbineexhaust

HRSGexhaust


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ameter. During the plant star-up down stream pressure of the above valves is around 1bar, and the upstream pressure is around 50bar. Due to this high differential pressure, large force acts on the stem of themain valve. But, the fore that acts on the integral by-pass valve is relatively small, since the diameter is only25mm. Thus, during the plant start-up integral by-pass valve is opened, and water flows through the inte-gral by-pass valve so that down stream pressure rises. When the down stream pressure increased, differen-tial pressure drops; and the main steam valve is operated.

Both supper-heated and saturated steam lines are provided vent valves that operate in case of a suddenpressure rise.

Two blow-down lines are provided in order to maintain chemical balance of the drum, and water thatcomes from these blow-down lines goes to IBD (intermittent blow down) and CBD (continues blow down)tanks. Similar to LLP drum, separate filling line is provided for initial filling.

6 . 3 H i g h p r e s s u r e ( H P ) c i r c u i tSimilar to LP circuit water flows to HP circuit from LLP drum through the HP feed water pumps.

Figure 6.5: HP Boiler feed pump

The discharge line of the HP feed water pumps goes to the HP economizer 1 module through the HP feed water main isolation valve which is associated with a integral by-pass valve. HP circuit consists of threeeconomizers, one evaporator and two supper heaters.


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Figure 6.6: HP circuit

Feed water is injected to the outlet of the supper heater 1 module to control the temperature at the outletof the supper heater 2 modules. Similar to LP circuit HP circuit also consists of feed water control station,ejector, startup pump, blow-down lines, and an initial filling line.


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7 Steam turbine

Figure 7.1: Steam turbine

HP and LP superheated steam line, which come from HRSG, can carry condensate droplets especially dur-ing plant star-up. It is very important to maintain steam quality, before admit steam into steam turbine.

Automated steam drip legs and manually operated steam drains are attached to the HP and LP steam head-ers. Condensate that collects in the drip legs of HP steam header, goes to a tank called HP flash tank. Simi-larly LP flash tank is incorporated in the system to collect condensate that comes from drip legs of LPsteam header. Both flash tanks are connected with the condenser, and hence condensate that comes fromdrip legs will go back into the system through the condenser.

To reduce NOx formation in the gas turbine, steam is injected into the combustion cans of the gas turbine,and the steam requirement is fulfilled by extracting steam from the turbine. But, when the plant is operatedat low loads, pressure of the extraction steam is not sufficient. Hence, HP steam header provides steam forNOx reduction during part load operation.

HP steam header divides into two branches, and there are two steam injection ports in the turbine. Eachbranch is associated with an isolation valve called HPSV (High Pressure Steam Valve) and another valvecalled HPCV (Higher Pressure Control Valve).

In case of an emergency shutdown HPSV valve closed immediately to stop the steam supply the steam tur-bine. HPCV valve is used to control the steam flow rate, and hence it used for load controlling of the tur-bine.

LP steam line does not have branches, and it is also associate with a LPSV (Low Pressure Steam Valve) anda (Low Pressure Control Valve)


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8 Condensate system

Figure 8.1 Condensate extraction pump

Steam turbine is located on the condenser, in which, exhausted steam condensed due to heat transfer fromsteam to cooling water. Bottom part of the condenser is called hot-well, and the make up water requirementof the system is carried out by hot-well makeup pumps. This make up water is taken from the CST (Con-densate storage tank).


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Figure 8.2 Condensate system

Major portion of the CEP discharge is taken for LLP drum, and small amount is used in vacuum pump,steam turbine gland steam system, , steam turbine exhaust hood spray, LP and HP by-pass valves, SWAS(Steam water analysis system) and in vacuum breaker valve.

Steam turbine exhaust temperature is around 40 oc and this temperature should not increase to a very highlevel since, condenser is not designed for such situation. Hence, provision is provided to spray water to thesteam turbine exhaust when its temperature increases beyond 92 oc. This is called steam turbine exhausthood spray, and this spray water line is taken from CEP discharge.

During the plant shut down condenser vacuum reduces from 0.074bar to atmospheric pressure. This isdone by opening a valve called vacuum breaker valve which is installed in a line whose one end is con-nected to the condenser and the other end exposed to atmosphere. During normal operation one side ofthe vacuum breaker valve exposed to vacuum and the other end exposed to atmospheric pressure. Thus,

water line that starts from CEP discharge provides water to the vacuum breaker valve in order to have abetter sealing.

One other important function that takes place in the condensate system is chemical dosing. This is to main-tain the ph level of the water of the system.

During normal operation condenser inside pressure is around 0.074bar, and before start-up this is at at-

mospheric pressure. Hence, during the start-up, air inside the condenser is sucked using vacuum pumpsthat are connected to condenser.


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Figure 8.3 Vacuum pump

Both these pumps are operated during the plant start-up to create the vacuum quickly, and once the insidepressure reach 0.074bar one pump is switch off while the other one remains in operation. It is not possibleto have a perfect sealing everywhere in condensate system, and hence air can leaks into the system. Thus,one vacuum pump is in continues operation in order to remove air that leaks into the system. Vacuumpump is also requires seal water, and this requirement is fulfilled by CEP discharge water.


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9 Cooling water system

Figure 9.1 Cooling water system

The main objective of the cooling water system is to provide cooling water for the condenser. This systemconsists of CW (cooling water) pumps, CT (cooling tower) fans, CWST (cooling water storage tank), andCT makeup pumps.

To avoid algae generation in the cooling tower basin, calcium hypo-chloride is injected, and the concentra-tion of this chemical in the cooling water is measured using a parameter called FRC (free residual chlorine).

This FRC level is maintained around 0.5PPM in the CT basin. But when it is need to carry out CT blow-down, FRC must be reduced due to environmental concerns. Thus, sodium sulphate is injected into CTblow-down header to reduced FRC of the blow-down water.

Figure 9.2 Cooling tower

Cooling tower make-up pumps, which take water from the cooling water storage tank, pump water into CTbasin to maintain the makeup water flow. Four numbers of cooling tower fan generates the necessary draft

to cool the water, and when the plant is in full load operation all the fans must be used, and during partload operation one CT fan can be switch off.


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Figure 9.3 Cooling water pump

Three cooling water pumps are installed, and when plant is at full load, two numbers of pumps are suffi-cient to provide the necessary flow, and the other one is the standby pump.


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10 SWAS (Steam water analysis system)

Raw water contains number of minerals, and it is not possible to use this raw water for the steam cycle without treatments. This is because mineral could get deposited on the internal surfaces of the pipes thatcarry steam and water. Hence, raw water is treated in a water treatment plant to produced de-mineralized

water. When concentration of mineral increase, electrical conductivity of water increases. Thus, mineralconcentration is measured using a parameter called siemens per meter (S/m).

One other important parameter is the pH level of the fluid. Generally pH level of the fluid should be main-tained around 9 in order to minimize the corrosion of the pipes. This is done by injecting various chemicalsinto the system, and the concentrations of these chemicals should also be measured frequently.

Figure 10.1 SWAS panel

Thus, water samples are taken from different location such as drums, supper heater outlets, CEP discharge,for testing purposes. Separate lines which are small in diameter are used to extract steam and water fromabove mentioned locations to collect samples. The fluid pressure is reduced using valves that are installed inthese lines, and a cooler is used to condense steam at sample collection point to. This whole system is calledsteam water analysis system (SWAS), and offline and online measurements are carried out to monitor thequality of the steam and the water in the steam cycle.

Oms1

Siemen =


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11 System modelling

11 . 1 C o m b i n e d c y c l e h e a t r a t eBoth corrected and actual power outputs are available in the control room data base, and actual power out-put is used to calculate actual heat rate. This actual heat rate is divided by correction factors to obtain thecorrected heat rate.

Net actual power output of the plant PTNET= (Acquired from control room data base)

Fuel temperature TFUEL=

32TFUEL8.1TFUELF +=

tyFuel_densityFuel_densi131.5141.5 = API [20]

Fuel reference temperature TFUELREF=

Specific enthalpy of fuel at fuel reference temperature 1H=

Specific enthalpy of fuel at combustion chamber inlet temperature H2=

[20]

3.1013PATM1 =

Actual combined cycle heat rate HR_UNH=

PTNET

H1)H2(LHVfuelmHR_UNH+

=&

[20]


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11 . 2 G a s t u r b i n e e f f i c i e n c yIn order to analyze the gas turbine efficiency, a system boundary must be established. Since, there are sev-eral numbers of subsystems are involved, system boundary can be selected such away that, all the subsys-tems are inside the system boundary, so that it is not necessary to analyze each and every sub system in de-tail. Outer surface of the gas turbine compartments is selected as the boundary of the system.

Figure 11.1 System boundary

Fuel flow rate can be taken from the control room data base, and hence rate of heat input from the fuel,can be calculated using the calorific value

Temperature and the pressure of steam that is injected into gas turbine can be taken from the control roomdata base, and thus heat input from the steam can be calculated.

Heat removal through cooling water, Convective and radiation losses, and heat removal from ventilationfans can be calculated by local measurement.

1 1 . 2 . 1 G a s t u r b i n e c o o l i n g w a t e r s y s t e mCooling water pump discharge pressure = 4.11 barsCooling water pump suction pressure = 0.3 bars

Above values were taken from log sheets

Differential pressure across the cooling water pump = 3.81 barsDifferential pressure across the cooling water pump = 38.82 m

Air

SteamInjection

Fuel

Flue gas &Super heated steam

Turbine

Heat removal throughcooling water

Convective andradiation losses

Heat removal from ventilation fan

Electrical power

1

2 3

4


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Figure 11.2 Cooling water pump characteristic curve of Gas turbine

Hence, flow rate through the gas turbine cooling water = 194 m 3/hrInlet cooling water temperatures of the radiator = 49.4 oc (measured)Outlet cooling water temperatures of the radiator = 42.2 oc (measured)

Density of cooling water at above temperature = 998 kg/ m 3 Specific heat capacity of water = 4.18kJ/kg oc

Heat rejected from gas turbine cooling water system= Heat_CW_GT

)2.424.49(1000000

18.4998194Heat_CW_GT =

83.5Heat_CW_GT = GJ/hr

62.1Heat_CW_GT = MW

1 1 . 2 . 2 G a s t u r b i n e f u e l e n e r g yFuel flow rate fuelm

&= [TPH] (Acquired from control room data base)

Higher heating value of fuel HHV= [MJ/kg]

As explained in the fuel system chapter, samples are sent to an industrial laboratory to measure the calorific value of fuel. Since, fuel flow rate and heating value is known, rate of heat input to the gas turbine can becalculated.


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1 1 . 2 . 3 G a s t u r b i n e e l e c t r i c a l p o w e rMeasured power output of gas turbine generator PGTM= [MW] (Acquired from control room data base)

Frequency correction for gas turbine generator PGTFL= [MW]

Voltage correction for gas turbine generator PGTVL= [MW]

Power output after correcting for voltage and frequency PGT= [MW]

1000PGTVLPGTFL

-PGTMPGT += [21]

Electrical power output of gas turbine generator rator_GTPower_gene= [GJ/h]

1003600

rator_GTPower_gene = PGT

1 1 . 2 . 4 G a s t u r b i n e s t e a m i n j e c t i o nFlow rate of steam that injected to gas turbine WINJ1= [kg/s] (Acquired from control room data base)

Flow rate of steam that injected to gas turbine WINJ= [kg/h]

3600WINJWINJ =

Pressure of steam that injected to gas turbine PINJ= [bar] (Acquired from control room data base)

Temperature of steam that injected to gas turbine TINJ= [ oc] (Acquired from control room data base)

Since, temperature and the pressure of the steam that is injected into gas turbine is known, enthalpy can becalculated.

Enthalpy of steam that injected to gas turbine HINJ= [kJ/kg]

1 1 . 2 . 5 G a s t u r b i n e a i r i n t a k e a n d e x h a u s tUsing ambient temperature TA , compressor inlet air enthalpy can be calculated.

Ambient temperature TA=

Compressor inlet air enthalpy h1_air =

Flue gas pressure at gas turbine outlet PFG= [bar] (Acquired from control room data base)

Flue gas temperature at gas turbine outlet TFG= [bar] (Acquired from control room data base)

Partial pressure of steam in flue gas PSTMFG= [bar]

1000WINJ

WGT_EXH

1000WINJ

PFG)(PATMPSTMFG+

+=

Steam that was injected into the gas turbine become superheated and leaves with flue gas. The enthalpy ofthis superheated steam can be calculated since, pressure and temperature known.

Enthalpy steam at gas turbine exhausts THINJ_GT_EX= [kJ/kg]


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Air flow rate at compressor inlet air m&= [TPH]

Flue gas flow rate at gas turbine outlet WGT_EXH= [TPH]

WGT_EXHfuelmair m =+ &&

Stoichiometric air to fuel ratio of fuel f =

14.6f = [22]

air mfuelm &

&= [22]

+

+=1 )f 1(x [22]

Gas turbine exhausts temperature TTXM= [ oc] (Acquired from control room data base)

Since, ( TTXM ) is known, enthalpy can be obtained from table 14.1

Enthalpy of flue gas at turbine outlet HFG=

Enthalpy of air at turbine outlet 4_air h=

DH4xhHFG 4_air += [22]

1 1 . 2 . 6 G a s t u r b i n e c o m p a r t m e n t c o n v e c t i v e l o s s e sSummation of length of the perimeters of gas turbine compartments rtmentP_GT_compa=

150rtmentP_GT_compa = (Measured)

Height of the GT compartment rtmentH_GT_compa=

6.5rtmentH_GT_compa = (Measured)

Surface temperature of GT compartments T_s=

45T_s = (Measured)

Temperature of the boundary layer between atmosphere and the GT compartment surface T_boundary=

2TAT_s

T_boundary +=

Volumetric expansion coefficient of boundary layer VolExp=

Dynamic viscosity of air in the boundary layer boundary=

Density of air in the boundary layer boundary=

Kinematic viscosity of air in the boundary layer boundary =


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boundary

boundary boundary

=

Thermal conductivity of air in the boundary layer boundaryk =

Prandtl number of air in the boundary layer Pr =

Since, temperature of the air in the boundary layer is known, volumetric expansion coefficient, dynamic vis-cosity, density, thermal conductivity, and Prandtl number can be obtained.

Grashof number 2S

3rtmentH_GT_compaTA)(TVolExpg =rLG [23]

Rayleigh Number Pr GR rLaL = [24]

Nusselt number ( L Nu ) can be obtained from following table.

Figure 11.3 [27]

Heat transfer coefficient for free convection convectionh=

boundaryk

rtmentH_GT_compaconvectionh Nu L

= [27]

Convective heat loss from gas turbine compartments ction_GTHeat_conve= [GJ/h]

9Sconvection 10

3600TA)(TrtmentH_GT_compartmentP_GT_compahction_GTHeat_conve =

1 1 . 2 . 7 G a s t u r b i n e v e n t i l a t i o n s y s t e m Ventilation system is incorporated to gas turbine in order to remove heat from all the compartments. Insidetemperatures of the accessory and turbine compartments are very close to ambient condition; and hence, itis possible to assume that the heat dissipation from ventilation fans of above two compartments is negligi-ble. But, inside temperatures of turbine, exhaust and load compartments are very high, and hence heat re-moval from ventilation fans of above three compartments must be estimated.


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1 1 . 2 . 7 . 1 T u r b i n e c o m p a r t m e n t v e n t i l a t i o n s y s t e m Volumetric air flow rate of turbine compartment ventilation fan mpartmentGT_turb_coV

&= (measured)

21425V mpartmentGT_turb_co =& [CFM] (measured)

Exhaust temperature of ventilation fan of turbine compartment ent b_compartmair_GT_tur T= (measured)

154T ent b_compartmair_GT_tur = [ oc] (measured)

Density of exhaust air of ventilation fan of turbine compartment ent b_compartmair_GT_tur =

Since, ent b_compartmair_GT_tur T is known ent b_compartmair_GT_tur can be obtained

Specific heat capacity of exhaust air of ventilation fan of turbine compartment ent b_compartmair_GT_tur cp=

Since, ent b_compartmair_GT_tur T is known ent b_compartmair_GT_tur cp can be obtained

Heat rejection from turbine compartment ventilation system turb_complation_GT_ Heat_Venti= [GJ/h]

6ent b_compartmair_GT_tur

ent b_compartmair_GT_tur ent b_compartmair_GT_tur 3mpartmentGT_turb_co

10

3600)TAT(

cp6028.3

Vturb_complation_GT_ Heat_Venti

= &

1 1 . 2 . 7 . 2 E x h a u s t c o m p a r t m e n t v e n t i l a t i o n s y s t e m Volumetric air flow rate of exhaust compartment ventilation fan partmentGT_exh_comV

&= (measured)

15230V partmentGT_exh_com =& [CFM] (measured)

Exhaust temperature of ventilation fan of exhaust compartment nt _compartmeair_GT_exhT= (measured)

138T nt _compartmeair_GT_exh = [ oc] (measured)

Density of exhaust air of ventilation fan of exhaust compartment nt _compartmeair_GT_exh =

Since, nt _compartmeair_GT_exhT is known nt _compartmeair_GT_exh can be obtained

Specific heat capacity of exhaust air of ventilation fan of exhaust compartment nt _compartmeair_GT_exhcp=

Since, nt _compartmeair_GT_exhT is known nt _compartmeair_GT_exhcp can be obtained

Heat rejection from exhaust compartment ventilation system exh_complation_GT_ Heat_Venti= [GJ/h]

6nt _compartmeair_GT_exh

nt _compartmeair_GT_exhnt _compartmeair_GT_exh3 partmentGT_exh_com

10

3600)TAT(

cp6028.3

Vexh_complation_GT_ Heat_Venti

= &


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1 1 . 2 . 7 . 3 L o a d c o m p a r t m e n t v e n t i l a t i o n s y s t e m Volumetric air flow rate of load compartment ventilation fan mpartmentGT_Load_coV

&= (measured)

11171V mpartmentGT_Load_co =& [CFM] (measured)

Exhaust temperature of ventilation fan of load compartment entd_compartmair_GT_LoaT= (measured)

162T entd_compartmair_GT_Loa = [ oc] (measured)

Density of exhaust air of ventilation fan of load compartment entd_compartmair_GT_Loa =

Since, entd_compartmair_GT_LoaT is known entd_compartmair_GT_Loa can be obtained

Specific heat capacity of exhaust air of ventilation fan of load compartment entd_compartmair_GT_Loacp=

Since, entd_compartmair_GT_LoaT is known entd_compartmair_GT_Loacp can be obtained

Heat rejection from load compartment ventilation system load_complation_GT_ Heat_Venti= [GJ/h]

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CHP Thesis KTH