Management of Thermal Power Plant Efficiency

Management of Thermal Power

Plant Performance Parameters

Dr. K.C. Yadav, Director

Learning Agenda

• Identification and analysis of input parameters as;

Uncontrollable

Semi-controllable

Controllable

• Analysis and forecasting of operating parameters of various

processes and equipments

• Estimation and analysis output (performance parameters)

• Determination of inevitable effect on performance parameters

under variation from design specified operating parameters

• Preparation of guidance message to the input material managers

and operation/efficiency managers to deal with variations.

3

Learning Agenda

• Commissioning Completion Checks

• Tenable Standard Practice Codes & Contract.

• Estimation of Turbine Heat Rate, UHR, SHR, APC Etc

• Management of energy efficiency of thermal cycle, turbine

& generator

• Analysis of Variation in Performance with Comparison to

Design Specified Values

• Determination of Performance Loss, as Inevitable or

Avoidable due to Variation in Input Parameters.

• Preparation of Guidance Message

Commissioning Completion Checks

The plant should be inspected thoroughly to see whether

there is any reason why trial run/testing cannot take

place

• Unmeasured mass loss

• Valves, ‘passing’

• Tube leakage

• Test equipment calibration

• Bypassing or recirculation

• Double measured mass flow

Checking of Fluid Machines (Pumps, fans Compressors,

Blowers etc)

• Gland sealing water supply

• Return flows must be measured and

• Minor miscellaneous leakages (such as pump gland drips)

should be assessed.

• All make-up to the system under test should be stopped

before testing commences

Basic Requirements for the Test

• The feed water measurement:• Water is supplied to seal the pump glands, most of which is then returned to

the deaerator, but some of which enters the pump. Therefore the gland seal

supply and return water flows must be measured to determine the amount of

in-leakage.

• SH/RH spray water flow measurement:• Its value must be measured as it will detract from the quantity of steam flow

to the HP turbine.

• Main/HRH steam flow measurement:• Before entering the HP cylinder some steam is tapped off the main line to

supply LP gland sealing and spindle leak-off steam. Hence these two values

must be assessed.

Basic Requirements for the Test

• The steam entering the HP cylinder:Qfw at O/L of Booster + feed pump gland in-leakage - reheat spray (Passing), LP

gland seal and spindle leak-off flows

• The steam entering the IP cylinder:Qs at HP cylinder exhaust minus the bled steam supplied to No. 6 + reheat spray

(Passing)

• Allowance for level in heater shells, condenser and

deaeratorDeaerator level low (due to a boiler leak) - extra water - change in bled steam flow

to the heaters - change steam flow in the turbine - affecting the turbine

performance.

Steady State Plant Conditions

Loading

Pressure

Temperature

Back pressure

• Recording of inevitable variations

• Estimation of the adverse effect on results

• Measurement Parameters as specified in extant codeThe feed flow should be measured at least every half-minute

The pressure and temperature need only be recorded every three minutes

during a one-hour test, or every five minutes in a two-hour test.

• Several tests at each loadings (100%, 80% and 60% MCR)

Standard Practices

Trial Run and Performance Guarantee Test (PGT) must beconducted in accordance with extant standard codes andother legally sustainable business documents.

Turbine Heat Rate & other associated performanceparameters have been relied upon ASME Test Code PTC 6for BHEL units in the Indian Utilities.

Data Acquisition and Error Analysis

Truly reliable data provides information of theprocess, which is further utilized for analysis andfuture of course action to achieve utmost optimizedperformance. The Data Acquisition System in ThermalPower Plants is a centralized data source, to whichcontributions are made from all the processequipments. One of the big advantages of automaticdata acquisition is that all of the points can bescanned much more quickly and this leads toimproved accuracy.

12

Need

Performance of Indian Thermal Power Units has been very poordue to;

• Wide variation in input (fuel, air and water) parameters than thatof the design

• Inadequate appreciation and understanding of suitablymodifying/changing the operating parameters to accommodatethe uncontrollable input parameters

• Lack of managerial will to prioritize performance parameters insequence of human safety, equipments’ life, energy/exergyefficiency and availability.

13

NeedThere is the need

• To analyze the variation in input parameters and their adverseeffect on thermal power plant performance parameters and tomodify operating parameters of various power plant processequipments to minimize the adverse effect on performanceparameters

• To promote performance management system to keep vigil overcause and effect relationship of all processes at micro level forthe achievement of most optimized values of performance controlparameters even when input parameters are significantly differentfrom the design prescribed values

14

Objective

To develop appreciation and understanding towards the

optimization of thermal power plant operating parameters toaccommodate wide variation in uncontrollable input parametersand in turn to achieve most optimized values of;

• Electricity availability parameters

• Energy efficiency parameters

• Equipments’ life parameters

• Human safety parameters

15

16

D/A

BFP

HPH

LPH

CW

17

Availability Parameters

• Availability Factor

• Plant Load Factor

18

Efficiency Parameters

• Boiler Efficiency

• Turbine Heat Rate

• Unit Heat Rate

• Station Heat Rate

19

Efficiency Control Parameters

• Main Steam Temperature

• Main Steam Pressure

• Hot Re-Heat Steam Temperature

• Condenser Vacuum

• Feed Water Temperature

• Flue Gas Exhaust Temperature

• O2 or CO2 % in Flue Gas

• Auxiliary Power Consumption

• Load Variation

20

Equipments’ Life Parameters

• Pre Combustion Parameter

• Combustion Parameters

• Post Combustion Parameters

• Steam quality parameters

• Condenser Parameters

• Turbo Supervisory Parameters

• Generator Parameters

• Tube Erosion Parameters

– Particle Trajectories

– Particle-Tube Impact Frequency

– Impact Velocity and Impingement Angle

21

Human Safety Parameters

• Air pollution parameters

NOx, SOx and SPM

• Water pollution

• Noise pollution

22

Estimation of Energy Efficiency Parameters

• Boiler Efficiency (Direct and Indirect method)

• Turbo Alternator Heat Rate

• Turbo Alternator Efficiency

• Unit Heat Rate

• Station Heat Rate

23

Energy Efficiency of the Boiler

(Qc*GCV+Hcredit)

Qms*(Hms-hfw)+Qrh*(Hhrh-Hcrh)

Boiler Efficiency by Direct Method

ηb =

24

Energy efficiency of the Boiler

Boiler Efficiency by Indirect Method

i.e. by the assessment of losses

Ηb = 100 – Total % Losses

25

Boiler Efficiency by Assessment of Losses

DFL = (C/100+S/267-CinAsh)*100/12(CO2+CO)*30.6*(T – t)

KJ/Kg Coal

WFGL=[1.88*(T-25)+2442+4.2*(25–t)]*(Mc+9H)/100 KJ/Kg coal

CinAshL=C in A * 33,820 KJ/kg Coal

UGL=23,717*(C/100+S/267-inAsh)*CO/12(CO2+CO)KJ/kgCoal

SHMainAirL= Ma * Hu * Cp * (T-t) KJ/Kg Coasl

SHinAshL= FlyAsh*Cpfa*(T–t)+BottomAsh*Cpba*(Tf-t) KJ/KgC

ShinRejectL= Qmr*Cpr*(Tc+a-t)

R&UA/CL (B in KJ/Kg Coal) Log10 B = 0.8167 - 0.4238 log10 C

Estimation of Turbine Heat Rate

Turbine Heat Rate is Reciprocal of Turbo Alternator

Efficiency in terms of heat units required to produce one

domestic unit of electricity i.e. KJ/KWHr or KCal/KWHr

ηta=MW/[Qms*(Hms-hfw)+Qrh*(Hhrh-Hcrh)]

Performance of Steam Turbine

• THR = [(Qms*Hms – Qfw*hfw) + Qrh*(Hhrh – Hcrh)]/P

P = PGen.Ter. – (Pexc + Pmin)

• ηta = 3600/THR = 860/THR = ηt*ηg*ηc

• ηt = Wt/Hise

• ηg = MW/Wt

• ηc = Hise /[(Qms*Hms – Qfw*hfw) + Qrh*(Hhrh – Hcrh)] or

• Hise = [Qms*(Hms–Hcrh)+Qrh*(Hhrh–Hexh)–Sum(qb*Hb)]

Thermal Cycle Efficiency

Enthalpy Drop Across the Turbine

HPT

Qms*(Hms-Hcrh)

IPT

+ Qrh*(Hhrh-H5) + (Qrh-q5)*(H5-Hd)

LPT

+ (Qrh-q5-qd)*(Hd-H3)

+ (Qrh-q3-q5-qd)*(H3-H2)

+ (Qrh-q2-q3-q5-qd)*(H2-H1)

+ (Qrh-q1-q2-q3-q5-qd)*(H1-Hexh)

30 of 27

Velocity Vector

Diagram for Pure

Impulse Turbine

β1α1 β2α2

β1 α1

β2α2

Blade Performance of Pure Impulse Turbine

Wo = C2 Cos α2 (clockwise tangential component)

Wi = C1 Cos α1 (anticlockwise tangential component)

R2 < R1 & R2 = µ*R1

For smooth surface µ = 1 & R2 = R1

P = [Wi - (-Wo)]*u = [C2 Cos α2 + C1 Cos α1]*u

C2 Cos α2 = R2 Cos β2 –u = R1 Cos β1 –u

or C2 Cos α2 = C1 Cos α1 - u – u = C1 Cos α1 – 2u

P = [C1Cos α1+C1Cos α1–2u]*u = 2*u*[C1Cos α1–u]

ηb = 2*P/C1**2 = 4*[(u/C1)*Cos α1 – (u/C1)**2]

ηs = ηn*ηb = (C1**2/2Hise)*(2*P/C1**2) = P/Hise

32 of 27

Velocity Vector

Diagram for

Impulse-Reaction

Turbine

β1α1 β2α2

β1 α1

β2α2

Work Done in Imp-Reaction Steam Turbine

Deduction of C2 & R1 in terms of R2 & C1

Degree of ReactionPressure drop in Moving Blades

________________________

Total Pressure drop =DR =Enthalpy drop in Moving Blades

Total Enthalpy drop

________________________

Stage Efficiency

Internal Losses

Turbine Pressure Survey

38

39

Turbine Survey Pressure

40

Turbine Survey Pressure

HPHs Out of Service

41

Turbine Survey Pressure1. HPHs Out of Service 2. HPT Stage Blockage

Unit Heat Rate

UHR = (THR in KJ/KWHr)/ηb

UHR = QC*CVC/MWHr

Station Heat Rate

SHR = Qct*CV/MWHr

SHR = 100*Qct*CV/(MWHr*(100-%APC))

SHR = UHR*100/(100-%APC)

It must be recognized that no amount of writteninstruction can replace intelligent thinking and reasoningon the part of operators, especially when coping withunforeseen operating conditions. It is operators’responsibility to become thoroughly familiar, not onlywith the equipment under his functional area but alsowith all pertinent process/control equipment.Satisfactory performance and safety depend to a greatextent on proper functioning of controls and auxiliaryequipment.

Condenser Performance

• Vacuum Efficiency

= Vexh / Videal = (Pg1 - Patm)Exh/(Pg2 - Patm)ideal

Where Pg2 = Ps Corresponding Ts, if no NC gas

• TTD=Ts-t2

• LMTD=(t2-t1)/ln((Ts-t1)/(Ts-t2))

• Impact of t1, Qs, Qcw and tube deposits

• Condenser condition curves

46

Energy Efficiency of the Turbine

ηc = ∆Hise/(Qms*(Hms-hfw)+Qrh*(Hhrh-Hcrh))

ηt = WT/∆Hiset

ηg = MW/WT

ηta = MW/(Qms*(Hms-hfw)+Qrh*(Hhrh-Hcrh))

47


Turbo Alternator Heat Rate

THR = (Qms*(Hms-hfw)+Qrh*(Hhrh-Hcrh))/MW

Expressed in KJ/KWHrn or in KCal/KWHr

THR = 3600/ ηta in KJ/KWHr

THR = 860/ ηta in KCal/KWHr

48


• UNIT HEAT RATE

• UHR = (THR in KJ/KWHr)/ηb

• UHR = QC*CVC/MW in KJ/KWHr

49

Energy efficiency of the Turbine

STATION HEAT RATE

• SHR = Qct*CV/MWt

• SHR = 100*Qct*CV/(MWt*(100-%APC))

• SHR = UHR*100/(100-%APC)

50

Condenser Vacuum Management

Effects of cooling water inlet temperature

• The primary one is to alter the steam saturation temperature by thesame amount as the change.

• The secondary effect is caused by the fact that the heat transfer ofthe cooling water film in contact with condenser tubes change withtemperature of the water.

The primary and secondary changes are in opposite direction. Themagnitude of the secondary effect is approximately equal to thefourth root of the mean cooling water temperature.

51


52


Cooling Water Flow

The primary effect of a change of cooling water flow is to alter it’stemperature rise. The secondary effect, which operates in the samedirection as the primary, results from the change of heat transferrate, due to the changed thickness of the cooling water boundaryfilm. It is approximately proportional to the square root of the flow

53


Effect of CW Flow on Vacuum

41

42

43

44

45

46

47

48

49

Qcw ( Cooling Water Flow)

Ts ( S

atu

ration T

em

p.

Ts

54


Change in Heat Transfer

• Level in Condenser Hot Well

• Steam Flow

• Internal/External Tube Deposits

55


Effect of Load on Condenser Vacuum)

42.543

43.544

44.5

4545.5

4646.5

47

47.548

43568

44439

45328

46234

47159

48102

43568

42696

41842

41005

40185

39382

Qs (Steam Flow)

Ts (S

atu

ration T

em

p)

Series2

56


Steam Ejectors / Vacuum Pumps

Mal operation of vacuum pump and steam ejectors reducevacuum. Starting ejector creates vacuum up to 540 mmHgCl, 10to 30 minutes after, the main ejector should be cut into servicefollowed by immediate withdrawal of starting ejector. Paralleloperation of both the ejector shall not only develop the lesservacuum but also damage the main ejector. Vacuum pump hasauto change over from starting to main and normally runsatisfactory

57


Performance Parameters

De superheating = T-Ts

Sub cooling = Ts-td

LMTD = (t2-t1)/ln((Ts-t1)/(Ts-t2))

Temperature rise (dt) = t2-t1

TTD =Ts-t2

Condenser Efficiency = (dt) / (dt + TTD) = (t2-t1) / (Ts-t1)

Vacuum Efficiency = Ts /Texh

TTD is high due to;

– Higher gaseous impurities

– Air ingress

– External tube deposits

– Internal tube deposits

58

59

60

CT Performance Parameters1. Range

2. Approach

3. Effectiveness

4. Cooling capacity

5. Evaporation loss

6. Cycles of concentration

7. Blow down loss

8. Liquid / Gas ratio

9. Drift loss

10. Make up Water

62

Feed Water Temperature Management

• Feed water heating system is consisted of two main ejectors, two glandcoolers, four low pressure heaters, one direct contact deaerator and threehigh pressure heaters

• Feed water temperature at the outlet of the last high pressure heater is avery important efficiency control parameter, which should be optimally halfof the main steam temperature

63


Feed water heaters problems and solutions • Gaseous impurities in the steam can be managed by better

management of boiler and pre-boiler system• Vapour line of each heater plays vital role in maintaining the

design prescribed value of saturation temperature and also keepterminal temperature difference in acceptable operating range.

• External tube deposits can gradually increase terminaltemperature difference which needs better de mineralized waterquality management

• Internal tube deposits can be effectively minimized by on-linecondensate polishing/treatment to maintain terminal temperaturedifference and condensate/feed water differential pressure acrossthe heater

64


• Deaerator is the only direct contact heat exchanger andremaining ten heaters of regenerative feed heating system areindirect contact type, major portion of which function like acondenser and hence required to be managed in similar mannerdiscussed for condenser.

• Both end portions of the each heater perform separatefunctions, one at the high temperature end works as de superheater and the other at low temperature end works like a subcooler. De super heating and sub cooling in the heaters areexergetically undesirable and hence attempts should be madeto minimize the both

Feed Water Heaters’ Performance

66

Excess Air Management

Oxygen in flue gas represents the excess air over and above the

theoretical air, which is proportionate to coal combustibles butExcess Air requirement increases with increasing coal impurities

67

Management of Oxygen in Flue Gas

Theoretical Air

=4.31*[8*C/3 + 8*(H-O/8) +S] Kg/Kg Coal --- (1)

Excess Air

=[(TheoreticalCO2%/ActualCO2%)-1]*100%-(2)

Excess Air

=(O2%*100)/(21-O2%)----------------------------- (3)

68


Shortcomings of the Existing Practice

– Unlike theoretical air, no coal parameter is incorporated andhence it does not give any guidance message to operator forsuitable change in excess air supply on the basis of coalquality parameters.

– Accurately estimated O2% in flue gas for a particular coal maynot be valid for a coal different in rank, petrology andcomposition.

69


Shortcomings of the Existing Practice

– Excess air calculated by using both the above referredequations, is the information of excess air that had beensupplied rather than would be supplied for a particular coal.

– Information of O2 % at the outlet of boiler does not providereliable guidance message to forced draught fan operator tosupply accurate quantity of air due to time lag and slowcombustion response.

70


Existing method of maintaining a fixed or an arbitrary percentage of

oxygen % in flue gas leads to either

• Over supply

or

• Under supply

of excess air particularly in case of wide variation in coal quality than thatof the design.

71


Alternative Method of Excess Air Estimation

• Excess Air

=K1*FC-K2*VM+K3*M+K4*A**2+K5--------(4)

• Excess Air

=K1*C-K2*(5H+3*O/8+S+N)+K3*M+K4*A**2+K5--(5)

• Excess Air

=k1*I-k2*V-k3*E+k4*M+k5*A**2+k6---------(6)

72


Assumptions for Applying New Method• Impact of Hard Grove Index (HGI), Moisture and Ash on

pulverizer capacity and fineness is taken care suitably as per thepulverizer condition curves.

• Pulverizer discharge valve orifices are healthy enough to ensureequal flow to all the four burners at the same elevation.

• Burner tips and tilting mechanism is not out of synchronism• All the fuel air dampers and auxiliary dampers are healthy

enough to follow the operating signals as specified

73


Assumptions for Applying New Method• No leakage of air anywhere in the air and flue gas path.• Proper functioning of the furnace safeguard supervisory system

(FSSS)• ID, FD & PA Fans are healthy enough to maintain Furnace

vacuum, Furnace differential pressure, Wind box pressure, HotP.A. header pressure

• ID, FD & PA Fans have sufficient extra capacity (above MCR)

74


Equations (4) and (5) are Solved as (7) and (8)

Excess Air=0.15*[(F.C.–V.M.)+(M+A**2/10)] ------------(7)

Excess Air=0.15*[C-(5H+3*0/8+S+N)+(M+A**2/10] ---(8)

75


Test of Equations• Have been carried out for large numbers of the coal samples, a

good numbers of which were collected from different thermalpower stations for the purpose of calculating the excess air. Thecoal parameters of actual samples vary randomly and henceleading to the same kind of variation in calculated excess air.

• Large numbers of coal samples were simulated by graduallyvarying the coal parameters so that the results can be presentedinto an user friendly simple graphics.

76


• Estimated excess air is converted into to equivalent amount of O2 %in flue gas, because there is no practice of maintaining excess air asoperating parameters. Graphs are plotted for guidance of forceddraught fan operator to maintain required oxygen percentage in fluegas on the basis of variation in coal parameters.

• Coal samples from leading Indian thermal power stations are placedin ascending order of calorific value along with otherproximate/ultimate parameters and estimated excess air (O2 % influe gas) graphically represented for estimating the excess air (O2 %in flue gas) by the forced draught fan operator. A large numbers ofsimulated coal samples are also considered in similar manner

77


78


79


Fig. 4 - Effect of Coal Parameter (Proximate Analysis) on Excess Air (O2% in Flue gas)

0

0.1

0.2

0.3

0.4

0.5

0.6

1 4 7 10 13 16 19 22 25 28 31

Ash Kg/Kg coal

Moisture Kg/Kg coal

Oxygen % in FG / 5 (E.7)

CV in KJ/Kg coal / 40000

Volatile Matter Kg/Kg coal

Fixed Carbon Kg/Kg coal

80


Fig. 3 - Effect of Coal Parameter (Ultimate

Analysis) on Excess Air (O2% in Flue gas)

0

0.1

0.2

0.3

0.4

0.5

0.6

1 4 7 10 13 16 19 22 25 28 31

Carbon Kg/Kg of coal

Hydrogen Kg/Kg coal

Oxygen Kg/Kg coal

Nitrogen Kg/Kg coal

Sulfur Kg/Kg coal

Ash Kg/Kg coal

Moisture Kg/Kg coal



81


Fig. 5 - Effect of Coal Parameter (Proximate Analysis) on Excess Air (O2% in Flue

gas)

0

0.1

0.2

0.3

0.4

0.5

0.6

1 4 7 10 13 16 19 22 25 28

Ash Kg/Kg coal

Moisture Kg/Kg coal


CV in K.J./Kg coal / 40000



82




0

0.1

0.2

0.3

0.4

0.5

0.6

1 4 7 10 13 16 19 22 25 28


Hydrogen Kg/Kg coal

Oxygen Kg/Kg coal

Nitrogen Kg/Kg coal

Sulfur Kg/Kg coal

Ash Kg/Kg coal

Moisture Kg/Kg coal



83



0

0.1

0.2

0.3

0.4

0.5

0.6

1 3 5 7 9

11

13

15

17

19

21

23

25

27

29

31

Ash Kg/Kg coal

Moisture Kg/Kg coal





84


Fig, 8 - Effect of Coal Parameter (Ultimate


0

0.1

0.2

0.3

0.4

0.5

0.6

1 4 7 10 13 16 19 22 25 28 31


Hydrogen Kg/Kg coal

Oxygen Kg/Kg coal

Nitrogen Kg/Kg coal

Sulfur Kg/Kg coal

Ash Kg/Kg coal

Moisture Kg/Kg coal



85

Operational Feasibility Analysis of the Proposals



0

0.2

0.4

0.6

0.8

1

1.2

1.4

1 4 7 10 13 16 19 22 25 28 31

Ash Kg/Kg coal

Moisture Kg/Kg coal





86





0

0.2

0.4

0.6

0.8

1

1.2

1.4

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31


Hydrogen Kg/Kg coal

Oxygen Kg/Kg coal

Nit rogen Kg/Kg coal

Sulfur Kg/Kg coal

Ash Kg/Kg coal

M oisture Kg/Kg coal



87




0

0.2

0.4

0.6

0.8

1

1.2

1.4

1 3 5 7 9

11

13

15

17

19

21

23

25

27

29

31

Ash Kg/Kg coal

Moisture Kg/Kg coal





88





0

0.2

0.4

0.6

0.8

1

1.2

1.4

1 4 7 10 13 16 19 22 25 28 31


Hydrogen Kg/Kg coal

Oxygen Kg/Kg coal

Nitrogen Kg/Kg coal

Sulfur Kg/Kg coal

Ash Kg/Kg coal

Moisture Kg/Kg coal



89



Fig. 13 - Effect of Coal Parameter (Proximate Analysis) on Excess Air

(O2% in Flue gas)

0

0.2

0.4

0.6

0.8

1

1.2

1 4 7 10 13 16 19 22 25 28 31

ash kg/kg Coal

Most kg/kg Coal

Oxygn % in FG/5 (E.7)

CVcoal KJ/Kg/ 40000

VM kg/kg Coal

FC kg/kg Coal

90


Effect of Ultimate Parameter on Excess Air (O2% in Flue gas)

0

0.2

0.4

0.6

0.8

1

1.2

1 4 7 10 13 16 19 22 25 28 31

Crbn kg/kg Coal

Hdgn kg/kg Coal

Oxgn kg/kg Coal

Ntgn kg/kg Coal

Slfr kg/kg Coal

ash kg/kg Coal

Most kg/kg Coal

Oxygn % in FG/5 (E.8)

CVcoal KJ/Kg/ 40000

91

Management of Oxygen in Flue Gas• Variation in CV due to combustibles lead to the proportionate

changes in theoretical air but excess air requirement changesindifferently depending upon quantities of impurities (oxygen,nitrogen, sulfur, moisture and ash) in coal and their combustionbehavior .

• Proposed excess air is leading to a value of oxygen in flue gasnear to the conventional value (i.e. 4%) in many cases, which areoperating at or near to the design coal parameters.

• Excess air (O2 % in flue gas) requirement is increasingtremendously for poor coals with higher ash content.

• Excess air (O2 % in flue gas) is too low for superior coalsspecifically with high volatile matter and low ash content.

92


Limitations of New Method of Excess Air Estimation

• Proposal of increasing excess air leads complete combustionof poor coal but may increase dry flue gas loss than thereduction in combustible loss. In such cases, minimum totalof combustible loss and dry flue gas loss shall decide theoptimized quantity of excess air rather than formula underreference.

• Even this may leads to total flue gas volume, which may behigher enough to cross limits of critical velocity andexponentially increases the flue gas erosion. In this situationload has to be reduced in place of reducing the optimized air.Load reduction cannot be more than 65% for very poor coaland supplementary fuel oil or gas has to be used to minimizeloss of boiler life and efficiency.

94

Management of Flue Gas Exhaust

Temperature

Flue gas exhaust temperature rise from 18 deg C to 20 deg C

causes 1% loss of boiler efficiency for higher ash coal to themoderate ash coal respectively

95

Management of Flue Gas Exhaust Temperature

0

5

10

15

20

80

90

100

110

120

130

140

150

160

170

180

190

Flue Gas Temperature in deg. C

Lo

sses i

n %

Dry Gas

Loss %

W et Flue

Gas Loss %

M o ist ure In

Comb ust io n

Loss %

B o iler

Losses %

96

Management of Flue Gas Exhaust Temperature

78

80

82

84

86

88

90

80 90 100

110

120

130

140

150

160

170

180

190

Flu Gas Temperature in deg. C

Blr

. E

ffic

ien

cy

97

Flue Gas Exhaust Temperature

Management

• Boiler Input System

Combustion air flow system

Coal & fuel oil flow system

• Flue gas flow system

• Water/steam flow system

98

Combustion Air Flow System

Accurate assessment and correct distribution of combustion

air solve many of the steam generator’s problems

99

Unit coal flow system• Bunkers

• Feeders

• Coal burners

• Pulverizes

• Primary air fans,

• Hot and cold primary air ducts

• Air pre heaters

100

Coal Flow System

Coal input parameter• Fixed Carbon

• Volatile Matter

• Ash

• Moisture

• Hard groove index

• Coal flow

101

Coal Flow System

Operating parameters• Hot primary air flow • Hot primary air pressure• Hot primary air temperature• Pulverized coal fineness• Temperature of the coal air mixture• Coal flow • Raw coal feeder speed• Mill differential pressure• Coal/air mixture pressure drop from mill outlet to burner

102

Coal Flow System

Coal supply limits• Fan power limit • Pulverized coal fall out limit• Pulverized coal pipe erosion limit• Mill outlet temperature limit• Mill power limit • Maximum coal flow limit • Grinding, drying & pulverized coal fineness stability limit• Air/coal ratio explosion limit

103

Coal Flow System

Notable Features of the Coal Flow System• Design specified quantity of the hot primary air is decided to be

adequate to dry maximum possible moisture in the coal. Relativelylesser percentage of actual moisture in coal than that of the designis accommodated by mixing cold primary air also known to betempering air

• Mill constraints drawn on airflow versus coal flow graph left verysmall space for mill operation, known as “mill operating window”

104

Coal Flow System Parameters

Mill Capacity ModulationAsh

Moisture

Hard Groove Index

Fixed carbon

Fineness

105


Hot primary air flow regulation

• Moisture content in the coal

• Hot primary air temperature

• Cold primary air temperature

106


Combustion air flow regulation

• Stoichiometric air flow

• Excess air flow estimation

107


Secondary air flow regulation

= Stoichiometric air + Excess air – Primary air

108


Essentials of Combustion

Combustibles from Coal

Oxygen Combustion air

Turbulence Combustion air pr. & dir.

Temperature Supplementary fuel/arc

Time Blr. dim. & combustion air

109


Primary air is meant for dry and transport the coal from mill to the

furnace.

Secondary air is supplied to ensure proper flow of products ofcombustion and to ensure complete combustion.

Tertiary air is supplied to suppress the heat flux to minimizepollutants production

110


Secondary air damper control system play vital role in

successful combustion, some of which modulate in proportion tothe fuel quantity and known as fuel air dampers where as theothers are meant for maintaining prescribed differential pressurein between the secondary air wind box and furnace. Place anddirection of secondary air supply is as valuable as the estimationof correct quantity.

111


Role of supplementary fuel firing equipments, monitoring devices,

soot blowers etc play equally important role combustion managementas that of secondary air dampers, burners, burner tilting mechanismetc.

112


Heat transfer from flue gas to the water/steam is influenced by input,

output and differential temperatures of both the hot and cold fluid.External and internal tube deposits or any input/ output variationdestabilize the proportionate heat transfer and cause abnormalitiesleading to the loss of boiler life and efficiency.

Air pre heater is the last heat exchanger in the coal combustion flowpath, which extract heat from the minimum temperature and send itback to the boiler through combustion air

Coal Flow System

114

Flue Gas Flow System

System Equipments• SADC & Burners

• Mills, Boiler Fans and APH

• Flame Scanners and Soot Blowers

• Evaporator, SH, RH and Economizer

• Boiler Drum

115


System Parameters• Parameters of input Fuel and Air• Wind box to furnace differential pressure• Mill to furnace differential pressure• Furnace vacuum• Burner tilt• (n-2) coal elevations out of ‘n’• Differential pressure and temperature of the flue gas across WW,

PSH, RH, FSH, LTSH Eco, APH & ESP• Fire Ball Position

116

Flue Gas Flow SystemControl of Soot Deposits

• Frequent soot blowing with designed steam pressure andtemperature can keep the tubes clean to improve the heat transfer.

• Long retractable soot blowers do not function satisfactorily andcausing lot of soot deposition on platen super heater, re-heater,final super heater, low temperature super heater and economizer.

• Air pre heater soot blowing also should be managed well becauseits choking results in reduced heat transfer and higher flue gasexhaust temperature. Air pre heater seals are also very importantand must be maintained.

117


Control of Acid Deposition

Flue gas exhaust temperature can be optimally reduced to avoid

occurrence of flue gas dew point temperature. Reduction of flue gasexhaust temper shall be lower for lower flue gas dew pointtemperature and high ambient temperature. High ash content of thecoal neutralizes the acidic effect due to its alkalinity and lead to alower flue gas dew point temperature.

118


SPM Control in Flue Gas

Electro static precipitator reduces the suspended particulate matter

up to the extent of 150 mg/NM3, higher fly ash erode the induceddraught fan impeller very severely and makes it quite difficult tomaintain the differential pressure across the various heatexchangers of the steam generators.

119

Water / Steam Flow System

Heat released in coal combustion is utilized inconverting pressurized water into superheatedsteam. Heat is absorbed as

• Sensible heat of water in economizer,• Latent heat of steam in water walls and• Sensible heat of steam in SH/RH.

Design specified parameters of flue gas and water / steam acrossvarious heat exchangers lead to a constant ratio of heat absorptionin them. Variation in airflow, coal flow and flue gas flow parametersvary the water / steam flow parameters which lead to change in heatabsorption ratio

120


Heat Balance Equation for the Boiler

Heat given by flue gas = heat taken by water/steam

Qc*CVc - Losses = Qms (Hms-hw) + Qrh (Hhrh – Hcrm)

Qfg*Cpfg*(Tf -Teco) = Qms*(Hms–hw) + Qrh (Hhrh–Hcrh)

121


Detailed Heat Balance

Qfg*Cpfg*[ (Tf-Tpsh) + (Tpsh-Trh) + (Trh-Tfsh)

+ (Tfsh-Tltsh) + (Tltsh-Teco) + (Teco-Taph) ]

= Qw*S*(tfwo–tfwi) + Qw*S*(Ts –tfwo) + Qms*L

+ Qms*Cps*(Tms–Ts) + Qcrh* Cps* (Thrh–Tcrh)

I1+I2+I3+I4+ I5+I6 = F1+F2+F3+F4

Auxiliary Power Consumption

1. Pumps

2. Fans

3. Mills

4. ESP

5. Ventilation & Air Conditioning

6. Lighting

7. Miscellaneous

123

Pump Performance

ηp = Q*p*g*H/KWHr*ηm

ηp is Pump efficiency

Q is flow in Kg/Sec

p is density in Kg/ m cu

g is gravitational acceleration in m/sec sq

H is total dynamic head in m

KWHr is electricity supplied to the motor in KJ

ηm is driving motor efficiency

124

Affinity Laws

125

Specific Speed

126

Pump Performance

127

Pump Performance

128

Pump Performance

129

Pump Performance

130

Fan Performance

Total Efficiency

= Energy equivalent to total dynamic head / Shaft Energy

Static Efficiency

= Energy equivalent to total static head / Shaft Energy

131

Static Suction Lift - The vertical distance from the suction air line to the centerline of the impeller.Static Discharge Head - The vertical distance from the centerline of the impeller to the point of discharge.Dynamic Suction Head - The Static Suction Lift plus the friction in the suction line. Also referred to as a Total Suction Head.Dynamic Discharge Head - The Static Discharge Head plus the friction in the discharge line. Also referred to as Total Discharge Head.Total Dynamic Head - The Dynamic Suction Head plus the Dynamic Discharge Head. Also referred to as Total Head.

132

133

134

System Pressure Effects

• Fan curves are typically given in terms of totalpressure vs. volumetric flow rate.

• A typical fan running at a fixed speed canprovide a greater volumetric flow rate forsystems with smaller total pressure drops.

• Total pressure loss is total of static pressureloss and dynamic pressure loss.

• If exit and inlet area of a duct are about thesame, the dynamic pressure loss (or gain) maybe minimal.

135

136

Notes on Performance Characteristics

• Manufacturer will provide a fan curve for each fan

produced.

• The fan curves predict the pressure-flow rate

performance of each fan.

• Choose a fan that gives you the volumetric flow rate

you need for system pressure drop.

• Choose a fan that has its peak efficiency at or near

operating point.

• Sometimes Characteristics are provided in a tabulated

data format rather than in a graph.

138

Raw Coal Preparation

For direct firing of pulverized coal, the most commonly used methodfor steam generation:-

• Uninterrupted and uniformly controlled supply of raw coal to the milland the pulverized coal to the furnace is the most essential requisite.

• Organic foreign materials need to be removed as they would besource of fire hazard or impair the flow pattern of coal, air or theirmixture.

• Metallic objects, especially large one’s should be removed as theywould obstruct the coal flow, incorrect mill operation and evenseriously damage the pulverizer components.

• Raw coal shall be crushed to required size to have uniform flow ratefrom feeder to mill.

139

Bowl Mill Performance Optimization

- Mill output modulation

- Low rate of mill rejects (less than 10 %)

- Pulverized coal fineness at mill outlet

- Combustibles in fly ash and bottom ash.

- Optimum auxiliary power consumption.

140

Bowl Mill Performance Optimization

TechniqueThe procedure for mill optimization is a series oftests carried out to achieve the desired results;

- Clean air flow test and hot air flow test, calibration ofair flow instruments.

- Optimization of journal spring compression load.

- Optimization of bowl dp value, keeping mill rejectsunder control

- Classifier vane setting. Modifying the outlet venturiand or inverted cone to achieve the desired outputand pf fineness.

141

Factors Affecting Bowl Mill Performance

• Size of the raw coal

• Raw coal HGI

• Raw Coal Quality (moisture & ash content

• Pulverized fuel fineness

• Mill internals wear

142

143

144

145

146

Mill Capacity Calculation

147

148

149

Pneumatic Carrying of Particles

• To maximize the carrying capacity of the installation and carry flowswith high-solids concentration ("dense-phase flow").

• The ratio of coal to carrying Air is around 0.5 - 0.6 kg/kg.

• Assuming a coal density ρc = 1.5 x 103 kg/m 3, and the density of thecarrying Air as ρg = 0.9 kg/m 3, the volume fraction of the coal can beshown to be very small, 0.036 % .

• An important aerodynamic characteristic of the particles is theirterminal velocity (the free-fall velocity in stagnant air) which for aspherical particle of d = 0.1 mm has an approximate value of0.3m/sec.

• Due to non-uniformities of flow behind bends, and to avoid settlingof solids in horizontal sections of the mill discharge pipes,approximately V = 16 - 20 m/sec has to be chosen.

150

Prediction of Coal Drying

For predicting the amount of coal drying from the pulverizers,

following methods have been accepted.

• For very high rank coals (fixed carbon greater than 93 percent), an

outlet temperature of 75 to 80° C appeared most valid.

• For low- and medium-volatile bituminous coals, an outlet

temperature of 65 - 70° C appeared most valid.

• Bituminous coals appear to have good outlet moisture an outlet

temperature of 55 to 60° C is valid.

• For low-rank coals, subbituminous through lignite (less than 69

percent fixed carbon), all of the surface moisture and one-third of

the equilibrium moisture is driven off in the mills.

151

Performance Calculations

Several performance parameters are

calculated for the pulverizer train including

effectiveness of coal drying requirements,

pulverizer heat balance, primary air flow

requirements, number of pulverizers

required as a function of load and auxiliary

power requirements.

152

Pulverizer Heat Balance

To perform the necessary pulverizer heat and mass balancecalculations, the following parameters are required:

• Primary air temperature.

• Primary air/fuel ratio.

• Fuel burn rate.

• Coal inlet temperature.

• Coal moisture entering the mills.

• Coal moisture content at the mill exit.

• Mill outlet temperature.

• Minimum acceptable mill outlet temperature.

• Tempering air source temperature.

• Tempering air flow.

153

Management of Equipments’ Life Parameters

Wear/tear mechanism• Erosion

• Corrosion

• Creep

• Fatigue

• Overheating

154

Erosion High velocity fluid streams with suspended solid impurities erode heat

exchanger in thermal plants ranging from condenser to boiler. Onaverage, the erosion wear is proportional to the impact velocity of theparticles to the power 2.5. In general the extent of surface erosion byimpingement of abrasive particles depends upon the following factors.

• System operation conditions (such as particle impinging velocity,impact angle, particle number density at impact, properties of thecarrier fluid).

• Nature of target tube material (such as material properties, tubeorientation and curvature, and surface condition)

• The properties of impinging particles (such as particle type and grade,mechanical properties, size and sphericity)

155

Erosion

Erosion Control Parameters• Free stream velocity of the fluid (Uo)

• Impact velocity (W1)

• Frequency of impaction (η)

• Impingement angle (β1)

156

Erosion

Boiler Erosion Control

Indian boilers have already suffered an irreparable loss of life and

capacity utilization. Large deviation in coal parameters from thedesign specified values, leads to significant variation in impactingparticles’ properties (grade, size and shape), which erodesexternal tube surface and cause the failure much before theexpiry of design life time.

157

Erosion

Flue Gas Volume

Vfg

=Vair+Vm*(H/4+CO/24+M/18+N/28+O/32)*Qc

158

Erosion

0

2

4

6

8

10

12

14

16

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31

C% IN C/10

H %

O %

N %

S %

%hike Total vol

HHV KCal/kg/4000

159

Erosion

0

0.1

0.2

0.3

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31

Hydrogn Kg/Kg coal

Oxygen Kg/Kg coal

Nitrogn Kg/Kg coal

Sulfur Kg/Kg coal

%total volum Chang/45

Carbon Kg/Kg coal/5

160

Erosion

0

0.1

0.2

0.3

0.4

0.5

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29

Hydrogn Kg/Kg coal

Oxygen Kg/Kg coal

Nitrogn Kg/Kg coal

Sulfur Kg/Kg coal


Carbon Kg/Kg coal/5

161

Erosion

0

0.1

0.2

0.3

0.4

0.5

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31

Hydrogn Kg/Kg coal

Oxygen Kg/Kg coal

Nitrogn Kg/Kg coal

Sulfur Kg/Kg coal

%total volum

Chang/10Carbon Kg/Kg coal/5

162

Erosion

0

0.1

0.2

0.3

0.4

0.5

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31

Hydrogn Kg/Kg coal

Oxygen Kg/Kg coal

Nitrogn Kg/Kg coal

Sulfur Kg/Kg coal


Carbon Kg/Kg coal/5

163

Erosion

0

0.1

0.2

0.3

0.4

0.5

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31

Hydrogn Kg/Kg coal

Oxygen Kg/Kg coal

Nitrogn Kg/Kg coal

Sulfur Kg/Kg coal

%total volum


164

Erosion

0

0.1

0.2

0.3

0.4

0.5

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31

Hydrogn Kg/Kg coal

Oxygen Kg/Kg coal

Nitrogn Kg/Kg coal

Sulfur Kg/Kg coal

%total volum


165

Erosion

Free Stream Velocity Control• Air flow

• Coal flow

• Coal fineness

• Burner tilt

• Mill outlet temperature

• Secondary air temperature

• Combustion temperature

166

Erosion

Free Stream Velocity Control – Cont.• Secondary air damper position

• Heat absorption

• Air pressure at outlet of forced draught fan

• Flue gas pressure drop across the platen super heater, re-heater,final super heater, low temp super heater, economizer

• Flue gas temperature drop across platen super heater, re-heater,final super heater, low temp super heater, economizer

167

Flue Gas Erosion Abatement Techniques

Some of the tube erosion parameters such as shape, size grade,

frequency & velocity of the impacting particle, free stream velocity ofthe carrier fluid and surface condition of the tube itself depend uponvarious boiler operating and input parameters which can beimproved by;

– Use of beneficiated coal reduces the frequency of impactingparticles. In case of poor coal quality, coal blending and oilsupport also reduce the boiler tube erosion.

168

Flue Gas Erosion Abatement Techniques–Flue gas volume is proportional to the volume of the combustion

air. Accurate excess air management is quite essential to keepfree stream velocity well within the erosion limits

–Frequent use of soot blowing keeps the tube surface cleanwhich do not allow the cross section area to reduce to a value atwhich free stream velocity can cross the erosion limits.

–Baffle plates can be used in high speed zone of boiler to keepthe flue gas velocity within the specified ranges.

169


– Furnace Vacuum and differential pressures across thewind box, platen super heater, re heater, final superheater and economizer also influence the impactingparticle velocity. Well maintained boiler fans are essentialto keep various deferential pressures within the specifiedranges.

– Particle size can be controlled by maintaining pulverizershealthy. Reduced pulverizer capacity operation isessential in case of lower hard groove index, high ashcontent, high moisture content of the coal, and largerparticle size or poor fineness at its outlet.

170

Management of Human Safety

Parameters

• Global warming

• Acid rain

• Desertification

• Ozone layer depletion

171

Air pollution

• SOx

• NOx

• Suspended particulate matter

172


– Sufficient clearance must be incorporated at the designstage itself on the basis of erosion severity.

– Tubes of higher erosion resistance should be used.– Boiler should not be allowed to run at higher loads with

very poor coal– Tower type boilers are reported to be less susceptible for

flue gas erosion.– Air ingress through men holes, peep holes/inspection doors

and cracks should be minimized.

174

Ambient Air Parameters

• Temperature

• Humidity

• Purity

Influence• Air conditioning systems

• Air cooled devices

• Air handling devices

175


Performance loss for A/C systems

Change in air conditioning load on account of ambient air

temperature/ relative humidity up to the acceptable optimumvalues for the men and material inside control volume isinevitable. Difference between inevitably optimized values andpre- decided standard values is avoidable.

176

Ambient Air ParametersPerformance loss of air cooled devices

Huge amount of heat is rejected to the ambient air from coolingwater, air cooled electrical/electronic equipments andelectromechanical losses. Temperature, Humidity and Purityinfluence the functional performance of various air cooled deviceseither because of alteration in sensible heat addition to the air orbecause of reduction in latent heat addition to the air on account ofdifferent values of ambient air temperature and humidityrespectively.

177


Performance loss of air cooled devices

Difference between the dry bulb temperature and wet bulbtemperature, is proportional to the evaporation of the coolingwater through wet cooling tower, which in turn proportionatelyreduces the temperature of the cooling water and finally it leadsto better condenser vacuum, failing which the differencebetween hot cooling water temperature and ambient airtemperature must be high enough to absorb the total heat ofcooling water as the sensible heat of air flowing through thecooling tower and failing both, loss of vacuum becomesinevitable.

178


Performance loss for air handling devices

Driving motors of blowers, fans and compressors consume

significant power in thermal power stations, which increases

with increasing air temperature.

Fans and blowers in the plant handle huge quantity of air at low

and moderate discharge pressure, none of which is provided to

regulate the temperature of air at its inlet. High humidity and

suspended solid impurities increase little power consumption

but deteriorate the components of air handling device quite

significantly.

More power consumption in high flow, low pressure air handling

devices is inevitable

179

Ambient Air ParametersFew other effects of high ambient air temperature

• High air temperature helps in reducing down the flue gas exhausttemperature by increasing average air pre heater metaltemperatures and delaying the sulfuric acid formation.

• High air temperature also helps in maintaining relatively highervalues of hot primary air and secondary air, which leads to betterpulverization and combustion.

• Combustion air play vital role at the fire side of the boiler inputand output, positive aspects of the changes increase theprescribed standards of the performance and reduce theavoidable component of inefficiency and vice-versa.

180

Raw Water Parameters

• Deterioration in raw water quality increase the cost of chemicaltreatment for drinking, bearing cooling and main working media(de-mineralized water).

• No such treatment is done for the condenser cooling water anddeteriorates the condenser life by tube erosion and corrosion,which adversely influence electricity availability and thermalefficiency.

181


Loss of Condenser Vacuum

Condenser vacuum is a semi controllable parameter which is

limited by cooling water inlet temperature. Such loss in condenservacuum is inevitable and hence its impact has been quantitativelydetermined so that managerial efforts of vacuum improvementcan be concentrated on avoidable loss which is equal to actualloss minus the estimated inevitable

182


Loss of Condenser Vacuum

Condenser vacuum is a semi controllable parameter which is limited

by cooling water inlet temperature. Such loss in condenser vacuumis inevitable and hence its impact has been quantitativelydetermined so that managerial efforts of vacuum improvement canbe concentrated on avoidable loss which is equal to actual lossminus the estimated inevitable

183

De Mineralized Water Parameters

Initial FillingIt is observed that the de mineralized make up water separately

filled in condenser hot well, deaerator and boiler drum by usingmake up water pump, emergency lift pumps and boiler fill pumpsrespectively. This by passes starting facilities of supplyingauxiliary steam to last low pressure heater, hydrazine dozing afterdeaerator. This do not save starting time and energy as it isclaimed but likely to reduce boiler and turbine life due to improperquality of the boiler feed water.

184

DM Water/Steam Parameters

Causes of abnormal water level in the condenser;

• Failure of the auto control valve• High steam flow• Malfunctioning of the condensate pump• Tube failure

Consequences of abnormal water level in the condenser;• Sub cooling of the condensate increase heat loading• High level reduce the heat transfer area for condensation, which

results in poor vacuum• low level leads to the damage of the pump and heaters.• Raw water damages the entire DM water and steam circuit in a

catastrophic manner

185


Condensate System

Extraction steam flow/pressure/temperature and condensate/feed water

flow/temperature are the uncontrollable parameters and in turn thesemake the feed water outlet temperature as the uncontrollable parameter.A very little control on auxiliary steam flow to the last low pressureheater for initial heating before the deaerator is rarely utilized, whichleads to loss of life and efficiency

186


Proper Deaeration

Deaerator is meant for physical deaeration of the feed water and

raising its temperature and pressure to the suction requirement ofboiler feed pump.

Hydrazine is injected after the deaerator to reduce the oxygen lessthan the minimum displayable value of the instrument provided for.

187


Feed Water System

Loss of boiler/turbine life and thermal efficiency due to non availability

of the high pressure heaters have been reported to be quite significantin many Indian thermal power station, which demands betterstandards of operation and maintenance practices.

188


Feed Water Flow to the Boiler

Controlling device of the boiler feed pumps quickly ensure the

sufficient differential pressure across the feed control station fromwhere actual flow to the boiler is regulated to maintain the designprescribed water level in the boiler drum.

Normal drum level represents the thermodynamic stability of theboiler, which is controlled by rate of steam generation and steamflowing out of the boiler. Steam generation depends upon firing rateand feed water supply.

189


Sensible heat addition in economizer

Feed water temperature at the inlet of the economizer must be morethan the flue gas dew point temperature.

And at the outlet of economizer must be sufficiently lower than thecorresponding flue gas temperature

190


Evaporation

Steam generation rate in the water walls (evaporator) is controlled

by heat absorption at external surface of the tubes and fire ballposition. Evaporation abnormalities reflects on drum level, un-stability of which indicates poor boiler health.

Provision of restricting orifices at the evaporator tubes inlet toensure equal flow through the tubes help in reducing localizedstarvation and subsequent overheating.

191


Steam Super Heating and Re Heating

Steam temperature at the outlet of the super heater and re heater

should be maintained without injecting any attemperation byproperly controlling the other parameters, such as burner tilt andselecting the lower elevation for fuel firing

192


Expansion of steam in turbine

Expansion of steam through steam turbine must be monitored in

terms of design specified reductions in temperatures and pressures

Variation in turbo supervisory parameters must be analyzed for theimprovement of running parameters beginning with steamtemperature, pressure and purity.

193


Steam Flow Control • Flow of steam to the turbine is controlled by turbine governing

system in line with turbo supervisory parameters, generatorparameters, condenser vacuum, grid frequency and boilerparameters inclusive of steam temperature and pressure.

• Normal governing equipments, test equipments, pre emergencyequipments and emergency equipments must be maintained welland kept on auto functioning until there is a dire need to bypass anyone of them

Auxiliary Power Consumption

Pump Characteristics

Thank you

04.01.2013

1944

1932

1913

1889

1832

1810

1500 1600 1700 1800 1900 2000

170/537/537

170/537/565

246/537/537

247/537/565

247/565/593

247/600/610

Pa

ra

me

ter

Heat Rate (Kcal/Kwhr)198

SUBCRITICAL

SUPERCRITICAL

199

169 247

STEAM PRESSURE (ata)

Base

Gain in Eff %

1.10

1.08

0.14

0.14

0.33

5370C/5370C

5370C/5650C

5650C/5650C

5650C/5930C

6000C/6100C

5370C/5370C

38.69

39.77

39.91

40.05

40.38

37.59%

SUPERCRITICAL – GAIN IN

EFFICIENCY

Efficiency %

200

ULTRA SUPERCRITICAL

1960s 1970s 1980s 1990s 2000s 2010s

Mature

Technology

R&D-

Advanced

USC

Subcritical 170

K/540oC/540o

Super critical 245/540/540

245/540/565

245-580/593

285-600-620

310-610/620

350-700/720

Year

SUPERCRITICALSUB- CRITICAL

Un

de

r In

du

ctio

n

Re

cen

tly I

ntr

od

uce

d

211

212

20421951 1948 1944

18601778 1757

1598

2469

2248 2244 2236

2126

1993

18731792

2744

24702387 2378

22612166

19511906

0

500

1000

1500

2000

2500

3000

JSPL - DCPP, Sub

Critical

(135 MW)

JPL - Tamnar, Sub

Critical

(250 MW)

NTPC - Korba, Sub

Critical

(500 MW)

JPL - Tamnar, Sub

Critical

(600 MW)

Adani Power

Mundra, Low

Super Critical

(660 MW)

Tata Mundra, High

Super Critical

(800 MW)

Shandong Zoxian

China, Ultra Super

Critical

(1 0 0 0 M W)

On going research,

Advance Ultra

Super Critical

(600 MW)

Heat Rate of Various Power Stations

Turbine Heat Rate Gross Unit Heat rate Net Heat Rate

Pr – 133 bar

Temp- 540 oC /

540 oC Pr – 147 bar

Temp- 540 oC /

540 oC Pr – 170 bar

Temp- 540 oC /

540 oC Pr – 181 bar

Temp- 540 oC /

566 oC Pr – 247 bar

Temp- 540 oC /

566 oC Pr – 280 bar

Temp- 565 oC /

593 oC Pr – 252 bar

Temp- 605 oC /

605 oC Pr – 310 bar

Temp- 705 oC /

705 oC

31.35

34.8136.03 36.16

38.0339.71

44.0845.12

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

JSPL - DCPP, Sub

Critical

(135 MW)

JPL - Tamnar, Sub

Critical

(250 MW)

NTPC - Korba,

Sub Critical

(500 MW)

JPL - Tamnar,

Sub Critical

(600 MW)

Adani Power

Mundra, Low

Super Critical

(660 MW)

Tata Mundra,

High Super

Critical

(800 MW)

Shandong Zoxian

China, Ultra

Super Critical

(1 0 0 0 M W)

On going

research,

Advance Ultra

Super Critical

(600 MW)

Efficiency of Various Power Plants

Pr – 133 bar

Temp- 540 oC /

540 oC

Pr – 147 bar

Temp- 540 oC /

540 oC

Pr – 170 bar

Temp- 540 oC /

540 oC

Pr – 181 bar

Temp- 540 oC /

566 oC

Pr – 247 bar

Temp- 540 oC /

566 oC

Pr – 280 bar

Temp- 565 oC /

593 oC

Pr – 252 bar

Temp- 605 oC /

605 oC

Pr – 310 bar

Temp- 705 oC /

705 oC

Carbon Capture and Storage

Documents

Management of Thermal Power Plant Efficiency