Performance Evaluation Of Mills, Boiler And Fans In Thermal Power Plants.

Introduction of power plant performance and monitoring, need, objectives, controllable and uncontrollable factors

Material Written, compiled and presented by: Mr. V.K.Gupta, Maintenance Faculty, NPTI, Badarpur 1

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 Objectives: The sole objective of monitoring the plant performance and calculating various efficiencies can be summarised as follow: ● To maximise generation, i.e. With the burning of the unit quantity of fuel (Coal or oil) The generation of electricity must be as close to the theoretical values. This can also be narrated the other way : i.e. to generate one unit of electricity, fuel consumption must be as close to the theoretical value as possible. ● This is termed as Plant Heat Rate. ● Plant Heat rate can be what is desired and what we achieve. ● The later is always more than the earlier one. ● There can be no of factors responsible for a higher value of the plant heat rate. 2

● The coal plant getting coal from mines is inferior than for what it is designed for. ● The inferior coal means it may have lower carbon contents, higher percentage of ash, higher moisture and volatile matters. In other words the Gross calorific value and net calorific value may be lower than what is desired. ● Incomplete burning of coal inside the furnace. ● The quantity of unburnt coal going waste into the bottom and fly ash is high. ● Mills not performing as they should. ● Quantity of Excess air is either high or low than the theoretical one. ● Fan not performing as expected. In other words a proper furnace draught is not established. ● High air ingress inside the furnace. 3

● Condition of boiler tube is bad. i.e High Scale deposits inside Super heater tubes, Ash deposits on the outside of the tubes, reducing heat transfer, Boiler tubes leakages, Clogging of economiser fins, Distortion in alignments in the various tube banks, Poor weld joints. ● Soot Blower not operating as expected. ● Higher rate of Boiler blow down. ● Improper operation. ● Lack of training. Still many more obviously will reduce the boiler efficiency meaning less heat being transferred to the boiler feed water and Steam. 4

What are the things which are in our control and if we care about them certainly plant performance / availability / capacity factor and as a result more generation and higher efficiency can be achieved. For a given power plant, heat rate depends on the plant’s design, its operating conditions, and its level of electric power output. In theory, 3,412 Btu of thermal energy is equivalent to 1 kWh of electric energy. For existing coalfired power plants, heat rates are typically in the range of 9,000 Btu/kWh to 11,000 Btu/kWh. A plant with the U.S. industry average heat rate of 10,300 Btu/kWh is operating with an overall plant efficiency of about 33% (3,412/0.33 = 10,339). 5

When it comes to efficiency, the first thing that we should consider are the losses. If we are able to minimize the losses then ultimately the efficiency will increase. Similarly in case of thermal power plant also many methods are employed in order to improve the efficiency. 1.Good Quality Coal 2. Proper Coal Pulverization 2. VFD for Motors 3. Bag Filters in ESP 4. TD-BFP 5. Duplex Heaters

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Now a days you will see that a new technology called "SUPER CRITICAL" is being employed by many new plants. In case of super critical power plants the efficiency of the turbine is increased as the super critical boilers work at a very high pressure, which ultimately increases the work done by the turbine. There are 3 TPS technologies available at present 1) Sub-critical technology (design efficiency 36–37%) 2) Super critical technology (design efficiency 44–45%) 3) Ultra Super critical technology (design efficiency more than 45%). So, Ultra Super critical technology power plant shall be the best from efficiency point of view. 7

Some general methods to improve the efficiency are 1. Operate the power plant near to design main steam pressure & temperature. 2. Use of VFDs 3. Replace conventional 6.6 KV HT motors with energy efficient motors. 4. Proper maintenance of LP & HP heaters, Economiser, Super heaters & Air-preheaters. 5. Attending passing of high energy drain valves. 6. Maintaining proper vacuum in condenser. 7. Using LED lights for lighting purpose 8

8. Optimizing and attending leakages of instrument & service air. 9. Checking of conditions of pumps 10.Optimizing the running of air conditioning system 11.Operating equipment close to design efficiency 12.Optimizing the number of coal mills running 13.Optimizing the running of conveyor belts for transporting coal from coal handling plant to main power house site. 14.Optimizing total air flow 15.Ensuring proper working of SADC dampers, soot blowers & burner tilt mechanism. 16. Maintain thermal insulation in right condition 17. Plant operation, follow procedures 18. Operate the Pump and fans near to it,s BEP

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Training, peer review, honest audit 19. Proper maintenance, Testing and calibration 20. On line instrumentation and their calibration 21. Efficient online repairing or maintenance facility 22. Root Cause analysis and implementation of the finding 23. Research and material failure analysis 24. Market/venders support 25. Welder’s qualification 26. ISI program and still many more 27. House Keeping 28. Labelling, sign boards and paintings of pipe lines 29. Implementation of safety culture 30. Workers (Operation and Maintenance qualifications) with incentive

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 What is not in our hand: 1. Quality of coal supplied 2. Quality of water supplied 3. Quality of ambient air

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 With my limited knowledge, few things which I can think of to improve thermal plant efficiency are as follows Using good quality coal Thermal plants have very low efficiency mainly due to burning of coal which requires a lot of energy. In India, we generally mix very small amount of high quality coal which is imported from foreign countries with coal obtained from Indian mines which is of generally low efficiency. By increasing the amount of high quality coal concentration, efficiency can be improved but then it will also lead to increase in power production cost which ultimately is to be paid by consumers. Hence , there must be balance between efficiency and cost. 12



By reducing the leakage of steam, flue gases etc:

The leaked out steam does not contribute to the power generation and is wasted thus decreasing the overall efficiency. Hence, leakage must be reduced which can be done by continuous real time monitoring of boiler, pipes, heat exchanger etc using advanced software and computation technologies. Also, the seals of boiler, pipes etc must be examined regular and , if required, must be replaced.  Continuous monitoring of coal and air input to boiler The amount of coal and air being fed to boiler must be continuously monitored in real time and must be regulated as required.

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● Higher plant availability or higher availability factor will also lead to higher plant efficiency. ● Online data or operating parameters monitoring by data acquisition or the distributed digital control system will also help in achieving exacting information helping to take corrective measure timely , which is a key to achieving higher plant efficiencies. ● Overall Plant/Station efficiency = Output of the station ----------------------- x100 Input of the station Energy sent out (KW) = --------------------------------------Fuel burnt(kg) x Calorific Value of fuel (Kcal/kg) 14

The turbine and generator efficiency are also taken into calculation while calculating the overall efficiency along with Boiler efficiency. Boiler efficiency for(RH boiler) ƞB = Steam supplied in kg x Total heat in superheated steam =

Total heat added to feed water in Boiler / kg ----------------------------------------------------------------Fuel burnt (kgs) x Calorific value of fuel (Kcal / kg)

ShB - hf ƞB = ----------------------- x 100 L x C.V Where: ShB= Enthalpy of S.H Steam ( Kcal/Kg) at Boiler hf = Enthalpy of feed water (kcal /kg)at F TS = Total Steam supplied in kg L = Fuel Burnt CV = Calorific Value of fuel

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Turbine efficiency:

ƞT =

=

Mechanical work output (kcal) ------------------------------------------------ x 100 Isentropic heat drop across turbine Mechanical work output (kcal) ---------------------------------------------- x 100S (hB – hA)

A & B are the points considered at turbine inlet and outlet hA = Enthalpy of steam at point A hB = Enthalpy of steam at point B

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The heat rejected in condenser is about 45 to 55% of the total available heat energy available at turbine inlet. Thus cycle efficiency:

ƞC =

Eenrgy available for conversion into work (kcal) ------------------------------------------------- x 100 Energy given as heat in boiler

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ƞG =

Ƞos

Electrical energy sent out (kWhr x 860) ----------------------------------------------------- x 100 Mechanical Work

= ƞB x ƞT x ƞC x ƞG

Thus overall station efficiency = Boiler efficiency x Turbine efficiency x Condenser efficiency x Generator efficiency

ȠOTA = ȠT x ȠC x ȠG ȠOS

= ȠB x ȠOTA

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Heat Rate: Heat rate is defined as heat supplied to steam to produce I KWh of electrical energy:

Heat supplied to steam in (Kcal) in boiler HR = ---------------------------------------------------------Electrical energy sent out in KWhr Since one 1KW = 860 Kcal ȠOS =

860 ---------- x 100 Plant HR

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Typical Losses Typical Losses Pressure

Temp.

Boiler

Turbine & cycle

Generator

Total

To bus bar

Bar

0C

% loss

% loss

% loss

% age

%age output

41.4

455

14

50.25

1.75

72

28

62

480

13

55

2

70

30

93

510

12.5

53.75

2.25

68.50

31.5

103

536

11

52.5

2.5

66

34

162

565

10

49

3

62

38

241

593

9

48.25

3.75

61

39

310

650

9

46.5

4.0

50.5

49.5

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 Typical Boiler Losses: 1. Dry Flue Gas loss 2. Wet flue gas loss (loss due to moisture in fuel and due to moisture formed by combustion of H2 in fuel 3. Moisture in combustion Air Loss 4. Unburnt carbon loss – carbon in Ash Loss 5. Unburnt gas loss -- Due to incomplete combustion of carbon 6. Radiation and unaccounted losses

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 Dry Flue Gas Loss depends upon two factors  Excess Air  Air Preheater gas outlet temperature high Excess Air: Excess air is the quantity of air over and above theoretical air being fed into the furnace by FD fans for complete combustion of pulverised coal. This hoovers around 20%. Too little excess air fuel is not completely burnt and too much lead to greater amount of heat carried to stack by flue gas by N2 contained in the excess. This heat loss amount to significant loss and this can be measured by measuring the O2 in flue gas. 22

 Air heater gas outlet temperature: The air heater outlet gas temperature should be lowest from the point of overall efficiency. On the other hand this temperature should be higher than the dew point of sulphur which otherwise will cause condensation and then corrosion of the ducting. For Indian coal with sulphur around 0.5% air preheater gas outlet temp be around 1300C. Lower leads to corrosion and higher decrease in Boiler eff. A typical 220C rise in gas outlet temp. reduces the boiler eff. By 1%.  Causes for higher gas outlet temp. ● Lack of shoot blowing ● Deposits on Boiler heat transfer surface ● High excess air 23

● Low final feed water temperature ● Higher ele. Burner in service at low loads. ● Defective baffles and bypass dampers, causing gas short circuiting some heater transfer surface. ● Improper combustion ● Poor milling plant performance – An incorrect PA / Sa ratio causing delayed combustion ● Air re-circulation reduces the heat removed from flue gas. ● Air in leakage before the combustion chamber.

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 Low air heater gas outlet temperature: Though in the short run, low APH gas outlet temperature improves eff. In the long run it can result in lower boiler eff. Because of deposition of sulphur on its elements and corrosion. The deposited material may also cause loss of availability and reduction in heat transfer in the air heater.  Wet Flue Gas loss: Moisture that enters the combustion chamber as part of the fuel causes a heat loss, because it must be heated to its boiling point first, then evaporation and then superheating before it leaves the boiler along with flue gas. So lot of heat is wasted in doing so. 25

 Carbon in Ash Loss: This loss depends upon the fineness of pulverised coal, excess air and combustion condition. If the conditions are not monitored properly the loss which should be around 1% may be as high as 4 to 5%.  Causes of high carbon in ash are: Coarse grinding Mal adjustment of flame Unequal loading of different mills Incorrect PA fan temperature. Causes of Coarse grinding: Mill in need of adjustment Exhauster speed too high in relation relative to feed rate. Weak fuel / air mixture i.e high PA Separator (Classifier) speed too high 26

Radiation and Unaccounted Heat Losses: These are the heat losses as follows 1) Heat carried away in ash 2) Loss from boiler casing to the surrounding 3) Heat loss in bottom water seal 4) Loss of heat due to unburnt volatile matter 5) These loss account for around 1%. Radiation loss depends upon effectiveness of the insulation all around the boiler casing and feed water piping.

 Problem associated with high ash contents in coal:  Effect of varying boiler load on efficiency:  Control of Boiler Blow Down:  Usually it is for a period of around 2 minutes in every shift and increase in boiler blow down will reduce the Boiler eff.  Auxiliary Power Consumption: Running additional auxiliary only when it is essential and that only when it is going to yield fruitful result.  Using efficient type of control for regulation of fans and pumps  Optimization of air, fuel and water consumption  Better maintenance and house keeping. 27

Optimization of oil consumption: PF boiler consumes oil under different operating conditions. It makes little difference in heat consumption. Too much dependence on oil for flame stabilization and lt low loads should be only as necessary and not an easy remedy. Cost of oil is far more than cost of coal so the generation cost will also be high. Oil should be used judiciously.

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Performance monitoring of Pumps and Fans The objective of observing the Performance of Fan and Pumps is very vital. Both Fans and Pumps are similar machines. Both have same like components. Even the operating principle of two is also similar. We understand the Bernoulli's theorem and also know that sum total of energies of the fluid flowing through a confined passage is constant. Usually there are three components of Total pressure that is Pressure energy, kinetic energy and potential energy. While the fluid is flowing through a pipe line or the duct one is altered at the cost of other until and unless energy is not added. 29

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Pumps and Fans add energy to fluid with the help of a motor and the rotating component that is impeller. Which increases the kinetic energy which if then converted to pressure at it’s own cost. These are known as Centrifugal machines. There is another which is called axial flow machines which only displaces the fluid at high rate axially without converting to pressure energy. We must understand the internals or the type to monitor it’s behaviour and gauge the performance. We must understand whether the energy input, after all it is costing to us, how much of it is doing it job. So come efficiency into picture. Every fan or a pump has a specific point of operation where it’s efficiency is maximum. Do we know that. 31

At this point the fan or the pump will deliver a known flow against a specified head. How much energy the pump or the fan is drawing from the motor should be know. If it is more than the specified one that means pumps is not performing well or where I am operating the pump is not correct. One more point depending upon the demand or the load on the unit the flow by the pump or the fan has to alter that is less or more than the operating point at which the efficiency was maximum, by throttling the discharge valve or the speed or the inlet damper or varying the pitch of the vanes what ever we do the flow should in the most efficient manner, one thing you must understand it is always at the cost efficiency and so it is uneconomical. That is what comes into picture. If I am operating the plant at less load than rated load it is always inefficient and performance of the fan or the pump will e considered to be poor. As said how do we do this is also important. It is therefore very essential that before we proceed into the job of calculating the performance and efficiency we must 32 understand the following.

In figure of pumping layout the pump takes water from below it’s centre line and deliver to some higher elevation. Various pumping terminologies or the terms have been mentioned. Let us study them. Suction Lift marked is known as Static Suction lift. When Velocity head and Suction friction head is added to static Suction lift it is called Suction lift or the total suction lift. Suction Lift = Static Suction Lift + Velocity Head + Frictional Head + Entry loss etc.

hL = hSSL + hv2/2g + hf + hi Or

hSSL = hL – ( hv2/2g + hf + hi)

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Here the water source is above the pump centre line. This is known as Suction Head. And Static Suction head S = Suction Head + Velocity head + Frictional Head + other losses it can be written like this: S = hs + Hv2/2g + Hf + He In both suction lift and suction head velocity of flow is almost decided as around 4 to 5 m/s what can be altered is the frictional head loss and entry losses.

hf

is given by = 4fv

2L/2gd

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Hf can be reduced by F is a constant and depends upon the type of flow and internal condition od the suction piping. It should be as smooth as possible. Velocity of flow is almost fixed Length of the suction pipe should be as short as possible Diameter of the suction pipe should be as large as possible

Similarly he can also be reduced by reducing entry losses and no of fittings etc. Avoid zig zag suction piping That is why entry point is always like a funnel or skirt.

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Similarly Static Discharge head hd = hD – (hV2/2g + H f d + h exit) So when pumps and fans performance is monitored friction head loss and entry and exit losses are seen Since they have direct bearing on static suction head and static discharge head. Some times Velocity may have to be reduced by increasing the suction pipe diameter.

Now NPSH = NPSH is a phenomenon at the suction side only. It is known as minimum pressure required at the pump inlet which will cause the full flow to entre the impeller eye.

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40

41

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43

44

45

46

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 Affinity laws The affinity laws for pumps/fans are used in hydraulics and/or HVAC to express the relationship between variables involved in pump or fan performance (such as head, volumetric flow rate, shaft speed) and power. They apply to pumps and fans in common. In these rotary implements, the affinity laws apply both to centrifugal and axial flows. The affinity laws are useful as they allow prediction of the head discharge characteristic of a pump or fan from a known characteristic measured at a different speed or impeller diameter. The only requirement is that the two pumps or fans are dynamically similar, that is the ratios of the fluid forced are the same. 48

Law 1. With impeller diameter (D) held constant: Law 1a. Flow is proportional to shaft speed: Q1 N1 ------ = ------Q2 N2 Law 1b. Pressure or Head is proportional to the square of shaft speed: H1 N1 ------ = { ---- } 2 H2 N2 Law 1c. Power is proportional to the cube of shaft speed:

P1 N1 ------ = { ---- } 3 P2 N2 49

Law 2. With shaft speed (N) held constant: Law 2a. Flow is proportional to the impeller diameter: D1 N1 ------ = ------D2 N2 Law 2b. Pressure or Head is proportional to the square of the impeller diameter: D1 N1 ------ = { ---- } 2 D2 N2 Law 2c. Power is proportional to the cube of impeller diameter: D1 N1 ------ = { ---- } 3 D2 N2 50

where Q is the volumetric flow rate (e.g. CFM, GPM or L/s), D is the impeller diameter (e.g. in or mm), N is the shaft rotational speed (e.g. rpm), H is the pressure or head developed by the fan/pump (e.g. psi or Pascal), and P is the shaft power

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Three Phase KW E I PF = 173∗ ∗∗ 1000

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COAL -COKE…. Grades of Coking Coal Grades of Non-coking Coal Grades of Semi-coking and Weakly Coking Coal Grade Ash Content Steel Grade - I

Not exceeding 15%

Steel Grade -II

Exceeding 15% but not exceeding 18%

Washery Grade -I

Exceeding 18% but not exceeding 21%

Washery Grade -II

Exceeding 21% but not exceeding 24%

Washery Grade -III

Exceeding 24% but not exceeding 28%

Washery Grade -IV

Exceeding 28% but not exceeding 35%

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COAL GARDES….CIL

Grade

Useful Heat Value (UHV) (Kcal/Kg) UHV= 8900138(A+M)

Corresponding Gross Calorific Value Ash% + Moisture % GCV (Kcal/ Kg) (at at (60% RH & 40OC) 5% moisture level)

A

Exceeding 6200

Not exceeding 19.5

Exceeding 6454

B

Exceeding 5600 but not exceeding 6200

19.6 to 23.8

Exceeding 6049 but not exceeding 6454

C

Exceeding 4940 but not exceeding 5600

23.9 to 28.6

Exceeding 5597 but not exceeding. 6049

D

Exceeding 4200 but not exceeding 4940

28.7 to 34.0

Exceeding 5089 but not Exceeding 5597

E

Exceeding 3360 but not exceeding 4200

34.1 to 40.0

Exceeding 4324 but not exceeding 5089

F

Exceeding 2400 but not exceeding 3360

40.1 to 47.0

Exceeding 3865 but not exceeding. 4324

G

Exceeding 1300 but not exceeding 2400

47.1 to 55.0

Exceeding 3113 but not exceeding 3865

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PERFROMANCE TESTING …..A TYPICAL SCHEDULE

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PERFROMANCE TESTING …..A TYPICAL REPORT

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BOILER PERFORMANCE…. DIRECT METHOD Basically Boiler efficiency can be tested by the following methods: 1) The Direct Method: Where the energy gain of the working fluid (water and steam) is compared with the energy content of the boiler fuel. 2) The Indirect Method: Where the efficiency is the difference between the losses and the energy input. The Direct Method Testing

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BOILER PERFORMANCE…. DIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT MATHOD

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BOILER PERFORMANCE…. INDIRECT MATHOD

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BOILER PERFORMANCE…. INDIRECT MATHOD

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BOILER PERFORMANCE…. INDIRECT MATHOD

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BOILER PERFORMANCE…. INDIRECT MATHOD

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BOILER PERFORMANCE…. INDIRECT MATHOD

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BOILER PERFORMANCE…. INDIRECT MATHOD

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BOILER PERFORMANCE…. INDIRECT MATHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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BOILER PERFORMANCE…. INDIRECT METHOD

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Step-1: Calculate the theoretical air requirement = [(11.43 x C) + [{34.5 x (H2 – O2/8)} + (4.32 x S)]/100 kg/kg of oil = [(11.43 x 84) + [{34.5 x (12 – 1/8)} + (4.32 x 3)]/100 kg/kg of oil = 13.82 kg of air/kg of oil

Step 4: Estimate all heat losses i. Percentage heat loss due to dry flue gas = m x Cp x (Tf – Ta ) x 100 ---------------------------GCV of fuel m = mass of CO2 + mass of SO2 + mass of N2 + mass of O2 0.84 x 44 0.03x64 20.74x77 m = ----------- + ---------- + ----------- (0.07 x 32) 12 32 100 m = 21.35 kg / kg of oil 21.35 x 0.23 x (220 – 27) = ------------------------------- x 100 10200 = 9.29%

Step-2: Calculate the % excess air supplied (EA) Excess air supplied (EA) = (O2 x 100)/(21-O2) = (7 x 100)/(21-7) = 50% A simpler method can also be used:Percentage heat loss due to dry flu Step 3: Calculate actual mass of air supplied/ kg of gas fuel (AAS) m x Cp x (Tf – Ta ) x 100 AAS/kg fuel = [1 + EA/100] x Theo. Air (AAS) = -----------------------------= [1 + 50/100] x 13.82 GCV of fuel = 1.5 x 13.82 m (total mass of flue gas) = 20.74 kg of air/kg of oil = mass of actual air supplied + mass of fuel supplied 20.19 + 1 = 21.19 ii. Heat loss due to evaporation of water formed due to H2 in =fuel = 21.19 x 0.23 x (220-27) 9 x H2 {584+0.45 (Tf – Ta )} ------------------------------- x 100 = --------------------------------10200 GCV of fuel = 9.22% where H2 = percentage of H2 in fuel 9 x 12 {584+0.45(220-27)} = -------------------------------10200 = 7.10% iii. Heat loss due to moisture present in air AAS x humidity x 0.45 x ((Tf – Ta ) x 100 84 = ------------------------------------------------GCV of fuel

BOILER PERFORMANCE…. BLOW DOWN Boiler Blow Down When water is boiled and steam is generated, any dissolved solids contained in the water remain in the boiler. If more solids are put in with the feed water, they will concentrate and may eventually reach a level where their solubility in the water is exceeded and they deposit from the solution. Above a certain level of concentration, these solids encourage foaming and cause carryover of water into the steam. The deposits also lead to scale formation inside the boiler, resulting in localized overheating and finally causing boiler tube failure. It is therefore necessary to control the level of concentration of the solids. This is achieved by the process of 'blowing down', where a certain volume of water is blown off and is automatically replaced by feed water - thus maintaining the optimum level of total dissolved solids (TDS) in the boiler water. Blow down is necessary to protect the surfaces of the heat exchanger in the boiler. However, blow down can be a significant source of heat loss, if improperly carried out.

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BOILER PERFORMANCE…. BLOW DOWN Conductivity as indicator of boiler water quality Since it is tedious and time consuming to measure total dissolved solids (TDS) in boiler water system, conductivity measurement is used for monitoring the overall TDS present in the boiler. A rise in conductivity indicates a rise in the "contamination" of the boiler water. Conventional methods for blowing down the boiler depend on two kinds of blow down: intermittent and continuous

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BOILER PERFORMANCE…. BLOW DOWN Intermittent blow down The intermittent blown down is given by manually operating a valve fitted to discharge pipe at the lowest point of boiler shell to reduce parameters (TDS or conductivity, pH, Silica and Phosphates concentration) within prescribed limits so that steam quality is not likely to be affected. In intermittent blow down, a large diameter line is opened for a short period of time, the time being based on a thumb rule such as “once in a shift for 2 minutes”.

Continuous blow down There is a steady and constant dispatch of small stream of concentrated boiler water, and replacement by steady and constant inflow of feed water. This ensures constant TDS and steam purity at given steam load. Once blow down valve is set for a given conditions, there is no need for regular operator intervention. Even though large quantities of heat are wasted, opportunity exists for recovering this heat by blowing into a flash tank and generating flash steam. This flash steam can be used for pre-heating boiler feed water or for any other. This type of blow down is common in high-pressure boilers. 87

BOILER PERFORMANCE…. BLOW DOWN Blow down calculations The quantity of blow down required to control boiler water solids concentration is calculated by using the following formula: If maximum permissible limit of TDS as in a package boiler is 3000 ppm, percentage make up water is 10% and TDS in feed water is 300 ppm, then the percentage blow down is given as: = 300 x 10 / 3000 =1% If boiler evaporation rate is 3000 kg/hr then required blow down rate is: = 3000 x 1 / 100 = 30 kg/hr Benefits of blow down control Good boiler blow down control can significantly reduce treatment and operational costs that include: •Lower pretreatment costs •Less make-up water consumption •Reduced maintenance downtime •Increased boiler life •Lower consumption of treatment chemicals

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BOILER PERFORMANCE…. a TYPICAL TEST FOR 500 MW

Abbreviated Efficiency Tests Boiler Losses Typical values Dry Gas Loss 5.21 Unburnt Loss 0.63 Hydrogen Loss 4.22 Moisture in Fuel Loss 2.00 Moisture in Air Loss 0.19 Carbon Monoxide Loss 0.11 Radiation/Unaccounted Loss 1.00 Boiler Efficiency

86.63

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BOILER PERFORMANCE…. OBJECTIVES

Boiler Performance Optimization •

To evolve an optimum operating regime for a boiler

•

To establish interrelationships between different operating parameters

•

To build a database by various parametric tests

A baseline test is conducted with normal running conditions. Thereafter, one variable is varied at a time and its effect on boiler losses and other operating parameters is studied to find an optimum set of parameters. 90

BOILER PERFORMANCE….

Effect of Operating Parameters on Boiler Losses

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BOILER PERFORMANCE….INSTRUMENTS

HVT - High Velocity Thermocouple Probe 92

BOILER PERFORMANCE…. Penthouse

Drum

SH Div. Panel

SH

.

.

Nose . Arch

.

Locations for HVT & HVS Sampling 93

BOILER PERFORMANCE….

Instruments Used • Dirty Pitot • Rotary Sampler • FG Sampling SystemProbes Bubble Jar Condenser Desiccant jar Vacuum Pump • • • •

Gas Analyzers Datascan boxes High Velocity Thermocouple High Volume Sampler

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BOILER PERFORMANCE…. FG Expansion Bellow

Test Ports

Economizer HVS

APH Sampling Locations APH FG

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BOILER PERFORMANCE….

High Volume Sampler

BOILER PERFORMANCE….

Sampling Ports in Flue Gas Ducts (Typical ) 100mm

Sampling Point for Flue Gas Temperature & Composition

97

BOILER PERFORMANCE….

Flue Gas Sampling Train FG Samples from probes Desiccant Jar Bubble Jar Condenser

Datascan Boxes

Gas Analyser s

Vacuum Pump

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Sampling Locations •

Flue Gas Duct at APH in/outlet

•

Primary Air Duct at APH in/outlet

•

Secondary Air duct at APH in/outlet

•

Furnace Gooseneck

•

Economizer Outlet

•

Feeder Inlet chutes

•

Bottom Ash Hoppers

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Air Ingress Points – Furnace Roof , Expansion joints, Air heaters, Ducts, ESP Hoppers, Peep Holes, Manholes, Furnace Bottom Air-inleakage

Furnace Outlet Zirconia O2 Probe Expansion Joints AH Seal Lkg

ESP

100

Oxygen % at various locations in boiler 10

O2 %

8 6 4 2 0 Furn Outlet 210 MW

AH Inlet 210 MW

AH Outlet

ID outlet

500 MW

210 MW 101

BOILER PERFORMANCE….

Typical Boiler Problems •

Imbalance in air and coal flow through the discharge pipes of an individual mill

•

High primary air flows through the mills

•

Difference in pulverized coal fineness amongst the discharge pipes of an individual mill

•

High furnace exit gas temperatures at furnace outlet

•

High SH or RH sprays

•

Imbalance in flue gas composition and temperature profile at furnace exit

•

Air ingress from the furnace bottom, from the expansion joints in the flue gas duct or from the duct between air heater and ID fans and quantification of the same 102

BOILER PERFORMANCE….

Typical Boiler Problems contd.. •

Air ingress from the nose arch, penthouse and boiler second pass and quantification thereof

•

Difference between on line zirconia reading and the actual oxygen in the flue gas duct as measured by the sampling grid

•

Difference between actual and 'on line' temperature measurement of air heater air / gas outlet temperatures

•

Fouling and Slagging

•

High unburnt Carbon in flyash or bottomash

•

High air heater leakage - reduced by ALCS operation

•

Boiler operation at high excess air 103

FAN PERFORMANCE

104

FAN PERFORMANCE

Effect of Blade Type on Erosion Resistance and Efficiency

105

FAN PERFORMANCE

Fan Curves • Manufacturer will provide a fan curve for each fan • 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 your system pressure drop. • Choose a fan that has its peak efficiency at or near your operating point. • Sometimes will provide data in a table rather than in a graph.

106

FAN PERFORMANCE

107

FAN PERFORMANCE

Centrifugal Fan Performance Curve.

108

FAN PERFORMANCE

Fan Laws Flow ? Speed

Pressure ? (Speed)2

Q1 N 1  Q2 N 2

SP1  N 1    SP 2  N 2 

2

Varying the RPM by 10% Varying the RPM by 10% decreases or increases air decreases or increases the delivery by 10%. static pressure by 19%.

Power ? (Speed)3

kW 1  N 1    kW 2  N 2 

3

Varying the RPM by 10% decreases or increases the power requirement by 27%.

Where Q – flow, SP – Static Pressure, kW – Power and N – speed (RPM) 109

FAN PERFORMANCE

Fan Laws • Law 1 – relates to effect of changing size, speed, or density on volume flow, pressure, and power level • Law 2 – relates to effect of changing size, pressure, or density on volume flow rate, speed, and power • Law 3 – shows effect of changing size, volume flow, or density on speed, pressure, and power • The laws only apply to aerodynamically similar fans at the same point of rating on the performance curve.

110

FAN PERFORMANCE

Scheme of Air and Gas Path

111

FAN PERFORMANCE

Draught System Pressure Variation

Duct APH

Duct

Furnace

Back pass

Duct

APH

ESP

Duct

FD Fan

Duct

• Pressure drop calculation in air & gas path and its comparison with design value. • Assessment of ID and FD fan power as a function of furnace pressure. • Assessment of effective kinetic rate coefficient as a function of furnace pressure.

ID Fan

Chimney

112

FAN PERFORMANCE

Pressure Variation Furnace Pressure At Various Points in Boiler

1 250

2 200

3 150

4 100

Furnace Pressure

5

FD Fan Inlet FD Fan Outlet

Airheater Inlet Airheater Outlet

Windbox Pressure

50

6

Furnace

0

7

Superheater Platen Inlet

1

2

3

4

5

6

7

8

9

10

11

12

13

14

8

-50

9 -100

10 -150

11 -200

12 -250

13

-300

14

Reheater Inlet LTSH Inlet Economiser Inlet Airheater Inlet E.P. Inlet I.D. Fan Inlet I.D. Fan Outlet

Points in Boiler

113

FAN PERFORMANCE Purpose of the Performance Test The purposes of such a test are to determine, under actual operating conditions, the volume flow rate, the power input and the total pressure rise across the fan. These test results will provide actual value for the flow resistance of the air duct system, which can be compared with the value specified by supplier.

Static Pressure: The absolute pressure at a point minus the reference atmospheric pressure. Dynamic Pressure: The rise in static pressure which occurs when air moving with specified velocity at a point is bought to rest without loss of mechanical energy. It is also known as velocity pressure.

Total Pressure: The sum of static pressures and dynamic pressures at a point. Fan Shaft Power: The mechanical power supplied to the fan shaft Motor Input Power: The electrical power supplied to the terminals of an electric motor drive. 114

FAN PERFORMANCE

General: The flow measurement plane shall be located in any suitable straight length, (preferably on the inlet side of the fan) where the airflow conditions are substantially axial, symmetrical and free from turbulence. Leakage of air from or into the air duct shall be negligible between the flow measuring plane and the fan. Bends and obstructions in an air duct can disturb the airflow for a considerable distance downstream, and should be avoided for the purposes of the test.

115

FAN PERFORMANCE Test length: That part of the duct in which the flow measurement plane is located,

is termed the ‘test length’ and shall be straight, of uniform cross section. It shall have a length equal to not less than twice the equivalent diameter of the air duct (i.e. 2De). For rectangular duct, equivalent diameter, De is given by 2 LW/(L+W) where L, W is the length and width of the duct. For circular ducts De is the same as diameter of the duct.

Inlet side of the fan: Where the ‘test length’ is on the inlet side of the fan, its downstream end shall be at a distance from the fan inlet equal to atleast 0.75De. .

Outlet side of the fan: Where the ‘test length’ is on the outlet side of the fan, the upstream end of the ‘test length’ shall be at a distance from the fan outlet of at least 3De.

116

FAN PERFORMANCE

117

FAN PERFORMANCE

118

FAN PERFORMANCE

119

FAN PERFORMANCE Measurement of Air Velocity on Site Velocity shall be measured by either pitot tube or a rotating vane anemometer. When in use, the pitot tube shall be connected by means of airtight tubes to a pressure measuring instrument. The anemometer shall be calibrated before the test.

120

FAN PERFORMANCE

Calculation of Velocity: After taking velocity pressures readings, at various traverse points, the velocity corresponding to each point is calculated using the following expression.

121

FAN PERFORMANCE

122

FAN PERFORMANCE

123

FAN PERFORMANCE

124

FAN PERFORMANCE

125

FAN PERFORMANCE

126

FAN PERFORMANCE

127

AIRPRE HEATER PERFORMANCE Operational Problem • High Gas Leaving Temperatures

• High Leakage of Air to Gas path

• Higher Pressure Drop Across APH

• APH Soot-blowing Cleaning Problems.

• Corrosion Of Cold End Heating Elements

•

Low APH exit Gas Temperature. 128

AIRPRE HEATER PERFORMANCE High APH Exit Gas Temp- Reasons • More gas flow. • High Gas inlet temperature • Less air flow. ( More Tempering Air, Chocking of SCAPH ) • Chocking of heating elements. • Damaged APH Elements.

High Leakage of Air to Gas path • Seal clearance • Poor sealing material.

• Length of seal separating two sides • Hot end / Cold end leakages • Entrained Leakage 129

AIRPRE HEATER PERFORMANCE Higher Pressure Drop Across APH

1. Choking of heating elements 2. Higher flows

3. Eroded/damaged heating elements - obstructs flow path.

4. Improper Soot Blowing steam parameters and eroded nozzles and steam pipes. 5. Low cold end average temperature

Choking Of Heating Elements 1.

Corrosion of heating elements

2.

Boiler slagging

3.

Improper drying of heating elements after water washing.

4.

Excess air operation.

5.

Leak in SCAPH and water washing & deluge line, soot blower passing etc.

6.

Frequent water washing of heating elements and improper drying. 130

AIRPRE HEATER PERFORMANCE Corrosion Of Cold End Heating Elements 1.

High sulphur content in fuel

2.

Low cold end average temperature

3.

Low load operation for long periods

4.

Improper firing procedure

5.

Boiler slagging

6.

Excess air

7.

Leak in SCAPH and water washing & deluge line, soot blower passing etc

8.

Frequent water washing of elements and improper drying.

131

AIRPRE HEATER PERFORMANCE Air Heater - Performance Indicators 1.

Air-in-Leakage

2. Gas Side Efficiency 3. APH Effectiveness. 4. X - ratio

5. Flue gas temperature drop 6. Gas & Air side pressure drops. (The indices are affected by changes in entering air or gas temperatures, their flow quantities and coal moisture)

132

AIRPRE HEATER PERFORMANCE Air Heater Leakage (%) • Weight of air passing from air side to gas side to the Wt of Flue gas passing. • Direct - Hot End / Cold End (60% through radial seals + 30% through Circumferential bypass) Air leakage occurring at hot end of the air heater affects its thermal and hydraulic performance while cold end leakage increases fans loading. • Entrained Leakage due to entrapped air between the heating elements (depends on speed of rotation & volume of rotor air space)

Leakage of air to gas is due to • • • •

Differential Pressure between Air & Flue Gas Increased seal clearances in hot condition Seal erosion / improper seal settings Damaged APH sector plates.

133

AIRPRE HEATER PERFORMANCE Air Heater Leakage (%)

Increased AH leakage leads to

•

Reduced AH efficiency

•

Increased fan power consumption

•

Higher gas velocities that affect ESP performance

•

Loss of fan margins leading to inefficient operation and at times restricting unit loading

Air Heater Leakage - Calculation Leakage is entirely between air inlet and gas outlet: Empirical relationship using the change in concentration of O2 or CO2 in the flue gas = CO2in - CO2out * 0.9 *100 CO2out = O2out - O2in * 0.9 * 100 (21- O2out)

= 5.7 – 2.8 * 90 (21-5.7)

Leakage% = 17.1 % CO2 measurement is preferred due to high absolute values

134

AIRPRE HEATER PERFORMANCE Gas Side Efficiency Ratio of Gas Temp drop across the air heater, corrected for no leakage, to temp head. = (Temp drop / Temperature head) * 100 where Temp drop = Tgas in -Tgas out (No leakage) Temp head = Tgas in - T air in Gas Side Efficiency = (333.5-150.5) / (333.5-36.1) = 61.5 %

135

AIRPRE HEATER PERFORMANCE Tgas out (no leakage) = Temp at which the gas heater if there were no leakage

would have left the air

= APH L * Cpa * (Tgas out - Tair in) + Tgas out Cpg * 100

Say leakage – 17.1%, Gas In Temp – 333.5 C, Gas Out Temp – 133.8 C, Air In Temp – 36.1 C Tgas nl = 17.1 * (133.8 – 36.1) + 133.8 100 = 150.5 C

136

AIRPRE HEATER PERFORMANCE Gas side Efficiency • It refers to internal condition of APH • Low Gas side efficiency- APH problems like Basket wear, Ash plugging, High Lkg

• Low gas side efficiency results in high Exit gas temp and Low Air outlet temp

137

AIRPRE HEATER PERFORMANCE X – Ratio Ratio of heat capacity of air passing through the air heater to the heat capacity of flue gas passing through the air heater. =

Wair out * Cpa Wgas in * Cpg

=

Tgas in - Tgas out (no leakage) Tair out - Tair in

Say leakage – 17.1%, Gas In Temp – 333.5 C, Gas Out Temp – 133.8 C , Air In Temp – 36.1 C, Air Out Temp – 288 C X ratio = (333.5 – 150.5) / (288 –36.1) = 0.73

138

AIRPRE HEATER PERFORMANCE X-Ratio - factors • • •

moisture in coal, air infiltration, air & gas mass flow rates leakage from the setting specific heats of air & flue gas X-ratio does not provide a measure of thermal performance of the air heater, but is a measure of the operating conditions.

LOW X-ratio due to 1. Excessive gas weight through the air heater or that air flow is bypassing the air heater. 2. High air leakage through Boiler setting. LOW X-ratio leads to a higher than design gas outlet temperature & can be used as an indication of excessive tempering air to the mills or excessive boiler setting infiltration. 139

AIRPRE HEATER PERFORMANCE Pressure drops across air heater •

Air & gas side pressure drops change approximately in proportion to the square of the gas & air weights through the air heaters.

•

If excess air is greater than expected, the pressure drops will be greater than expected.

•

Deposits / choking of the basket elements would lead to an increase in pressure drops

•

Pressure drops also vary directly with the mean absolute temperatures of the fluids passing through the air heaters due to changes in density.

140

AIRPRE HEATER PERFORMANCE AH Performance Monitoring •

O2 & CO2 in FG at AH Inlet

•

O2 & CO2 in FG at AH Outlet

•

Temperature of gas entering / leaving air heater

•

Temperature of air entering / leaving air heater

•

Diff. Pressure across AH on air & gas side

(Above data is tracked to monitor AH performance)

141

AIRPRE HEATER PERFORMANCE Factors affecting APH performance • PA Header Pressure High pressure results in increased AH leakage, higher ID fan loading, higher PA fan power consumption, deteriorates PF fineness & can increase mechanical erosion • Upstream ash evacuation • No. Of Mills In Service • Air ingress levels • Maintenance practices Condition of heating elements, seals / seal setting, sector plates / axial seal plates, diaphragm plates, casing / enclosure, insulation.

142

MILL PERFORMANCE 143

MILL PERFORMANCE

The Purpose of a Pulverizer: .

Must be able to pulverize consistently the design quantity of coal suitable for combustion. Able to dry wet coal up to the design wetness even at full output condition. Able to maintain the products within the desired grading

The Pulverizer’s are the HEART of a Pulverized Coal Fueled Boiler!

144

MILL PERFORMANCE

MILL PERFORMANCE INDICATORS • • • • • • • •

MILL OUTLET TEMPERATURE MILL OUT PUT M/T MILL FINENESS FRACTIONS MILL AIR FLOW MILL PRESSURE DROP (D.P) MILL REJECT RATE MILL MOTOR AMPERES WEAR PART LIFE 145

MILL PERFORMANCE

CAUSE OF MILL PERFORMANCE DETORIARATION

• • • • • • • •

QUALITY OF COAL (MOISTUR, HGI ETC.) UN BALANCED FLOW IN COAL PIPES. SETTLEMENT OF COAL IN COAL PIPES. POOR COAL FINENESS LOW PA TEMPERATURE FOREIGN MATERIAL INGRESS. LOSS THROUGH REJECTION WEAR PART LIFE 146

MILL PERFORMANCE-HGI

Calculate the Hardgrove grindability index using the formula: HGI = 13 + 6.93 M where M = mass of the test sample passing through 75-micron sieve after grinding. In practice M is obtained by deducting from 50 g the mass of the ground sample retained on 75-micron sieve.

147

MILL PERFORMANCE

MILL PERFORMANCE - IDENTIFICATION METHODS

• • • • •

NO LOAD RUN CLEAN AIR FLOW TEST DIRTY PITOT TUBE TEST MILL FINENESS SAMPLING TRENDING OF COAL PIPE METAL TEMPERATURE

148

MILL PERFORMANCE

OBJECTIVE OF TESTING • CLEAN AIR BALANCING BETWEEN BURNERS • DIRTY AIR BALANCING BETWEEN BURNERS • FUEL BALANCING BETWEEN BURNERS • FINENESS TESTING OF PF BETWEEN BURNERS • SETTLEMENT OF COAL PARTICLE IN COAL PIPE. 149

MILL PERFORMANCE

CLEAN AIR FLOW TESTS • STEPS INVOLVED ARE DETAILED IN THE TEST PROCEDURE • STANDARD “ L” TYPE PITOT IS USED. • CLEAN AIR FLOW BALANCE IS COMPUTED BETWEEN COAL PIPES • DEVIATION OF +\- 2% INDICATES A SATISFACTORY FLOW BALANCE AND FURTHER TRENDING IS REQUIRED. 150

MILL PERFORMANCE Dirty pitot tube – measuring the two phase mixture of Coal & Air

151

MILL PERFORMNANCE –S TYPE PITOT ….

152

MILL PERFORMANCE

153

MILL PERFORMANCE

Acceptance range • Clean air flow distribution to be with in +/2.5%. • Dirty air flow distribution to be with in +/5.0%. • PF distribution to be with in +/-10%. • Guarantees to be established for end mills with unequal length in fuel piping

154

MILL PERFORMANCE

ISOKINETIC COAL SAMPLING The Isokinetic Sampler is used to extract pulverized coal from (24) points of each coal pipe (depending on piping size).at as close to actual velocity entering the sampler nozzle, as the coal particles were flowing before collection. This is called “Isokinetic” Sampling. The prefix “iso” means same, and “kinetic” means energy or velocity of the particles. Because the coal particles are about a thousand times more dense than air, isokinetic sampling is important to obtain truly representative coal samples for sieving.Figure No. 7

155

MILL PERFORMANCE

COAL FINENESS ANALYSIS • FINENESS SAMPLE ANALYSIS NEEDS TO BE CARRIED OUT IMMEDIATELY TO AVOID COAGULATION IN CASE OF HIGH MOISTURE COALS • MINIMUM FOUR STANDARD MESH SCREENS TO BE USED • TVA DEVELOPED SOFTWARE ENABLES REVIEW OF MILLS PERFORMANCE DATA TO FOCUS ON VARIOUS TRENDS 156

MILL PERFORMANCE

Accurate weighing and sieving of the samples through 4 sieves is also important. Why four sieves? Because, with the desired near zero on 50 mesh sieve, at least three points are needed on the Rosin-Rammler Chart to plot the fineness Results. Four sieves of 50, 100, 150 and 200 mesh are recommended for fineness sampling.

157

MILL PERFORMANCE U.S. MESH

INCHES

MICRONS

MILLIMETERS

50 60 70 80 100 120 140 170 200 230

0.0117 0.0098 0.0083 0.0070 0.0059 0.0049 0.0041 0.0035 0.0029 0.0024

297 250 210 177 149 125 105 88 74 63

0.297 0.250 0.210 0.177 0.149 0.125 0.105 0.088 0.074 0.063

What does mesh size mean? Figuring out mesh sizes is simple. All you do is count the number of openings in one inch of screen .The number of openings is the mesh size. So a 4-mesh screen means there are four little squares across one linear inch of screen. A 100mesh screen has 100 openings, and so on. As the number describing the mesh size increases, the size of the particles decreases. 158

MILL PERFORMANCE

• • •

•

WHY IS MILL PERFORMANCE TESTING IMPORTANT? UNIT CAPABILITY GOVERENED BY MILL PERFORMANCE BOILER AND COMBUSTION SYSTEM PERFORMACE AFFECTED BY QUALITY OF PF COAL AND ITS DISTRIBUTIION RELIABLE FEEDBACK SHOULD FOCUS ON TIMELY MILL OVERHAUL VERY EFECTIVE CROSS CHECK OF THE STATION INSTRUMENTS FEEDBACK 159

MILL PERFORMANCE

USE OF METAL TEMPERATURE IN FUEL PIPE TO MONITOR CHOCKING • FUEL PIPING METAL TEMPERATURE IS BEING MONITORED IN FARAKA TO MONITOR FUEL PIPE CHOCKING. • RECENT STUDIES SHOWED THAT LOWER THAN MILL OUT LET TEMPERATURE IS NOT NECESSARILY AN INDICATION OF PIPE CHOCKING. • DIFFERENCE OF 7 TO 8 C WAS OBSERVED BETWEEN COAL AIR TEMPERATURE METAL TEMPERATURE FOR A PIPE WHICH WAS CLEAR.

160

MILL PERFORMANCE

Pulverizer Troubleshooting-Matrix • LACK OF CAPACITY OR HIGH POWER CONSUMPTION

• HIGH MOISTURE • LOW GCV • INCREASED RAW COAL SIZE. • GRINDING TOO FINE • EXCESSIVE BED DEPTH • INSTRUMENT ERROR

161

MILL PERFORMANCE

Pulverizer Troubleshooting-Matrix • EXCESSIVE MILL REJECTS

• CHANGE IN COAL GRINDABILITY, SULFUR & ASH. • IMPROPER COAL/AIR RATIO • THROAT GAP WEAR.

162

MILL PERFORMANCE

Pulverizer Troubleshooting-Matrix • COARSE GRIND

• CHANGE IN COAL GRINDABILITY • HIGH MOISTURE • INCREASED THROUGH PUT. • CLASSIFIER SETTING • MILL WEAR.

163

MILL PERFORMANCE

Pulverizer Troubleshooting-Matrix • LOW COAL \AIR TEMPERATURE

• • • •

HIGH MOISTURE LOW PA INLET TEMPERATURE PASSING OF COLD AIR. LOW A.H INLET TEMPERATURE • NON AVAILABILITY OF SCAPH

164

MILL PERFORMANCE

Pulverizer Troubleshooting-Matrix • CHANGE IN MILL DIFFERENTIAL

• LOW GRINABILITY • LOW MOSITURE • MILL INTERNALS PROBLEMS.

165

MILL PERFORMANCE

Pulverizer Troubleshooting-Matrix • MILL FIRES

• HIGH VOLATILES • MOISTURE • LOW COAL\ AIR TEMPERATURE. • BURNER LINE BALANCE

166

Optimization of Boiler total air

167

BOILER PERFORMANCE…. AIR OPTIMISATION

Concept • Efficient operation of boiler depends on optimisation of CO2 and O2 • This involved elimination of source of air ingress. • As different losses of boiler is affected by variation of air, the optimum value is determined by plotting the total loss and thereby determining CO2 and O2. 168

BOILER PERFORMANCE…. AIR OPTIMISATION

Air required for combustion • • • • •

Theoretical air required = 4.31[8/3 C + 8(H – O2/8) + S] Kg/ 100 Kg fuel Excess air = Theoretical CO2 % / Actual CO2 % - 1 = O2 % X 100 / (21 – O2 %) Theoretical CO2 for – Natural gas – Fuel oil – Bituminous coal

11.7 % 15.3 %

18.6 %

• Actual air x actual CO2 % = Th. Air x Th. CO2 % 169

BOILER PERFORMANCE…. AIR OPTIMISATION

Oxygen % at various locations in boiler 10

O2 %

8 6 4 2 0 Furn Outlet 210 MW

AH Inlet 210 MW

AH Outlet

ID outlet

500 MW

210 MW 170

BOILER PERFORMANCE…. AIR OPTIMISATION Air Ingress Points – Furnace Roof , Expansion joints, Air heaters, Ducts, ESP Hoppers, Peep Holes, Manholes, Furnace Bottom Air-inleakage

Furnace Outlet Zirconia O2 Probe Expansion Joints AH Seal Lkg

ESP

171

BOILER PERFORMANCE…. AIR OPTIMISATION

Air Ingress Calculations Air ingress quantification is done with the same formulae as those used for calculation of AH leakage Air ingress = O2out - O2in * 0.9 * 100 (21- O2out) The basis of O2 or CO2 calculation should be the same – either wet or dry.

172

BOILER PERFORMANCE…. AIR OPTIMISATION

Air optimization process • Find Dry gas, unburnt gas, combustible in ash and auxiliary power (fans) to find the total loss. • Repeat the same for different test air (% of CO2 at A/H inlet) settings. • Find the minimum total loss. • Find air setting corresponding to minimum total loss. 173

BOILER PERFORMANCE…. AIR OPTIMISATION

174

BOILER PERFORMANCE…. AIR OPTIMISATION

175

BOILER PERFORMANCE…. AIR OPTIMISATION

176

MILL PERFORMANCE….FEILD TEST Specific energy Consumption (Kwh./T of Coal) Acceptable SEC

SEC Comparision 11.00

10.00

SEC

9.00 8.00 7.00 6.00 5.00 Unit-3 Unit-4 Unit-5 Unit-6

Mill A 7.91 6.29 10.53 10.3

Mill B 7.63 7.79 7.43 8.8

Mill C 8.82 6.45 6.48 7.1

Mill D 7.93 7.54 7.90 6.6

Mill E 8.05 7.59 7.81 7.0

Mill F 7.44 7.32 7.78 6.8

Mill G 7.34 6.21 7.33 7.7

Mill H 7.52 7.06 7.28 7.6

Mill J 6.90 7.07 8.15 9.0

Mill K 7.05 7.25 7.20 10.0 177

MILL PERFORMANCE….FEILD TEST SEC(PG Test). PG Test SEC Unit-3

Unit-4

Unit-5

Unit-6

Mill A

7.8

7.5

7.7

7.8

Mill B

7.7

7.4

7.5

7.5

Mill C

8.0

7.6

7.5

7.6

Mill D

7.6

7.6

7.9

7.8

Mill E

7.9

7.5

7.8

7.8

Mill F

7.9

7.6

7.5

7.9

Mill G

7.7

7.7

7.8

7.6

Mill H

7.6

7.6

7.7

7.8

Mill J Mill K Standard Deviation SD of Audit

7.9 7.8 0.148 0.532

7.8 7.6 0.110 0.560

7.6 7.6 0.143 1.071

7.5 7.6 0.15 1.348 178

MILL PERFORMANCE….FEILD TEST

Acceptable Amp

Current (Amps) Current(Amps) Comparision. 140 135 130

SEC

125 120 115 110 105

100 Unit-3 Unit-4 Unit-5 Unit-6

Mill A Mill B 130 130.4 113 130.4 134 115 134.0 138.0

Mill C Mill D 113 131 113 129 112 129 117.0 117.0

Mill E 121 121 127 113.0

Mill F 122.9 124 123.4 118.0

Mill G Mill H 120 120 120 120 119 118.4 130.0 124.0

Mill J 132.8 124 130.1 131.4

Mill K 120 123.2 115.7 125.1 179

MILL PERFORMANCE….FEILD TEST Classifier O/L temp Clssifier O/L Temp. 85 83

Temp Degree C

81 79 77 75

73 71 69 67 65

Unit-3 Unit-4 Unit-5 Unit-6

Mill A 78 74.9 81.5 73.5

Mill B 79 83 74 76

Mill C 82.2 74.4 74 75

Mill D 80.9 75 78.9 80

Mill E 79.9 78.1 76.9 74.9

Mill F 75.6 82 77.9 72.6

Mill G 83.3 82 84 73.5

Mill H 82.3 72 79 75.2

Mill J 82.5 72.5 82.5 75.4

Mill K 75.6 76.4 83 76.2 180

MILL PERFORMANCE….FEILD TEST Coal Flow (T/hr) Coal Flow T/hr 70

Coal Flow T/hr

65 60 55 50 45 40 Unit-3 Unit-4 Unit-5 Unit-6

Mill A 65 65 50.8 50

Mill B 65 60.2 63.13 61.7

Mill C 55 64 64.5 63

Mill D 64.2 62.6 63.4 65.3

Mill E 65 62.59 64.3 63.4

Mill F 64.5 64.5 63.39 64.3

Mill G 65.4 62.8 62.5 62.9

Mill H 59.6 59.6 63.2 64

Mill J 64.9 62.4 62.8 60

Mill K 64 60.3 63.5 181 45.74

MILL PERFORMANCE….FEILD TEST Mill Loading

Mill Loading (Percent) 105.00 100.00 95.00

Percent

90.00 85.00 80.00 75.00 70.00

65.00 60.00

Mill A Mill B Unit-3 97.90 94.48 Unit-4 77.90 89.33 Unit-5 101.90 89.33 Unit-6 98.04 103.24

Mill C 92.38 78.67 79.62 85.14

Mill D 96.95 89.90 95.43 81.52

Mill E 99.62 90.48 95.62 84.57

Mill F 91.43 89.90 93.90 82.86

Mill G 91.43 74.29 87.24 92.76

Mill H 85.33 80.19 87.62 92.76

Mill J 85.33 84.00 97.52 102.48

Mill K 85.90 83.24 87.05 182 87.05

MILL PERFORMANCE….FEILD TEST P-Air/Coal ratio

183

MILL PERFORMANCE….FEILD TEST Mill Fineness.

% Coal through -200

Mill Finness 77 76 75 74 73 72 71 70

Unit-3 Unit-4 Unit-5 Unit-6

A 70 73 74 74

B 74 71 75 76

C 73 72 73 74

D 75 74 71 74

E 75 73 72 74

F 71 74 74 72

G 74 72 74 74

H 74 71 74 74

J 74 75 72 71

K 71 72 74 71

Limits : +50 mesh 1%, -200 mesh 70 % 184

MILL PERFORMANCE….FEILD TEST Unit-3 Coal pipe Temp (Degree C) U3 Pulveriser Pipe Temp 69

Temp Degree C

67 65 63 61 59 57 55

Cr-1 Cr-2 Cr-3 Cr-4

MILL A MILL B 63.5 65.2 64 66.5 65 64.9 65 65

MILL C MILL D MILL E 62.3 63.5 66 63 63.5 65.2 63.2 64.5 63.5 63 62.9 64.8

MILL F 66 65 65 65.3

MILL G MILL H 62 59.8 65 59.8 65 60.2 64 60.2

MILL J 62.5 63 63.2 64.2

MILL K 64 64 65 65 185

MILL PERFORMANCE….FEILD TEST Unit-4 Coal pipe Temp (Degree C) U-4 Pulveriser Pipe Temp 70

Temp Degree C

65 60 55 50

45 40 Cr-1 Cr-2 Cr-3 Cr-4

Cr-4 Pipe temp was less Pipe was found choke during Dirty Pitot Test

MILL A MILL B MILL C MILL D MILL E MILL F MILL G MILL H MILL J MILL K 67 65.2 59 63.5 65.8 67 66 65.5 67.8 65 67.5 66.5 59.2 64 64.5 67 68 66.5 69.9 66 68 64.9 60.1 64.2 64.3 68 68 66.4 68.4 65 67.4 67 60.2 64.3 66 67.2 64 67 41.6 66 186

MILL PERFORMANCE….FEILD TEST Unit-5 Coal pipe Temp (Degree C) U-5 Pulveriser Pipe Temp 69

Temp Degree C

67 65

63 61 59 57

55 Cr-1 Cr-2 Cr-3 Cr-4

MILL A MILL B 65 67.2 66 66.2 66 68 68 67.4

MILL C MILL D MILL E 63 60.2 62 63 65.2 62.4 65 64.2 63 66 61.7 62.2

MILL F 62 64 66 63.4

MILL G MILL H 63 64 64 64 63 60 64 64

MILL J 63.2 63 62.5 64.2

MILL K 64 64 64 65 187

MILL PERFORMANCE….FEILD TEST Unit-6 Coal pipe Temp (Degree C) U-6 Pulveriser Pipe Temp 70

Temp Degree C

65 60 55 50 45 40

35 Cr-1 Cr-2 Cr-3 Cr-4

Cr-4 Pipe temp was less Pipe was found choke during Dirty Pitot Test MILL A MILL B 62 61 61 62 62 60 62 62

MILL C MILL D MILL E 55 60 58 57 59 59.2 57 60 59.6 57 60 59.6

MILL F 64 63 64 63.8

MILL G MILL H 63 64 64 63 63 64 64 64

MILL J 63.2 65.5 65 37

MILL K 65 64 64 64 188

MILL PERFORMANCE….FEILD TEST Mill Capacity after Correction for Fineness. Mill Capacity for Fineness 102

100

% of Cpacity

98 96 94 92 90 88

Unit-3 Unit-4 Unit-5 Unit-6

Mill A 100 96.1 94.8 94.8

Mill B 94.8 98.7 93.5 92.2

Mill C 96.1 97.4 96.1 94.8

Mill D 93.5 94.8 98.7 94.8

Mill E 93.5 96.1 97.4 94.8

Mill F 98.7 94.8 94.8 97.4

Mill G 94.8 97.4 94.8 94.8

Mill H 94.8 98.7 94.8 94.8

Mill J 94.8 93.5 93.5 98.7

Mill K 98.7 97.4 97.4 98.7 189

MILL PERFORMANCE….FEILD TEST Corrected Mill Capacity. U-3 Design

Moisture

HGI

FINENESS

15

55

70

PG TEST

C1

C2

C3

CF

CAP

0.973

1.05

0.95

0.971

63.57

Mill A

19

52

70

0.953

0.97

1

0.924

60.55

Mill B

19

52

74

0.953

0.97

0.948

0.876

57.40

Mill C

19

52

73

0.953

0.97

0.961

0.888

58.19

Mill D

17

52

75

0.976

0.97

0.935

0.885

57.98

Mill E

17

52

75

0.976

0.97

0.935

0.885

57.98

Mill F

17

52

71

0.976

0.97

0.987

0.934

61.20

Mill G

16

52

74

0.984

0.97

0.948

0.905

59.27

Mill H

16

52

74

0.984

0.97

0.948

0.905

59.27

Mill J

16

52

74

0.984

0.97

0.948

0.905

59.27

Mill K

17

52

71

0.976

0.97

0.987

0.934

61.20

Where Correction factor For moisture-C1, For HGI-C2, For fineness-C3, C=C1*C2*C3

190

MILL PERFORMANCE….FEILD TEST Corrected Mill Capacity. U-6 Design

Moisture

HGI

FINENESS

15

55

70

PG TEST

C1

C2

C3

CF

CAP

0.973

1.05

0.95

0.971

63.57

Mill A

17

52

74

0.976

0.97

0.948

0.897

58.79

Mill B

17

52

76

0.976

0.97

0.922

0.873

57.17

Mill C

15

52

74

1

0.97

0.948

0.920

60.23

Mill D

17

52

74

0.976

0.97

0.948

0.897

58.79

Mill E

17

52

74

0.976

0.97

0.948

0.897

58.79

Mill F

17

52

72

0.976

0.97

0.974

0.922

60.40

Mill G

17

52

74

0.976

0.97

0.948

0.897

58.79

Mill H

17

52

74

0.976

0.97

0.948

0.897

58.79

Mill J

17

52

71

0.976

0.97

0.987

0.934

61.20

Mill K

17

52

71

0.976

0.97

0.987

0.934

61.20 191

MILL PERFORMANCE….FEILD TEST Velocity Profile Mill-3A MILL 3A

24.0

Velocity of Pulv. Coal in Pipes m/Sec.

22.0 20.0

Cr-1 Cr-2

18.0

Cr-3 Cr-4

16.0

Poly. (Cr-1) Poly. (Cr-2)

14.0

Poly. (Cr-3) Poly. (Cr-4)

12.0 10.0 0

4

8

12

Travel of Pitot tube.(Num of Points) 192

MILL PERFORMANCE….FEILD TEST Velocity Profile Mill-3K MILL 3K

22.0

Cr-1

20.0

Velocity of Pulv. Coal in Pipes m/Sec.

Cr-2

18.0

Cr-3 Cr-4

16.0

Poly. (Cr-1)

14.0

Poly. (Cr-2)

12.0 Poly. (Cr-3)

10.0 0

4

8

12

Travel of Pitot tube.(Num of Points)

Poly. (Cr-4)

193

MILL PERFORMANCE….FEILD TEST Velocity Profile Mill-4J Cr-1

22.0 Cr-2

20.0

Velocity of Pulv. Coal in Pipes m/Sec.

Cr-4 was found choke . cleared by purging & Hammering.

MILL 4J

24.0

Cr-3

18.0 Cr-4

16.0 Poly. (Cr-1)

14.0 Poly. (Cr-2)

Cr-4 DP and Velocity “Zero” & Coal Pipe Temp 41.6 Degree C against Other Pipes 69 Degree C

12.0 10.0 0

4

8

12

Travel of Pitot tube.(Num of Points)

Poly. (Cr-3) Poly. (Cr-4)

194

MILL PERFORMANCE….FEILD TEST PA Fan- Power PAF-MW 1.6 1.4

Power(MW)

1.2 1 0.8 0.6 0.4 0.2 0 PAF-A PAF-B PAF-A(PAB) PAF-B(PAB)

Unit-3 1.263 1.209 1.08 1.09

Unit-4 1.155 1.167 1.07 1.09

Unit-5 1.223 1.204 1.09 1.1

Unit-6 1.37 1.137 1.1 1.08 195

MILL PERFORMANCE….FEILD TEST

Coal

Predicted

Sample1

sample2

For moisture-C1

97.6/100

97.3/100

97/100

For HGI-C2

106/100

105/100

105/100

For fineness-C3

93/100

95/100

95/100

C=C1*C2*C3

0.961

0.970

0.970

196

MILL PERFORMANCE….FEILD TEST

Guaranteed Coal

Predicted coal

Capacity (T/hr)

65.5

-----

moisture

15

HGI

MIL OPTIMIZATION

Coal (actual)

Coal (Avg)* 20 Samples

14

14-17

15.4

55

60

62-79

68.5

Fineness 200 mesh

70

75

76-87

81.4

Mill O/L temp

82

82

-

*Samples are tested at CIMFR 197

Mill Capacity Correction Curve Mill Capacity Vs Grindability Index

HGI limit

198

Mill Capacity Correction Curve Mill Capacity Vs Fineness

Fineness limit

199

MILL OPTIMIZATION

Mill Capacity Correction Curve Mill Capacity Vs Moisture

200

MILL OPTIMIZATION

Pragayan

Power consumption per unit coal transported Actual for 2009-10 vs PG test St-II MILL

Coal Flow

Current

Coal Flow

CURRENT

Current/T/H

Current/T/H

KW/T/H

KW/T/H

A

55

110

64

124

2.00

1.94

8.00

7.75

B

51

116

65

125

2.27

1.92

9.10

7.69

C

56

113

63

126

2.02

2.00

8.07

8.00

D

54

110

65

124

2.04

1.91

8.15

7.63

E

47

114

64

126

2.43

1.97

9.70

7.88

F

50

107

64

127

2.14

1.98

8.56

7.94

G

57

111

65

125

1.95

1.92

7.79

7.69

H

52

107

63

119

2.06

1.89

8.23

7.56

J

53

121

63

125

2.28

1.98

9.13

7.94

K

53

117

64

124

2.21

1.94

8.83

7.75

Power(KW) per T on of Coal

KW/hr/Ton coal

10.00 9.00 8.00 actual

7.00

desired

6.00 5.00 4.00 1

3

5

7

9

11

13

15

17

19

201

THANK YOU

202