Condenser & Feed water heaters

7/30/2019 Condenser & Feed water heaters

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Condenser performance is one of the important factors for efficient operation of the

plant. Higher the Rankine cycle efficiency if lower is the temperature at which heat is rejected.

Hence maintaining condenser back pressure at design value is important. Condenser design

is based on expected values of Heat load, C. W. Inlet temperature and quantity of insoluble

gases. If any one or more of these values exceed the design value, higher than expected back

pressure may result. Objective of the Condenser performance test is to know whether condenser

is performing as per the design expectations at operating parameters. Deviations are then

analyzed for finding out the causes and actions for improvement are initiated. Analysis of

condenser performance is based on following indices, which are evaluated from test results.

Per f o r m ance I nd i ces :

Absolute pressure deviation from expected/ design.

Terminal temperature Difference (TTD)

Cleanliness Factor.

Sub-cooling of condensate and air / steam mixture

Heat Transfer Coefficient

Effectiveness of tube cleaning

Circulating water velocity in tubes

Circulating water temperature rise

Flow rate of air / steam mixture

Dissolved Oxygen in condensateEffect of condenser performance on heat rate

These indices are computed from the test results in following ways.

Condense r Du t y : It is the measure of heat load on condenser. Based on test data, this

parameter is computed and deviation from design value is found out.

Condenser Duty = (Heat added in Main Steam + Heat added in HRH steam) 860 (Gross

Generator output in KW + Generator losses in KW + Heat lost by radiation)

Where Heat added in Main Steam = M.S. Flow in Kg/ Hr (Enthalpy of Main Steam

Enthalpy of Feed Water) Kcal / HrHeat added in Reheat Steam = HRH Steam Flow in Kg/ hr (Enthalpy of HRH steam Enthalpy of CRH steam) Kcal / Hr

Radiation Loss = 0.1% of Gross Generation in KW

Generator Losses = (Mechanical Losses + Iron Losses + Stator Current losses) KW,These Values taken from Generator Loss Curve

860 = Equivalent heat energy for 1 KWh electrical energy.

CONDENSER AN D FEED W ATER HEATERPERFORMANCE


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Condenser Duty (Kcal /hr)

Condense r coo l i ng w a t e r F low = m3 / hr

Cp (Tout Tin) D

Where Cp = Specific Heat of Water = 1 Kcal / Kg deg CD = Density of water = 1000 Kg / m3

Tout = Average C W outlet temperature, deg C

Tin = Average C W inlet temperature, deg C

A l t e r n a t e M et hod : C W flow can be found out from cooling water pumps Head Vs Discharge

flow characteristics. Head developed by the pump is measured during the test. It is then

corrected for design speed as follows.

Head Developed (Nd) Computed Head =

(N)

Where Computed Head = in mwc

Head developed by the pump = in mwc

Pump Running speed N = rpm

Pump Design speed Nd = rpm

W at e r Ve loci t y i n Condenser Tubes :

C. W. Flow Rate 106

Velocity =

3600 Tube area (Number of tubes No. of tubes plugged)

Where Tube velocity is in m/sC.W. Flow rate is in m3/ hr

Tube area is in mm2

Log M ean t em per a t u r e D i f f e r ence :

Tout - TinLMTD =

Tsat - Tin

Ln

Tsat Tout

Where LMTD is in Deg C

Tsat is in deg C, (Saturation temperature corresponding to condenser pressure)

Clean l in ess Fac to r :

U actual (Actual Heat Transfer Coefficient)Cleanliness Factor =

U theoretical (Theoretical Heat transfer coefficient)

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Condenser flow Cp (Tout Tin) Density of waterU actual =

A condensing LMTD

U actual = kcal/ hrm2 0CDensity of water = 1000 Kg/ m3

A condensing = (Tubes surface area No. of tubes ) in m2

U theoretical = C1 C2 C3 C4 Velocity

Values of Constants C1 through C4 are known from the tables given below

Values o f cons tan t C1

Tube diameter in inches 3/4 7/8 1.0

C1 (V in m/s and U in W/(m2-K) 2777 2705 2582


Water temp C 21.11 26.66 32.22 37.77

C1 1.00 1.04 1.08 1.10


Tube Material Tube wall Gauge - BWG

24 22 20 18 16 14 12

Admiralty Brass 1.06 1.04 1.02 1.0 0.96 0.92 0.87

Arsenical Copper 1.06 1.04 1.02 1.0 0.96 0.92 0.87

Copper Iron 194 1.06 1.04 1.02 1.0 0.96 0.92 0.87

Aluminum Brass 1.03 1.02 1.00 0.97 0.94 0.90 0.84

Aluminum Bronze 1.03 1.02 1.00 0.97 0.94 0.90 0.84

90-10 Cu-Ni 0.99 0.97 0.94 0.90 0.85 0.80 0.74

70-30 Cu-Ni 0.93 0.90 0.87 0.82 0.77 0.71 0.64

Cold rolled low Carbon Steel 1.00 0.98 0.95 0.91 0.86 0.80 0.74

Stainless Steel Type 304/ 316 0.83 0.79 0.75 0.69 0.63 0.56 0.49

Titanium 0.85 0.81 0.77 0.71 - - -


C4 0.85 for clean tubes, less for algae covered tubes.

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Expec t ed LM TD f o r Dev ia t i on f r om des ign va lue :

Correction for C W Inlet temperature, Ct:

1/4

Ct = Saturation Temp Test LMTD testSaturation Temp design LMTD design

Cor r ec t ion fo r C.W. Flow , Cf :

1/2

Ct = Tube Velocity test

Tube velocity design

Cor r ec t i on f o r condense r h ea t l oad Cq :

Cq =Condenser Duty design

Condenser Duty test

Expected LMTD = LMTD test Ct Cf Cq deg. C

Expec t ed Sa t u r a t i on t em per a t u r e :

| Tin Tout Expo [ Z ] |

Expected Saturation temperature =

| 1 Expo [ Z ] |

Z = (Tout Tin) / Expected LMTD

Where Tout = Temperature of C.W at condenser outlet

Tin = Temperature of C.W at condenser inlet

Feed W a t e r Hea t e r Per f o r m ance :

Feed Water heater performance indices are :

1. Terminal Temperature Difference, also called TTD

2. Drain Cooler Approach, DCA,

3. Extraction steam flow rate to the heater.

These indices are computed from the Extraction Steam Parameters, Feed water Inlet/

outlet parameters and Drain or drip parameters. These indices are then compared with design

/ expected values and actions are planned to correct the deviations. Following discussions

explain how these indices are evaluated.

Ter m ina l t em per a t u r e D i f f e r ence, TTD :

TTD = (Saturation temperature of extraction steam Temperature of Feed Water at Heater

outlet)

Dra in Coo le r Appr oach, DCA :

DCA = (Temperature of Heater Drip Temperature of feed water at Inlet)

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Desuperheating

Condensing

Drain Cooling

Extraction Steam Inlet

Drain From cascaded heater Feed Water O/ L

FW I/L

Drain Outlet

502

Desuperheating Condensing Zone Subcooling

Shell Steam

Temperature

Ex t r ac t i on St eam Flow :

The heat balance around the heater is given by

Heat Energy released from extraction steam = Heat energy absorbed by feed water

Heat Energy released from extraction steam = Extraction steam flow rate (sp. enthalpy

of steam specific enthalpy of drip water)

Heat energy absorbed by feed water = Feed flow rate through heater (Sp. Enthalpy of

Feed water at heater outlet - Sp. Enthalpy of Feed water at heater inlet) + Drain flow from

cascaded heater (Enthalpy of Drain from cascaded heater Enthalpy of drain in the

heater under analysis)

Heat energy absorbed by feed waterExtraction steam flow rate =

(Enthalpy of steam Enthalpy of drip water)

Measured values are

1) Extraction steam pressure and temperature

2) Feed water temperature and pressure at inlet and outlet of heater

3) Drip temperature4) Feed Flow rate

Typ ica l Feed Wat er Heater :


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Pr o f i l e o f Hea t Gain by f eed w a t e r i n Hea t e r

Poor performance of the heater results in Low feed water temperature at Heater outlet.

Probable reasons can be found out from the performance indices as per following guidelines.

Reasons f o r Low Feed W a t e r Tem per a t u r e a r e1) Excessive makeup

2) Poor performance of the heater.

High T.T.D. or High D.C.A. temperature results in Poor performance.

Reasons fo r h igh TTD are :

1) Excessive Venting because of worn out vents, vent malfunction

2) High water level in heater shell due to Tube leaks or improper setting of Heater level

control

3) Leak in the partition of the header for feed water inlet / outlet

4) Noncondensible gases in shell side5) Excessive tube bundle pressure drop because of tubes internal fouling ro excessive no. of

tubes plugged

Reasons f o r h igh DCA t em per a t u r e a r e :

1) Drain cooler inlet not submerged in the drip

2) Low water level in the heater due to improper setting of the set point or Control valve

bypass left open or it is passing

3) Excessive tube bundle pressure drop because of tubes internal fouling or excessive no. of

tubes plugged

Low feed water temperature also result due to passing of the Heaters Feed sidebypass valve.

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In thermal power plant, Chemical Energy of fuel is converted to electrical energy. The

conversion cycle is based on Thermodynamic Vapor Cycle, called Rankine Cycle. Conversion

takes place through various stages and different processes are involved for the purpose. Dueto the various limitations nature has imposed, such as Irreversibility in the process, heat

losses to atmosphere, Friction losses, Heat Transfer losses, to name a few, efficiency of

conversion is always less than 100%. In addition to these losses, some heat energy is rejected

because, steam temperature and pressure drop to such low values (after doing work in Turbine),

that further conversion to useful work is not possible. Due to all these reasons, energy input

is much more for one kWh electrical energy output from the Generator. If the Chemical /

Electrical conversion process should have been 100% efficient, 860 Kcal heat energy input

should have given one kWh electrical energy out put at Generator terminals. This r a t i o of

Electrical Energy Outputover a certain period of time to Chemical Energy inp ut to the Plant

over the same period is called Hea t r a t e.

In modern plants, designed for High temperature and pressure Steam admission to

Turbine, efficiency and heat rate can be around 36% and 2400 Kcal/ KWh respectively.

The term Heat rate is defined in many ways as follows:

Net Un i t Hea t r a t e: It is the ratio of energy input to Boiler in terms of Heat energy of fuel, for

one kWh of electrical energy output at Bus Bars, i.e. after UAT. If the out put and input is

considered for a period of an hour, then it is Net Unit Heat rate for one Hour. Similarly, it can

be calculated over a period of a Day, a Week, a Month or a Year.

In this case, it is the sent out energy that is considered, hence, consumption of electrical

energy for driving the plants auxiliaries is also accounted for.

Gross Un i t Heat r a te : It is the ratio of energy input to Boiler in terms of Heat energy of fuel,

for one kWh of electrical energy output at Generator Terminals. In this case, auxiliary

consumption is NOT accounted for.

Net Turb ine Cyc le Heat ra te : It is the ratio of heat energy contained in steam admitted to

Turbine for one kWh of electrical energy output at Generator Terminals. In this case, auxiliary

consumption and losses in Boiler are NOT accounted for.

Oper a t i ng Hea t r a t e : It is the heat rate calculated by considering the inputs and outputs

from the plant only when it is synchronized with the grid. In this case, the fuel input required

for steam conditioning, from light up to synchronization is not considered. Also auxiliaries

consumption during the period of plant shut down is not considered.

W h a t i n f o r m a t i o n d o es H e at r a t e g i v e ?

The plant is designed to generate electricity at certain design heat rate. Deviations fromdesign values give a valuable information regarding the operational and maintenance practices.

Also, by comparison with the historical data, decisions can be taken while making investments

on the maintenance and renovation. Also, problem area can be identified and analyzed for

improvements. A deviation in Gross Turbine Cycle heat rate tells us about energy conversion

scenario in turbine, including condenser and regenerative feed heating process. If Net average

unit heat rate deviates from that of design, it tells us how much extra amount of energy is put

in and how much money is wasted.

HEAT RATE OF THERMAL POW ER PLANT


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Now a days, tariff for supply of electricity to consumers is fixed by Maharashtra Electricity

Regulatory Commission. While fixing tariff, MERC has given the benchmark heat rate values

for all power plants in MSEB. If actual heat rate is more than the benchmark heat rate, the

additional expenditure incurred shall not be considered in Generation cost for fixing tariff.

Naturally MSEB will have to absorb the cost of this expenditure. Another important aspect is

of conservation of fast depleting natural resources, such as coal and fuel oil. When power is

generated at optimum heat rate, minimum possible fuel is consumed. Less fuel consumption

also leads to lesser extent of pollutants added to the environment. Hence monitoring and

controlling the heat rate to the optimum level has many benefits.

Ca lcu lat i ons o f hea t r a t e :

Net Unit Heat rate, for given time period, is calculated by the formula,

(Coal Consumption Its Calorific Value + Oil Consumption Its Calorific Value)

Generation measured at Bus Bars

To measure coal consumption accurately is very difficult. Also the calorific value of coal

varies and its continuous, on line measurement is not possible.

Hence, in normal practice, unit heat rate is calculated by the simpler method:

Unit Heat rate = Turbine Cycle Heat rate / Boiler Efficiency calculated by loss method.

Turbine Cycle Heat rate = (Total Heat added to Turbine in Kcal) / (Generation in MU)

Total Heat added to Turbine Cycle =

((Sp. Enthalpy of S.H. Steam at Boiler Outlet x Total Steam Flow Rate to H.P.T.)

(Sp. Enthalpy of Feed Water at economizer inlet x Feed Water Flow rate at

economiser inlet))

+ (Sp. Enthalpy of R.H. Steam at Reheater outlet Sp. Enthalpy of C.R.H. steamat Reheater inlet) x Reheat Steam Flow

+ (Sp. Enthalpy of S.H. Steam at Boiler Outlet Sp. Enthalpy of S.H. spray) x

S. H. Attemperator Flow

+ (Sp. Enthalpy of R.H. Steam at Reheater outlet Sp. Enthalpy of Reheat attemporator)

x R. H. Attemperator Flow.

Values of temperature, pressure and flow rate are known from instrumentation and

specific enthalpy can be known from Steam tables. The value of generation is known from the

Energy Meters. If reading of energy meter connected to Generator terminals is considered in

this formula, the heat rate obtained is Gross Heat rate and if that from Bus Bar energy meter

is considered, then it is the net heat rate.

For method of calculation of Boiler efficiency by loss method pl. refer the chapter on the topic.

Fac t o r s a f f ect i ng t he Tu r b in e Hea t r a t e :

1) Main Steam Temperature at H.P.T Inlet

2) Main Steam Pressure at H.P.T Inlet

3) Reheat Steam Temperature at I.P.T Inlet

4) Reheat Steam Pressure at I.P.T Inlet

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5) Condenser Vaccume

6) Temperature of Feed Water at Economiser Inlet.

7) Boiler efficiency

8) S.H. and R.H. attemperation flow rate.

The ef f ec t o f i nd i v idua l pa r am e t e r i s d i scussed be low :

Rankine cycle efficiency, rankine = 1 (T2/ Tm1) (1)

Where; T2 is temperature of heat rejection, (2)

Tm1 is Mean temperature of steam admission = (h1 - h4s) / (s1 - s4s). (3)

h1 & s1 are specific enthalpy and entropy of steam at admission temperature and pressure,

h4s and s4s are the Sp. Enthalpy & entropy of feed water at Economiser inlet.

1) Temperature and Pressure of steam admission (M. S. as well as H.R.H) : Forrankine tobe high, Mean temperature of Steam admission (Tm1 in expression 1 above) should be as

high as possible. Metallurgical constrains limit these values for the given Turbine. However, by

maintaining the steam parameters close to the values specified by the Manufacturer, maximum

possible Mean temperature of Steam admission is achieved thus cycle is operated at design

efficiency. Effect on heat rate due to Deviation from design values for 210 MW LMW plant is

as follows :

Parameter Expected Value Actual Value Heat rate Excess Coal Excess coal

deviation Consumption consumption

Kcal/kwh /KWh ( C.V. 3500 over the year,

Kcal/Kg) at 80% PLF

Main Steam temp. 537 C 532 C 1.648 0.0048 Tons

H.R. Steam temp. 537 C 532 C 3.3342 0.0009 2190Tons

Main Steam Pressure 140 Kg/cm 138 Kg/cm 2.417 0.0.0006 1016 tons

2) Condenser Vaccume plays a very important role in efficiency of the Rankine Cycle. Ifvaccume is less than design value, i.e. if Condenser absolute pressure is more than design

value, corresponding saturation temperature is more, thus Heat is rejected at Higher

Temperature (T2 in expression 1 is less than design) and cycle efficiency drops. This increases

Heat rate. Also the of the L.P.T. backpressure increases, thus reducing the conversion of Heat

Energy to work in Turbine. This increases specific steam rate thus increasing fuel consumption.

In Condenser, only latent heat is rejected, hence condensate temperature is always at saturation

temperature. If condenser pressure is less than design value, temperature of condensate

shall also be less. This causes low feed water temperature, thus increasing the heat rate.

Following table shows effect of deterioration of condenser vaccume on heat rate.

Parameter Expected Actual Excess Heat rate Excess Coal Consumption / Excess coal

Kcal / KWh KWh ( C.V. 3500 Kcal/Kg) consumption over theyear, at 80% PLF

Condenser 690 670 19 0.0054 7989 Tons

mm Hg. mm Hg.

3) Less Temperature of feed water at Economizer inlet causes efficiency of Rankine Cycle to

drop, as Mean temperature of steam admission decreases. Values of h4s and s4s in expression

3 above are high, thus reducing Mean temperature.

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Parameter Expected Actual Excess Heat rate Excess Coal Consumption / Excess coalKcal / KWh KWh ( C.V. 3500 Kcal/Kg) consumption over the

year, at 80% PLF

Feed Water 253 C 248 C 22 0.0063 9261 Tons

Temp.

Reasons f o r Low St eam t em per a t u r e and P r essu r e :

In the Power Plant, there can be many reasons for low temperature of Steam at Boiler

and Reheater outlet. Passing spray water control valves and motorized valves, inadequately

tuned temperature control system, fouled surfaces of the Super Heaters are some of the

reasons. These reasons become more dominant when the plant is operating at loads below

maximum rating. Throttling of steam flow due to partially shut valves is the major reason for

low pressure of steam at Turbine admission.

Reasons f o r poo r vaccum e in Condenser :

1 ) Ai r in gr ace in co nd en ser : Air ejection system of the condenser has the capacity to

remove non-condensable gases present in the steam in normal operation. As the condenser isoperated at less than atmospheric pressure, it is prone for air leaking in to it. Sealing systems,

such as Turbine Gland Sealing, Water sealing of the evacuation system Valves, are provided

to prevent the air ingrace. If Gland sealing steam pressure and temperature and Valve Gland

sealing water pressure are not maintained properly, atmospheric air enters the condenser in

large quantity. Evacuation system can not remove the excess air and hence condenser pressure

increases. Condensers are also provided with many tapping points for instrumentation. Many

of these tapping points are used only for carrying out acceptance tests. Once these tests are

over, the temporary instrumentation connected to condenser is removed. If any of such tapping

point remains open by oversight, air enters the condenser. There is also a chance of cracks

developed on the connection between L.P.T. casing and condenser. Damaged gaskets on flanged

joints, leaking vent valves provided on Pressure gauges, cracked impulse lines, passing vaccume

breaker valves, atmospheric vent or drain valves on C.E.P. inlet piping, if are open, also causeair ingrace. Evacuation equipment, such as Steam Ejectors, Electrical Vaccume Pumps are

provided with airflow measuring devices. Any increase in the flow rate indicates air ingrace.

Condenser air leaks can be identified by manual inspection while the plant is on load. Helium

Leak Detectors can also check air leaks. When the unit is shut down, condenser leaks can be

detected by filling Condenser with D.M. Water up to certain high level. But this test needs lot

of prior preparation.

2 ) H igh C. W . Tem per a t u r e , I nsu f f i c i en t Flow r a t e o r Fou led hea t t r ans f e r su r f ace :

Condensers are heat exchangers. Heat transfer takes place from steam to cooling water from

the tube surface. Cooling water takes away the Latent Heat from condensing steam. The heat

transfer equation is

Q = U * A * Tm (1)

Where Q is heat load on condenser, a function of mass rate of steam condensing

U is the coefficient of heat transfer,

A is the surface area of tubes

Tm is Log Mean Temperature Difference,

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Ti - Tf

Where Tm = (2)

Ln (Ti / Tf)

Ti = (saturation temperature of steam C.W. inlet temperature) (3)

Tf = (saturation temperature of steam C.W. outlet temperature) (4)Also called Terminal Temperature Difference or TTD

Relationship between Water flow rate and heat load is given by

mw = Q / ( cp * (T2 T1) ) (5)

(T2-T1) = (mw * cp) / Q (6)

Where mw is Mass flow rate of Water

cp is specific heat of water = 4.2 Kcal / Kg / C,

T2 is Temperature of Water at condenser outlet

T1 is Temperature of Water at condenser inlet,

In the installed system, Mass flow rate of water (depends on the C.C.W pumping capacity)and Heat Load (Mass of steam from LPT exhaust) becomes constant. And as per equation 3

above, heat removal capacity solely depends on (T2 - T1). Temperature of Cooling Water, T2,

at Condenser outlet can increase only up to the value decided by design T.T.D. for the condenser,

Design value for T.T.D. in Condensers is generally 2.5 C, as designing condenser for TTD

below this is not viable. Hence, ultimately, the heat removal becomes directly dependent on

Cooling Water Inlet temperature (assuming other factors to be constant for the given case).

Increase in this temperature will cause reduction in mass of steam getting condensed. In such

cases, some steam remains in vapour form, causing Condenser Pressure to increase. Similarly,

even if Cooling Water temperature is within design limits, but its mass flow rate reduces,

same scenario can be expected.

If heat transfer coefficient deteriorates, it again lead to increased Condenser Pressure,

as all the steam do not condense because of insufficient cooling.

Reasons f o r H igh C. W . t em per a t u r e :

In Cooling Towers, evaporative cooling of Hot water takes place. Air, sucked by the C.T.

Fan, flows in cross flow direction to water flow, comes in contact with air, causing evaporation

of water. The heat energy required is taken from Water, thus cooling it. The rate of evaporation

is dependent on Relative Humidity of air and its dry bulb temperature C.T. design is made

considering yearly average value of R.H. found from historical data.

If the R.H. and Dry bulb temperature of ambient air is high, evaporation is low and

hence Water temperature does not drop to the design values. This situation may arise during

some periods of the year and is not controllable. The controllable reasons are;

1. Non availability of some of the C.T. fans,2. Unequal distribution of water to individual cell of the cooling tower,

3. Some of the water not coming in contact with air stream,

4. Reduced surface are of mass of water due to damaged or plugged nozzles,

5. Sensible heat gain by cold water when it flows from C.T. to C.W. Pump sump.

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Reasons fo r Low C.W. Flow ra t e ;

1) C.W. Flow rate required for maintaining Condenser Vaccume at rated generation from

the plant are calculated by designers. Accordingly C.W. Pump rating is calculated. Velocity of

cooling water through condenser tubes is the controlling factor. The pumps selection is based

on calculated values of Hydraulic Resistance of the C.W. Lines, Condenser tubes, elevation to

which hot water should reach etc. Hydraulic resistance of the C.W. circuit increases due to

following reasons :

i. Number of Plugged condenser tubes more than considered while designing the system

ii. Reduction in Tube cross sectional area due to scaling in the tube or deposit of mud, algae

or organic growth within the tubes

iii. Throttling of Flow distribution valves at C.T. Cells

iv. Throttled isolating valves in the system

v. Deterioration of pump performance due to eroded or corroded impeller.

vi. Heavy and undetected leakage from the under ground piping.

Reasons f o r de t e r i o r a t i on o f Hea t t r ans f e r coe f f i ci en t :

Scaling and fouling, corrosion, and organic growth on condenser tubes reduces the abilityof heat transfer between Steam and cooling water. Ingrace of ambient of air in to the condenser,

which blankets the tube surface. Air has very low thermal conductivity and it causes drop in

Heat Transfer coefficient.

To minimize the problems of scaling, it is extremely necessary that cooling water softness

be maintained. Calcium and Magnesium salt precipitates stick to the metal surface forming

hard and difficult to remove scales. These salts have very poor thermal conductivity. Commonly

encountered scales are

i. Calcium Carbonate

ii. Calcium Sulphate

iii. Silicate Scales

iv. Calcium Orthophosphate

v. Magnesium saltsvi. Iron salts

Fouling is caused by deposition of suspended matter, insoluble in water. Foulants are

Mud and silt, Natural Organics, Microorganisms, Air borne Dust, Vegetation etc.

Pr even t i ve M easu r es : The concentration of salts takes place because of evaporation of

water in the cooling towers. Even if softened water is used, concentration of these salts

increases in closed circulation system. One of the ways to reduce the concentration is taking

fresh water in to the cooling pond to make up for the evaporated water. But by this method,

huge quantity of make up water is required. Another way is to softening. But soft water has

greater tendency for corrosion. Maintaining pH of water between 6.0 to 8.0 by feeding acid in

the system. But there are many disadvantages such as control of pH, safety in handling huge

quantity of acid etc. On line circulation of sponge balls through condenser tubes, and occasional

acid cleaning of the condenser tubes are other ways to prevent scaling.

M ic r ob ia l Gr owt h : Microorganisms enter cooling towers through air, make up water and

dust. The major problems are Algae, Fungi and Bacteria. Chlorine is usually adequate to

prevent the growth. But, it is effective only if pH is 8.3 or below. Free chlorine of 0.2 to 0.5

ppm is sufficient. Beyond 8.3 pH Chlorination does not satisfactory results.

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Tem per a t u r e o f f eed w a t e r a t Econom ize r i n le t :

Feed water temperature is another factor, which decides the efficiency of Rankine Cycle,

as is evident from expression 1 above. Tm1 decreases if temperature of feed water at Boiler

outlet is low. High availability of feed water heating system and also its optimum performance

are important factors. Reasons for poor performance of feed heaters are :

1. Scaling of the tubes

2. Inadequate venting of Feed waters before cutting those in service

3. Passing and leaking heater bypass valves

4. Heater getting bypassed frequently due to High water level of because of inefficient

heater level control instrumentation

Boi le r Losses and e f f i c iency :

Boilers are designed to operate at certain efficiency. Typical figures of the losses in the

Boiler (designed values) are :

Loss t ak in g p lace % loss

Dry Flue Gas loss 4.64

H2O and H2 in fuel 5.60

H2O in air 0.18

Unburnt Carbon 0.60

Radiation 0.19

Unaccounted 0.40

Manufacturers Margin 0.50

Total Losses 12.11

Ef f i c i en cy 8 7 .9

Controllable losses are 1) Dry Flue Gas loss and 2) Unburnt Carbon. Losses due toMoisture in fuel and air are uncontrollable. Ambient air, when introduced in the boiler, also

carries with it water vapors. Hydrogen in Coal reacts with Oxygen in air and forms moisture.

Along with flue gas, water vapors also receive heat energy produced from combustion of fuel.

This energy is lost to atmosphere through Chimney.

Flue gas loss and Unburnt Carbon loss are the controllable losses. Effect of deviation of some

of the parameters on Heat rate :

Parameter Expected Actual Excess Heat rate Excess Coal Consumption / Excess coalKcal / KWh KWh ( C.V. 3500 Kcal/Kg) consumption over the

year, at 80% PLF

Excess Oxygen 3.5 % 4.0% 3.467 0.001 1600 Tons

Unburnt Carbon 1.0% 1.5 % 3.782 0.0011 1700 Tons

Flue Gas Temp 135 145 18.67 0.00533 7853 Tons

Moisture in coal 9% 11% 2.75 .00078 1156 Tons

Flue Gas Loss :

Combustion of fuel produces flue gas. Its major constituents are

1. Carbon Di Oxide produced by Carbon & Oxygen reaction,

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2. Nitrogen from air,

3. Fly ash,

4. Oxygen,

5. Water Vapours.

Temperature of flue gas leaving air pre heaters is maintained at 135 to 140 C. Total

Heat content in the flue gas is =

(Volume of flue gas in m/sec x Sp. Heat of the flue gas x Specific Weight x Flue gas temperature)

Specific Heat of the flues gas is 30.6 kJ / Kg / C.

Specific weight of the flue gas is 0.796 Kg/ m.

When boiler is operated with Optimum air supply and temperature of flue gas at APH

outlet must is maintained within the design limits, flue gas loss is at its minimum. Primary Air

+ Secondary air is the total Combustion air supplied to Boiler. Depending on the Coal Analysis

and required velocity of air + coal mixture through coal pipes, manufacturers specify P.A.

Flow through coal mill in relation to Coal Feeding.

Com bus t ion A i r r equ i r em en t f o r t he Bo i l er : Requirement of air for combustion of coalvaries as per the constituents of coal being fired. If it is less than required, incomplete

combustion takes place leading to high unburnt carbon loss. If it is more than required,

combustion can be complete but Flue gas quantity increase leading to higher flue gas losses.

For Pulverized coal fired Boilers, 20% Excess air supplied under specific conditions, ensure

complete combustion. By maintaining 3.5 % Oxygen in flue gas (On dry flue gas basis) at

Economizer outlet ensures, that the Boiler if being fed with 20% excess air. It needs to be

emphasized that Spec i f i c Cond i t i on s m us t be m e t to ensure minimum losses. These

conditions are:

1. Fuel particle size must confirm to specified dimensions.

2. All the coal nozzles must admit equal mass of fuel in furnace and hence , primary air

velocity through pipes must be equal and as P.A. flow to mill should be proportional to

mill loading as specified by the manufacturer

3. Coal / Air mixture temperature at Pulveriser outlet must be 77 C.

4. Secondary air must enter combustion chamber from pre determined places only.

5. Secondary air must enter the furnace at predetermined velocity from all elevations.

6. Diffusers on the coal nozzles must be in proper condition to ensure that the jet of air/

coal mixture, emanating from nozzle, is well distributed.

7. Furnace must be air tight to eliminate possibility of entry of ambient air.

When all these conditions are satisfied, then only efficient combustion in the furnace,

supplied with 20 % excess air is ensured. Fuel admission and combustion system has following

equipment to ensure these conditions.

1. Oxygen Analyzers : In situ, Zirconia probe Oxygen Analyzers, installed on Economiseroutlet ducts, continuously monitor Oxygen in flue gas. Automatic air flow control loop

regulates F.D. Fan Inlet Guide Vanes in such a way that 3.5% Oxygen in flue gas is

maintained through out the operation of Boiler.

2. Fuel air dampers (named after the coal elevations i.e. A, B, C, D etc) on all the Four

Corners should be open only for the elevations that are in service. Position of these

dampers must be equal for all the corners. Regulation of these dampers is as per the

quantity of coal feeding measured as Coal Feeder speed. Dampers of the elevations AA.

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FF, BC and DE should open equally for all Four Corners. These dampers are regulated to

maintain Furnace Windbox D.P. to the value specified by the manufacturer. Dampers

AB, CD and EF are regulated as per Fuel Oil pressure for Oil elevation in service. For the

oil elevation not in service, dampers regulate as per the Furnace Windbox D.P.

3. Orifice plates in Coal Pipes : To ensure that all burners (nozzles) at all coal elevations

admit equal mass per sec in the furnace, two requirements should be fulfilled. Primary

air flow velocity in each of the pipe must be equal and fuel/ air ratio in all pipes should

be the same. Inserting the Orifice plates, thus equalizing the hydraulic resistance of all

the pipes equalizes pipe velocity. Cold air flow tests are conducted on coal mills at

regular intervals. Results from these tests give valuable information of condition of Orifice

plates and partially or fully choked up pipes. If coal mill is operated with Primary air flow

rate less than that specified, velocity of coal air mixture drops below 20 mtr/sec, causing

separation of coal particles from stream and consequent settlement in pipes, resulting

partial choke up. If the temperature of coal / air mixture at coal mill outlet drops below

60 C, there is a possibility of condensation of water vapor which also result in separation

of coal particles and its settlement.

4. Mill air flow control dampers : For ensuring the coal / air ratio equal, P.A. flow rate to millshould be as per mill loading and hence regulated by feeder speed. Coal mill manufactures

give the P.A. Flow rate and mill loading characteristics.

5. Mill temperature control system: By ensuring coal air mixture at 77 C, adequate dryness

of coal is ensured, which is one of the important requirements for proper and efficient

combustion.

6. Furnace Windbox DP Control system : Velocity at which secondary air enters the

furnace is determined by Furnace Wind box differential pressure. For every boiler,

value of Furnace Wind box differential pressure is specified for different loading

conditions. By sticking to the specified values, it is ensured that velocity of secondary air

is as per the combustion reaction requirement. For this purpose, opening of Secondary

Air dampers of the wind box is controlled by automatic control loop for Furnace Windbox

DP. Set point for this loop is generated as per the boiler load as indicated in the enclosedFig.1.

7. Corner Firing : For achieving efficient and sustained combus t ion a t des i r ed r a t e ,

Oxygen in Air must reach the Coal particles at that rate. Oxygen molecule reach burning

coal particles by a process called Diffusion. Ratio of Concentration of Oxygen at particle

surface to that in surrounding gas mixture decides rate of diffusion. This rate is highest

when Coal particle is surrounded by air which contains 21 % Oxygen. Furnace atmosphere

is made of mixture of Coal, Air, Flue Gases and Ash particles. To ensure that coal particles

will always remain surrounded by air, place of air admission, velocity at which air is

admitted and turbulence in the furnace are of prime importance. First two requirements

are fulfilled as discussed above. Tangential firing fulfills requirement of turbulence.

8. Air tight Furnace: Furnace pressure is always maintained at 4 5 mm W.C. below

atmosphere. If furnace is not air tight, ambient air will enter furnace. But, the velocity of

this air is very low. This air can not mix with the jets of Secondary air and Primary air /

Fuel mixture admitted at very high velocities and hence does not take part in combustion.

But, it travels with flue gas, and distorts the Oxygen reading, thus replacing the Secondary

air. It is therefore extremely important that tramp air entry be prevented.

9. Pulverization of coal for design particle size : The above discussions deal with the

importance of Fuel firing equipment and air supply to boiler. Role of particle size is as

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important as that of proper supply and distribution of air in the furnace. As explained,

care is taken that coal particles will always be surrounded by air in the furnace. In

furnace, very small size air Packets are interspersed in the homogeneous mixture of

gases. Total oxygen required for complete combustion of the individual particle depends

on mass of particle, which in turn depends on the size to which particle is pulverized.

Smaller is the size of particle, smaller the quantity of Oxygen required for its complete

combustion. Hence, by ensuring that 70% of Coal passes through 200 Mesh, it will

always remain surrounded by air packet which will contain enough Oxygen. But, it is

also important that size distribution of balance 30 % coal should be:

Passing through 100 mesh; 85% and above

Retained by 50 Mesh: Less than 0.5%

Resident time of particles in the furnace is generally 1 to 2 seconds. Bigger particles will

not burn completely due to lack of Oxygen, within this time and leave the furnace as unburnt

Carbon, thus increasing losses. Coarser particles also lead to increase in slagging.

Opt im iza t i on o f Com bus t ion P r ocess : Supplying 20% excess air ensures that combustion

will be complete. How ever, there is always a possibility that in certain type of Coal and

combustion conditions, Excess Oxygen requirements can even go below 20%. It may also be

possible that in some conditions, excess Oxygen requirements may be more than 20%. In

power plants, where coal from different mines is fired regularly, such conditions may arise

very frequently. To ensure that combustion remain efficient in varying condition and Optimum

air is supplied to Boiler in all conditions, Carbon Mono Oxide monitoring in flue gas is done. If

combustion is not complete, concentration of CO in flue gases increases. Complete combustion

is indicated by 100 ppm Co in flue gas at Economizer outlet. If combustion is incomplete due

to insufficient air, Co level shot up immediately to very concentration values. Fig. 2 shows the

variations in Co with ref to Air supplied to Boiler.

Other Factors : Following factors also cause deterioration of plant performance, thus increasing

heat rate. Many times, these factors are not measurable directly by plants instrumentation.

But, their effect can be known from regular tests.

Low e f f i c iency o f H.P. Turb ines , I .P. Turb ine and L .P. Turb in e: Turbine cylinder isentropic

efficiency is the measure of how efficiently turbine has converted input heat energy in to

mechanical work. Isentropic efficiency of Turbine Cylinder is given by :

Actual Enthalpy of steam at Inlet Actual Enthalpy of steam at exhaustEfficiency =

Actual Enthalpy of steam at Inlet Ideal Enthalpy of steam at exhaust

Actual Enthalpy is known from steam parameters at Inlet and Exhaust. If steam expands

in turbine without change of Entropy, then it is called ideal expansion. By finding out Temperature

for Actual exhaust pressure and actual entropy of steam at Turbine inlet, value of ideal enthalpy

is known. Turbine manufacturers give the expected Efficiencies. Any subsequent deviation

from expected values indicate deterioration of Turbine and can be corrected in the planned

outages.

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Ai r Hea t e r l eakage : In Trisector Airheaters, air leakage, through seals, in to flue gas takes

place. Due to rotating rotor, the air side and flue gas side sectors are sealed by radial as well

as axial seal plates. Deterioration of sealing arrangement increases air leakage increasing

I.D. Fans loading. Leakage of ambient air in to flue gas through damaged ducts and through

E.S.P. Hoppers is another reason of increased loading fo the I.D. Fans. The extent of both the

leakages can be so high that I.D. Fan loading reaches its maximum, leading to either restriction

on Generation or in worst case, purposeful reduction of Secondary air. By measuring Oxygen

at Air Heater outlet and ESP outlet monitoring of extent of air leakage is possible.

M ake up w a t e r consum p t ion : Consumption of make up water is because of following reasons:

1. Soot blowing

2. Steam ejectors

3. Opening of C.B.D.

4. Passing of drain valves

5. Leakages of steam or feed water.

6. Steam used for Oil heating and steam tracing of oil lines.

7. Operation of auto drain traps to remove condensate from steam pipelines.

To certain extent, steam consumed for Soot Blowing, Oil heating and Ejectors and

Water lost through C.B.D. can be calculated. If this data is monitored regularly, extent of

leakage from system can be guessed. Any leakage from system indicates heat lost and lead

to increased heat rate.

Spr ey W a t e r F low r a t e f o r S t eam t em per a t u r e Con t r o l : There is no direct effect of

attempartion flow in heat rate deviation. But increased sprey flow rate indicates deterioration

of Boiler Conditions.

Aux i l i a r y Consum pt ion : Increased Auxiliary Consumption indicates more energy consumed

by auxiliaries. It also makes less energy available for distribution to consumers. Closelymonitoring these values helps in monitoring of health of the auxiliary. Regular energy audit

gives valuable information on repairs to be carried out and planned maintenance.

Conc lus ion s : From above discussions, it can be concluded that, operation of the Thermal

Power Plant at optimum conditions reduces Gross Unit heat rate. The factors that affect heat

rate are:

1) Parameters of steam at HPT, IPT inlets,

2) Condenser Performance

3) Cooling Tower Performance,

4) Combustion of fuel in Boiler with Optimum air supply, thus reducing Dry Flue Gas loss

and Unburnt Carbon loss.

5) Auxiliary Consumption

6) Air heater leakage

7) Duct Leakage

8) Ingrace of tramp air in Boiler

9) Make up water consumption

10) Turbine Cylinder Efficiency

11) Feed Water temperature at Economizer Inlet.

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Fig . 2 , Change i n CO i n f l ue gas w i t h com bus t i on a i r supp l y

Fig . 1 , Va r i a t i on i n F u rnace W indbox DP con t ro l ck t . se t po i n t w i t h l oad

140 mm Wcl.

Furnace

Windbox DP

40 mm Wcl.

40 % 70 %

Boiler Load

CO in flue gas

In ppm

Deficient air supply

100 ppm

Optimum Air Supply Air supply to Boiler

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516

I . BOI L ER PERFORMA NCE

A ) Op t im i zi ng To t al ai r su pp li es :Supplying correct air quantity for combustion is vital for optimization of boiler operation.

Too little air will cause unburnt losses and too much air will increase the dry flue gas losses.Carbon mono-oxide monitor can be effectively used for enabling supply of correct air

quantity of air for combustion. Flue gasses in a pulverized fuel boiler will normally have a

residual quantity of carbon mono-oxide in the vicinity of 100 ppm.

If the amount of excess air supplied to the furnace is greater than the design excess air value,

then the flue gas flow rate and the amount of heat lost to the atmosphere will increase,

causing a decrease in energy efficiency. This situation can occur if the plant control system isdefective or there is incorrect plant operation.

B) Co m b ust ib le m at er ia l s i n a sh :

The amount of unburnt in ash is a measure of effectiveness of combustion process andmilling plant. Normally about 1.5% carbon in dust is regarded as optimum. Values higher

than this are indicative of the following.1. Poor grinding.

2. Incorrect combustion air supplies.

3. In correct p.f. classifier setting or mills in need of adjustments.

Apart from the milling plant the actual combustion process can lead to high carbon in

ash. If the air supplies are badly adjusted, even though grinding is proper, unburnt losses can

occur. For the best control of flame all mills should ideally produce the same size of product,and also all mills should be equally loaded as this spreads the fire evenly. Unequal grading

produce flames, which have different characteristic and so are insensitive to secondary air

adjustments. The air temperature is also important because of influence of the rate of ignitionand flame length. The primary air to secondary air ratio is also an important norm, which

should not be allowed to deviate too much from the recommended value.

C) A ir h ea ter g as o ut l et t em p er at u r e :

Optimum air heater gas outlet temperature recommended by manufacturer should be

adhered to.The temperature of the flue gas leaving the air heater (which is the final heat exchange

element in the boiler) has a direct influence on the station efficiency. For example, a 22OC

increase in this temperature above optimum could result in a 1% decrease in station efficiency.There are many causes of an increase in this temperature, all to do with reductions in energy

absorbed from the hot gas in or after the furnace. The most usual problems are :

1. Ineffective air heater soot blowers2. Holed & torn elements, a particular problem at the cold end plates because of corrosion.

3. Fouling, corrosion/erosion and blocking of air heater elements.4. Deposits on the external heat transfer surfaces of the furnace, super heaters, re-heaters

and economisers - many of these surfaces have to be regularly cleaned using soot

blowing for increase in efficiency resulting from cleaner heat transfer surfaces.

5. Fouling of the internal heat transfer surfaces of the furnace, super heaters, re-heatersand economisers caused mainly by incorrect chemistry of the water and steam in these

tubes; or by incorrect material selection of the tubes; or by the tube material overheating;

or combinations of these

UNI T PERFORMANCE AND OPTI MI SATI ON


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6. Defective or non-availability of Soot Blowers.

7. High Excess Air (This will increase the gas weight and also elevate the temperature,however if excess air is very high, dilution effect may predominate and the flue gas

temperature will fall).

8. Low feed water inlet temperature at Economiser inlet.

9. Defective baffles in gas paths.10. Poor milling and poor combustion resulting in long burn off times and result in higher

outlet gas temperature in addition to fouling.11. Use of higher rows of burners at lower loads.

12. Air leakage before combustion chamber.

I I . TU RB I N E PERFORM AN CE

A) I n t e r na l Losses :

Nozzle Friction, Blade friction, disc friction, diaphragm gland and blade tip leakage,partial admission, wetness and exhaust.

B) Ex ter na l Losses : Shaft gland leakages.

The common cause of cylinder efficiency deterioration include,

1. Damage to blades caused by debris getting past the steam strainers.2. Damage to tip seals and inter stage glands.

3. Deposition on blades, normally start at last few I.P. stages and carry on to the first fewL.P. stages.

4. Increased roughness of blade surface.

I I I . FEED W ATER HEATER PERFORMANCE

Deterioration of feed water heater performance occurs for the following causes.

1. Air accumulation2. Steam side fouling

3. Water side fouling.

4. Drainage defects.

Once a i r accum u la t i on occurs it is manifested in the following.

a) Reduced heater drain water temperature

b) Increased T.T.D. (Terminal Temperature Difference)c) Possible elevation of steam to Heater temperature.

d) Reduced temperature rise of feed water or condensate.

St eam s ide f ou l i ng : The effect of steam side fouling can be observed by the followinga) Progressive increase of T.T.D.

b) Drain Temp unaffected

c) Reduced feed water temperature rise.

W at e r s ide f ou l i ng : Common cause of waterside fouling is oil.

Thermal magnification of the trouble are similar to steam side fouling except that the on-set

of increasing T.T.D. is usually sudden and rate of deterioration is rapid.

Dra inag e de fec ts : Apart from passing of valves, the usual troubles are,

a) Damaged flash box internals.

b) Reduced orifice openings.c) Enlarged orifice openings.

d) Drip pumps defective.

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Ef f ec t o f hea t e r f ou l i ng : Fouling always causes increase in T.T.D. resulting from lower feed

water outlet temperature. Therefore when feed enters the next heater it will be colder thannormal and so increases the steam consumption at that heater. Increased steam flow will

cause increased velocity and mass flow, which may cause mechanical damage.

As a general guide, the turbine generator heat rate will be affected by 0.07% for 10C change

in T.T.D. of HP Heaters.It is recommended that feed heater TTD be monitored every day.

I V . CONDENSER PERFORMANCE :

It is an accepted fact that less than half the heat in fuel is converted into electrical

energy and losses in condenser account for more heat than does the electrical output. Inother words, at any time in the operation of the unit, more MW is going out through the

condenser than which is coming through the generator.

Even very small worsening of backpressure is very expensive in terms of extra heat requiredfor a given output. In fact condenser performance is the most important operating parameter

on a unit. In fact the condenser performance is the most important operating parameter on a

unit, so the factors which worsen condenser back pressure must be clearly recognized so that

effective remedial measures can be taken.The factors affecting performance of condenser are :

1. Variation of C.W inlet temperature.2. Variation of CW Quality

3. Interference with heat transfer.

Condenser T.T.D is a measure of interference with heat transfer. A high TTD means aworsened condition.

The temperature gradient, which is the main driving force for the heat transfer, is expressed

as log mean temp. difference. (LMTD).

The main factors affecting the heat transfer in a condenser are

1. Effect of air blanketing on steam side of tubes. The effect of air ingress is the main factorcausing poor performance of condensers. Air ingress can be measured by use of orifice

plates provided at the ejector outlets.2. Deposition of oil or oxides of copper or iron on the steam side (Copper Oxide etc.)

surface affecting the heat transfer adversely.

3. Deposition on the insides of the tubes due to scale, slime, mud or dirt.

OPTI MI SATI ON OF UNI T PERFORMANCE

Monitoring just a few parameters, it is possible to get a good idea whether plant is

working in optimized condition or not.

These parameters are :

1. Condenser Vacuum.2. Main steam pressure at turbine inlet.

3. Main steam Temperature inlet at turbine inlet.4. Reheat temperature at turbine inlet.5. Final feed water temperature after heater block.

6. Boiler excess air.

7. Unburnt / combustible material in ash.

8. Air heater gas outlet temperature.

9. Make up water consumption.

If each of these conditions is at optimum value there is a good chance that the unit is

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being operated at or near the optimum performance limits. Therefore it is a good practice to

record the above parameters regularly, say once per shift and take action on any deviationsthat are significant.

The significance of each of these parameters in optimization of unit is discussed here as

under.

1 . CON DEN SER V ACUU M :

This is the most important parameter that is required to be monitored. The significanceof it can be understood from the fact that a vacuum drop equivalent to 10 mm of Hg would

cause a loss of approx. Rs. 415/- hour in terms of fuel cost when running the unit at full load.

(The figures are based on performance calculations done at Chandrapur in 1996.)It is therefore necessary that in every shift back pressure should be analysed for deviations

from optimum. One of the reasons for the drop in back pressure is the air ingress in the

condenser. Checks should be carried out to see if air ingress is excessive.For checking the air ingress, help of Helium leak detector may be taken to identify and

/ or quantify the air ingress points. The best way to do this is to note the air suction depression.

This is a method by which presence of air is determined by measuring temperature of contents

of air suction pipe to air ejectors / vacuum pumps. When there is only a little air present, thetemperature is very little below the saturated steam temperature say within 4.50C. as more

and more air is present the temperature falls the more air the greater depression of airsuction compared to saturated steam temperature. Preferable the thermometers are to in

direct contact with the contents of air suction pipe.

Alternately at regular intervals, say once a week confirm how long it takes for the backpressure to detoriate by a set amount when the air pump suction valves are shut. Comparison

with the time taken when condenser was known to be in good condition will indicate the

degree of air leakage.

2 . M A I N S TEA M PRESSU RE A T TU RB I N E I N L ET :

A change in turbine stop valve pressure will result in corresponding change in output.Hence it is the most important that when the unit is on full load, the turbine stop valve

pressure is kept at correct value. In general the effects of change in Turbine Stop Valvepressure are :a) Steam flow will change.

b) Changed flow will cause the pressure through the turbine to change, including bleed

steam pressure.c) Because of (b) the feed heater outlet water temperature will change.

d) Total Heat of TSV steam, R/H steam and final feed water flow will change.

e) Boiler feed pump output will change to cope-up with changed flow.

f) Because the flow through turbine has altered so the volumetric flow to condenser will

change.

Thus it is seen that a simple change in TSV pressure reflects throughout the cycle.It can be seen from the calculation that 5 Kg/cm2 pressure drop at turbine inlet would result

in a loss of Rs 185/- per hour approximately. Based on calculations done in 1996.

3 . M AI N S TEA M TEM PERA TU RE A T TU RB I N E I N LET :

Variations in the TSV steam temperature result in variations in the specific volume of the

steam and this results in a change of steam flow.

Other results are :

a) Change of total heat to TSV Steam.

b) Change of total heat to HP cylinder exhaust steam.

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c) The change of flow will alter the pressure throughout the turbine and this will change the

bleed steam flow to heaters.Calculations indicate that a 50C drop in the main steam temperature could result in a

loss of around Rs. 100/- per hour at full load.

4. REHEAT OUTLET STEAM TEMPERATURE :Variations in the Reheat Outlet Steam temperature will cause:

a) Change in total heat of the steam.b) Change of steam flows to the condenser for a given loading.

50C drop in the Reheat Outlet Steam temperature would result in a loss around

Rs. 154/- per hour at full load.

5. FI NAL FEED W ATER TEMPERATURE AFTER HEATER BLOCK :

The final feed water temperature should be measured after the HP Heater block bypasshas joined the feed line and deviations from optimum should be investigated. Water flows

through the bypass will cause the final feed heater outlet temperature to be higher than final

feed. Variations of feed flow from optimum will cause changes of output and heat rate.

In addition there can be deviations from optimum at individual heaters. Whatever is thetrouble at a heater it must affect one or more of these parameters.

a) Heater Terminal Temperature Difference.b) Drain outlet terminal temperature difference.

c) Bleed steam pipe pressure drop.

d) Steam temperature at heater inlet.

6 . BOI LER EXCESS AI R :

Boiler combustion efficiency is largely dependent upon supplying correct quantity of

excess air at right place. Supplying too much of excess air will increase dry flue gas losses.

This is because the quantity of gas will increase and so will the heat content as excess air will

absorb heat more readily than the heat exchange surface, thus increasing the Air heater gasoutlet temperature.

7 . COM BU STI B LE M ATERI A LS I N ASH :

The permitted values for the carbon in ash are 0.8 % in fly ash and 4.8% in bottom ash

as per the design. Values greater than above are indicative of:

a) Poor grindingb) Incorrect combustion air supplies.

c) Incorrect pulveriser fineness classifier settings.

It is calculated that 1.5% carbon in ash is equivalent of about 0.5% boiler losses amounting

to around Rs. 236/- per hour approximately at full load.

8 . A I R HEATER GAS OUTLET TEM PERATURE :

The causes of high air heater gas outlet temperature are :

a) Ineffective A/H soot blowing.b) Holed and torn elements.c) Deposits on boiler heat transfer surface.

d) Defective soot blowers resulting in reduced heat transfer in discrete location and result

will be as in (c).

e) High excess air increases the gas weight and also elevates the temperature. However if

the excess air is very high dilution effect may predominate and the gas temperature will

fall.

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f) Low final feed water temperature has to be remedied by extra firing in the boiler and this

will result in high exit gas temperature.g) Poor milling and poor combustion results in long burn off times and result in high gas

temperature at furnace exit in addition to fouling.

h) Using upper rows of burners on low loads.

Generally speaking a final gas temperature of about 200C above optimum will result inboiler efficiency loss of about 1%, which amounts to a loss of Rs. 472/- per hour at full load.

9 . M AK E U P W A TER CON SU MPTI ON :

Makeup water is replacing water and steam, which has been lost from system and contains

considerable quantities of heat.There are four usual sources of loss:

a) Passing of valves / leaks.

b) Boiler blow downs.c) Drains going to waste

d) Soot blowing.

Of the above four sources of loss, the first three can be controlled by good house keeping.

As regards the soot blowing losses if it is carried out too often heat is wasted whereas if it isnot carried out often enough the heat transfer may become heavily coated and heat transfer

will be reduced and thus the final gas temperature will rise. Hence there must be optimuminterval between soot blowing, but just that may be difficult to determine. The basic problem

is that soot blowing affects boiler efficiency and boiler availability.

An expression for heat loss due to carrying of soot blowing is :

Loss =Heat loss to soot blowing steam

Heat given to TSV Steam + Heat given to RH steam

Loss = 0.25Qs+

Qs(h

1-h

5)

(h2

h5) + Q

R(h

4 h

3)

Where Qs= Soot blowing steam as a percent of TSV steam flow.

QR

= Reheat steam flow as fraction of TSV steam flow.

h1

= Total heat of steam at A/H gas outlet temperature & pressure.h

2= Total Heat of Steam at TSV conditions.

h3

= Total Heat of Steam before Re-heater.

h4

= Total Heat of Steam after air heater.h

5= Heat in final feed water.

The term 0.25 Qs is the approximate loss due to raising the temperature of the cold

make up water to final feed water temperature.

For operational purposes it is convenient to determine some reference temperature (say

gas temperature leaving primary super heater) and commence soot blowing when it reaches

a certain value, allowance being made for boiler loading. The alternative of blowing out at

preset times (say once per shift) has little to commend except convenience. One of the main

parameters that determine the frequency of soot blowing is the ash content of coal.

The above explanations are given to bring home the importance of maintaining the fewvital parameters to their optimum values for bringing down the operating losses. If each of

the above conditions is maintained at the optimum it can be assured that the unit will be

running at minimum losses and maximum efficiency and consequently the coal rate per HWHgeneration will also come down appreciably.

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Turbine performance plays a major role in Turbine Cycle Heat rate. Isentropic Efficiency

of turbine is the important parameter that indicates performance of the Turbine. In impulse

stages of the turbine, steam expands thorough nozzles, causing increase in its kinetic energy.

The high velocity steam jet is then made to impinge on the moving blades fixed on the rotor,

causing blade and rotor to move. Thus the heat energy is converted to mechanical work. As a

result of the conversion, steam temperature and pressure drop over the stages of turbine.

Amount of heat energy converted to work, by applying first law of thermodynamics,

= (Heat Energy contained by steam at admission Heat Energy contained by steam at exhaust.)

= (Enthalpy of steam at Admission Enthalpy of steam at exhaust)

If the expansion of steam had taken place ideally, the isentropic efficiency of the Turbine

cylinder would have been 100%. In such case Entropy of steam at exhaust and at admission

should have remained the same. But, due to the irreversibility in the process of expansion, all

the heat energy is not available for conversion to work.Isentropic efficiency of turbine is thus expressed as a ratio of Actual change in Enthalpy

across the turbine, compared to Theoretical change (At constant entropy) expressed as

percentage.

M et hod o f Ca lcu la t i on : The method of calculating the efficiency is demonstrated for HPT as

follows.

Isentropic efficiency of HP Turbine =

(Enthalpy of steam at HPT Inlet Actual Enthalpy of steam at HPT Exhaust)

(Enthalpy of steam at HPT Inlet Ideal Enthalpy of steam at HPT Exhaust)

En t h a lpy o f s t eam a t HPT I n le t : This is known from the steam tables for steam admissionpressure and temperature.

Actua l En th a lpy o f s team a t HPT Exhau s t : This is known from the steam tables for exhaust

steam pressure and temperature.

I dea l En t h a lpy o f s t eam a t HPT Exhaus t : This is known by first finding out the ideal

temperature of exhaust steam at actual exhaust steam pressure and entropy of steam at

admission. Then ideal enthalpy is known from steam tables, by considering actual exhaust

pressure and ideal exhaust steam temperature.

Similarly isentropic efficiencies of IPT and LPT are calculated by considering appropriate

steam parameters for these turbines.

Ef f e c t o f T u r b i n e Ef f i c i e n c y o n h e a t r a t e f o r 2 1 0 M W p l a n t : (Unit heat rate of 2500 Kcal/kWh)

One percent improvement in Efficiency of % Effect on Turbine Cycle heat rate Effect on Unit Heat Rate

HP Turbine 0.2 % Heat rate - 5 Kcal / kWh

IP Turbine 0.2 % Heat rate - 5 Kcal / kWh

LP Turbine 0.5 % Heat rate -12. 5 Kcal / kWh

TURBI NE PERFORMAN CE

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In addition to the irreversibility of the expansion of steam in turbines, following losses

contribute to reduced efficiency :

1 ) Flu id Fr i ct ion : This is the biggest cause for losses in the turbines. Fluid friction loss can

amount for 10% of the total energy available to turbine. By proper design velocities,

these losses are minimized but can not be completely eliminated. Friction losses are

present due to

i) Friction in steam nozzles

ii) Blade friction, which can be minimized by reduction in velocity of steam by compounding

etc.

iii) Turbulence at blades when blade shape does not posses proper angle of entrance for

steam at loads other than design load.

iv) Friction between steam and rotor disc on which blades are mounted.

v) Rotating blades and rotor produces centrifugal action on steam. Due to which some part

of steam flows radially to casing, which gets dragged along the moving blade.

vi) Churning of steam in moving blades, especially when the turbine is on part load operation.

This loss takes occurs in impulse stages.

2 ) Leak ag e loss : Steam leakage can occur within and outside the turbine and amount to

1% loss of the total energy supplied to the turbine. The leaking steam gets throttled and

represents unavailable energy. Causes of leakage are as follows.

i) Steam leakage takes place along the blade tips and casing when there is a pressure drop

across the blades as in the case of reaction turbines. The loss is greater in high-pressure

turbines. Also ratio of blade height to clearance (between the blade tip and casing) also

affect this loss. Greater being the ratio, greater is the loss.

ii) In pressure compounded turbines, leakage of steam leaks along the shaft at diaphragms

on which nozzles are mounted.

iii) Some steam also leaks out side the turbine from the shaft glands.

3 ) Mo ist ur e Loss : Some part of steam converts to moisture in the turbine. The dropletsare generally move at a low speed. Some droplets strike the moving blades at off-design

angles and reduce the mechanical work of the rotor. Other droplets are accelerated to

velocity of steam and thus momentum exchange takes place reducing the energy in

steam. Usually, the moisture content is limited to 12% at exit steam.

4 ) Leav in g l oss : The residual steam velocity at the last row of rotating blades in a turbine

is quite high because of decrease in pressure and increase in specific volume. The

corresponding kinetic energy represents a loss from the turbine. Magnitude of the leaving

velocity is kept to the minimum by proper combination of height of last blades, speed

and area of the exhaust duct to the condenser. In large turbines, velocity of steam at

exhaust is in the range of 270 to 300 m/s. Provision of double flow paths in IP and LP

Turbines, gradually increasing the exhaust duct also reduces the leaving velocity. This

loss is to an extent of 2 to 3% in modern turbines.

Hence, if the Turbine Performance deviates from the design value, it presents an

insight in to the condition of turbine internals, and hence it is monitored in the power

plants.

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524

Financial Accounting is mainly used for an instrument to record transactions of thebusiness to satisfy the requirements imposed by fiduciary relationship between the business

and its owners as well as third parties connected with business such as creditors, financial

institutes etc. Basic function is limited to recording, classifying & summerising the business

transactions of only financial character through Trial Balance, Income Statement and Balance

Sheet.

Management Accounting covers (i) Financial Accounting, (ii) Cost Accounting (iii)

Revaluation Accounting, (iv) Budgetary Control, (v) Inventory Control, (vi) Statistical Methods

(vii) Interim Reporting, (viii) Taxation, (ix) office Services (MIS- Management Information

Services) and (x) Internal audit system

Cost Accounting is the process of accounting for costs. It embraces the accounting

procedures relating to recording of all incomes and expenditures and the preparation of

periodical statements and reports with the object of ascertaining and controlling the costs. It

is, thus, the formal mechanism by means of which the cost of products or services are

ascertained and controlled.

Objec t iv es o f Cos t Accoun t in g :

Main objectives of cost accounting can be summerised as follows :

1) Determining Selling price : Cost accounting collects costs related to individual product &

services connected to such product, which plays main role in deciding selling price.

2) Determining & controlling efficiency : Cost accounting : Cost accounting involves a study

of various operations used in manufacturing a product or providing a service. It facilitates

measuring of efficiency of organisation, station, unit and section as well as means of

increasing efficiency.3) Facilitating preparation of financial & other statements : The third objective of cost

accounting is to produce statements at such short intervals as the management may

require. Financial Accounts are prepared only once at the year end and it shall be of no

use for current decision-makings by the management.

4) Providing basis for operating efficiency : Cost accounting helps the management in

formulating operating policies. These policies may relate to any of following matters

i) Determination of cost-volume-profit relationship

ii) Shutting down or operating at a loss

iii) Making or buying from outside suppliers

iv) Continuing with the existing plant and machinery or replacing them by improved &

economic ones.

Elem ent s o f Cost

There are three broad elements of cost : Material (Direct material or Indirect material),

Labour (Direct Labour or Indirect Labour and expenses (Direct expenses or Indirect expenses)

Direc t Mater ia l comprises of all materials which becomes an integral part of the finished

product and which can be conveniently assigned to specific physical units. Similarly Direc t

Labou r comprises of all labours, which takes active and direct part in the production of

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particular commodity. Direc t Expenses are those, which can be directly allocated to specific

cost centers or cost units.

The term OVERHEAD includes indirect material, indirect labour and indirect expenses.

Thus all indirect costs are overheads.

A manufacturing organisation can be broadly divided into three divisions: (i) Factory or

Works where production is done, (ii) Office and administration, where routine as well as policy

matters are decided and (iii) Selling and Distribution where product is finally sold & distributed

to customer.

Components of total cost are :

Pr im e Cos t : It consists of costs of direct material, direct labour and direct expenses.

Factor y Cost = Prime Cost + Factory Overhead

(It is also known as Works cost, production or manufacturing Cost)

Cost o f Produc t ion = Works Cost + office & administrative Overheads

Cost o f Sales = Cost of production + Selling & distribution Overheads

COST SHEETS

The cost sheets are prepared for historical cost data or for estimated cost data.Ascertainment of future costs and making comparisons with the past records help the

management in fixing up the selling prices of the products. Several important decisions can also

be taken by the management regarding profit planning, production and marketing strategy, etc.

The preparation of Cost sheets call for special knowledge of cost accounting and well

trained personnel for giving appropriate treatment to computation of profit, raw material

stock and also to stock of work in progress while preparing statement of total production cost.

CLASSI FI CATI ON OF COSTS

Fixed , va r iab le and sem i - va r iab le cos t s

The cost which varies directly in proportion to every increase or decrease in the volume

of output or production is known as variable cost. The cost, which does not vary but remains

constant within given period of time and range of activities in spite of the fluctuations inproduction, is known as fixed cost. The cost, which does not vary proportionately but

simultaneously cannot remain stationary at all times is known as semi-variable cost.

Pr oduc t cos t s and pe r iod cost s : Costs, which become part of the cost of the product, are

called Product Costs and costs, which are not associated with production, are called Period

costs.

Di r ec t Cos t s and I nd i r ec t cos t s : Already explained above.

Dec is ion d r iven cos ts : Some costs are specifically attributed to particular decision. The

decision may lead to either profit or loss. It may result into comparatively better or worst

outcomes than those predicted. Abnormal loss or abnormal profit can be associated with

specific decision. For example, Koradi TPS has purchase a powder to mix with coal in anticipationto improve heat rate. But after actual use, there is no improvement in heat rate. It is decision

driven cost/ loss.

Relevan t cos t s and i r r e levan t cos t s : Relevant Costs are those, which would be changed

by the managerial decision. While irrelevant costs are those, which would not be affected by

the decision.

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Shu t dow n cos t s and sunk cos t s : Due to some temporary difficulties like shortage of raw

material, non-availability of labour etc, sometimes operations may have to be suspended for

a period. During this period although no work is done, yet certain fixed costs, such as, rents,

electricity, insurance, depreciation, maintenance etc for the entire plant will have to be incurred.

Such costs are known as shut down costs.

Sunk costs are historical costs or past costs. These are the costs, which have been

created by a decision made in the past that cannot be changed by any decision that will be

made in future. These cost are irrelevant for decision-making.

Exam p le : Koradi TPS purchased a machine for Rs. 30,000. The machine has an operating life

of 5 years without any scrap value. Soon after making purchase the management of Koradi

TPS feels that the machine should not have been purchased since it cannot yield the operating

advantage originally contemplated. Of course, it is now expected to result in saving in operating

costs of Rs. 18,000 over the period of 5 years. The machine can be sold immediately for Rs.

22,000.

In taking the decision whether machine should be sold or be used, relevant amounts to

be compared are Rs. 18,000 in a cost saving over 5 years and Rs. 22,000 that can be realized

by selling the machine. Rs 30,000 invested in machine is not relevant & is a sunk cost.

Oppor t un i t y Cos t s : The Opportunity cost refers to the advantage, which has been foregone

on account of not using the facilities in a manner originally planned.

Exam p le : If Koradi TPS is to decide whether to provide certain amount of steam at offered

cost for some other operations instead of generation of electricity. Then in such decision, the

revenue which could fetch by generating electricity by such steam is the opportunity cost

which, should be taken into account for evaluating the profitability of using such steam for

other purpose.

COST REDUCTI ON A ND COST CONTROL

Cost Reduction and Cost Control are two different concepts. Cost Control has achieving

the cost target as its objective while cost reduction is directed to explore the possibilities ofimproving the targets themselves. Thus cost control ends when targets are achieved while

cost reduction has no visible end. It is a continuous process.

AREAS OF I MMEDI ATE ATTENTI ON

1. Daily Declared OLC for Unit and Station

2. Economics of Unscheduled Interchanges

3. Fixed Cost/ Variable Cost/ Consideration

4. Asset / Reliability Concept/ Availability Monitoring

5. Daily Cost of sectional works, processes/ services

FOCUS ON LONG RANGE PLANN I NG

Flexible Budgeting, Inventory, Purchase policy

Contract Monitoring/ Outsourcing

Pricing Strategy/ Transfer Pricing Concepts

Merit Order Stack Monitoring/ On Line Bidding

Monitoring External Environment & Changes in Internal Environment through SWOT

analysis & Strategic Planning

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COST REDUCTI ON TECHN I QUES

The following are some important cost reduction techniques.

1. Costing & Value Chain Analysis

2. Standardisation, simplification & Quality Control

3. Job study, work study and Motion study

4. Budgetary Control

5. Inventory Control

6. Value Engineering & Learning curve effect

7. Job evaluation and Merit Rating

Cost in g & Va lu e Cha in An a lys is

The first step is to establish Cost Accounting System and standardize the basic routine

functions of cost collection, cost analysis & cost reporting.

The Costing System as being practiced in Generating Stations in MAHAGENCO recognizes

division of power generation activities in any station into different process centers and service

centers. Each process center, which is either u n i t w i se or s t a g e w i se, is further divided into

sub process centers (SPC). Every SPC has number of systems and area wise locations onwhich different operation & maintenance activities are done. The data of cost of manpower

(direct, indirect & idle), material (Raw Materials, Spares & consumables) and contracts deployed

on each of these activities based on defect card raised by Operating staff is collected through

entries in PPMS (Power Plant Monitoring System) software in Works Planning System. PPMS is

designed to give cost statements of every activity and also to arrange the cost components

incurred on every cost centers on daily basis.

Broad D iv is ions in t o Cos t Cent ers & Serv ice Cent ers .

PROCESS CEN TRE SERVI CE CENTRE

0110 Coal Handling Plant 0001 Boiler Maintenance

0210 Raw Water Intake System 0002 Turbine Maintenance

0310 Pre Treatment Plant 0003 CHP (Mech. Maint.)

0410 Soften Water Plant 0004 CHP (Elect. Maint.)

0510 D.M. Plant 0005 Vehicle Maint

0610 Hydrogen Generating Plant 0006 Elect. Maint. (Main Plant)

0710 Milling Plant 0007 Testing

0810 Boiler And Auxiliaries 0008 Instrumentation Control

0910 Fuel Oil Handling Plant 0009 Civil Maintenance

1010 Turbine & Generator 0011 Water Treatment Plant (M)

1110 CW System

1210 Ash Handling Plant

1310 Common Technical Services1410 Township

1510 Administration

The reports in three standard formats from each power station are sent to Head Office to

compile & compare for inter power station analysis. The above Costing System, which is being

practiced in a premature stage, is now to re-mould in expert style for utilisation in competitive

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environment to deal with continuously changing business conditions. A sound management

Information System is the basic need for such re-orientation of Costing System.

It is utmost necessary now to re-examine the Costing System freshly at strategic level

and then for attempts to re-establish the basic process of daily cost accumulations in the

power plant as a main stream of administrative process. The plan for such implementation

needs to be strategically approved by topmost management in MAHAGENCO and responsibility

needs to be assigned to such specially constituted team with cost-benefit impacts of such

implementation as a special project. Following target steps can be considered for such attempts.

1. Preparation of Flow chart for every process & its SPC. Identifying assets in such process

centers and standard systems in each SPC. Calculation of asset for each process center

& service center.

2. Covering all activities through job/ defect card system. Establishing daily routines in all

operation sections for proper defect card entries & daily monitoring of permits issued &

cleared.

3. Establishing of daily routines of work Plan, Job Completion Sheets and Sectional daily

Cost analysis.

4. Establishing entries of important machines running, standby, under permit timings throughPPMS.

5. Establishing Centralised Purchase/ Work Order on line monitoring process through

centralised dispatch information & bills receipt system.

6. Establishing on line inventory/ stores with on line issues against defect cards.

7. Establishing Contract monitoring through daily contract work allotments & on line

monitoring of RA Bills through PPMS.

8. Establishing on line time management system & salary linking to costing tasks.

9. Establishment of On Line daily & periodic Costing System and value chain of primary &

support activities.

10. Making available full Management Information System for decision making at all levels

of management in MAHAGENCO.

St anda r d i sa t i on , s im p l i f i ca t i on & Qua l i t y Con t r o l :

T e c h n i c a l P a r a m e t e r s : Generation, Availability Factor, PLF, Heat Rate, Specific Fuel

Consumption, Auxiliary Consumption, Annual/ Capital Overhaul outages.

Elem ents o f Cost o f Genera t io n : Fixed Cost & Variable cost Contribution, Cost contribution

by Process centers & Service centers, Variance analysis, Standard cost deviations

Sta t ion as a Pro f i t Center : Return on asset, Merit Order Stack Position, ABT performance,

Technical performance, Liquidity Performance

Con t r i bu t i on o f Respons ib i l i t y Cen t e r s i n Va lue Cha in o f P r o f i t Cen t e r :

Jo b s t u d y , w o r k s t u d y a n d M o t i o n s t u d y

D e fi n i n g a l l j o b s t h r o u g h W o r k I n s t r u c t i o n s : Creating environment for scientific analysis

of job, Time bound review till satisfactory yield is ensured from job methods.

Cont in uous Process o f Job enr ichm ent : Identifying frequency of failures, Minimising repeat

works, improving work methods, definining jobs with respect to processes/ individual

responsibilities.

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Budge t a r y Con t r o l

Resour ce gap ana ly s is & Cap i ta l Budget ing exer c ise : Identifying resource requirement,

resource allocation & measures to bridge resource gap at sub section/ section level, Comparative

study of in-house means & outsourcing avenues.

Fixed v . Flex ib le Bud gets : Continuous review of budget in changing environmental aspects,

linking with Long Range Planning.

Scien t i f i c Dec is ion Techn i ques : Use of statistical models, standardizing decision-making

process,Study of impact of decision.

Budge t Con t r o l Or gan isa t i on : Establishment of continuous budget monitoring exercise

and internal audit features.

I n v e n t o r y Co n t r o l

Es t ab l i sh ing On L ine Pu r chases , I nven t o r y & Aud i t t r a i l : Complete on line & totally

computerized system of purchase activi

Documents

Condenser & Feed water heaters