Session03_PET-02.Mentainance and Management

7/29/2019 Session03_PET-02.Mentainance and Management

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Power Engineering and Training Services, Inc. (PET)

2011 Climate Change Action Clean Coal Technology International

Cooperation Project CCT Transfer Project Dispatch Technology

Interaction (USC Coal-fired Power Plant Operation Technology)

Power Plant O&M Technology

(Efficiency Maintenance and Management)



Copyright© Power Engineering and Training Services Co.,Inc. All rights reserved.

2Table of contents

Sheet No.

1. Thermal efficiency of fossil-fueled power stations 4～ 12

in Japanese electric power utilities (SC&USC power plants)

2. Efficiency management (Coal-fired boilers) 14～ 17

3. Factors causing the losses of boiler and turbine 19～ 24



1. Thermal efficiency of fossil-fueled power

stations in Japanese electric power utilities

(SC&USC power plants)




4Shifts in thermal efficiency (Gross & Net) of fossil-fueled power stations

in Japan

Note: By the fiscal year of 1975, nine electric power companies are included.

Shifts in thermal efficiency (including ten electric power companies)

17.21

22.23

29.8

18.86

24

31.89

41.3541.0141.0940.940.941.084140.7740.59

3938.7838.2138.0838.0337.7537.11 39.6939.4539.439.2139.2139.4239.3339.0538.87

37.2137.0536.3136.2536.39

34.74

35.93

10

15

20

25

30

35

40

45

1951 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2001 2002 2003 2004 2005 2006 2007 2008

T h e r m a l e f f i c i e n c y （％）

GrossNet

In the fiscal year of 1951 in J apan, the (gross) thermal efficiency was about 18% at thefossil-fueled power stations. However, from then on, we built new power stations andadded new generating units to the existing ones. Old facilities were replaced by new ones.Moreover, we made efforts to improve operation technology and to implement thorough

maintenance. As a result, thermal efficiency had been greatly improved.

※ Thermal efficiency refers to how much energy is effectively produced out of thethermal energy input. In the case of the fossil-fueled power generation, it indicates thegenerated electricity in terms of the thermal energy of the fuel consumed. In other words,when thermal efficiency of a fossil-fueled power station grows, its fuel consumption will bereduced because that amount of energy has been used effectively. In this way, fuel costwill thus drop.

From the late 1960s, environmental protection had become a must. In response,electrostatic precipitators were installed. As a countermeasure against SOx, flue gasdesulfurization (FGD) equipment had been adopted. To control NOx, efforts had beenmade to improve low-NOx combustion process and develop low-NOx burner. In addition,we also started to adopt SCR equipment.

The fossil-fueled power stations we constructed in J apan from the 1970s were eithersupercritical (SC) or ultra-supercritical (USC) power generating plants.

The first supercritical boiler we set up in J apan was the No.1 unit of Anegasaki PowerStation owned by The Tokyo Electric Power Company, Incorporated (TEPCO). Itsgenerator output is 600MW. It started commercial operation in December 1967. Thisboiler is a supercritical constant pressure once-through model. Its steam pressure is24.1MPa and steam temperature is 538℃/566℃ (degrees Celsius). The boiler was fueledby heavy oil. From then on, supercritical pressure once-through boiler had taken root inthe power generating units of 500MW or bigger. Since the 1970s, the capacity per unitgrew even bigger. In September 1974, the No.5 unit of Kashima Power Station owned by The Tokyo Electric Power Co., Inc. (TEPCO) started commercial operation. It is fueled byheavy oil and its capacity is 1,000MW.




5Cumulative installed capacity of newly-built power stations by fuel

type (SC & USC power plants)

ＵＳＣ累計

各年度火原協「火力原子力発電誌」火力発電設備表を参考に作成

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

1 9 6 0 年1 月

1 9 7 0 年1 月

1 9 8 0 年1 月

1 9 9 0 年1 月

2 0 0 0 年1 月

2 0 1 0 年1 月

2 0 2 0 年1 月

新設発電設備容量

( M W ) 石炭

三隅1号 1,000MW

新小野田1号 500MW

重原油

ガス

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

1 9 6 0

1 9 7 0

1 9 8 0

1 9 9 0

2 0 0 0

2 0 1 0

2 0 2 0

I n s t a l l e d c a p a c i t y o f n e w l y - b u i l t g e n e r a t i n g u n i t s

( M W )

Coal

Misumi Unit 1-1,000MW

Shin-Onoda Unit 1-500MW

Heavy oil

Gas

USC in total

References: “Tables of Thermal Power Gene rating Units” in the

Journal The Thermal and Nuclear Power of each fiscal year edited by

Japan’s Thermal and Nuclear Power Engineering Society (TENPES).

This graph shows the installed capacity of the newly-built generating units owned by J apanese electric power companies. The capacity is categorized by the fuel type.

From 1970 through 1990, the power plants fueled by heavy oil and gas had beenconstructed. However, from the late 1980s, coal-fired power plants became themainstream. In particular, most of the power plants constructed after 1990 were coal-firedones of USC.

For your information, The Chugoku Electric Power Co., Inc. (CEPCO) completed theconstruction of Unit One of Shin-Onoda Power Station in 1986. It is a supercritical (SC)unit with a capacity of 500MW. Its steam pressure is 24.1MPa and the temperature is538/566 degrees Celsius (℃). In 1998, The Chugoku Electric Power Co., Inc. (CEPCO)completed the construction of the No.1 unit of Misumi Power Station. This is a 1,000MWUSC plant. The steam pressure is 24.5MPa and its steam temperature is 600/600degrees Celsius (℃).

Misumi Power Station was the first 1,000MW class power plant in J apan which steamtemperature reached 600/600 degrees Celsius (℃). So far, it has been operated smoothlyever since the start of commercial operation.

Presently in J apan, more than half of the coal-fired power plants are USC plants. We cansay the in the field of USC power generation, J apan is one of the front runners in theworld.




6

USC

69%

SC

31%

Composition of installed capacity of newly-built SC & USC power

stations by fuel type

Proportion of capacity of newly-built power

stations by fuel type

Proportion of USC coal-

fired power stations

Gas

24%

Heavy oil

38%Coal

38%

References: “Tables of Thermal Power Ge nerating Units” in the



The graph on this slide shows the proportion of the installed capacity of supercritical (SC) and ultra-supercritical (USC) pressure generating plants that were built in J apan in the past few years. Theplants include those presently under construction and the capacity is classified according to the

type of the fuel. The power plants fueled by coal and heavy oil consist of 38% of the installed capacity. Besides,gas-fired plants are 24% of the total.

From the late 1970s, new gas-fired power plants continued to be constructed. However, since thelate 1990s, for the purpose of achieving higher efficiency, GT/ST combined cycle plants becamedominant instead. These plants are not included in SC and USC units because the steam pressureat the inlet of steam turbine is not a supercritical one. For this reason, the capacity percentage of the gas-fired power plants has thus become lower.




7Changes in capacity of newly-built SC & USC generating units in coal-

fired power stations

SC,USCプラント

References: “Tables of Thermal Power Gene rating Units” in the



0

200

400

600

800

1000

1200

1 9 5 0

1 9 6 0

1 9 7 0

1 9 8 0

1 9 9 0

2 0 0 0

2 0 1 0

2 0 2 0

G e n e r a t o r o u t p u t ( M W )

SC & USC plants

Prior to 1981, only the maximum unit capacities of subcritical

generating plants at the time of construction are indicated here.

This diagram here shows the changes in capacity of the coal-fired power stationsthat had been built in J apan in recent years.

Since the late 1980s, the supercritical (SC) and ultra-supercritical (USC) generatingplants have become the mainstream in J apan. At the same time, the capacity perunit has also been increased. In particular, more 1,000MW class units have beenconstructed. One reason for that is the fact that there was few land area for plantconstruction. Another reason is for the purpose of reducing construction cost.

Presently in J apan, the power generating plant with the biggest capacity is TachibanawanPower Station of Electric Power Development Co., Ltd. (J -Power). Ithas two units, Unit One and Unit Two. Each unit equally has a capacity of 1,050MW.




8Increase in main steam pressure of coal-fired power stations

SC,USC（＞24.1MPa）

1981年以降のプラントは，SC,USC

各年度火原協「火力原子力発電誌」火力発電設備表を参考に作成

15.0

17.0

19.0

21.0

23.0

25.0

27.0

1 9 5 0

1 9 6 0

1 9 7 0

1 9 8 0

1 9 9 0

2 0 0 0

2 0 1 0

2 0 2 0

M

a i n s t e a m p r e s s u r e ( M P a )

SC&USC（＞24.1MPa）

After 1981, SC&USC plants




This figure shows how the main steam pressure has been increased in the coal-fired power

plants that were constructed in the previous years in J apan.

All the power plants that were built after 1981 are SC and USC ones, which main steampressure is at 24.1MPa or higher.




9Increase in main steam temperature of coal-fired power stations

530

540

550

560

570

580

590

600

610620

630

1 9 5 0

年1 月

1 9 6 0

年1 月

1 9 7 0

年1 月

1 9 8 0

年1 月

1 9 9 0

年1 月

2 0 0 0

年1 月

2 0 1 0

年1 月

2 0 2 0

年1 月

主蒸気温度

( ℃ ) Presently, 593-600℃ is mainstream.

M a i n s t e a m t e m p e r a t u r e ( ℃ )




The figure on this slide shows the changes in main steam temperature of the coal-fired power

plants that were constructed in J apan in the past few years.

Until the 1990s, the main steam temperature had been either 538 degrees Celsius (℃) or566℃ (1,050°F). However, in 1997, 593℃ (1,100°F) was adopted for the first time in J apanat Unit Two of Matsuura Power Station owned by Electric Power Development Co., Ltd. (J -Power). Next year in 1998, 600℃ was applied to Unit One of Misumi Power Station of theChugoku Electric Power Co., Inc. (CEPCO). After that, 600℃ class has become themainstream.




10

530

540

550

560

570

580

590

600

610

620

630

1 9 5 0

年1

月

1 9 6 0

年1

月

1 9 7 0

年1

月

1 9 8 0

年1

月

1 9 9 0

年1

月

2 0 0 0

年1

月

2 0 1 0

年1

月

2 0 2 0

年1

月

再熱蒸気温度

(

℃ )

Increase in reheat steam temperature of coal-fired power stations

Presently, 593-620℃ is mainstream.

R

e h e a t s t e a m t e m p e r a t u r e ( ℃ )




This figure shows how the reheat steam temperature has been changed at the coal-fired

power plants that were constructed in J apan in the past few years.

By the 1990s, the reheat steam temperature had been 566℃(1,050°F). However, in 1993,593℃(1,100°F) was adopted for the first time in J apan at Unit 3 of HekinanPower Station of Chubu Electric Power Co., Inc. Since then, the reheat steam temperature has been furtherincreased continuously. At present, the reheat steam temperature at the newly-built No.2 unitof Isogo Power Station owned by Electric Power Development Co., Ltd. (J -Power) is at 620℃.Currently, it is the highest reheat steam temperature in J apan.

J ust like what I have described in the above, the steam pressure and temperature have beenincreased in J apan year by year. The latest power plant in J apan is the newly-built No.2 unit of

Isogo Power Station owned by Electric Power Development Co., Ltd. (J -Power). Its mainsteam pressure is 25.0MPa and main steam temperature is at 600℃ (degrees Celsius).Meanwhile, its reheat steam temperature reaches 620℃ (degrees Celsius).

So far, J apan has attained the top level of USC technologies in the world through the USCtechnology development as well as the construction and operation of our USC power stations.




11Comparison of Misumi (USC) and Shin-Onoda (SC)

Suppose the subcritical drumboiler (plant efficiency 37%)

as the target for comparison.

The calculation is based on the

coal consumption in this case.

The coal heating value is set at

6,300kcal/kg air dried (AD)

basis.

300,000t per year450,000t per yearReduction of coal

consumption

Design value46.43%48.56%Turbine efficiency

Design value89.61%89.21%Boiler efficiency

Design value41.06%43.0%Plant efficiency

（HHV-based, gross）

Remarks

Shin-Onoda

Power Station

(SC)

Misumi

Power Station

(USC)

Comparison of Misumi (USC, 1,000MW) and Shin-Onoda (SC, 500MW)

The table here on this slide draws a comparison between Misumi Power Station and Shin-Onoda Power Station of the Chugoku Electric Power Co., Inc. Misumi Power Station has one

USC unit and Shin-Onoda Power Station has two supercritical (SC) units.We can see from this table that the boiler efficiency of both power stations is almost the same,but turbine efficiency differs. Consequently, there appears a difference in plant efficiency. Whydoes Misumi Power Station have a better turbine efficiency? Mainly, one reason is that thesteam pressure and temperature are higher at Misumi Power Station. Another reason is thatthe last stage of low-pressure turbine at Misumi Power Station has longer blades by usingcross compound. In the previous chapter, we have mentioned that the capacity factor of Misumi Power Station is more or less higher than that of Shin-Onoda Power Station. The mainreason for this just lies in the difference in plant efficiency.

At the bottom of this table, we list the reduction of coal consumption. At this point, we supposethe subcritical pressure drum boiler (which plant efficiency is 37%) as the target for

comparison. The calculation we made here is based on the coal consumption in this specifiedcase. The coal heating value is set at 6,300kcal/kg air dried (AD) basis.




12Comparison of thermal efficiency (Gross and LHV-based) of fossil-fueled

power plants in different countries of the world

References: ECOFYS, “INTERNATIONAL COMPARISON OF FOSSIL POWER EFFICIENCY AND CO2 INTENSITY”.

Japan

UK France

North Europe

South Korea

Germany

US

Australia

China

India

Note: 1. Thermal efficiency is the weighted averag e gross thermal efficiency (LHV-based) of the generating units fueled by coal, oil, and gas.

2. In the countries other than Japan, thermal efficiency is calculated on the basis of low heating value (LHV). The figures related to Japan

(HHV-based) are converted to LHV-based ones. Even the LHV-based values are about 5-10% higher than those HHV-based ones.

3. The own-use power generation units and t he like are excluded.

(Year)

Th e r m al Ef f i c i e n c y

This diagram compares the gross thermal efficiency of the fossil-fueled power plants indifferent countries all over the world.

The gross thermal efficiency is based on low heating value (LHV). It is a weightedaverage value of different efficiencies of the power plants fueled by coal, oil, and gas.

In J apan, we have both the conventional (steam turbine) US and USC power stations aswell as the combined cycle (Gas Turbine and Steam Turbine) ones fueled by gas. Owingto these power stations, J apan has kept the highest efficiency in the world ever since theyear 1990.



2. Efficiency management

(Coal-fired boilers)




14The necessity of efficiency management

1. Objectives of performance

management business

Confirm performance

values through

performance tests

Find causes

(site/causes)

Reduced

performance Study and

implement

countermeasures

(1) (2) (3)

(4)

(5)

Reflected in repair plans

Performance

recovery

Determine optimum interval in accordance with loss and

inspection costs brought about by reduced performance

X: Number of days until this inspection day since last inspection

ｙ

XX

X: Number of days until check day since last inspection

y: Monetary loss amount until check day brought about by reduced

performance

Y: Monetary loss amount until this inspection day brought about by reduced

performance

Y

Y = k ́ X

Z = 1/2 ´ k ´ X2

Z: Accumulated monetary loss amount caused by reduced performance

Z

Point in time at which accumulated monetary loss amount (Z) caused by reduced performance is

approximately equal to inspection costs.

Economical power station

operation

k: Amount of monetary loss increase per day

Objectives of performance management business at thermal power stations.

(1) When a decrease in plant efficiency occurs, quickly manage the situation and

maintain power station efficiency by seeking the causes of the decrease and then carrying outcountermeasures.

(2) Accurately manage and control the condition of power equipment subject to

aging and increasingly harsh operating conditions, then reflect your findings in the repair plans

and equipment-type inspection cycle for the next periodic inspection.

(3) Promote diversion and operation which will contribute to reducing generation

costs, conserving energy and lessening the impact of global warming issues.

* PowerPoint maintenance plan examples

When the amount of increase in monetary loss due to decreased efficiency ishypothesized to be a linear progression, it is possible to begin thinking aboutinspection periods from an economical point of view (i.e., minimizing the totalmonetary amount of both loss amounts arising from decreased efficiency andinspection expenses).




15Thermal efficiency management methods

n Managing daily efficiency(1) Managing target values

An important method for managing performance is to set targets and then carry outmanagement in accordance with deviation from these targets. This method is known as targetmanagement. Target values, also known as standard values, are values which a device can beexpected to maintain only when it is operating normally and with no malfunctions. These valuesare set in consideration of the results of acceptance tests on setting values at the time of commencement of operation, and are sometimes adjusted in accordance with circumstancesarising during continued operation.

[Example of condenser vacuum target values]Degree of vacuum target values are set by setting upper and lowervalues in accordance with design values (standard curves) from the timeof installation of each unit. The range of upper and lower values is set in consideration of instrumentaccuracy, tube cleanliness factors and variations in actual results.

[Handling aberrations from target values]• When the degree of vacuum is higher than the upper target value,

carry out inspections on the measurement devices associated withthe degree of vacuum.• When the degree of vacuum is lower than the lower target value,investigate the causes and implement countermeasures.

D e gr e e of v a c u um

Seawater temperature

Upper targetvalue

Lower targetvalue

Standardvalue

There are two types of target values: operating condition values such as each

part's temperature and pressure, and performance values such as unit efficiency

and boiler efficiency.It is necessary to compare items whose numerical values are subject to change in

accordance with external conditions by first carrying out corrections such that

these conditions will all be identical.

Because the condenser degree of vacuum varies widely in accordance with

external conditions (cooling water temperature), upper and lower values are set

for the standard curve expressing the relationship between cooling water

temperature and condenser degree of vacuum, and target values are set within the

scope of these upper and lower values.





n Managing daily efficiency(2) Managing control values

Design values, planning values and control values are taken as standards for main steam pressure andtemperature, turbine vibration values and electrical energy output. These standards are then used to

judge whether a plant's current operating status is normal or abnormal.

（3） Trend management

Set management items and evaluate operational status using daily operation records and

performance test results; plot representative items affecting performance (condenser degree of

vacuum, GAH draft loss, etc.) on a daily, semi-weekly and monthly basis, thus managing trends.

Check itemControl values and

check details

Basis for control values

(*indicates remarks)

Electrical energy

output

Max. hourly value：352 MWh

Max. daily value：8,400 MWh

Listed operating requirement values

(Overload value：authorized capacity ´ 1.03)

Must not exceed authorized capacity ´ 24Hr.

Main steam

pressure

17.46MPa (177kg/cm2)

or greater must not exceed

12 hours per year

Rating (16.67Mpa (169k) ´ 1.05)

Gross efficiency (correction value)

Before periodicinspection

After periodicinspection

(Example of control value management records)

The control values for electrical energy output are checked against the basis of

generator output control values approved by the national government.The main steam pressure control value is an example of control values based upon

interval length conditions of periodic utility inspections of boilers.

(Example of trend management records)

Changes in equipment conditions are managed by chronologically graphing data from

operation diaries (journals) and other sources.

While the record example graph reflects gross efficiency (correction value), it was

formed by correcting factors impacting efficiency, such as air temperature and

condenser degree of vacuum, to standard values.





n Regarding performance testingIn order to evaluate, during periodic inspections, the results of countermeasures designed to improve

thermal efficiency and performance, evaluate performance test items (plant thermal efficiency, turbineefficiency, boiler efficiency, etc), and also keep full records for the unit as a whole, thus carrying out pinpointevaluations. Also, take advantage of periodic rated outputfixing to take smoke measurements and other

measurements, thus carrying out simplified performance testing in accordance with the above-mentioneditems.

Performance testing implementation requirements (outline)

• Test implementation period : Implement tests before periodic inspections, after periodic inspectionpreparations or otherwise as needed.

* In order to confirm performance recovery results through periodic inspections.• Test load : Test loads should be carried out by operating equipment at a uniformrated load, or also at partial load as necessary.• Limiting items : Make test conditions uniform, and exercise caution so as not toreduce test accuracy.

(1) For coal units, limit changes to coal types and changes to mixedcombustion ratios while

maintaining a uniform fuel quality.(2) Carry out ash removal from soot blowers and clinker hoppers in advance in order to maintain

normal operation during testing.(3) Fix load before testing and choose a stable time so that the test devices will be at test load

conditions and each section will operate normally and stably (in terms of pressure, temperature,

etc.).(4) Operating conditions [Stabilize operating conditions, and control actions that will lead to outside cs]• Performance calculation : Performance calculation methods (calculation equations) are to be

set forth in a separate requirements manual.

Limiting items (4) Example of operating condition limits

a. The generator outlet is set as the test load standard, and a uniform

load is maintained using a load limiter.b.Generator reactive power must be made as constant as possible.

c. Generator hydrogen pressure must be kept at normal operatingregulation values.

d.Combustion conditions must be kept constant.

* Avoid changes in the degree at which air dampers are opened, aswell as changes to gas O2 settings.

e. The number of auxiliary operating units and their operating conditionsmust be kept constant.

* Avoid periodic replacements of spare equipment, as well as startingtests performed on emergency equipment.

f. In principle, auxiliary steam and general-purpose steam are to bestopped except for what is needed for direct operation.

g.Do not perform blow down for steam, boiler water or feed water.

h. In principle, do not recover soot blowers or Clinker hoppers.



3. Factors causing the losses of boiler and turbine




19Regarding boiler heat loss [Example of drum-type boilers]

Heat loss during random-sampling tests performed on boilers was as shown in the following graph.

0%

20%

40%

60%

80%

100%

90MW 120MW 175MW

Other

Radiation conduction

Unburned carbon

Moisture content of air

Fuel hydrogen content

Dry exhaust gas loss

11.31% 11.14% 11.03%

AA

Regarding boiler heat loss

This graph shows the breakdown of boiler heat loss from the results of acceptance performance tests performed on coal-fired drum-type boilers.

Boiler loss is approximately 11% of boiler fuel ratio.

This graph furthermore reveals that boiler efficiency is only slightly influenced by load

differences.

Loss breakdown reveals that exhaust gas heating value (dry gas and fuel hydrogen content)

loss is at approximately 10%, which makes up a large portion of total loss.

The total of all boiler losses at 175MW is 11.03%.

100 minus 11.03 is 88.97, which is to say that boiler efficiency is approximately 89%.The loss method, then, is the method in which all losses are totaled, or in which efficiency is

calculated in accordance with actual measurements, etc.




20Boiler loss factors and monitoring items

Combustion ash

sensible heat loss

Increased fuel moisture content

and hydrogen content, increased

AH outlet gas temperature

Increased exhaust gas volume (gas O2,

AH leak volume), increased AH outletgas temperature

Increased usage coal ash amount

(depends upon type of coal)

Increased unburned material in

ash, increased unburned gas

Non-control item (response with

thermal insulation repairs)

Non-control item (discrepancies arising

through instrument error, etc.)

5.3%

4.4%

0.08%

0.65%

0.23% (Manufacturer design value)

0.35%

Increased humitidy content, gas

O2 content in air, increased AH

outlet gas temperature

Radiation loss

Other loss

Unburned ash loss

Dry gas loss

Wet gas loss

Loss caused by fuel

moisture content and

hydrogen content

Loss caused by

humidity content in air

used for combustion

This table is a compound display of boiler loss factors as well as monitoring items.

(1) Dry exhaust gas loss

•Dry exhaust gas loss refers to the heat loss caused when dry gas (combustion gas from which water steam has been removed) escapes from the boiler.

• When monitoring dry gas loss, it is necessary to monitor whether exhaust gas amounts (gas O2, AH leak

volumes) are increasing, and also whether the AH outlet gas temperature is rising.

(2) Wet gas loss

There are two kinds of wet gas loss: loss caused by fuel moisture content and hydrogen content, and loss caused

by humidity content in the air during combustion. Of these two, loss caused by humidity content in the air during

combustion is extremely slight. Furthermore, fuel moisture content and hydrogen content both exert a profound

impact upon fuel conditions, with attention being paid to rising AH outlet gas temperature as a monitoring item.

(3) Combustion ash sensible heat loss

While heating value loss is also caused by the ash content of combustion gas allowing heat to escape outside of

the hopper, this loss ratio is extremely slight.(4) Unburned ash loss

There are two kinds of unburned loss: loss caused by combustible content (C) emitted during the combustion of

fuel (solid fuel / liquid fuel), and unburned gas loss arising through the occurrence of unburned fuel byproducts

(CO). Both kinds of loss increase with shortages of air used in combustion, as well as with decreased fuel

qualities.

In general, the concentration of unburned gas within exhaust gas is extremely low during normal operating

conditions, which is to say that this loss ratio is very small.

(5) Radiation loss

Radiation loss is the heat loss due to radiation arising from differences between the temperature of the outside air

and the temperature of the boiler main body and of the surfaces of gas ducts and piping.

(6) Other loss (unmeasured loss)

Other loss (unmeasured loss) refers to losses caused by instrument errors, steam leaks, feed water blow and drain

emissions.




21Countermeasures against factors causing

reductions in boiler efficiency (1)

Increase soot blow frequency

Event Cause Countermeasure

Clean cage parts (horizontal SH, RH,

ECO) with water

Furnace heating surface taint

Increased excess air factor Regulate optimal air amount

Carry out pipe inspections

(chemical cleaning)

Carry out low-excess-air-firing

operation tests

Repair ru ptures/corrosion in/on the

air preheater

Regulate air amount, adjust dampers

Increased dry

exhaust gas loss

Reduced air preheating

performance

Remove element clogging (wash with water)

Repair wear to seal parts

Scale adhering to the inner surface

of water pipes

Secondary

combustion

Monitor ECO outlet gas

temperature

Dry gas loss is calculated by finding the product of exhaust gas specific heat, dry exhaust gas volume, and the

difference in temperature between AH outlet gas and AH inlet air.

Because it is difficult to conceive that dry exhaust gas specific heat and AH inlet air temperature would change due

to facility problems, dry exhaust gas volume increases, as well as increases in AH outlet gas temperature, are bothmonitored.

1. Factors in increases in dry exhaust gas volumeÞ Countermeasures

(1) Increased excess air factor Þ Regulating optimal air amount, checking for abnormalities in the gas O2analyzer

(If a reading is obtained which is lower than the actual amount of O2)

Carry out a low-excess-air-firing operation test

(2) Leaks from the AHÞ Wear repair of seal parts, usage of AH sensor drive

2. Increases in AH outlet gas temperature

(1) Furnace heating surface taintÞ Increase frequency of soot blow, wash cage part heating panel (horizontal

SH, RH, ECO) with water (2) Reduced AH heat exchange abilityÞ Repair element corrosion/rupture

* Although exhaust gas loss decreases as the temperature of AH outlet gas decreases (which is an extremely

effective way to increase boiler efficiency), it is necessary to make determinations in consideration of AH

element low-temperature corrosion.

(Low-temperature corrosion: Water steam and SO3 in exhaust gases react to form sulfuric acid vapor; when

temperatures are reduced, this vapor condenses (when it reaches the sulfuric acid dew point) and becomes

sulfuric acid mist, which causes corrosion.)

(3) Scale adhering to the inner surface of water pipes⇒ Carry out inspections of the amount of adhered scale,

carry out chemical cleaning

* Scale inhibits heating, because the thermal conductivity of scale is vastly less than that of steel.

(4) Secondary combustion (combustion in the upper portion of the boiler)⇒ Carry out combustion adjustment

(Regulate air amounts, adjust type of dampers)




22Countermeasures against factors causing

reductions in boiler efficiency (2)

Investigate burner tips

Event Cause Countermeasure

Poor combustion

Consider fuel oil injection

pressure and atomizing

Consider pulverized

coal mesh (mill

performance tests)

Increased

unburned matter

Regulate air

amount

Unburned loss increases in tandem with increases in unburned matter in exhaust gases (in

ash).

Factors of increases in unburned matter in exhaust gases (in ash)

Þ Countermeasures

(1) Poor combustion Þ Investigate burner tips (for wear, clogging, etc.)

Þ Regulate air amount

Þ Consider fuel oil injection pressure and atomizing (when

liquid fuels are in use)

Þ Consider pulverized coal mesh (asperity) (reduced

pulverizer performance)




23 Turbine room loss

Moving blade outlet current

velocity loss

Valve throttling loss, steampassageway loss

Bearing loss, oil pump power

consumption

Gland steam leak loss

Friction between steam and blade, flow

delamination and disruption

Nozzle labyrinth, tip leak loss

Steam's velocity energy (Steam's

velocity energy is dynamic en ergy at

the final l ow-pressure exhaust stage,

and cannot be recovered)

Flow in the direction of steam

circumferential direction, friction

against inner and outer peripheral wall

Wet steam (water droplets)

impacting moving blades

Draft loss on surface of wh eel

Internal stage

loss

Exhaust loss

External leak loss

Valve and plumbingpressure loss

Mechanical loss

Approximately 67%

of internal loss

Approximately36% of internal

stage loss

Approximately

20% of internal

stage loss

Approximately 17% of

internal loss

Condenser loss Turbine exhaust potential heat

Total internal

loss: 100% Rotation loss

Secondary flow

loss

Axis / moving blade peak

area leak loss

Wetness loss

Profile loss

Approximately 0.3 to 0.5%

Steam cycle loss

Turbine room loss comprises losses such as internal turbine loss, condenser loss and other external

losses.

This table shows the categorization of internal turbine loss.Internal stage loss (loss occurring within the stage) comprises the greatest portion of internal turbine

loss.

Internal stage loss is comprised of the following types of loss:

(1) Profile loss … Friction between steam and blade (nozzle), flow delamination and disruption

(2) Secondary flow loss … Flow in the direction of steam circumferential direction, friction against

inner and outer peripheral wall

(3) Axis / moving blade peak area leak loss … Nozzle labyrinth, tip leak loss

(4) Wetness loss … Wet steam (water droplets) impacting moving blades

(5) Rotation loss … Draft loss on surface of wheel

Non-stage loss is comprised of exhaust loss, external leak loss, valve and plumbing pressure loss and mechanical loss.

Exhaust loss … Loss caused by moving blade outlet velocity (Steam's velocity energy

is dynamic energy at the final low-pressure exhaust stage, and cannot be

recovered)

* Low-pressure turbine final stage exit steam moves at an extremely high velocity, and thus

cannot be disregarded as a source of loss.

* Residual velocity loss is in inverse proportion to the square of the surface area of the final

low-pressure outlet steam passages.• External leak loss … Loss caused by steam leaking from the gland area.• Valve and plumbing pressure loss … Pressure loss caused by valve throttling, loss caused by

friction along steam passages.• Mechanical loss … Loss caused by bearing friction, loss caused by oil pump power consumption




24Factors in reduced turbine performance

Scale flies from the boiler side and

adheres to moving blades and

stator blades.

• Friction loss increases due to

increased asperity on blade surfaces.• As adhesion progression, blade profile

disintegrates and stage properties

decrease.

Metal rust, etc., flies from the boiler side

and corrodes stator blades (especially in

the first stage)

Corrosion is caused by water droplets in

wet steam striking moving blades

(especially in the final low-pressure

stage).

• Increased asperity on blade surfaces• Blade deformity (increase in

passageway surface area)

Internal efficiency degradation caused

by changes in stage flow rate and

pressure in various areas

Gaps widen due to contact and friction

between static and rotating parts, such

as gland labyrinth, nozzle labyrinth and

tip fin.

• Increased leak loss

Aging deformation of various turbine parts

Heat exchanger heating surface taint

Condenser air leak

Scaling on blades

Blade

corrosion

Widening gaps

Other

• Turbine overhaul inspections are used to remove scales that have adhered to the inside of

the turbine.

Water quality treatment is also important.

In Japan, silica density within steam is controlled to 20ppb for drum-type boilers.

• Moving blade erosion arises when rusted metal scales, etc., are carried over by steam

from the boiler side of the turbine side. Stator blades (high-pressure to medium-pressure

first stage) are particularly susceptible to corrosion; surface hardening treatment is to be

carried out as a countermeasure.

• Gap management is necessary for the seal parts of gland labyrinths and tip fans, etc.

Parts must be replaced which exceed control target values.

Session03_PET-02.Mentainance and Management

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