2 Functional and Operational Control of Thermal Power Plants

I.

2 Functional and Operational Control of Thermal Power Plants 2.1.1 Operation control

Since safe and economical operation is carried out at thermal power stations while carefully checking environmental problems, there are many points that operators must judge to take appropriate measures. Therefore, a large load is applied to operators in case of an emergency.

Therefore, it is necessary to automate emergency manual operations to be taken against faults, as well as to automate normal manual operations in order to minimize operators’ judgments. To keep the final protection of the plant, it is absolutely required to take appropriate measures for the plant facilities.

A unit protection device is installed to protect each unit if a fault occurs in any unit and it becomes difficult to continue safe operation of the unit. This unit protection device is called the “unit trip interlock.” Basically, the unit trip interlock is classified into the boiler protection interlock (MFT), turbine protection interlock (MTS), and generator protection interlock (86G).

These interlock systems may vary depending on the manufacturer’s design. In principle, however, the once-through unit boiler, turbine, and generator are mutually interlocked. Figure 35 shows an example of the trip interlock system. 2.1.1.1 Boiler protection interlock (MFT)

This boiler protection interlock is intended to shut down the fuel supply to stop the boiler if it becomes difficult to continue stable combustion of the boiler. The conditions for tripping of this interlock may vary slightly depending on the type of boiler, that is, whether it is drum boiler or a once-through unit boiler. Generally, these conditions are fuel pressure drop, high furnace pressure, stopping of two ventilating fans, protection of the reheating unit, supply water flow rate drop, and drum level drop. In addition to these conditions, unit emergency stop and turbine/generator trip conditions are interlocked. According to the boiler model, further conditions are interlocked. 2.1.1.2 Turbine protection interlock (MTS)

If it becomes difficult to continue stable operation of the turbine, the solenoid is operated to stop the turbine. The conditions for tripping of this interlock are turbine overspeed, thrust error, bearing hydraulic pressure drop, and degree of vacuum drop, etc. In addition to these conditions, the unit emergency stop, turbine manual stop, and generator trip conditions are interlocked.

Basic interlock circuit

Problem on generator side

Problem on turbine side

Generator trip

Turbine trip

Fire extinguishing of boiler

A ty

pe

Description If a problem occurs on the

turbine side and the turbine is tripped (each turbine valve is opened), the generator and boiler are stopped conditionally. This system is that the T-G and T-B are not tripped if the conditions are not satisfied. This system is mainly used for

units designed by Ebasco.

A-type interlock circuit



Problem on boiler side

Generator trip

Turbine trip


Any of the thrust, hydraulic pressure, or exhaust speed is faulty.

Conditions for protection of the reheater

Description If a problem occurs on the

turbine side and the turbine is tripped (each turbine valve is opened), the generator and boiler are stopped immediately. In this group, a circuit to

immediately extinguish fire in the boiler if a problem occurs on the generator side is added.

B-type interlock circuit




Generator trip

Turbine trip


Description If a problem occurs in any of the

boiler, turbine, or generator, mutual interlock is activated to trip the unit completely. This interlock where the turbine

is tripped immediately if a problem occurs in the boiler is a characteristic feature, which cannot be seen in the A type or B type.

C-type interlock circuit




Generator trip

Turbine trip


B ty

pe

C ty

pe


Fig. 35 Examples of trip interlock systems

12

13

2.1.1.3 Generator protection interlock (86G) A status where stable operation of the generator or transformer is difficult is detected by the

protective device or protective relay. After this, the generator is disconnected from the system and the turbine is tripped to stop the generator at the same time. The conditions for detection of the protection are ratio differentiation of the generator, loss of excitation, ratio differentiation of the ground fault or transformer, impulse hydraulic pressure, overexcitation, etc. In addition to these conditions, the high/low frequency of the system and the protection of the bus-bar are interlocked. 2.1.1.4 Protection device tests during operation

The important point during plant operation is that the plant can be stopped safely in case of an emergency. To maintain this safety, it is necessary to periodically check the operation status of various safety prevention apparatus installed for protection of the plant. Table 3 shows examples of the protection device tests.

Table 3 Examples of protection device tests Inspection test item Frequency Contents of test

Valve tests (1) Main steam stop valve

Twice/week

The valves are manually opened or closed one by one from the central control room to check the valve operation and open/closed indication lamp operation.

(2) Intercept valve, reheated steam stop valve, combined reheat valve

Twice/week The valves of each system are manually opened or closed from the central control room to check the valve operation and open/closed indication lamp operation.

Protection device tests (1) Lock-out

(Oil trip)

Once/week

After the operation of the emergency shutdown device has been removed, the test handle is operated to check the operation of the oil trip mechanism.

(2) Thrust failure protection trip Once/week After the operation of the thrust failure protection device has been removed, the test handle is operated to check the operation of the thrust bearing wear trip mechanism.

Extraction check valve test Twice/week Valves are manually opened or closed with the test handle or switch to check the valve operation and open/closed indication lamp operation.

Oil pump automatic starting test Once/week The hydraulic pressure is decreased using the testing equipment in the simulated mode to check the automatic startup at the set hydraulic pressure levels of the auxiliary oil pump, emergency oil pump, and turning oil pump.

Main turbine

Main oil tank oil level alarm test Once/week The indication rod of the oil gauge is moved up or down to check the alarm operation.

Valve test Once/week The high-pressure and low-pressure steam stop valves are opened or closed manually to check the operation of the valve and open/close unit.

Protection device tests (1) Overspeed trip

Once/month

After the trip circuit has been removed, the RPM is increased in the simulated mode to check the overspeed trip set hydraulic pressure level.

(2) Bearing hydraulic pressure drop trip

Once/month After the trip circuit has been removed, the bearing oil pressure is decreased in the simulated mode to check the trip set hydraulic pressure level.

(3) Thrust failure protection trip Once/month After the trip circuit has been removed, the thrust position is moved in the simulated mode to check the trip set hydraulic pressure level.

Oil pump auto starting test Once/month The hydraulic pressure is decreased using the testing equipment in the simulated mode to check the automatic startup at the set hydraulic pressure levels of the extra main oil pump and emergency oil pump.

Turbine driven feed pump

Spare feed water pump (motor drive) starting test

Once/month The pump is manually started at the work site, and a load is applied to check the operation of the auxiliary oil pump and minimum flow recirculating valve.

Emergency pump automatic starting test (Seal oil discharge pressure, low differential pressure alarm test)

Once/week The discharge pressure and differential pressure of the seal oil are decreased using the testing equipment in the simulated mode to check the alarm operation and auto startup at the set hydraulic pressure level.

Seal oil equipment

Vacuum drop alarm test of vacuum tank

Once/month The vacuum level is decreased using the testing equipment in the simulated mode to check the alarm operation.

I.

14

2.1.2 Boiler operation control during normal operation It must be strongly attempted to find the error status early and to prevent problems during

normal unit operation in order to maintain stable operation status. The actions to be actually taken are basically classified into the inspection at the work field, and the sampling and evaluation of the operation records. It is important to take these actions daily in order to check status change in the early phase, and this leads to appropriate actions and measures being taken in a timely manner. 2.1.2.1 Inspection at the work field

As a rule, the inspection interval must be every work shift. Walkaround inspection of the boiler main unit parts and boiler auxiliary devices is carried out. The inspection results must be kept. If any problem symptom is observed, it is necessary to grasp any status change as time elapses.

Generally, walkaround inspection is carried out according to the checklist. In addition to this inspection, further inspection points, such as unusual noise, unusual odor, or discoloration must also be inspected.

The combustion status inside the furnace must also be checked during walkaround inspection. However, if the type of coal to be used is changed, the inspection must be carried out with special attention.

One of the points to inspect the status of clinker and ash sticking to each heat transfer surface inside the furnace is to check whether or not excessive development or accumulation exists. The other point is that the contamination status of each heat transfer surface is checked with the secular change in the operation data stated on the next page to appropriately operate the soot blower or wall deslagger. When the type of coal to be used is changed, these points become particularly important. 2.1.2.2 Sampling and evaluation of operation records

To grasp the secular change in the boiler static characteristics and to evaluate performance, records of the boiler operated at its rated output are sampled periodically.

In daily operation, it is basically checked whether or not the balance among the feed water flow rate, fuel flow rate, and air flow rate is correct.

As deviation of the boiler input command to the output command and deviation of the water/fuel ratio and air/fuel ratio are checked, it is possible to judge whether or not the balance is correct.

Additionally, it must be strongly attempted to check changes in the make-up water quantity in order to find any boiler tube leak in the early phase.

In the coal-fired boiler, the characteristics of the boiler may change greatly according to the coal properties. The heat absorption distribution of the furnace, SH, and RH is changed according to the combustibility of the coal or slagging/fouling ability. According to the contamination degree of the heat transfer surface, the exhaust gas temperature increases and it adversely affects the boiler efficiency. Therefore, the heat absorption status of each heat transfer surface is grasped by checking the following points.

Changes in control parameters using the RH temperature control or SH temperature control Changes in the gas temperature of each part of the rear gas duct including the gas temperature at the

outlet of the ECO. The soot blower and wall deslagger can be operated at efficient intervals. Since changes in coal properties may affect the characteristics of the exhaust gas (NOx, unburned matter in ash,

etc.), it is necessary to grasp the characteristics if the type of coal to be used is changed. If an imbalance occurs in the metal temperature distribution of each part of the furnace, SH, and RH or in the

steam temperature distribution of each part of the SH and RH, it is thought that changes in combustion status may be the cause. Therefore, it is necessary to check the damper opening of the wind box at the work field.

Since an increase in the AH differential pressure may greatly affect the drive power of the ventilating equipment or the operation tolerance, it is important to grasp the secular change. Normally, the AH soot blower is operated at intervals of work shifts (three times/day). If the AH differential pressure increases, appropriate measures to shorten the interval are taken.

15

If the AH differential pressure becomes excessively large (normally, the reference level is the planned value multiplied by “1.5”) or if the ventilating equipment capacity reaches its limit, it must be investigated whether to water wash the AH.

For the pressure loss of the water and steam systems (particularly pressure loss of the furnace), the increased speed caused by the secular change is grasped and it is used as a factor to judge the chemical washing timing, etc. 2.1.2.3 Others

It is important to strictly control the water quality during boiler operation including startup according to the standard for water treatment. 2.1.3 Auxiliary units of the boiler

Generally, the auxiliary units of the boiler are the feed water, ventilation, and fuel systems. This section describes the ventilating equipment, air preheater, and coal pulverizer of the coal-fired boiler plant. 2.1.3.1 Ventilating equipment

In the coal-fired boiler, a balanced air ventilation system is generally utilized to achieve the following purposes.

1) The furnace pressure is maintained at a constant level to maintain combustion stability. 2) The furnace pressure is maintained at atmospheric pressure or lower in order to prevent coal ash from leaking

outside. A centrifugal type or an axial flow type ventilating equipment (fan) is utilized. The control

system of the centrifugal ventilating equipment is the inlet damper control, inlet vane control, RPM control, or a combination of them. The control system of the axial-flow ventilating equipment is the moving blade variable control, inlet vane control, RPM control, etc. With these controls, the process values for an object are controlled. The following lists up cautions operation.

Axial flow type: According to the characteristics of the ventilating equipment, there is a surging area. If the operation point enters this surging area, the pressure and gas volume are changed rapidly accompanied by vibration, causing damage to the unit.

Centrifugal type: There is no clear operation impossible area as described for the axial flow type. However, the operation may become unstable in a low-load area, causing vibration or noise of the duct.

(1) Induced draft fan (IDF) This fan is intended to keep the furnace pressure at a constant level of atmospheric pressure or lower. To

prevent wear caused by coal ash, a dust removal equipment (EP, etc.) is installed downstream. Basically, the PID control is used to control the furnace pressure. In many induced draft fans, the air flow rate signal is used as an advance signal.

(2) Forced draft fan (FDF) This fan is intended to feed the combustion air (secondary air) to the boiler. The air flow rate for

combustion is controlled by the combustion volume command from the boiler control unit and the correction signal from the O2 control of the exhaust gas at the outlet of the boiler. When two systems, that is, the ventilation system and air pre-heater, are installed in the boiler, the IDF is

interlocked with the FDF in the same system. There are many examples where the other fans are also stopped if one fan is stopped. This interlock is intended to prevent overheating of the gas temperature at the outlet of the air pre-heater

and decreasing in the air temperature at the outlet since an imbalance occurs between the air volume and gas volume passing through the air pre-heater if the IDF or FDF is stopped.

(3) Primary air fan (PAF) This fan is intended to feed the air (primary air) used to transfer the coal from the coal-pulverizing

machine to the burner.

I.

Fig. 9 Cold primary air system Fig. 10 Hot primary air system

Boiler Boiler

Gas

Secondary air

MillPrimary air Mill

Moving vane auto operation command of B-induction fan

A-air pre-heater startup

B-air pre-heater startup

Moving vane of A-induction fan fully

closed

A-induction fan startup

Auto operation of moving vane of A-induction fan


closed

Moving vane auto operation command of A-induction fan

A-forced draft fan startup

Auto operation of moving vane of

A-forced draft fan

Moving vane of B-induction fan fully

closed

Moving vane auto operation command of A-forced draft fan

B-induction fan startup

60s 60s

A

MB

Mopof

B-forced draft fan startup

A

B

60s

Fig. 11 Exampl


closed

A-induction fan stop

A-forced draft fan stop

30s

Moving vane of A-forced draft fan

fully closed

Fig. 12 Examp

The primary air also has the purpose oloaded into the coal-pulverizing machincoal.

The primary air temperature at the infan installation places and the number different from those of the hot primary a

In the cold primary air system, one pre-heater regardless of the number of cthe primary air duct pressure. On the to one coal-pulverizing machine is instal

oving vane auto eration command B-forced draft fan

Ventilation system startup completion

uto operation of moving vane of -forced draft fan

uto operation ofmoving vane of B-induction fan

oving vane of -forced draft fan

fully closed

16

e of ventilation system startup sequence

Moving vane of B-induction fan fully

closed

Moving vane of B-forced draft fan

fully closed

B-induction fan stop

Ventilation system stop completion

B-forced draft fan stop

le of ventilation system stop sequence

f drying raw coal to allow easy pulverizing of raw coal to be e in addition to the purpose of transferring the pulverized

let of the coal-pulverizing machine is 180°C to 250°C. The of fans to be installed in the cold primary air system are ir system. or two fans are installed on the upstream side of the air oal-pulverizing machines. This fan is intended to control other hand, in the hot primary air system, one fan specific led on the downstream side of the air pre-heater. This fan

is intended to control the primary air flow rate. Figures 9 and 10 show an outline of each system. Additionally, Figs. 11 and 12 show examples of

the startup sequence and stop sequence of the ventilation system, respectively. 2.1.3.2 Air pre-heater (GAH)

This air pre-heater is intended to increase the combustion air temperature and to collect the heat of the exhaust gas at the outlet of the boiler. Generally, a regeneration-type air pre-heater is utilized where hot gas and air are alternately made to contact the heat transfer materials called “elements” to exchange the heat. There are two kinds of systems available: the Ljungstrom system in which the elements are rotated, and the Rothemuhle system in which the elements are fixed and an air duct called a “hood” is rotated. Figures 13 and 14 each show GAH, respectively. Normally, the GAH is separated into two sections, that is, the hot gas-passing section and the combustion air-passing section. In the coal-burning boiler with the cold primary air system, the air side is separated into the primary and secondary sections. The following describes cautions on operation of the regeneration-type air pre-heater.

1) Air leak

Center section on

high-temperature side

17In the regenerative air pre-heater, air leaking to the gas side cannot be avoided due to its structure.

Fig.13 Example of Ljungstrom-type GAH

Fig. 14 Example of Rothemuhle-type GHA

Sector plate on high-temperature side Primary air outletGas inlet Guide bearing Secondary air outlet

Lubricant circulation unitSoot blower on

high-temperature side Sensor drive unit

Rotor drive unit

Heating element

Soot blower on low-temperature side

Main pedestal

Side pedestal

Connecting duct

Rotor

Pin rack Gas outlet

Center section on low-temperature side

Rotor post Secondary air inletPrimary air

inletSupport bearing

Secondary air outlet

Gas inlet Primary air outlet

Collar seal

Soot blower Primary air hood

Sealing frame Secondary air hood

Stator Hood drive unit

Heat transfer surface Pin rack Main shaft

Secondary gas outlet

Primary gas outlet

Primary air inlet

Secondary air inlet

Rotation unit

I.

18

lement diameter also becomes large. Additionally,

ssively narrow, the seal mechanism may make

2) -temperature part of the element decreases to a level close to the sulfuric acid

3) terials (used cables at the factory, wood chips, soot including unburned matter, etc.)

ntion should be taken since past cases also occurred while these two timings.

ment. .

ures if a fire occurs in the GAH.

2.1.3.3 Coal-pulverizer (Mill) igned to pulverize coal to a fine particle size diameter necessary to burn

it

r m

al mills. The mill is composed of a duct, damper, pr

olume is adjusted by changing the feed coal volume to be loaded into th

cycle, after the temperature inside the mill has been lowered, the coal feed is

Therefore, it is required to adjust the seal appropriately. Recently, as the capacity of the unit becomes large, the ethe thermal deformation volume becomes large. The leak volume cannot be suppressed by the fixed seal. Therefore, an automatic seal adjustment unit is installed. If the air leak volume is too large, it’s necessary to be cautious that the FDF, PAF, and IDF are overloaded. Additionally, if the gap of the seal mechanism is made excecontacts, causing current value hunting or overload of the GAH motor. GAH differential pressure If the temperature at the lowdew point, ash and SO3 chemical compounds are accumulated and the element is blocked. Additionally, as the operation time elapses, the GAH differential pressure increases. It is difficult to remove the ash andSO3 chemical compounds by the soot blow. Therefore, water washing is needed. It is very important to always keep the temperature of the low-temperature part over appropriate temperature level or more. (The temperature is controlled by the steam type air pre-heater.) Fire of GAH element If any combustible maexist on the GAH element, a fire may occur due to the oxygen concentration and atmospheric temperature. The risk of fire is the highest when a boiler with high oxygen concentration is started up or during boiler banking. Great atteThe following describes fire prevention measures. 1) No combustible materials shall be put on the ele2) The element shall always be kept clean by the soot blowAdditionally, it is also important to establish operation proced

This coal-pulverizer is des by the burner. Generally, this machine is called “mill.” In the coal-burning boiler, this mill is

one of the important auxiliary units that greatly affect the operation characteristics of the plant. The mill is classified into two types of the coal-pulverizing method, that is, the vertical mill (rolleill, etc.) and the horizontal mill (tube mill, etc.). Figures15 and 16 show overall diagrams of typicimary air chamber, seal unit, pulverizing unit, separator, pyrite emission unit, and pulverized

fuel pipe. In any mill, raw coal is dried, pulverized, coarse grain is separated, and transferred continuously inside the mill.

Generally, the combustion ve mill in the vertical mill. Additionally, the combustion volume is controlled by changing the

primary air flow rate passing through the mill in the horizontal mill. In the horizontal mill, the feed coal volume is controlled to keep the coal seam level inside the mill drum at a constant level.

The following describes cautions on operation. 1) Remaining coal stop

In the normal mill stopstopped and the coal remaining inside the mill is purged in that order.

19

Pulverized coal outletCoal feed port

Motor for rotary classifier

Rotary classifierHousing

Reject chute

Coal feed pipe Roller pressurizing unit

Roller

Table segment

Primary air port

Table

Primary air inlet

Motor

Speed reducer

Fig. 15 Example of vertical mill (Roller mill)

Fig. 16 Example of horizontal mill (Tube mill)

If the mill is stopped in case of an emergency, the above steps cannot be performed correctly. Pulverized coal and raw coal exist inside the mill in relatively high-temperature status. Therefore, great caution shall be taken since nature conservation or mill explosion may occur. This risk increases as the volatile components included in the raw coal are large. To prevent a fire inside the mill or to extinguish a fire, inert gas (inert steam) injection equipment or fire-extinguishing water injection equipment are often installed. It is necessary to establish procedures if the mill is stopped in case of an emergency.

2) Mill motor overload When using coal (coal with low HGI) with poor grindability in the roller mill, the mill motor may be

Primary air inletPulverized fuel pipe

Coal feed pipe

Pulverized fuel pipe

Coal feed pipe Pulverized

coal outlet

Coarse grain separator

Motor

Mill drum

I.

overloaded. In this case, the coal feed volume needs to be limited. 3) Temperature at mill outlet

If surface moisture of raw coal that is stored in an outdoor coal yard is high due to rain or other factors, raw coal drying, pulverizing, and transfering processes are not performed smoothly. As a result, an accident occurs which the inside of the mill is filled with coal. This phenomenon occurs if the mill differential pressure increases. (In the tube mill, the current value of the mill motor is lowered.) In the initial indication, it is shown that the temperature at the mill output is decreased. If the temperature at the mill output decreases excessively and it cannot be maintained, appropriate measures are needed to limit to the coal feed volume.

4) A/C The weight ratio of the primary air volume that is the air for transfer of the pulverized coal to the pulverized coal volume is called “A/C (Air/Coal).” Generally, the mill is operated at an A/C range of approximately 1.8 to 3.0. If the A/C becomes high (the concentration of the pulverized coal is thin), the naturalness of the pulverized coal is lost, causing an accidental fire. Recently, a burner that allows stable combustion even though the A/C is high is put into practice. However, if the A/C becomes high when using a burner other than such a burner, it is necessary to perform combustion aid using the pilot ignition burner.

5) Flow velocity inside the pulverized coal pipe The flow velocity inside the pulverized coal pipe from the mill to the burner shall satisfy the following conditions. 1. This flow velocity shall be the flame propagation velocity. (The flame propagation velocity is

determined by the A/C and the volatile components included in the coal.) 2. This flow velocity shall be faster than the level at which pulverized coal is not subsided or accumulated

inside the pipe. 3. This flow velocity shall be slower than the level at which the inside of the pipe wears out.

Therefore, a velocity ranging from 18 to 30 m/s is generally used. The flow velocity inside the pipe is almost determined by the primary air flow rate. However, the primary air flow rate shall not be excessively decreased.

20

Pilot ignition burner ignition

Cool air damper open Hot air damper closed

All mill outlet dampers open/Mill seal air damper open Primary air shut-off/Regulation damper open

Mill warning Seal differential pressure/Primary air volume/Waiting for mill

temperature conditions satisfied

Mill motor startup

Coal supply volume above specified value

Coal feeder startup Mill outlet

temperature above specified value

Initial coal feed completion

Pilot ignition burner fire-extinguishing command

Lubricant unit startup Rotary classifier startup Roller pressurizing unit

startup Coal gate open

Mill system startup

Mill system startup conditions satisfied

Auto operation of coal feeder SS

Mill stop coal feed volume

Pilot ignition burner ignition

Coal gate close/Coal feeder stop

Mill purge

Mill motor/roller pressurizing unit/rotary classifier stop

Primary air shutoff/Regulation damper close All mill outlet dampers close

Mill inlet seal air damper close

Cool air damper open Hot air damper closed

Mill inlet temperature below specified value Mill outlet temperature below specified value

Pilot ignition burner OFF

Mill system stop

Fig. 17 Example of vertical mill startup Fig. 18 Example of vertical mill stop

Since the combustion volume rather than the primary air volume is controlled in the horizontal mill, the auxiliary air damper is opened to keep the minimum flow velocity inside the pipe if the flow velocity decreases.

6) Coal feed volume and coal consumption volume When the mill is operated at a constant load, a relationship is established in which the coal feed volume is equivalent to the coal consumption volume (combustion volume). However, this relationship is not established when the mill is started or stopped or when the mill load varies. Precise grasping of the combustion volume is an essential condition for boiler control. In particular, it is

21

absolutely necessary to control the steam temperature in the once-through boiler. Generally, the combustion volume is measured by the coal supply machine. However, when the mill is started up, the coal supply start does not meet the coal consumption start. In the control system, when the mill is started up or stopped, the simulated coal consumption signal is used as combustion volume in order to adjust the coal consumption close to the coal consumption characteristics suitable for actual conditions. The coal consumption characteristics may vary depending on the type of coal. Changes in steam temperature and exhaust gas O2 may occur when the mill is started up or stopped. Therefore, these points must be taken into consideration.

7) Mill pyrite Rocks or other foreign objects other than the raw coal supplied to the mill are discharged to the outside of the mill without being pulverized. These discharged foreign objects are called “pyrites.” In the horizontal mill, such foreign objects are not discharged to the outside and they are accumulated as materials for pulverizing. In the vertical mill, pyrites are snapped from the primary air port inside the mill to the primary air chamber, and then they are discharged to the outside. If this processing unit malfunctions, pyrites and coal are accumulated in the primary air chamber. As a result, a fire may occur by the hot primary air. Therefore, it is important to check that the pyrite-processing unit functions correctly. According to the circumstances, the mill needs to be stopped. Figures 17 and 18 show examples of the vertical mill startup sequence and stop sequence.

2.2 Power Supply Operations

Electric power demand is not always constant and it varies greatly depending on the season or time zone. Since the daily electric power demand varies as time elapses as shown in the daily load curves stated in Fig. 27,

it is necessary to supply electric power corresponding to the demand that varies every moment. Additionally, since the economy and followingness of each power generation method differ from each other, it

is also necessary to generate electric power with an appropriate combination of power generation methods by taking their features into consideration. When the daily load is classified into the base load, middle load, and peak load, each load is classified into the relevant power generation method as described below.

Pumping-up hydraulic power

Adjustable hydraulic power

Pea

k Pumping-up hydraulic power

(Ele

ctric

pow

er)

Oil fired power(Energy)

Mid

dle

LNG fired power

Bas

e

22

Fig. 27 Example of daily load curves and combination of power generation methods by time zone (1) Base load

Since the variation in load is small and the utilization factor is high, large capacity thermal power, nuclear power, and run-off-river hydraulic power, which can be operated continuously for an extended period of time and has an excellent efficiency, are operated. (2) Middle load

This middle load has intermediate characteristics between the base load and peak load. Since electric energy larger than that of the peak load is required, the middle capacity thermal power, which is relatively economical and has excellent start/stop characteristics, is used. (3) Peak load

Since the load varies greatly in the peak load range, the excellent adjustment capability of electric power generation and frequent start/stop ability are required.

Additionally, it is necessary that the operation time is short and the utilization factor is small. Therefore, even though the efficiency is slightly sacrificed, pondage type hydraulic power or reservoir type

hydraulic power having less construction cost, or pumping-up hydraulic power or gas turbine having excellent peak characteristics can be operated.

The following describes the typical operation method of a thermal power plant during daytime and nighttime. 2.2.1 Output adjustment by load dispatching operation

Since the electric power demand is changed every moment as described previously, it is necessary to supply electric power corresponding to this demand. Since changes in electric power demand cannot be adjusted by hydraulic power alone, it is also necessary to adjust the output using the thermal power generation plant. The operation is performed using the following auto control together with the output adjustment based on the power supply command. (1) Automatic frequency control (AFC)

The system frequency varies due to an unbalance between electric power generation and demand. Therefore, the generator output is adjusted so that the frequency of the electric power system is kept within the specified value. (2) Economical load dispatching control (ELD or EDC)

The load is dispatched so that the general power generation cost for each power generation unit becomes the

(Time)

Run-off-river hydraulic power

Coal fired power

Nuclear power

23

lowest price. 2.2.2 Minimum load operation

As nuclear power generation is used for the base load operation to the daily electric power demand, the minimum load operation of the thermal power plants is conducted to adjust the supply capacity to the electric power demand during daytime and nighttime. Therefore, this minimum load operation becomes important, as well as stop operation during nighttime. In particular, it is required to enable lower minimum load operation of a large capacity plant and to improve the power generation efficiency in a low load area.

The minimum load may vary depending on the fuel, capacity, main machine, and/or auxiliary machines of the plant. However, the minimum load is generally 10 to 40% of the rated output.

The following describes the typical subjects and considerations related to the turbine during minimum load operation. (1) Steam flow rate

If the steam flow rate decreases, a local overheating problem occurs due to an unbalance of the flow rate between the boiler overheating unit and reheater. Therefore, the steam temperature, gas temperature, and evaporation tube wall temperature need to be considered. In the case of a once-through boiler, it is necessary to keep a supply water volume of 25 to 30% or more of the maximum evaporation volume in order to ensure the stable flow inside the evaporation tube constituting the water wall of the furnace. (2) Wetness of turbine exhaust chamber

If the reheating steam temperature drops or the vacuum degree of the condenser increases during low-load operation, the wetness of the exhaust chamber may increase. Since this wetness may corrode the vane in the final stage of the low-pressure turbine, it is absolutely necessary to conduct the operation by taking the wetness into consideration. (3) Temperature of turbine exhaust chamber

The vacuum degree of the condenser tends to be high during low-load operation. This may cause the temperature of the exhaust chamber to lower and adversely affect the vibration and differential expansion. Furthermore, the steam flow rate may decrease at an extremely low output ranging from 5 to 10% of the rated output. Therefore, the temperature of the turbine exhaust chamber may increase due to windage loss. Generally, to prevent this problem, the water is continuously sprayed into the exhaust chamber to decrease the temperature.

However, the continuous water spray may corrode the vane at the final stage. Therefore, great care should be taken for this point. (4) Drain control of feed water heater

The drain from the feed water heater must be collected to the feed water heater at the lower stage as much as possible in order to improve the thermal efficiency. Therefore, the pressure inside the feed water heater decreases in the low-load operation area and the pressure difference inside each feed water heater decreases. If the pressure difference inside the unit among the feed water heaters decreases, it becomes difficult to discharge the drain to the feed water heater at the lower stage. To prevent such a problem, great care should be taken, such as switching of the collection destination to the condenser, etc. (5) Control of boiler feed water pump

Since the supply water flow rate decreases during low load operation, the discharge flow rate of the boiler feed water pump also decreases. If the supply water flow rate of the boiler becomes less than the re-circulation flow rate of the pump, the operation enters a status whereby the minimum flow rate of the pump is maintained by the re-circulation control valve. Therefore, great care should be taken since the control valve is damaged if the pump is operated for an extended period of time in the above status. Additionally, when using the turbine driven feed water pump, great care should be exerted so that the pump is not operated at a speed close to its critical speed. 2.2.3 Leading power factor operation

In recent power systems, as the capacity of the extra-high voltage power transmission line or power transmission line increases and the difference in generated power during daytime greatly differs from that during nighttime, the leading power factor operation of the reactive power control is conducted so that the operation is performed by changing the tap of the inductive phase modifying equipment (reactor or synchronous phase modifier) or by operating the synchronous generator using the advancing power factor.

The leading power factor operation of the generator means that the field current of the generator decreases by utilizing the characteristics of the synchronous machine and the operation is performed using the advancing power factor to absorb the reactive power of the power system. The following describes the problems and notes when

performing the leading power factor operation of the generator. (1) Stability drop due to low excitation

When the leading power factor operation is performed, the internal induced voltage becomes small. As a result, the internal phase angle increases and synchronizing power decreases, causing the stability to lower.

The stability is determined by the terminal voltage and reactance of the generator, as well as the external impedance. Therefore, when performing the leading power factor operation, it is necessary that the under excitation limit (UEL) of the automatic voltage regulator (AVR) is set at a position where both the allowable limit by the possible output curve of the generator and the static stability limit of the system are satisfied to prevent the loss of synchronism. (2) Temperature increase of iron core and mechanical part

If the leak magnetic flux entering the iron core end part of the stator increases, the temperature increases due to the eddy current induced by the elements making up the iron core end part. Therefore, even though the stator end part of the turbine generator uses a structure that suppresses the temperature increase, it is necessary to conduct the operation with the possible output curve area of the generator by taking changes in the stator iron core temperature, stator coil temperature, and cooling gas temperature into consideration.

Figure 29 shows an example of the generator output curve.

24

Curve AB: Limited by magnetic field temperature. Curve BC: Limited by armature temperature. Curve CC: Limited by armature iron core end temperature.

Del

ay

Rea

ctiv

e po

wer

[pu]

Active power (pu)

Under excitation limit (UEL)

Adv

ance

Fig. 29 Generator output curve

2.3 Start-up and Stop Operation Control 2.3.1 Start pattern

Electric power demand changes not only throughout the year, but also weekly and daily. A thermal power unit start or stop in order to adjust its output to flexibly correspond to changes in power demand. The unit has the following start patterns from unit stop to unit start. (1) Cold start

The unit is started after it has been stopped for an extended period of time, such as for periodic inspection. (2) Weekly start and stop (WSS)

In WSS, the unit is stopped at nighttime on a Friday or on a Saturday when the electric power demand decreases, and then it is started early on Monday morning when the electric power demand starts increasing.

The stop time is 12 to 36 hrs. Figure 2 shows an example of this schedule.

Fig. 3 Da

Fig. 2 Wee

(3) Daily start and stop The unit is stopped at midnight, and then starte

differences in electric power demand between dayt3 shows an example of the daily start and stop sche

This daily start and stop is necessary because efthe base load units, such as nuclear or large capaci

In this daily start and stop operation, the adversconsidered. In the first case, thermal stress on the

P

aral

lel-o

ff

Outp

Main sttemper

Main spressu

Par

alle

l-o

ff

Output

Main steam temperature

Main steam pressure

25ily start and sto

kly start and st

d the next mornime and nighttdule. ficient operatioty thermal powe effects on the turbine rotor i

Igni

tion

St

art

ut

eam ature

team re

Par

alle

l

Igni

tion

Star

t

p schedule

op schedule

ing so that the power generation corresponds to ime. The stop time is from 6 to 12 hrs. Figure

n of the power system is achieved by increasing er generation. unit service life and supply reliability should be s a particularly problem.

Par

alle

l

26

(This thermal stress is caused by d es eam and turbine rotor when the unit is

roblems, it is necessary to take appropriate measures, such as improvement of the unit re

used to restart the unit after it has been stopped for a short time (about less than 6 hrs.) due to sy

diately before the trip. However, since th

.3.2 Starting of unit tline of the start steps of the coal burning supercritical pressure voltage transformation

on

he unit is determined by the boiler or turbine status. As described in Ta

ed on the start time re

ifferenc in temperature between the ststarted. Normally, this temperature difference is called “mismatch temperature”.) According to the low cycle

fatigue index (LCFI) of the turbine rotor, the number of yearly start and stop cycles is limited to take measures against this problem. In the second case, the start and stop time is short and the operation reliability needs to be kept at a high level.

To solve these pliability, omission of operation steps, and/or review of standards.

(4) Quick start This quick start isstem problems or power control. Normally, the quick start is called “very hot start”. In this case, the thermal stress of the turbine requires special attention. The metal temperature of each part meets the steam temperature immee boiler and piping after restarting are cooled as the stop time elapses, the steam temperature is mismatched with

the metal temperature due to decrease of the steam temperature and throttle of the control valve. Therefore, it is preferable that the steam temperature is increased to a high temperature level and the speed is increased rapidly, and the parallel and load are increased. 2

Figure 4 shows an ouce-through plant. The following describes the operating procedures and provides notes on each start step.

(1) Determination of start schedule The period of time required to start tble 1, the unit start mode is determined by the metal temperature at the first stage of the turbine. As the time

required for each event is added, the overall time required for the start process is calculated. In the start schedule, the parallel schedule time is determined to the base point. Basquired described above, the schedule time, such as boiler ignition, turbine start, and full load achievement is

determined.

Fig. 4 Unit start steps (Cold start)

Water quality check

Main steam pressure

RPM

Output

Pre

para

tions

for u

nit s

tart

Con

dens

ed w

ater

cle

anup

and

vac

uum

incr

ease

Low

-pre

ssur

e cl

eanu

p

Hig

h-pr

essu

re c

lean

up

Boi

ler c

old

clea

nup

Prep

arat

ions

for b

oile

r ign

ition

Boi

ler i

gniti

on

Boi

ler h

ot c

lean

up

Tem

pera

ture

incr

ease

/pr

essu

re in

crea

se

Pre

para

tions

for t

urbi

ne s

tart

Turb

ine

star

t/spe

ed u

p

Prep

arat

ions

for

para

llel

Coa

l cha

rgin

g st

art

BFP

M/T

cha

nge-

over

Wet

/dry

cha

nge-

over

Parallel/ output

increase 1

Output increase II

Output increase III

Volta

ge tr

ansf

orm

atio

n st

art

Coa

l sin

gle

fuel

firin

g

Wat

er q

ualit

y ch

eck

Pow

er s

uppl

ydi

strib

utio

n

27

Table 1 Example of start modes Start type Item Unit

Very hot start (Stopped for 2 hrs.)

Hot start (Stopped for 8 hrs.)

Warm 2 start (Stopped for 32 hrs.)

Warm 1 start (Stopped for 56 hrs.)

Cold start (Stopped for 150

hrs.) Metal temperature at 1st stage °C 460 - 390 – 460 340 – 390 230 – 340 - 230

Main steam pressure MPa 8.5 8.5 8.5 8.5 8.5 Main steam temperature °C 510 470 410 410 400

Reheating steam temperature

°C 505 480 377 289 200

Steam temperature at 1st stage

°C 438 391 315 315 301

Metal temperature at 1st stage

°C 494 453 368 326 216

Plan

ned

valu

es a

t sta

rt

Mismatch temperature °C -56 -62 -53 -11 +85 Turbine speed up ratio rpm/min. 300 300 150 150 100

Low-speed heat soak time min. 0 0 0 0 20 High-speed heat soak time min. 0 0 0 0 55

Initial load volume % 3 3 3 3 3 Initial load holding time min. 0 0 15 15 60

The boiler start mode is determined by the fluid temperature at the inlet of the water separator, and it is then

used for the fuel program for start or start by-pass valve control. (2) Preparations for unit start

Inspect and check each part so that the work during unit stop is completed and there is no obstacle hindering the start.

Confirm that units related to common facilities are being operated correctly or that they are ready for operation. Confirm that the interlock, alarm device, and monitoring instrument function correctly, and that the fuel and

demineralized water necessary to start are maintained. (3) Pre-boiler cleanup

In the once-through boiler, it is necessary to supply high purity water from the start. Therefore, cleanup is carried out to remove impurities (particularly, iron content) from each system prior to the

ignition. In the pre-boiler cleanup, the vacuum in the condenser is increased, and then the condenser system,

low-pressure supply water system, and high-pressure supply water system are cleaned up from the upstream side in order.

In each system, the circulation operation is carried out through the condensate demineralizer so that the water quality becomes the standard value or less after the standard to pass the water to the condensate demineralizer has been satisfied using the blow outside the system.

Additionally, the turning operation of the turbine is performed to prevent deflection of the turbine rotor before increasing the vacuum. (4) Boiler cold cleanup

When the water quality in the pre-boiler satisfies the boiler passing water standard, the water is fed to the boiler to perform the cleanup at a normal temperature. Table 2 shows the water quality standard when the once-through boiler is started.

After the boiler has been filled with water (this work is not needed when the boiler filled with water has been stored), the blow outside the system is performed through the drain system of the water separator. After the water quality of the blow water has satisfied the standard for the water passed to the condensate demineralizer, the circulation operation is performed until the water quality is the standard value or less through the condensate demineralizer. (5) Preparations for boiler ignition

The supply water system is changed from the cleanup status to the boiler ignition status. The ventilation system is started to purge the furnace. The remaining unburnt gas is purged at a specified air

flow rate for a specified period of time in order to prevent explosion in the boiler furnace. (Example, 30% MCR flow rate for 5 min.)

The fuel system for start (oil or gas) is started up to check the system for leak. Generally, light oil is used for the start.

(Note) Cleanup is essential for a cold start. The cleanup is usually omitted for the WSS or DSS start. The operation often enters the ignition preparations from the low-pressure cleanup circulation status during unit stop.

(6) Boiler ignition and hot cleanup After the boiler has been ignited, the temperature is increased to the target temperature of the hot cleanup (fluid

temperature at the outlet of the furnace is approx. 150°C.). The temperature is kept at this cleanup target

28

temperature. If the water quality becomes the standard value or less, the temperature increase is restarted. (7) Temperature increase and pressure increase

The temperature increase and pressure increase of the boiler are performed to achieve the steam conditions at turbine start determined by the turbine start mode. By adjusting the fuel charging volume, the start bypass valve and drain valve in the steam system, the temperature increase and pressure increase are completed within the target time.

The feed water flow rate and air flow rate are controlled to their minimum flow rates. At this time, the re-heater protection (prevention of burning) and the thick wall part protection (relaxing of thermal stress) exist as limitation items when started. The former is limited by the gas temperature at the outlet of the furnace, as well as the fuel charging volume. The latter is limited by the temperature increase ratio at the inlet of the water separator and the outlet of the super heater. (8) Preparations for turbine start

In the cold start, the metal temperature of each turbine part decreases to a level close to room temperature. When starting the turbine in this status, thermal stress occurs as a result of the difference in temperature when compared to the steam.

Table 2 Water quality at starting of once-through boiler (When the volatile substance process applies.) Process Circulation before ignition

(Boiler cold cleanup)

Temperature increase/pressure increase circulation (Boiler hot cleanup)

Load operation [1/2MCR (42) or less]

Cla

ss

Max. operating pressure (MPa) Greater than 15 and 20 or

less

Greater than 20

Greater than 15 and 20 or

less

Greater than 20

Greater than 15 and 20 or

less

Greater than 20

pH (at 25°C) 8.5 – 9.6 (19) 9.0 – 9.6 8.5 – 9.6 (19) 9.0 – 9.6 8.5 – 9.6 (19) 9.0 – 9.6 Electric conductivity (mS/m) (11)(19) (at 25°C)

(µS/m) (11)(19) (at 25°C) 0.1 or less 100 or less

0.1 or less 100 or less





Dissolved oxygen (µgO/l) 40 or less (36) 20 or less (38) 10 or less 10 or less 7 or less 7 or less Iron (µgFe/l) 200 or less 100 or less 100 or less 50 or less 30 or less 30 or less Copper (µgCl/l) 20 or less 20 or less 20 or less 10 or less 5 or less 5 or less Hydrazine (µgN2H4/l) 20 or more (38) 20 or more (38) 20 or more 20 or more 10 or more 10 or more

Economizer inlet

Silica (µgSiO2/l) 30 or less 30 or less 30 or less 30 or less 30 or less 30 or less Electric conductivity (mS/m) (11)(19) (at 25°C)

(µS/m) (11)(19) (at 25°C) 0.1 or less 100 or less




- -

- -

Feed

wat

er

Furnace water wall outlet Iron (µgFe/l) 300 or less 300 or less 200 or less (40) 100 or less (41) - -

Note (38) This value becomes the target according to the boiler shape. (39) When starting the unit after it has been stopped for a long period of time, it is preferable to adjust the hydrazine concentration to a higher level in order to promote forming

of a protective coat inside the system. At this time, the hydrazine is dissociated in the water and it exists as the hydrazinium ion (N2H5

+). (40) The target concentration of the iron is 100µgFe/l or less. (41) The target concentration of the iron is 50µgFe/l or less. (42) This shows an abbreviation of the maximum continuous rating that means the maximum continuous load.

To reduce this thermal stress, the warming of the casing and control valve must be carried out before starting

the turbine. Additionally, it is important to check for faulty parts, such as the shaft position or eccentricity using the turbine

monitor instruments before starting the turbine through turning. (9) Turbine start and speed up

Items to be considered most at turbine start are thermal stress and vibration problems. Therefore, the warming (heat soak) is performed until the rotor temperature reaches the transition temperature [temperature, at which the mechanical properties of the material lower rapidly (becomes fragile)] to prevent the fragility of the turbine rotor from being broken or to reduce the thermal stress of the rotor surface and the stress at the center of the rotor.

This heat soak is classified into two groups. The first group is the low-speed heat soak in which the turbine is started with low-speed RPM kept in order to prevent the turbine rotor from being broken. The second group is the high-speed heat soak in which the turbine is started at a rated RPM to prevent excessive thermal stress of the rotor as the parallel and output increase.

As described above, the heat soak time and speed up rate are determined by considering the thermal stress in order to control the service life of the rotor.

Additionally, it is necessary to determine a start schedule most suitable for the turbine so that vibration is minimized.

To determine this turbine start schedule, the start load operation chart (mismatch chart) is provided. The heat soak time and speed up rate are usually determined by the metal temperature at the first stage, as well as the main steam temperature and pressure when the turbine is started up.

Table 1 shows examples of the speed up rate and heat soak time in each start mode. It is important that the turbine is started according to the schedule created based on this chart and the operation is performed while carefully checking the steam temperature so that the difference in temperature between the internal and external

29

metal surfaces of each turbine part and the steam temperature change ratio do not exceed their limit values. The vibration and expansion difference are monitored during increasing of the turbine RPM.

Great care should be taken as the amplitude tends to be large at a speed close to the critical speed of the rotor. In the boiler, as the turbine speed increases, the fuel charging volume is adjusted to keep the necessary steam

volume. For a cold start, the fuel charging volume is minimized before starting the turbine in order to reduce the thermal stress applied to the turbine. It is also necessary to prevent excessive increase of the main steam temperature by suppressing the increase of the fuel charging volume during speed up to the minimally required level. (10) Preparations for parallel

If heavy oil facilities are provided, light oil is changed to heavy oil before starting parallel output. Variations in main steam temperature and main steam pressure are checked when changing light oil to heavy oil.

It must be checked that the ash processing facility, desulfurization facility, and denitration facility have been started and they are in standby mode before charging the coal after parallel output has been started.

If the coal on the belt of each coal supply machine is discharged, each coal supply machine needs to be put in coal on status. (11) Parallel, output increase 1

When the turbine reaches the rated RPM, the generator voltage is increased to its rating, and then the turbine is synchronized with the system to put in parallel status.

After the initial output is kept using the initial output volume corresponding to the turbine start mode, the output increases to 20%ECR.

In the output increase process, the turbine valve is changed, the low-pressure/high-pressure feed water heater is started, and the coal burner at the first stage is started. Variations in main steam pressure in the process utilizing the bleed air and in the coal charging process are checked carefully while the output is increasing. Additionally, it is also necessary to carefully check the NOx and SOx control after the coal has been charged.

After the output has reached approx. 20%ECR, the boiler supply water pump is changed from the electric drive (M-BFP) to the turbine drive (T-BFP). After that, the power at the station is changed (start transformation → station transformation). (12) Output increase II

The output increases to 50%ECR. The wet/dry of the boiler is changed at an output of approx. 25%ECR (the boiler status is changed from recirculation to once-through status and the control system is also changed to once-through control). By changing the wet/dry of the boiler, the boiler circulation pump (BCP) is stopped.

According to the voltage transformation mode, the main steam pressure starts increasing at an output of approx. 30%ECR. This operation is controlled by the boiler input command. However, in the output and main steam pressure increase process after the wet/dry has been changed to “dry”, it is necessary to carefully check the balance between the feed water flow rate and fuel flow rate, as well as variations in the steam temperature of each part.

As the output increases, the coal burners are ignited in order and the oil burners are turned off to burn only coal. Additionally, the second T-BPP unit is put in the service in status.

After the output has reached 50%ECR, the stable operation of the unit is checked and the water quality of each part is checked. When the water quality satisfies the standard value, the drain is collected from the high/low pressure supply water heater. (13) Output increase III

The output increases to 100%ECR. As the output increases, the coal burners are ignited in order. After the output has reached 100%, the operation status of the unit is checked and the patrol inspection is

performed at the work field to check that no errors exist. After that, load dispatching ferry is done. 2.3.3 Stopping of unit

When stopping the unit, the output is decreased sequentially according to the stop schedule in which the stop period, heat radiation cooling during this period, and operation conditions for next start are taken into consideration.

The stop method is classified into four groups as described below. Figure 5 shows an outline of the stop steps. 1) Normal turbine stop & boiler hot bank

This stop method is used to stop the unit according to the standard (normal) stop schedule, such as the weekly start and stop and the daily start and stop.

2) Boiler forced cooling stop This stop method is used to cool the boiler in a short time to ensure work safety during boiler related repair work (in-furnace work or repair of pressure resistant parts, etc.). The normal operation is performed until the units are put in the parallel-off status. After the units have been put in the parallel-off status, water and air are fed continuously to cool the boiler.

3) Turbine forced cooling stop This stop method is used to cool the turbine in a short time to ensure work safety if repair work needing the turbine oil pump stop is needed. The main steam pressure is normally kept at a higher level than the normal level corresponding to the output drop, and the main steam temperature and reheating steam temperature are decreased to a lower level than the normal target temperature to stop the units. Figure 6 shows a typical stop pattern. In this case, boiler forced cooling needs to be performed for safety reasons.

4) Boiler & turbine forced cooling stop This stop method is used to cool both the boiler and turbine when stopping the unit accompanying the periodic inspection. The following describes the operating procedures and cautions for the stop step.

(1) Preparations for unit stop After the unit stop schedule has been determined, heavy oil warming and steam type air pre-heater (SAH) are

started when using heavy oil.

Output

Dry

/wet

cha

nge-

over

Star

ting

of p

repa

ratio

nsfo

r uni

t sto

p

30

Fig. 5 Unit stop steps (Normal turbine stop)

Out

put d

rop

star

t Vo

ltage

tran

sfor

mat

ion

star

t

Output drop I Output drop II Output drop III

Oil

burn

er ig

nitio

n

BFP

T/M

cha

nge-

over

Par

alle

l-off

Coa

l sin

gle

fuel

firin

g

Boi

ler o

ff

Turb

ine

trip

Vacuum retention Boiler hot bank

Boiler forced cooling Vacuum break

Pressure

31

Fig. 6 Example of turbine forced cooling stop

Additionally, the preparations for auxiliary steam supply from another boiler or a boiler in the plant are performed. (2) Output drop I

The output drops to 50%ECR. When the output is approximately 95%ECR, the main steam pressure starts dropping according to the voltage

transformation mode. According to the output drop, the coal burners are turned off sequentially. (3) Output drop II

The output drops to 20%ECR. According to the output drop, the oil burners are ignited and coal burners are turned off.

Additionally, the first T-BFP unit is put in the service out status. The drain tank level of the water separator increases when the output is approximately 25%

ECR. The BCP is started to change-over the dry/wet. After the M-BFP has been put in the service in status, the second T-BFP is put in the service out status. The output reaches 20%ECR. The transition to heavy oil single fuel firing is completed and the power

change-over in the plant (station transformation → start transformation) is completed. (4) Output drop III, parallel-off

The output is dropped to the parallel-off target value (5%ECR). The high-pressure/low-pressure supply water heater is stopped according to the output drop.

Additionally, oil burners are turned off in order. When the output reaches the parallel-off target value, the parallel-off is performed.

(5) Turbine trip, boiler off After completion of parallel-off, the turbine is tripped. After checking that the auxiliary steam is changed to

another boiler or a boiler in the plant, all oil burners are turned off. When the burner purge is completed after the final burner has been turned off, the MFT is then operated to

check that all fuels are shut off completely. After the MFT has been operated, the furnace purge is performed for 5 min.

2.3.4 Stopping of boiler

There are two kinds of boiler stop methods after parallel-off, that is, boiler hot bank stop and boiler forced

Load Temperature

Re-heating steam temperature

Main steam temperature Load

Main steam pressure

1%/min.RPM

RPM

0.5%/min.

TimeLoad drop start Parallel-off.

360 min

32

cooling stop. The above stop methods are carried out according to the schedules even though there is a difference between

the plan stop and work stop. In addition to the above stop methods, there is a stop method by the MFT operation during unit operation. (1) Normal stop

When the unit stop schedule is determined, heavy oil warming or SAH is started according to the output drop schedule time. The preparations are made so that the auxiliary steam can be supplied from another boiler or a boiler in the plant.

When the output drop is started, the coal burners are turned off in order according to the decrease of the fuel flow rate. When the output is approximately 95%ECR, the main steam pressure also drops according to the voltage transformation program.

In particular, the balance among the supply water, fuel, and air (boiler input command, water-fuel ratio, air-fuel ratio) should be checked carefully.

The heavy oil burners are ignited in order when the output becomes 50% or less. If the preparations for ignition of the heavy oil burners are not in time, the output is kept at 50%ECR.

When the output becomes approximately 25%ECR, the drain tank level of the water separator increases. As the BCP is started, the dry/wet is changed over.

The output reaches 20%ECR. Check that the transition to heavy oil single fuel firing is completed and the power change-over in the plant (station transformation → start transformation) is completed. After checking the above, the output drops to the parallel-off target value (5%ECR).

After the output has reached the parallel-off target value, the parallel-off is performed, and then the turbine is tripped.

After checking that the auxiliary steam is changed to another boiler or a boiler in the plant, all oil burners are turned off.

When the burner purge is completed after the final burner has been turned off, the MFT is then operated to check that all fuels are shut off completely. After the MFT has been operated, the furnace purge (after purge) is performed for 5 min. (2) Stopping of boiler hot bank

After the MFT has been operated and the furnace purge has been completed, the ventilation system and water/steam system are sealed to minimize the heat loss of the boiler as preparations for restart.

The contents of the stop operation are described in clause 1.3-(5). The result data of the boiler pressure drop rate and steam temperature drop rate during hot bank is grasped. If

the drop rate is excessively fast, check whether any leak comes from the start bypass valve, or the main steam/super-heater drain valve.

Heat or pressure remains in the boiler during hot bank. As a rule, the operation and adjustment of the boiler system valve, and the inspection and work of the equipment leading to the boiler system valve, and the opening of the manhole must not be performed. (3) Boiler forced cooling stop

Before conducting the inspection work or periodic inspection work related to the boiler, forcibly cool the boiler to stop it in order to enable safe work on the turbine side.

The contents of the stop operation are described in clause 1.3-(6). After forced cooling has been completed, the boiler storage status may vary depending on the stop purpose.

Table 6 shows examples of storage methods (except for plant that the oxygen process applies to the water process).

Actually, water filled status or nitrogen disused status often occurs. In this case, the boiler water is blown completely after the forced cooling has been completed, and then the boiler is stored in the dry status. (4) Measures for MFT operation

The operators must understand the causes of the MFT operations fully. If MFT occurs, check that the protection interlock functions properly. Additionally, the boiler must not be restarted until the cause of the MFT has been located and corrective action has been taken. The following describes the measures to be taken after the MFT has been activated when the operation of the auxiliary machine in the ventilation system is continued.

1) Check items after MFT The fuel shut-off valve, burner valve, and SH/RH spray valve are closed. The auxiliary machines are tripped. (Mill, coal supply machine, PAF, and RFP, etc.)

33

The mill hot air gate and damper are closed. The burner complete off alarm signal send items through the television set inside the furnace.

2) The air flow rate is the furnace purge air flow rate (normally, 30% of MCR flow rate). The furnace is purged for 5 min. or longer.

3) The auxiliary steam supply is changed to another boiler or a boiler in the plant. 4) To prevent fire caused by spontaneous ignition, the air is flown at the minimum air flow rate to purge

the flammable contents of the coal remaining in the mill and pulverized coal pipe in order to cool the inside of the mill (volatile purge). If a mill inert system is provided, the mill is made inert to prevent a fire.

5) Each part of the boiler is inspected visually to check that no faults exist. In particular, when the MFT is operated from the high-output, the solenoid escape valve (PCV) may be activated. Therefore, it is necessary to check that no leak exists after activation.

6) After the cause of the MFT has been found and corrective measures have been taken, the operation is restarted. At this time, if it takes long to locate the cause, it is possible to stop main auxiliary machines in the ventilation system, but the damper in the gas duct is put in the natural ventilation status (to purge the volatile content).

7) After the pilot torch has been ignited, oil remaining in the trip burner is purged. 8) Coal remaining in the mill is purged after parallel. Additionally, if the mill clearing system is provided,

the remaining coal is processed by the clearing when the preparations for pyrite processing unit are completed.

Table 6 Example of storage methods in case of once-through boiler stop 1 2 3 4 Stop period

Item 48 hrs. or less 48 hrs. to 1 week 1 week or more to 1 month 1 month or more

Boiler main body From economizer to outlet of water separator

Hot banking (Valve is closed with normal operation kept.)

Nitrogen sealing storage or water filling storage N2H4 50 – 100 mg/λ



Super-heater and re-heater

Same as above. Same as left. Nitrogen sealing storage (Re-heater: Dry storage)

Nitrogen sealing storage (Re-heater: Dry storage)

If the auxiliary machine in the ventilation system is tripped, the furnace must be purged after the damper in the

gas duct has been put in the natural ventilation status. Additionally, when all power supplies are lost, it is checked that the fuel is shut-off and the back-up operation of the AH is performed by the air motor and that the damper in the gas duct is put in the natural ventilation status. (5) Operation of Soot Blower When Unit Is Not Used ～Boiler clinker removal～

When working inside the furnace during the suspension of boiler operation, it is necessary to conduct clinker removal before paralleling off in order to ensure safety against clinker fall. 2.3.5 Concept of turbine start

Thermal power generation facilities in Japan were originally positioned for adjustment of the load. However, thermal power generation actually comprises approximately 60% of all capacity, and this output will continue to be important in the future. Additionally, thermal power generation facilities are considered increasingly important for stable energy supply.

Thermal power generation facilities are classified into two groups, combined power generation facilities having high efficiency and excellent operability, and conventional power generation facilities utilizing various fuels and having rich operation results. Continuing the operation of conventional power generation facilities is important in order to maintain a range of energy sources, and there are plans worldwide to construct thermal power generation plants mainly using coal. Since coal is dispersed worldwide and its deposits are abundant, conventional thermal power generation plants are being constructed.

It is desirable to increase the capacity of conventional power generation facilities and to improve their efficiency levels in order to reduce greenhouse gas emissions. In 2000, commercial operation started of Tachibana Bay Plant, controlled by Electric Power Development Co., Ltd. This state-of-the-art large capacity plant (1,050MW) has a main steam pressure level of 25MPa and a temperature of 600 °C, and utilizing high steam conditions with a re-heating steam temperature of 610 °C.

However, the turbine has many small gaps and is rotated at high speed and high temperature. Therefore, rubbing or excessive thermal stress occurs, causing damage to the unit.

For this reason, utilization of the proper operation method and monitoring method is more important by considering extension of the periodic inspection, which has been utilized recently.

As the number of new plant being constructed in Japan is decreasing rapidly, and the construction and maintenance of power generation plants are shifting overseas, the remote monitoring service business is started.

The following items can be monitored by the manufacturers in their own country. 2.3.5.1 Reduction of thermal stress

Thermal stress occurs inside the steam turbine caused by differences between the temperature of each steam turbine part and the steam temperature to be ventilated.

The cautions on the turbine start plan is that this thermal stress occurring in the rotor and casing is reduced. The thermal stress of the high-pressure rotor operated under the severest conditions is monitored to control the LCFI (Low Cycle Fatigue Index). To monitor this thermal stress, the metal temperature at the outlet of the first stage of the turbine is determined as a representative measurement point. This measured metal temperature value is used to make the judgment.

According to the metal temperature at the first stage achieved by natural cooling during the stop time and the turbine plan ventilation temperature, which has been adjusted with the boiler side beforehand, the start mode is classified into those described in Table 7. As the stop time is longer, the start time also becomes longer.

Table 7 Examples of start mode classifications and stop time levels Start mode Stop time Remarks Very hot start Stopped for up to 4 hrs. from

immediately after turbine trip.

Hot start Stopped for 8 to 11 hrs. DSS: Parallel-off at midnight and parallel-in the next morning.

Warm start I Stopped for 32 hrs. WSS I: Parallel-off at midnight on Saturday and parallel-in on Monday morning.

Warm start II Stopped for 56 hrs. WSS II: Parallel-off at midnight on Friday and parallel-in ion Monday morning.

Cold start Stopped for 150 hrs. or longer Stopped for 1 week or longer.:page 15

RPM: 3600 rpm Load: 100%Vacuum degree

Main steam pressure

(Preparations for ignition M - BFP start/Ignition) (Vacuum pump start) (Parallel-in (initial load holding)) (Low-pressure cleanup) (Condensate water cleanup) (Turbine start)

(High-pressure cleanup) (M/T change-over) (Rub check)(Boiler cold cleanup) (Low-speed heat soak) (2nd T-BFP turn ON)

(Boiler hot cleanup) (Speed up start)

Fig. 19 Example of typical start

As described above, the natural cooling is started and the rotor temperature is changed according to the turbine

stop time. The typical start mode is classified into various typical classes because the operation mode is classified into patterns by operation style. To relax the thermal stress that occurs as a result of the difference in temperature between the main steam and rotor, it is necessary to adjust the start method.

As described above, since the time needed for the start is different from the stop time, it is important to grasp the start time for the power supply plan.

Figure 19 shows the events in the typical cold start processes. The following introduces the main monitoring items in the start process. (1) Pre-warming

In the cold start in which the turbine is started from almost room temperature, warming of the high-pressure turbine is needed to reduce the thermal stress. The metal temperature after the first stage is controlled. This pre-warming is intended to reduce the brittleness of the rotor even though it depends on the material. (2) All-around flow operation

To reduce the thermal stress of the construction, casing close to the nozzle at the first stage or nozzle during ventilation, the all-around flow operation (full-arc operation) is performed. When using the machine control method (MHC), the sub-valve of the MSV is opened to perform. When using the individual oil tube method using the electric control method (EHC), all control valves are opened slightly to perform this method. At approximately 7% of the load after starting, the partial insertion operation is started. Figure 20 shows the relationship between the opening of the control valves and load during this partial

34

insertion operation as an example of the voltage transformation operation.

Mai

n st

eam

pr

essu

re

Con

trol v

alve

s o p

enin

g

Fully opened.

4th valve 1st to 3rd valve

Load Fig. 20 Example of pressure and control valves opening during voltage transformation operation

(3) Low-speed heat soak operation

In the cold start, the heat soak operation is performed by the steam passing through the turbine in the status that the heat transfer effect is high. This operation is performed by taking the critical RPM of the generator having the lowest critical speed into consideration. This RPM is generally about 800 rpm. (4) High-speed heat soak

When the RPM reaches the rated RPM, the heat soak operation is started to further heat up the turbine evenly. At this time, since the heat transfer effect becomes high together with the stream flow rate, the initial load holding time may be extended. 2.3.5.2 Other limited factors related to start

Important items to be monitored other than factors related to the thermal stress are those related to the vibration and elongation difference. The following shows items related to the vibration. (1) Eccentricity

In an example 700MW-plant, the maximum diameter of the steam turbine shaft is approximately 500mm, a large diameter. The span between the bearings is approximately 6m. Therefore, to suppress the bend of the rotor, it is necessary that the turning is generally performed for approximately 10 hrs. or more to set the eccentricity to the standard value or less.

Table 8 Vibration control values Detection location Shaft Bearing Remarks

Detection RPM 3000rpm/3600rpm 1500rpm/1800rpm 3000rpm/3600rpm 1500rpm/1800rpm

12.5 17.5 6.2 8.7 Rated speed or more Alarm value

15 21 7.5 10.5 Less than rated speed

Stop value 25 35 12.5 17.5 (2) Vibration limit value

The turbine speed must pass through various critical speed ranges including the generator until the turbine reaches the rated RPM. Additionally, since the turbine is a large high-speed rotating unit, the vibration may increase due to the eccentricity and bearing lubrication status or small imbalance.

Therefore, it is necessary to set the alarm value and stop value, which are the control value or less as shown in Table 8 according to “Technical standard for thermal power generation facilities” and “Electric technical standard for steam turbine for thermal power generation and standard for generator vibration”.

Furthermore, the control is used by which the vibration amplitude and vibration increase rate are determined as parameters and the control is classified into the safe zone, alarm zone, and trip zone. In this control, the previously described three zones are classified into “critical speed range or less”, “critical speed range”, and “critical speed or more” by the RPM range to control the turbine vibration by computer.

35

Start

Oil

tem

pera

ture

Continuous turning

Control valve change-over

36

Fig. 21 Example of bearing lubricant oil temperature setting and monitoring

(3) Oil temperature

It is important to control the lubricant oil temperature in order to form a stable lubricant film, to protect the bearing, and to prevent oil whip. The temperature width shown in Fig. 21 is set to change the control value according to the turbine operation status (RPM). (4) Metal temperature

It is important to monitor the bearing metal temperature for protection of the bearing metal. The temperature monitoring conditions may vary depending on the bearing shape, such as thrust bearing, oval journal bearing, or tilting pad journal bearing. Additionally, it is also important to monitor rapid changes in metal temperature. (5) Vacuum degree in exhaust chamber

If the vacuum degree is much higher than the design value (pressure inside the condenser is too low), the low-pressure casing is deformed, causing rubbing to occur. Additionally, as the vacuum degree decreases, the vibration stress at the final stage increases. (6) Temperature in exhaust chamber

It is further important to control the temperature around the final stage as the vane at the final stage is made longer. Measures for protection of the final stage, such as use of casing spray are taken so that flexibility of the operation is not lost. (7) Limitations on wetness

Monitoring is important for protection of erosion on the vane at the final stage. Even though the wetness at the outlet of the final stage is generally controlled in a range of 8 to 12%, it is necessary to take appropriate measures or to perform the monitoring in a range exceeding this wetness range. The start point of the expansion curve of the re-heating part, that is, the pressure and temperature of the re-heating steam must be monitored.

Figure 22 shows a conceptional diagram of the typical wetness limitation curve expressed by the equivalent re-heating steam pressure line that indicates the re-heating steam conditions for wetness of 12%. The lower portion of each re-heating pressure curve shows the operable range.

Turning disengagement

Rated RPM

α RPM of rating

Stop O

il te

mpe

ratu

re

Continuous turning

Equivalent to control valve change-over load

α RPM of rating

Turning start

Turbine trip

The lower portion of each re-heating steam pressure shows

the operable range.

Vacu

um d

egre

e

Equivalent re-heating steam pressure line

37

Fig. 22 Concept of wetness limit curve

Re-heating steam temperature

Under the operation conditions, the motion that comes and goes between the wet area and dry area is called

“dry and wet alternation”. However, it is important that coming and going between the wet area and dry area are eliminated at the final stage or L-1 (stage one before the final stage). Impurities in the steam may accumulate in the nozzle and on the vane due to dry and wet alternation, causing corrosion to occur.

Allo

wab

le ti

me

Frequency

Fig. 23 Concept of frequency limit curve (example of rating 3600rpm) (8) Frequency limit value

The principal vibration of the vane at the final stage is designed so that it is separated well properly to the rated RPM. However, the operation may be performed with the principal vibration beyond the rated RPM as the effect on the system side is received.

Figure 23 shows the frequency limit curve. The control of the service life is “Σtf/Tfo ≤ 1.0” and the operation needs to be performed without exceeding this formula.

t f : Cumulative operation time at frequency (f). Tf0 : Allowable operation time at frequency (f).

High and medium pressure rotor expansion direction Low pressure rotor expansion direction

Low pressure expansion difference meter Thrust bearingHigh pressure expansion difference meter

Low pressure B High pressure

Low pressure AMedium pressure

High and medium pressure casing High and medium

pressure bearing base on front

(Second bearing base)Low pressure B

casing Low pressure A

casing Combined with low pressure

casing

Low pressure B expansion direction

38

Fig. 24 Example of casing and rotor expansion directions

High and medium pressure and low pressure A expansion direction

(9) Expansion difference

The rotor is warmed earlier than the casing at startup, on start. Figure 24 shows a concept of the rotor and casing moving directions as a typical example of three casing types.

The difference in expansion between the rotor and casing may become the biggest on the anti-generator side of the high pressure turbine and the generator side of the low pressure B turbine. The elongation difference meter is provided on these parts as shown in the drawing to monitor them.

Figure 25 shows an example of the monitoring method. Rotor long means that the rotor is extended longer than the casing. Rotor short is opposite to rotor long. The green mark shows the status that the turbine rotor is kept pushed against the front side in the cold condition.

The red band shows the area causing contact in the axial direction. As the rotor is rotated, it is pulled by centrifugal force in the circumferential direction and it is then shortened.

Gre

en

mar

k

Red

m

ark

Orange band Red bandRed band

1st a

larm

poi

nt

2nd

alar

m p

oint

Max. rotor shortMax. rotor long

Fig. 25 Example of limitations on expansion difference

That is, even though the rotor does not enter the red band on the long side during operation, it is extended as it

is released from the centrifugal force in the stop process. As a result, the rotor may enter the red band area.

On the contrary, when the rotor is started in a status close to the short side before the RPM is increased, it may advance toward the rotor short side as the RPM is further increased. This width shows the portion between the red mark and the first alarm point, and the orange band.

2. 4 Performance Management 2.4.1 Grasping of performance

In the performance control of thermal power plants, the constant, accurate grasping of unit operation, and working to improve thermal efficiency are most important.

As a method to grasp performance, the deviation from the desired value which can be expected as long as the equipment is operated normally including the acceptance performance test results etc., and also initial design values at the start of operations are controlled. This desired value comprises operation status values such as the temperature and pressure of each part, and performance values such as unit efficiency and boiler efficiency. The latter performance values change by external conditions and therefore revision of the same conditions is necessary for making comparisons. Setting of coefficients for revision may be performed by theoretical calculation or by testing.

Next, in order to reasonably maintain facility performance in thermal power plants, in general, daily control is made so that appropriate measures may be taken by monitoring the operation status. By monitoring the necessary control items by instruments, daily operation log, calculators, etc., abnormal conditions are detected early and by conducting operation and maintenance properly, efforts are made to perform reference value operations.

On the other hand, every day operation conditions are grasped from operation records and typical items which affect performance (condenser vacuum degree deviation, exhaust gas temperature, exhaust gas O2) are plotted by day, ten days, month in graphs, and the trend controlled. Especially, in regard to power plants with coal energy and such where coal quantity, quality cannot be grasped in real time, the plant situation is grasped by trend control.

Also, to evaluate performance and thermal efficiency improvement measures at the time of regular inspection, performance test items (high pressure turbine internal efficiency, air preheater efficiency, feed water heaters, etc.) were grasped and simultaneous records taken on the overall unit for detailed control. 2.4.2 Grasping of equipment performance

To control performance changes of the unit, unit performance tests were conducted regularly, and efficient operation, maintenance and improvement of facilities are being undertaken.

In general, performance tests were conducted with minimum output, 2/4 output, 3/4 output and rated output and items such as plant thermal efficiency are being measured. 2.4.2.1 Heat input and output of a thermal power plant

An example of fuel, electric output, and various losses of a thermal power plant is shown in Fig. 2.4.2.1. The major part of fuel consumed in boiler combustion is used for the generating of steam. This steam is sent to the turbine but a little over ten percent of the heat quantity are discarded into the atmosphere as exhaust gas. Steam that flows into the turbine expands inside the turbine and works to rotate the generator to generate electric power. During this time, a part of the work becomes mechanical loss such as by bearings, etc. and also becomes generator loss. The steam which has expanded with the turbine exhaust pressure flows into the condenser where it is cooled to become condensed water while the heat quantity possessed by the steam is discharged into the cooling water of the condenser.

39

Fig.2.4.2.1

Heat loss by exhaust gas Mechanical loss Generator

loss Cycle loss In-station

motive power

Turbine end output (D)

Gross electric output

Net electric output (F)Boiler fuel

(A) (E)Turbine room heat input (B) Heat discharge

loss (G) to condenser

Boiler auxiliary steam (C)

40

With oil fired thermal power use boilers, furnaces into which air is forced drafted by a force draft fan are widely adopted. With this system, operation is performed with the pressure inside of the furnace or flue higher than the atmospheric pressure and therefore caution must be exercised on leakage of gas and measures taken. Also, in the case of coal fired boilers, blast furnace gas or coke oven gas burning boilers, a balanced draft system in which the gas pressure inside the furnace is maintained slightly lower than the atmospheric pressure by an induced draft fan is mainly adopted.

The reason for this is that with coal fired boilers, consideration is made for ash leakage and with blast furnace gas and coke oven gas fired boilers, the fuel gas containing a large amount of CO is hazardous and the supplied pressure of fuel gas is low. With boiler capacity becoming greater, the consumed motive power of force draft fans and induced draft fans also becomes greater and therefore it becomes necessary to restrain the draft loss of the convective heat transfer surface to a suitable value. Table 2.4.2.1 shows an example of draft loss of respective parts of a large capacity boiler of the coal fired balanced draft system.

Table 2.4.2 .1Example of draft loss of a boiler (Calculated values at maximum continuous load)

Items Draft loss kPa

Air (secondary) side pressure loss Forced draft fan inlet air duct and silencer 0.54 Forced draft fan outlet air duct 0.43 Air preheater 1.37 Air preheater outlet - Burner wind box inlet air duct 0.59 Burner wind box 1.47

Total

4.40

Gas side pressure loss 1.37

Superheater - Economizer 1.03 NOx remover 1.52 Air preheater 1.59 Gas, gas heater, and electrostatic precipitator 0.84 Economizer outlet - Induced draft - fan inlet flue and silencer 1.06 Induced draft fan outlet flue and chimney

Total

7.41

Total pressure loss of air and gas 11.81

2.4.2.2 Boiler When calculating boiler efficiency, it is necessary to clarify whether the standard of the fuel calorific value is of

a high level calorific value containing latent heat of vaporization at the time the moisture from hydrogen in the fuel becomes steam or whether it is of a low level calorific value in which latent heat of vaporization is deducted from the high level calorific value. In this chapter, explanation is provided with high level calorific value as the standard.

As a method to obtain boiler efficiency, the quantity of heat which is transferred to the feed water in the boiler and used to generate steam is compared with the heat quantity which should be generated by the combustion of the fuel fed to the furnace. This is called the heat input output method and is expressed by the following equation.

)1(%100)h-(hWefficiencyBoiler l0 s⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅×=

hf HG

Where WS is the boiler steam quantity kg/h, h0, h1 is the generated steam and feed water enthalpy kJ/kg, Gf is the fuel consumed quantity kg/h, and Hh is the high level calorific value of fuel kJ/kg.

As another method, the boiler heat loss is calculated from the exhaust gas temperature and the exhaust gas amount after passing the entire generating surface of the boiler, (the outlet if there is an air preheater) and by deducting this from 100%, the boiler efficiency is obtained. This is called the heat loss method and is calculated by the formula mentioned later. The heat loss becomes less as the exhaust gas temperature is lowered and boiler efficiency rises but for this a larger air preheater generating surface is required and facility expenses increase. Additionally, in the case where fuel containing sulfuric content is used, the problem of low temperature corrosion (sulfuric corrosion) occurs and therefore it is important to select a suitable exhaust gas temperature in planning the boiler. In current boilers, the exhaust gas temperature is set at 130 - 150°C with coal and heavy oil (crude oil) fuel, at 165°C with high sulfuric content heavy oil, etc, and around 100°C with gas fuel but with certain fuels, normally an environment preserving device (Electric dust collector, desulfurizing equipment) is installed for the back wash and therefore it is necessary to optimize the exhaust gas temperature in the entire facility including this. (1) Dry exhaust gas loss L1

Out of the heat loss by the exhaust gas discharged from the outlet of the boiler (air preheater), when the portion by latent heat of dry gas is assumed to be:

Gdry : Dry gas amount per 1 kg of fuel kg/kg Cg : Average specific heat of dry gas ≒１.0 kJ/kg°C tg : Air preheater outlet exhaust gas temperature °C to : Boiler efficiency standard temperature °C

)2(%100)t-(tCGL ossdry1 ⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅×=

hH

(2) Loss L2 by hydrogen moisture in the fuel Out of the heat loss by the exhaust gas exhausted from the boiler (air preheater) outlet, the loss caused by

evaporation of the moisture produced from hydrogen in the fuel and the contained moisture during combustion of the fuel and moreover the loss caused by heating up to the temperature of exhaust gas and discharged:

Where; Mf : Moisture produced from hydrogen in 1 kg of fuel and the moisture kg/kg contained in the fuel ∆hR : Latent heat of vaporization contained in moisture ≒ 2,500 J/Ks Cm : Average specific heat of steam ≒ 1.9 J/kg°C Cw : Specific heat of water at reference temperature ≒4.2kJ/kg°C

)3(%100)t-C-t-C(ML swsmhR f2 ⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅×

+∆=

hH

41

42

(3) Loss L3 by moisture in the air Out of the heat loss by the exhaust gas which is discharged from the boiler (air preheater) outlet, the loss caused

by latent heat of moisture contained in the air for combustion is assumed to be: MA : Moisture contained in air for combustion per 1 kg of fuel, whereby:

)4(%100)t-(tCML os aa3 ⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅×=

hH

(4) Loss L4 by radiation heat It is difficult to accurately obtain the heat loss radiated into the atmosphere from the peripheral walls of the

boiler and appurtenant facilities. This loss becomes proportionally smaller with large capacity boilers because their surface area becomes relatively smaller and also because the radiation heat amount is roughly constant irrespective of the load; the proportion of loss becomes smaller as the load becomes larger. (5) Loss L5 by unburned fuel gas

This is the heat loss due to the combustible gas remaining such as CO in the fuel gas because of incomplete combustion.

)5(%100)CO()CO(

)CO(H

C23,700L2h

5 ⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅×+

××

=

Where;

23,700 : Lost heat amount kJ/kg when carbon becomes CO by incomplete combustion of carbon in the fuel

C : Combusted carbon amount kg/kg in 1 kg of fuel (CO, CO2 ) : CO and CO2 density vol. % in exhaust gas

Besides the above, there is combustible gas loss by unburned hydro-carbons and H2 but these are of minute amounts which can be neglected in current commercial use boilers.

(6) Loss L6 by combustion residue This is heat loss mainly by unburned carbon in the combustion residue by combustion of solid fuel.

)6(%100H

C'900,33Lh

6 ⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅××

=

Where

33,900 : Combusted heat amount KJ/Kg of carbon C’ : Unburned carbon amount KJ/Kg per 1 kg of fuel

This heat loss in liquid and gaseous fuel is negligible. (7) Other loss L7

Besides the above, there are small losses such as by carrying out of combusted ash or steam atomizing or heat losses which cannot be measured or for which the cause is unknown and these are treated as other losses. Errors of measuring instruments may be included in this loss.

From the above heat losses, boiler efficiency may be expressed by the following equation

)7(100efficiencyBoiler 7

1⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅−= ∑

=lLi

Table 2.4.2.2 shows examples of boiler efficiency and heat loss of commercial use boilers for exclusive firing of heavy (crude) oil, of natural gas and of coal.

With natural gas, the hydrogen content during combustion is approximately double that of heavy (crude) oil and therefore the loss by hydrogen moisture content during combustion is great. Since the exhaust gas temperature is low, dry exhaust gas loss is small but boiler efficiency becomes approximately 2% lower compared with heavy (crude) oil. Also with coal, the hydrogen content during combustion is even less than that of heavy (crude) oil and therefore even when loss by unburned carbon is considered, boiler efficiency tends to become the highest among the three fuels. However, coal characteristics will differ greatly by origin and caution must be exercised in the evaluation of its efficiency.

Table 2.4.2.2 Examples of heat loss by boiler efficiency (Calculated values by rated loads)

Heavy (crude) oil

exclusive boiler Natural gas

exclusive boiler Coal exclusive

boiler Exhaust gas temperature (Air preheater outlet)

°C 140 99 135

Excessive air factor (Air preheater outlet)

1.14 1.16 1.20

Boiler heat loss Dry exhaust gas loss % 4.33 2.70 4.31 Loss by hydrogen content during combustion

% 6.53 10.19 4.03

Loss by moisture content in air % 0.07 0.05 0.09 Loss by radiation heat % 0.17 0.17 0.17 Loss by unburned fuel gas % 0.00 0.00 0.00 Loss by combustion residue % 0.00 0.00 0.52 Other losses % 1.00 1.00 1.50

Total % 12.10 14.11 10.62 Boiler efficiency (Higher calorific value standard)

% 87.90 85.89 89.38

43

Boi

ler e

ffici

ency

(Hig

her c

alor

ific

valu

e st

anda

rd) (

%)

Coal fired boiler

Heavy (crude) oil firing boiler

Natural gas fired boiler

Boiler load (%)

Fig. 2.4.2.2 Relation between boiler efficiency and boiler load

Also, in general, with heavy (crude oil) fired boilers, the air preheater low temperature end average metal temperature is controlled by a steam type air preheater and as a result, the lowering of exhaust gas temperature at low load is small and boiler efficiency becomes maximum between the rated load where excessive air factor is low to 75% load.

On the other hand, with exclusive natural gas fired boilers and exclusive coal fired boilers, the exhaust gas temperature drops greatly with lowering of load and therefore boiler efficiency tends to become maximum with a load of around 50 to 75%. At loads lower than this, boiler efficiency tends to drop because of the increase in dry exhaust gas loss by the increased excessive air factor and increase in radiation loss. (Fig. 2.4.2)

44

2.4.2.3 Steam Turbine Turbine performance (turbine room performance, turbine plant performance) is expressed with the use of the

terms, heat rate, thermal efficiency, internal efficiency, etc. (1) Heat rate, thermal efficiency, steam consumption ratio

Turbine heat rate is the quantity of heat required to produce 1 kWh of electricity and is expressed by the following equations. 1. In the case of non-reheat turbines

)1(H ⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅−−

==s

eewwss

sR

LiGiGiG

LQ

2. In the case of reheat turbines (Fig. 2.4.2.3-1)

)2()(H'

⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅−−+−

==s

eerrrwwss

sR

LiGiiGiGiG

LQ

Boiler

Fig. 2 .4.2.3-1 Turbine reheat cycle

Where:

HR : Turbine heat rate (kJ/kWh) Q : Quantity of heat consumed by the turbine (kJ/h) Lg : Generator end electric output (kW) GS : Turbine inflow steam quantity (kg/h) iS : Turbine inflow steam enthalpy (kJ/kg) GW : Feed water quantity to boiler (kg/h) iw : Feed water enthalpy to boiler (kJ/kg) Go : Quantity of steam to outside of turbine plant such as boiler auxiliary steam (kg/h) io : Steam enthalpy to outside of turbine plant such as boiler auxiliary steam Gr : Quantity of reheated steam ir : Medium pressure turbine flow in steam enthalpy (kJ/kg) ir’ : High pressure turbine outlet steam enthalpy (kJ/kg)

The definition of turbine heat rate may be expressed in two ways, either gross or net, depending on whether feed water pump drive motive power is considered or not.

LP turbine Turbine HP turbine

Boiler auxiliary steam etc.

Condenser

#5 Heater #6 Heater

Condenser pump

#1 Heater 2 Heater #3 Heater Deaerator

Feed water pump Low pressure pump

45

a. In the case of feed water pump electric drive

)3(⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅=sL

QRateHeatGross

)4(⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅=− BFPs LLQRateHeatNet

b. In the case of water feed pump turbine drive

)5(⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅=+ BFPs LLQRateHeatGross

)6(⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅=sL

QRateHeatNet

Where LBFP : Motive power required for feed water pump Turbine thermal efficiency ηt is expressed by the following equation.

)7(%100600,3⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅×=

Rt

Hη

According to Fig. 1, this is

)8(%100)()(

)(⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅×

−=

CBE

tη

Moreover, the following definitions are used to express efficiency of the generation plant.

)9(%100)()(efficiency malplant ther Gross ⋅⋅⋅⋅⋅×=

AE

)10(%100)()(efficiencyheat plant Net ⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅×=

AF

The two factors which affect turbine heat rate and thermal efficiency are steam conditions of boiler steam production, condenser vacuum degree, feed water temperature and feed water heating steps, etc. namely the heat cycle conditions are the performance of the turbine itself. Fig.2.4.2.3-2 shows the trends of unit capacity and thermal efficiency of commercial use reheating turbines.

Vacuum degree 5.1 kPaa (722 mmHg)

Turb

ine

ther

mal

effi

cien

cy (%

)

31 MPa class

24 MPa class

16.6 MPa class

12.5 MPa class

10 MPa class

Output (MW)

Fig. 2.4.2.3-2 Unit capacity and turbine thermal efficiency

46

(2) Turbine internal efficiency, turbine efficiency To express the performance of the turbine itself, turbine internal efficiency and turbine efficiency are used.

Internal efficiency ηi is expressed by the ratio between steam adiabatic heat drop Ho (Theoretical work load of zero loss steam) and heat drop Hg effectively used.

)11(%100/ ⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅×= og HHiη

Figure 2.4.2.3-35 shows the steam condition (Pressure, enthalpy functions) in the case of the reheating turbine and the internal efficiency of the high pressure turbine, medium pressure turbine and low pressure turbine are expressed by the following quotation.

Fig.2.4.2.3-3 5 Reheating turbine steam expanded diagram (i-s diagram)

Pressure: Px: Turbine main steam check valve inlet P0: 1st step nozzle inlet P1: High pressure turbine outlet Pr: Before medium pressure turbine reheat

stop valve P2: Medium pressure 1st step inlet P3: Medium pressure turbine outlet P4: Low pressure turbine inlet P5: Low pressure exhaust (Condenser inlet)∆EL: Exhaust loss

Saturation line

High pressure turbine

)12(1

'

⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅−−

==iiii

HH

s

rs

Ho

eHIHη

Medium pressure turbine

)13(3

4 ⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅−−

==iiii

HH

r

r

lo

elItη

Low pressure turbine

)14(54

64 ⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅−−

==iiii

HH

Lo

eLILη

Turbine efficiency is the ratio between theoretical work and effective work, and is the product of internal efficiency and mechanical efficiency. The relation between the turbine efficiency ηr of a back pressure turbine or a simple condenser turbine and the steam specific consumption SR (Kg/kWh) is as follows:

)15(600,3⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅==

steS

SR

HPGS

ηη

Where: GS : Inflow steam quantity (Kg/h) Pg : Generator output (KW) Ho : Adiabatic heat drop inside turbine (KJ/kg) ηg : Generator efficiency

47

(3) Heat balance (Heat balance diagram) Steam expanded diagram Figure 5 is an example of a reheating turbine heat expanded diagram. The pressure, temperature, enthalpy or

quantity of steam of each part of the turbine, based on the expanded diagram shown in the diagram are called the heat balance diagram. Figure 2.4.2.3-4 shows a 1,000,000 kW heat balance diagram. The manner of steam expansion, the condition of steam at each part, turbine extraction, etc, are normally obtained by performance calculation by turbine makers. The heat balance around the feed water heater periphery is calculated by the following procedures.

High pressure turbine

Low pressure turbine (A)

Medium pressure turbine

Fig. 2.4.2.3-4 Example of 1,000 MW supercritical pressure turbine heat balance

(1) Piping pressure drop from the turbine extraction point to the feed water heater is normally maintained at

around 5% of the pressure (2.5 - 12%). (2) Temperature inside the feed water heater becomes the saturation temperature of the extraction pressure. (3) The feed water heater outlet feed water temperature is selected to be 2.5 to 5°C lower than the saturation

temperature inside the heater and feed water heater to be designed. (In the case of a direct contact type such as a deaerator, the outlet feed water temperature is to be the same as the saturation temperature and also in the case where the extraction temperature is fairly higher than the saturation temperature in reheating steam turbines, etc., this temperature may be utilized with a superheat reducing section provided inside the feed water heater with the feed water selected to be 0 - 3°C higher than the saturation temperature. (Refer to Chapter 2, Clause 3.4)

(4) When a drain cooler is provided in the water feed heater, the drain outlet temperature is designed to be 5 to 10°C higher than the water feed temperature.

(5) Taking the No. 5 heater in Fig. 2 as an example, the extraction amount necessary for the water feed heater is obtained by the following procedure. (However, the heat discharge loss is to be neglected.) Gx (ix-i14) = Gw(i12-i11)-Gd(i13-i14)

Where: Gx : Extraction quantity (Heated steam quantity) ix : Extraction enthalpy Gw : Feed water quantity i11 : Feed water heater inlet feed water enthalpy i12 : Feed water heater outlet feed water enthalpy Gd : Inflow drain quantity i13 : Inflow drain enthalpy i14 : Outflow drain enthalpy

Boi

ler Low pressure

turbine (B)Condenser

Make up water

Condenser pump BFP turbine

Grand steam condenser

Condensate booster pump

Boiler feed water pump Drain pump Feed water booster pump

48

2.4.2.4 generator (1) Available output curve

Figure 2.4.2.4-1 shows an example of available generation output curve. This curve is divided into parts (A), (B), and (C).

Lagg

ing

phas

e Le

adin

g ph

ase

Fig. 2.4.2.4-1 Available output curve

(A) Range restricted by rotor coil temperature (B) Range restricted by stator temperature (C) Range restricted by stator core end part temperature

1) Range restricted by rotor coil temperature

The restrictions by rotor coil temperature may be obtained under the conditions of a constant field current. Namely, this may be obtained by the V curves shown in Fig. 2.4.2.4-2 36, whereas a line parallel to the axis of the ordinate is drawn through field current 1f at the rated load and rated power factor, and the intersecting point of the line with the respective V curve power factor is plotted on the MW-MVAR coordinate to obtain the restriction by rotor coil density.

Terminal voltage=Rated Voltage

Out

put (

MVA

)

Field current (A)

Fig. 2.4.2.4-2 V curve

2) Range restricted by stator coil temperature Restriction by the stator coil temperature may be obtained from constant conditions of the stator current. It

becomes a circle which passes through rated point P with the origin point as the center of the circle.

49

3) Range restricted by the stator core end part temperature The cause for increasing of temperature of the stator core end part in the leading phase range is that the

composite magnetic flux from the magnetic flux by stator coil end magnetomotive force and the magnetic flux by rotor coil end magnetomotive force increase with a lower excitation (leading power factor) and the eddy current of the core end part becomes greater. This upper limit is higher with machines with a larger short circuit ratio but with recent large capacity machines with large electrical charge, the end part temperature increase tends to become large and therefore overheating is prevented by core end magnetic shield, core end slit, core end stage, non-magnetic finger plate, non-magnetic rotor coil retaining ring, etc. (2) Resistance capacity to short period overload

Loads exceeding the available output curve even though for short periods will result in a rapid increase of temperature and therefore repeated overload operation is not desirable because the service life of the generator coil will be shortened, but there is a permissible range in which the insulation is not greatly affected. Table 2.4.2.4-12 shows the overload permissible limit specified by ANSI C50-13. Table 2.4.2.4-1 Short period overload resistant amounts

Time (seconds) 10 30 60 120 Armature current (%) 226 154 130 116

Field voltage (%) 208 146 125 112

(3) Continuous unbalanced load resistance

When a generator is operated under unbalance load or by single phase load, a negative phase current flows in the stator coil and as a result, the revolving field which revolves in the opposite direction at the same speed turns off the rotor and an eddy current of double frequency flows on the surface of the rotor and the rotor wedge and the rotor overheats. Especially in the part in which the eddy current concentrates, if the unbalance becomes serious, burning may result by local overheating.

The permissible limit of continuous unbalanced load is greatly affected by the material and structure of the equipment and cannot be specified in one manner. Table 2.4.2.4-2 shows the permissible limit proposed recently by ANSI where limitations are made more severe with large capacity machines.

Table 2.4.2.4-2 Unbalanced load resistance Continuous unbalanced

load I2(%)

Short period unbalanced load I2t*

Indirect cooling loss 10 30 Direct cooling loss 10 - 800 MVA 801 – 960 MVA

8

951 – 1,200 MVA 6 1,201 – 1,500 MVA 5

I2t = 10 – 0.00625 (MVA – 800)

*I2 (P.U.) t (Seconds) (4) Short period unbalanced load resistance

At the time of short period unbalance load such as by one-line ground and line short circuit, the double frequency eddy current flows on the rotor surface and the rotor overheats for the same reason mentioned in clause 6.3. The most severe failure by rotor overheating is line short circuiting.

Where the negative phase current is /2, a failure continuation time of 1 second, the temperature rise of the rotor is proportional to tdt but with consideration of equivalent negative phase current/

22

/∫ot

2SQ which gives the same

temperature rise in t seconds, adopting of /22sqt as the scale is widely accepted. With large capacity machines, the rotor is of light weight compared with the capacity, and therefore the

reduction of relative thermal capacity was considered and i22t<30 for indirect cooling machines and i22t/≤10 was generally adopted but with the recent super large capacity generators, the limitations shown in Table 3 have been proposed to ANSI. (5) Efficiency

Generator loss consists of core loss, mechanical loss, stator I2R loss, stray load loss, and world magnetic I2R loss.

50

1. Core loss If the used material is assumed to be the same, core loss relates to magnetic flux density, frequency, and stator

core weight, and with their increase, core loss increases. 2. Mechanical loss

Mechanical loss consists of bearing friction loss and windage loss. Since windage loss is proportional to gas density, the windage loss of hydrogen cooling machines is extremely smaller than that of air cooling machines. This is one of the advantages of the hydrogen cooling machine. Bearing friction loss increases in an exponential function manner with increases in revolutions and journal diameter. 3. Stator I2R loss and stray load loss

Stator I2R loss is proportional to the square of the stator current and stator coil average length/coil cross sectional area. In addition, surface loss is affected by void length and winding pitch, becoming smallest with a 5/6 winding pitch and loss decreases as void length increases. 4. Field I2R R Loss

Field I2R Loss is proportional to the square of the field current and field resistance but as shown in the V curve of Fig. 36, more field current becomes necessary with the same output as the power factor becomes lower and loss increases.

Figure 2.4.2.4-3 shows the generator efficiency and changes in efficiency by partial load of a typical capacity generator. As shown in this figure, in general, in the case of standard specification generators, efficiency tends to become better with larger capacity. Also, in regard to partial load, core loss and mechanical loss are constant and therefore efficiency rapidly worsens with low load but in the case of hydrogen cooling machines, lowering of gas pressure inside the machine and operating at low load is possible and as a result, windage loss decreases and normally, the maximum efficiency rate is displayed at 70 - 80% load.

Gen

erat

or e

ffici

ency

(%)

Load (%)

Fig. 2.4.2.4-3Generator efficiency curve

2.4.2.5 Condenser facilities

Vacuum degree control of condenser facilities, causes of vacuum degree lowering and their judgment, as well as restoring means and the appropriate number of circulating pumps to be operated are decided. (1) Desired value of vacuum degree

In regard to the daily desired vacuum degree of condensers, a control value is set against the design value when the respective units are installed.

Figure 2.4.2.4-4 shows the philosophy on desired values. The control width of the vacuum degree is set with consideration of accuracy of instrumentation, cleanliness of tubing, and dispersion of the performance record. With an increase in the vacuum degree when the cooling water temperature is low, turbine specific heat changes

51

from decreasing to increasing and since there is a risk of problem occurrence in the facilities, the vacuum degree is controlled so that it does not exceed the efficiency limit vacuum degree. (2) Facility control

By the frequency of operation and data measurements of the respective facilities, difference control of the desired value of the vacuum degree is being conducted.

The following shows the general control items. Operation control of the ball cleaning device Control of electrolytic protection device Measuring of vacuum pump extraction quantity Control of instrumentations Tubing brushing cleaning Cleaning of the inlet channel and circulating pump chamber

(3) Disposition to adopt when deviation is seen from the desired value of the vacuum degree First, check to see if there is any abnormal condition of instrumentation and when confirming, pay attention to

the following points. Drain accumulation in the detection piping Temperature compensation if the standard temperature differs between the mercury vacuum gauge and

the atmospheric pressure gauge. Difference between the atmospheric pressure compensated vacuum degree and the transmitter side. Whether there is any abnormal condition in the correlation between the atmospheric compensation value

of the mercury vacuum degree gauge and the respective temperatures of the exhaust room and hotwell. Any abnormal condition of the mercury vacuum degree and atmospheric temperature gauge at the time

of periodic checking.

Vacu

um

degr

ee

Upper limit of vacuum degree

Efficiency limit vacuumdegree Vacuum degree

desired value Lower limit of vacuum degree

Turbine specific heat consumptioncorrection coefficient (%)

Sea water temperature (°C)

Area A--- Desired value (Design value ± α) Area B --- Area in which checking of the vacuum degree related instruments

should be checked. Area C--- Area in which cause should be investigated and measures

conducted.

Fig. 2.4.2.4-4 Philosophy on desired value of vacuum degree.

(4) Investigation method of cause for deviation of vacuum degree from the desired value When a deviation seen from the vacuum desired value is found with measuring instruments in a normal state, in

general, investigate the following. 1.Increase in leak in quantity of air

The lowering of the vacuum degree occurs when leak in exceeds the extraction capacity of the vacuum pump. 2.Lowering of cleanliness of tubing

With no increase in the leak in air amount and with the vacuum pump found to be normal, the cause of lowering of the vacuum degree is often caused by the lowering of cleanliness of the tubing. 3.Lowering of the cooling water volume

When the cooling water volume drops, an increase of difference in the cooling water inlet, outlet temperature ( T), increase of CWP discharge pressure, and lowering of the condenser water chamber level occurs, and an abnormality of the condenser side (tubing clogging, siphon cut-off, etc.), abnormality of the CWP side ‘CWP

52

performance lowering, CWP chamber water level lowering, check washing valve seat leak, etc. are conceivable. 4.Abnormality of the vacuum pump

When an abnormality of the vacuum pump is seen, conduct changeover testing with a spare machine and compare the respective air extraction amount and vacuum degree.

Also, since the seal water relations of the vacuum pump greatly affect the vacuum degree, pay attention to the following points.

a. Increase in seal water temperature by contamination of the seal water cooler, increase of bearing cooling water temperature.

b. Shortage of seal water by abnormality of the seal water pump, clogging of the discharge strainer of the pump, etc.

c. Lowering of water level by malfunctioning of float valve for seal water tank water level adjustment 5.Increase of condenser heat load

The desired value of the vacuum degree is calculated from the design heat load, cooling water amount, and heating surface, etc. and if the heat load increases above the design value, even if the cooling water volume and others are in accordance with designed values, the vacuum degree decreases. Especially, with the once-through boiler unit, leakage of the respective bypass valves from the start-up bypass system to the condenser causes lowering of thermal efficiency and care should be exercised. (5) Performance curve

The vacuum degree of the condenser is affected by the condenser load, cooling water inlet temperature, and cooling water volume. Condenser pressure is obtained from saturation steam temperature ts.

pppc

s

e

ttt

ecG

Qtt11

1)11(

121

−

−+=

−×××+=

γ (1)

Where

γ×××

=pc cGKAp (2)

Figure shows an example of the condenser performance curve. The condenser pressure change at the time of changes in condenser heat load and cooling water inlet temperature when the cooling water volume is constant is shown. When the condenser pressure is recorded by the elapse of time in this curve, the contamination coefficient, etc. of the cooling pipe may be assumed. This curve is a straight line at the time of no load to a certain load. When the condenser load is small or the inner pressure is low, the condenser pressure is restricted by the performance of the air extraction device and there are cases where the pressure to be obtained by equation (1) cannot be obtained.

53

Fig. 2.4.2.4-5 Assumed performance curve of the condenser 2.4.2.6 High pressure water feed heater

In a condition with a constant rated output, to measure the water feed outlet terminal temperature difference (T.D.) as well as the drain outlet temperature difference (D.C.), the following data items are collected, evaluated and countermeasures executed.

Water feed temperature (inlet, outlet) of the respective high pressure water feed heater Extraction temperature, pressure of the respective high pressure water feed heater Drain outlet temperature of the respective high pressure water feed heater Inner pressure of the respective high pressure water feed heater Drain flow rate of the respective high pressure water feed heater Drain level of the respective high pressure water feed heater Drain water level adjusting valve opening of the respective high pressure water feed heater Water feed pressure loss

The water feed outlet terminal temperature difference (T.D.) and the outlet temperature difference (D.C.) are obtained from the following equations

T. D=TS-TW (OUT) D.C= Td-TW (IN)

Where T.D. : Water feed outlet terminal temperature difference (°C) D.C. : Drain outlet temperature difference (°C) TS : Saturation temperature (°C) to water feed heater inlet steam pressure TW (OUT) : Water feed outlet temperature (°C) Td : Drain outlet temperature (°C) TW (IN) : Water feed outlet temperature (°C)

(1) The effect by the water feed heater performance on the turbine cycle a. The number of water feed heater units and temperature increase

Although decided with consideration of the heater output and economy, in general, from an economical aspect, 6 to 8 heaters are installed for 200 MW and over. There is a close connection between the number of water feed heaters and temperature increase and in regard to water feed temperature rise per unit of water feed heater, it is

54

desirable to raise the temperature evenly with heaters of less than the reheating point in the one step reheating cycle. From the aspect of performance, it is optimal to plan to increase the average temperature rise at the low pressure feed water heater rather than to increase the temperature of the feed water reheater by extraction from the reheating pump.

This temperature rise is restricted by the thermal stress, etc. of the water chamber and normally, the increase is suppressed to around 20 to 75°C. (2) Effect by terminal temperature difference (T.D.) change

To obtain the effect on turbine heat rate by T.D. changes, the extraction quantity changes to the respective water heat heater T.D. change are calculated, and with the turbine inlet steam quantity kept constant, the heat rate may be obtained from the extraction quantity change and output quantity change. The following shows an example of calculation in regard to a high pressure feed water heater.

a. Trial calculation data Subject unit 600MW At rated output, when T.D. is +3°C

b. Trial calculation results Decrease of extraction quantity by T.D. increase EXT

Turbine room input heat increase by reheated steam quantity increase by extraction quantity decrease by T.D increase

Exhaust quantity increase by extraction quantity decrease by T.D. increase

Increase of exhaust loss heat quantity by exhaust quantity increase

Output heat decrease from the turbine room by feed water temperature decreasing

Increase of turbine room consumption Q

55

Condenser

G : Flow rate kg/h T : Temperature °C I : Enthalpy kcal/kg CRH, HRH : Low, high temperature

reheated steam EXT : Extraction EXH : Exhaust FW : Water feed I, O : Inlet, outlet COND : Condensed water

Output change

(increase)

Turbine room thermal efficiency HR’ after T.D. increase

Reference heat consumption

Reference output

Heat rate change ratio

Gross thermal efficiency change quantity

2.4.2.7 Boiler exhaust gas control

Together with the reduction of boiler exhaust gas loss and saving of fuel expenses, to reduce the running costs of boiler operation and maintenance expenses, and repair expenses, and attempt to improve overall efficiency, control values are set on the AH low temperature part average temperature, exhaust gas temperature control exhaust gas O2 value, and AH air leakage ratio and control are executed. (1) AH low temperature average temperature control

In accordance with the sulfuric contents in the used fuel, the optimum value is set for each boiler with sulfuric

Reference output

Reference specific heat consumption (HR)

Reference output

56

acid dew point measurement etc. as a reference and upon confirming the corrosion situation of the AH element, etc. staged lowering is attempted. It is desirable to set the average temperature control value at the maximum point of sulfuric acid condensation quantity in accordance with the sulfur contents of the used fuel but reduction should not be made in one stroke but in stages with consideration of the following points and confirming that there are no problems.

Deviation of the theoretical value and actual record value of the sulfuric acid dew point The relation between the sulfur contents in the fuel and produced SO3 density. Local metal temperature drop by unbalance of gas temperature distribution

(2) Exhaust gas temperature control The AH outlet exhaust gas temperature differs greatly by boiler according to the boiler and AH structure, and

the kind of fuel and since it fluctuates greatly by factors such as load and atmospheric temperature and air leakage of AH, it is difficult to set a standard but it is set upon executing of countermeasures on temperature decrease of exhaust gas by each boiler, conducting an actual machine test with the AH element in the best condition, with the air leakage in the minimum condition and based on these results, with exhaust gas control data as a reference and with the atmospheric pressure as the parameter. The deviating trend to the control value is grasped and when the deviation is large and continuous, the following deviation factors are analyzed and appropriate measures are to be taken.

Lowering of exhaust gas temperature by increase in AH air leakage amount Aging deterioration by corrosion, wear of AH, and rising of exhaust gas temperature by lowering of AH performance by staining of the heating surface, etc.

Increase of exhaust gas temperature incident to dry gas quantity increase by Combustion gas O2 (Excess air factor)

Those by characteristic changes of the fuel. (3) Control of exhaust gas O2

The Eco outlet combustion gas O2 differs by each boiler, depending on the boiler, combustion method, and type of fuel. Therefore, a combustion test is to be made after improvement of combustion facility or after periodic inspection as required, O2 distribution is to be measured, abnormality of instruments, inappropriateness of detection point, faulty combustion, etc., deviation factors from control values are to be analyzed, and if a large deviation situation continues, the O2 meter, burner tip, and body, and damper are to be checked for combustion air or exhaust gas O2 distribution is to be measured and suitable measures taken. (4) AH air leakage ratio

The temperature of the gas which passes the boiler will differ depending on the boiler condition (cold boiler hot boiler, etc.) which in turn effects changes in the amount of heat deformation. Therefore, to prevent leakage of AH air, the setting of respective seals is calculated in advance and the gap value is set in a cold boiler condition so that the clearance becomes minimum in rated load operation but a certain amount of leakage is unavoidable. However, with the new type AH, with the improvement of the seal plate supporting method and additions to the seal section, direct leakage from the seal gap has been improved compared with the old type. Furthermore, to reduce leakage from the high temperature side radial seal which was the greatest leakage factor during operation, a sensor drive system of the high temperature side sector plate has been developed. With this system, the rotor shaft side that controls the gap between the sector plate and seal to a minimum under any boiler operation condition is structured so that it constantly follows the contraction-expansion of the rotor, and control is conducted so that only the gap of the rotor periphery and sector plate outer end section gap becomes minimum.

2.5 Example of Operation Control and Performance Management (Hokkaido Electric Power Co., Inc) 2.5.1 Overview of Hokkaido Electric Power Co., Inc.

Hokkaido Electric Power Co. Inc. was established in May 1951 to supply electricity in the Hokkaido region.

With an area of about 83,500km2 and a population of 5.7 million, Hokkaido is flourishing in agriculture, fishery and tourism. The capital city, Sapporo, with a population of 1.7 million, located at 45 degrees at north latitude, once hosted the winter Olympics in 1972, and has held “Sapporo Snow Festival” every February visited by numerous visitors including those from foreign countries.

Hokkaido Electric Power Co., Inc., established on May 1, 1951, has the headquarters in Sapporo and has been engaged in electric power generation, transmission and distribution by about 5,800 employees. Table 2.5.1-1shows the electric energy sale, the supply facilities and transmission and distribution facilities.

Electric energy demand Total 30,833 GWhYear 2005 Electric light 11,540 GWh Electric power 2,218 GWh Specific scale 17,075 GWhSupply facilities Total 66 places 6,505 MW Hydro-electric power station 53 places 1,231 MW Thermal power station 12 places 4,115 MW Nuclear power station 1 place 1,158 MWTransmission and distribution facilities Transmission distance 8,230 km Transforming station 369 places 19,300 MVA Distribution line distance 66,753 km

Table 2.5.1-1

The company has 12 thermal power stations. The breakdown is shown in Table 2.5.2.

Steam power station 6 places 3,900 MW Gas turbine power station 1 places 148 MW Internal combustion power station 4 places 17.4 MW Geothermal power station 1 places 50 MW

Table 2.5.1-2

Fig. 2.5.1 Thermal Power Stations of Hokkaido Electric Power Co. Inc.

Okhotsk Sea

Japan Sea Sunagawa power station

Naie power stationOnbetsu power station

SapporoDate power station

Tomatouatsuma power station

Tomakomai power stationMori power station

Pacific OceanShiriuti power station

57

2.5.2Overview of Coal Thermal Power Station The steam power stations are six places include seven units of coal thermal power stations in three places. The outline of the facilities of these seven units is shown in Table 2.5.3.

Start of operation

Authorized output Main steam Reheat steam Boiler type Boiler

efficiency Turbine

efficiencyUnit

efficiency Name Date MW

Fuel Pressure (MPa)

Temperature (℃)

Temperature (℃)

No.1 unit Oct., 1980 350 16.6 566 538 Natural circulation 87.28 45.03 39.41 No.2 unit Oct., 1985 600 24.1 538 566 Supercritical once-through 87.91 47.70 41.93 Tomatouatsuma No.4 unit Jun., 2002 700

Foreign coal 25.0 600 600 Ultra supercritical

once-through 88.73 49.83 44.21

No.1 unit May, 1968 175 16.6 566 538 Natural circulation 87.08 45.14 39.26 Naie No.2 unit Feb., 1970 175 16.6 566 538 Natural circulation 87.08 45.55 39.40 No.3 unit Jun., 1977 125 12.5 538 538 Natural circulation 85.72 43.63 37.41 Sunagawa No.4 unit May, 1982 125

Domestic coal

17.7 538 538 Subcritical once-through 86.27 45.40 39.16

Table 2.5.2

2.5.3Practice in Tomatouatuma Power Station 2.5.3.1 Organization and Service

This power station is operated by 102 personnel in three divisions. The operation of environmental facilities has been outsourced to the affiliated companies. Fig. 2.5.3-1 shows the organization and service.

58

Power Station Organization and Operation /Management System

Fig.2.5.3-1 Power Station Organization Operation /Management of Power Stations

Machinery staff

Electrical

Measurement staff

Maintenance Div.

Business staff

Environment Engineering Staff

Operation staff

Management staff

Environment Facility Staff

Generation Div.

Environment Engineering Div.

Deputy manager

Station manager

Planning and management of maintenance, repair of facilities and daily maintenance as well as repair and maintenance works

1. Supervision, communication, PR, investigation planning/execution of environmental conservation matters

2. Operation/management of smoke, feed/waste water, ash handling facilities, environment monitoring facilities.

3. Investigation, test planning and execution for operation/performance of facilities 4. Treatment/management, utilization planning/execution of waste after generation 5. Analysis management, chemical investigation of fuel, boiler water, etc 6. Accident prevention/safety for hazardous materials

1. Oversight, communication, PR related power station management 2. Operation/ management of generation facilities (except Environment Engineering related) 3. Management of fuel 4. Compilation, analysis, management of operation history data 5. Investigation, test planning and execution for operation/performance of facilities 6. Press release and public hearing 7. General affairs, emergency/disaster office, PR, document control, administration 8. Personnel affairs, education, labor, welfare, safety and health 9. Accounts, land management

10. Other items not supervised by other divisions

For operation of power stations, the following shall be conducted under the supervision based on the regulations and policies stipulated by the head office (Thermal Power Dept.)

Main generation related operations outsourced to other companies

・Cleaning, greening, security, port management ・Coal stock, transportation, ash handling work ・Operation and monitoring of smoke, feed/waste water facilities ・Chemical analysis work ・Daily maintenance / inspection work

59

2.5.3.2 Operation System The power station consists of two rooms: the central control room where the boiler, turbine and generator are operated,

and the centralized management room where the environmental facilities are operated. The detail is shown in Fig. 2.5.3-2

Generation manager Environment engineering manager

Engineering assistant

manager +

4 personnel

Facility assistant manager

+ 6 personnel

Operation

management of environmental facilities

Operation management of environmental facilities

Administration deputy manager

+ 7 personnel

Control of BTG

generation facilities

Central control unit × 5 groups Operation of BTG generation facilities Centralized management

room (operation is outsourced to affiliated

companies)

Daytime shift (11 personnel)

+

× 4 groups

Operation

assistant

manager +

Operators (8

people)

Fig. 2.5.3-2

2.5.4. Management for Operating Power Station Various kinds of managements have been carried out in accordance with the standards s

Generation Facilities Maintenance and Service Manual”. 2.5.4.1 Operation Management

The “Steam Power Generation Facilities Maintenance and Service Manual” stipulates thstandard (Table 2.5.4-1), setting standard for control and permissible values for trial operation (

In addition to usual monitoring by operators, the plant operation conditions are input into coSystem Configuration) for proper control. 〇 Examples of management documents - Daily report (Table 2.5.4-4):One hour value (24 points), maximum-, minimum

one-day energy amount for the management items - Monthly report (Table 2.5.4-5):Boiler and turbine maintenance logs, month-end gen

60

Team

leader + 8

operators

Operation of environmental facilities

et forth in “Steam Power

e operation management Table 2.5.4-2), etc.

mputers (see Fig. 2.5.4-3:

-, average values, and

eration records, etc.

Table 2.5.4-1 Operational Management Standard

Measure location Record frequency

Indicator Operation management items Unit Measure values

Control values under normal

operation Recorderoffice Site

1/ day

1/ month

1/ year

As needed

Remarks

Operation time Hrs/min. Daily and monthly totals

Paralle – parallel off (Start sending air – stop for house boiler)

Generated energy MWh Daily and monthly totals

Rated output × 24 hours

Generator output MW Max value Rated output Maximum value within 1 hour Main stop valve steam pressure

MPa Max value Rated value ×

1.05

Sum up monthly the operation time 5% over rated pressure

Main stop valve steam temperature

°C Max value Rated value +

8°C

Sum up monthly the operation time at 8°C, 14°C, 28°C over rated temperature.

Reheat stop valve steam pressure

MPa Max value Rated value ×

1.05

Reheat stop valve steam temperature

°C Max value Rated value +

8°C

Sum up monthly the operation time at 8°C, 14°C, 28°C over rated temperature.

Main steam flow rate t/h Max value Smaller one of

the MCR or turbine intake

Condenser vacuum mmHg Min value Min operation Atmospheric pressure corrected value Coal (humidity) t Crude oil kl Heavy oil kl Orimulsion t

Fuel

Co

nsum

ptio

n

Diesel oil kl

Monthly total

For generation

* Over ratedShaft Under 12.5Turbine vibration amplitude 1/100mm

Max value JEAC3717 caution value*

Bearing No. Amplitude Bearing Under 6.25

61




operation Recoderoffice Site

1/ day

1/ month

1/ year

As needed

Remarks

pH (25°C) Silica µgSiO2/l

Boiler water quality Electric

conductivity µS/cm

pH (25°C) Silica µgSiO2/l Electric conductivity

µS/cm Feed water quality

Dissolve O2 µgO/l

Average value

Water quality standard value

According to “thermal power station water management manual”

RBOT minute Over 70 mins. All oxidization mgKOH/g Under 0.3 Impurities mg/100ml Under 10Kinetic viscosity (40°C)

mm2/s

(New oilstandard) ± 10%

Water content mg/l Under 500

Lubricate oil for turbine

Color phase ASTM

-

Under 4

According to “turbine oil management manual”

Gross Unit efficiency Net

%

Calculatevalue

Boiler drum water level mm Highest, lowest

Warning value

Boiler drum pressure MPa Maximum Rated × 1.05 Superheater spray flow rate t/h Maximum Max operation Reheater spray flow rate t/h Maximum Max operation Turbine ejector pressure MPa Maximum Rated × 1.05 Turbine ejector temperature °C Maximum Rated + 8°C Bearing inlet oil pressure MPa Minimum Warning value Bearing outlet oil pressure °C Maximum Warning valueTurbine contro oil pressure MPa Minimum Warning value

62

63




operation Recorderoffice Site

1/ day

1/ month

1/ year

As needed

Remarks

Control valve opness % Maximum Max operation Also possible with cum angel

Expansion of turbine shaft mm

Maximum

Managed by difference expansion warming value for more than 2 casings

Expansion of turbine shaft mm Maximum Expansion of turbine shaft, casing

mm

Maximum Warning value More than 2 casings

Turbine speed rpm Maximum Rated × 1.05

64

Table 2.5.4-2 Setting Standard for Control and Permissible Values for Trial Operation

(Boiler)

Items Unit Control value standard setting

for trail operation Permissible value standard setting for trail operation

Remarks

Generator load MW Rated output (referred to as “rated” hereafter)

Rated output (referred to as “rated” hereafter)

↓

Economizer inlet feed water MPa Design pressure for rated Design pressure for rated × 1.05

↓

Superheater inlet or main steam Steam pressure for rated Steam pressure for rated × 1.05

↓

Pres

sure

Reheater outlet steam Design steam pressure for rated

Design steam pressure for rated × 1.05

↓

Economizer inlet feed water °C Design temperature for rated MCR or max operation value ↓ Superheater inlet or main steam Design temperature for rated Design temp for rated + 8°C <

Tem

pera

ture

Reheater outlet steam Design temperature for rated Design temp for rated + 8°C <

Main steam t/h Design flow rate for rated MCR or turbine intake amount ↓ Feed water Design flow rate for rated MCR ↓ Superheater spray Design flow rate for rated MCR or max operation value ↓

Flow

rate

Reheater spray Design flow rate for rated MCR or max operation value ↓ Drum water level mm Design water level for rated Warning value ↓ ↑ Economizer gas oxygen concentration

% Object value for rated Warming value (low) ↑

Furnace kPa Design value for rated Warning value ↓ ↑ Forced fan outlet pressure Design value for rated Fan rated value ↓ Pulverizer inner pressure (For vertical mill, pressure difference of primary fan)

Design value for rated Minimum flow speed (For vertical mill, mill pressure difference corresponding to min. flow speed)

↑

Pulverizer coal surface Design value for rated Tube mill: Warning value ↑ or ↓ ↑

Wind box Design value for rated Equilibrium: lower limit, pressureized: MCR

↑

Gas mixing fan Design value for rated MCR ↓ Gas recirculating fan Design value for rated Fan rated value ↓ Induced fan inlet pressure Design value for rated Fan rated value ↓

Dra

ft

Air preheater gas outlet/inlet difference

Design value for rated MCR or max operation value ↓

Reheater inlet (superheater outlet)

°C Design value for rated MCR ↓

Air preheater inlet Design value for rated MCR or max operation value ↓

Com

busti

on g

as °C

Air preheater outlet Design value for rated MCR or max operation value ↓

Air preheater outlet °C Design value for rated MCR or max operation value ↓ Pulverizer inlet Design value for rated Max operation value ↓

Air °C

Pulverizer outlet Design value for rated Warning value ↓ Auxiliary equipment motor A Rated current of motor Rated current of motor ↓ Auxiliary equipment bearing temperature °C Operation value for rated Warning value or max

operation value ↓

65

Inlet feed water temperature °C Design value for pump Highest operation value ↓ Feed water flow rate t/h Design value for pump Pump rated value ↓ Feed water inlet pressure MPa Design value for pump NPSH or minimum value

(Booster inlet pressure: NPSH)

↑

Turb

ine d

riven

feed

Feed water outlet pressure MPa Design value for pump Rated value or warning value (whole pumping process + pump inlet: MCR)

↑



Remarks

Boiler water circulating pump inlet/outlet pressure differential

MPa Design value for pump Warning value (low) ↑

Rotation speed rpm Design value for rated Design turbine rotation ↓ ↑ Feed water flow rate t/h Design value for rated Pump rated value ↓ Feed water outlet pressure MPa Design value for rated Warning value or min

operation value ↑

Steam inlet pressure MPa Design value for rated Turbine design pressure × 1.05 ↓

Turb

ine d

riven

feed

pum

p

Steam inlet temperature °C Design value for rated Turbine design temperature + 8°C

<

Coal consumption t/h Design value for rated Rated value for pulverizer ↓ Burner pressure MPa Design value for rated Warning value ↑ Temperature °C Design value for rated Warning value ↓ Fu

el

Hea

vy/c

rude

oil Flow rate t/h Design value for rated MCR or facility’s max

capacity ↓

Fuel

pum

p Fuel pump outlet pressure MPa Design value for rated Pump rated value ↓

Explanation of signs in “Remarks” column ↓: To be operated at or under permissible value (For warning value only, under permissible value) ↑: To be operated at or over permissible value (For warning value only, over permissible value) ↓↑: To be operated within the range of permissible value

: No description as control value is necessary required <: To be operated under the permitted level

66

(Turbine)



Remarks

Generator load MW Rated output (referred to as “rated” hereafter)

Rated output (referred to as “rated” hereafter)

↓

Main steam MPa Steam pressure for rated Steam pressure for rated × 1.05

↓

First stage outlet Design steam pressure for rated

Design pressure for rated × 1.05

↓

High-pressure turbine outlet Design steam pressure for rated


↓ Pres

sure

Reheater outlet steam Design steam pressure for rated


↓

Main steam °C Steam temperature for rated Steam temperature for rated + 8°C

<

High-pressure turbine Design steam temperature for rated

Design steam temperature for rated

<

Reheat steam Steam temperature for rated Steam temperature for rated + 8°C

<

Tem

pera

ture

Exhaust room Saturation steam temp for design vacuum

Warning value ↓

Control oil MPa Design oil pressure for rated Warning value ↑

Oil

Bearing oil Design oil pressure for rated ↑ Control valve operness (cum angle) % (deg) Design openness for rated Max operation value ↓ Condenser vacuum kPa Design vacuum Max operation value ↑ Difference expansion mm Design difference expansion

for rated Warning value ↓

Thrust bearing °C Supply oil temperature + 20°C

Warning value ↓

Bear

ing

retu

rn o

il

Radial bearing Supply oil temperature + 20°C

Warning value ↓

Vibration (shaft / bearing) 1/100 mm

At or under warning value Caution value in JEAC3717 ↓

Pressure MPa Design pressure for rated Maximum operation value ↓

Air

blee

d Temperature °C Design temperature for rated ↓

Explanation of signs in “Remarks” column ↓: To be operated at or under permissible value (For warning value only, under permissible value) ↑: To be operated at or over permissible value (For warning value only, over permissible value) ↓↑: To be operated within the range of permissible value

: No description as control value is necessary required <: To be operated under the permitted level

Fig 2.5.4-3 Appendix 3-2

Schematic of Thermal Performance / Heat Management System

67

Power Station Head Office

Thermal Power Dept

Calculation Center

Input from other depts.

Input for unsystemized power stations Data link to other depts.

Plant control system Performance management system Heat management system

Performance Business transaction automation calculators

Performance Large computersmanagement system management systemUnit calculator

Temperature sensor Heat management Data transmission

statistic data Pressure sensor Lsw, etc

(1) Heat management data check

(2) Compilation, calculations

(3) Report output

Performance management terminal

Business terminal Business terminal

Unit calculator process functions

Display current output of each generator

Output various monthly reports

Distribution

Submit to governmentagencies

(Specified formats)

(1) Heat management data check output

(2) Monthly report output

Performance management terminal

(1)Operation history(2)Operation condition monitor (3)Plant efficiency analysis (4)Start/stop loss management (5)Equipment management(6)Turbine thermal stress calculate(7)Unit start/stop

Ex. Tomato-Atsuma Unit No.2(1) Operation history

(2)Operation condition search

(3)Plant efficiency analysis

(4)Start/stop loss management Boiler/turbine maintenance diary

(5)Auxiliary equipment preparation operation time,

start/stop times

Table 2.5.4-4

68

Monthly Report (Table 2.5.4-5)…..Boiler and Turbine Maintenance Log, Month-end Generation Record, etc

73

74

April, 2004 Month Eng Generation Record Items This month After last inspection Cumulative total

(B) 15837 – 35 Generation time Hr – Min 720 – 00 (T) 15837 - 35 18821 - 02

(B) 10,853,339 Generated output MWh 447,775(T) 10,853,339

12,348,254

(B) 6 Startup times times 0(T) 6

34

Coal (w) t 144,001 3,558,145 Fuel Consumption Diesel oil kl 16.3 1,650.4

Gross efficiency % 42.64 Net efficiency % 40.70

This month After last inspection Items Main steam Reheat steam Main steam Reheat steam (B) 0- 01Time operated with steam pressure

5% over rated pressure hours -

min 0 - 00 (T) 0- 01

(B) 0- 00 (B) 0- 00 Time operated with steam temp 8°C over rated temperature

hours - min 0 - 00 0 - 00 (T) 0- 00 (T) 0- 00


hours - min 0 - 00 0 - 00 (T) 0- 00 (T) 0- 00


hours - min 0 - 00 0 - 00 (T) 0- 00 (T) 0- 00

Water Quality Management Record

Items Control value Measured value CWT

operation 8.5 – 9.0 8.82 pH (25°C) AVT

operation 9.3 – 9.5 -

Silica µgSiO2/l 20 ↓ 3 CWT

operation 0.2 ↓ 0.05 Electric conductivity µS/cm AVT

operation 0.3 ↓ - CWT

operation 20 – 200 ↓ 100.0 Dissolved oxygen µgO/l AVT

operation 7 ↓ -

75

2.5.4.2 Management System by Computer (1) Functions of unit computer

Input of unit operation conditions, and display and print-out of necessary data Output of daily reports needed for daily management Data collection and efficiency calculation needed for performance management Calculation of turbine thermal stress Start/stop of the unit

(2) Functions of performance management system Tabulation of statistical thermal management data and transmission of them to the headquarters Collection of performance test data and thermal efficiency calculation Accumulation of major operation condition values of the unit

→ Retrieval of operation condition values and trend monitoring are available → Turbine efficiency calculation, condenser cleanliness calculation, management of heat exchanger

operation conditions, management of major equipment operating hours, etc Management of start/stop loss Document-output aid in the designated form

(3) Plant management system Tabulation of operation data from all the power stations Output of various monthly and yearly reports in and out of the company

(Major report data: generated energy, thermal efficiency, in-station ratio, utilization ratio, fuel consumption performance, etc)

2.5.4.3 Other Management (1) Start/stop loss management

The start/stop loss, which does not serve for generation, is properly managed because the fuel, in-house electricity and supplementary steam amount used for start/stop largely affect the efficiency and costs.

(2) Periodical Equipment Tests

Protection devices and other equipment are periodically tested to check for correct operation. Turbine-valve stick prevention test Protection device operation test (oil pump automatic startup and thrust wear test, emergency speed

governor lockout test) Startup test of emergency power supply device (gas turbine) Periodical switching to backup machine

2.5.4.4 Daily Inspection of Facilities (patrol)

The patrol of facilities, items and the patrol method are stipulated in Table 2.5.8. Usually, daily and priority patrols are carried out by the operator once per shift. Also the patrol by managers and the safety-focused patrols are carried out as needed.

Shift time and patrol time 22:00 8:00 16:00 22:00 Shift 1 Shift 2 Shift 3 Patrol Specific patrol

76

Daily Inspection Standard Frequency Facilities Items 1 / day 3 / day Method Remarks

Boiler safety valve

Drum safety valve, superheater safety valve, reheater safety valve, etc

Leakage Tentacle, visual, hearing

Defects in hangers Visual Vibration Tentacle, hearing Main

piping Main steam, reheat steam, feed water, condenser pipings, etc

Leakage Visual, hearing Combustion condition Visual

Furnace Inside furnace Situations inside Visual, hearing Vibration, unusual sound Tentacle, hearing

Temperature rise, oil surface, oil leakage

Tentacle, smell, visual

Main rotating machine (excluding steam turbine)

Forced draft fan, induceddraft fan, gas recirculating fan, gas mixing fan, boiler water pump, feed water pump (MD, TD), pulverizer, heavy oil pump, orimulsion pump, circulating water pump, condenser pump, condenser booster pump, etc

Leakage from gland part Visual

Heavy oil pump for power stations using such fuel, orimulsion for Shiriuchi PS only

Vibration, unusual sound from valve Tentacle, hearing

Steam leak from valve gland Visual, hearing Main

valves

Main stop valve, control valve, reheat stop valve, intermediate prevention valve

Abnormality in working Tentacle, hearing

Vibration unusual sound, temperature Tentacle, see, hear

Steam leak from casing Visual, hearing

Oil drain from bearing Visual Steam turbine

Loosening of nut, bolt Visual, tentacle

Leakage Visual, hearing Main heat exchanger

Feed water heater, deaerator, cooling tower, etc Water level Visual

Generator Main body, collector ring, excitation board, etc

Usual sound, vibration, smell

Visual, hearing, tentacle, smell

Relays Auto voltage adjuster, relay board, power board, etc

Usual sound, smell Visual, hearing, smell

Breaker C/C, L/C, MCS Usual sound, smell Visual, hearing, smell

Hydrogen seal oil equipment

Hydrogent cooler, seal oil equipment, etc

Usual sound, vibration, smell, leaking


Armature cooling equipment

Amature cooling equipment Usual sound, vibration, smell


Main transformer

Main, house, startup, transformers

Usual sound, vibration, smell, leaking

Visual, hearing, smell

Table 2.5.4-6

77

d. Performance Management

2.5.5 Efficiency management on a daily basis (1) Maintenance of proper operation by condition monitor, equipment patrol, record meters, diary record.

Observe whether the output, pressure, temperature, flow rate of steam, condenser vacuum, fuel consumption are properly maintained. (2) Operation for performance maintenance

・ Condenser vacuum is maintained by reflecting the cleanliness management in the operation of backwashing,

a ball washing equipment.

・ Reduction of exhaust gas loss is improved as heat collection of each section is promoted by operation of

boiler as well as preheater soot blower.

2.5.5.2 Performance test (1) Objective

Operation data and thermal efficiency is to be obtained after unit is kept constant, eliminating as many external factors as possible for affecting the efficiency fluctuations so as to compare the against changes and conditions before/after periodic inspection. (See Appendix 2.5-1Steam Power Station Performance Test Manual) (2) Frequency

Before periodical inspection 100% load

After periodical inspection 100% load or needed for operation

(3) Management items 1. Thermal efficiency (measured value, corrected value)

・ Gross thermal efficiency

・ Net thermal efficiency

・ Auxiliary power ratio

・ Boiled room efficiency

・ Turbine room efficiency

2. Boiler room heat loss

Heat loss is calculated by adding various losses, such as, dry gas loss, loss caused by water and hydrogen

content in fuel, unburned matter loss, etc

3. Efficiency correction

Test results are kept in a constant condition by adjusting the values such atmospheric temperature, steam

temperature/pressure, condenser vacuum and etc to design values.

4. Preparation of control charts

Test results are displayed in charts and, for significant changes, analysis is done.

(4) Results of performance test The results and records of the performance test conducted at Tomato-atsuma coal fired power plant are shown in table

2.5.5-1. Additionally an actual example of performance control chart administrated at the same power plant is shown in table 2.5.2-2.

Table 2.5.5-1

78

83

Transition in Thermal Efficiency (Generating End) in 2007 [for December]

The thermal efficiency of each unit has no problem within the control range.

control chart (3σ method)

Maintenance Division Environmental Engineering Division Electricity Power Generation Division Deputy Manager Deputy Manager Deputy Manager

(Central control room) Director Deputy Director Manager Steam

Drum Steam

Equipment Computer Manager Environmental Facilities

Environmental Engineering

Manager operation

management

person in

charge

A B C D E

No. 1 Unit

No. 2 Unit

No. 4 Unit

Year

Year

Year

Thermal efficiency

Thermal efficiency

Thermal efficiency variation

Thermal efficiency variation

under survey

Low coefficient of use

efficiency (month) 38.28 Beginning 38.03 Middle 38.61 End 38.19

efficiency (month) 40.74Beginning 41.68Middle 40.63End 39.96

coefficient of use

bowl cleansing stop to vacuum down

periodical check

efficiency (month) 43.73Beginning 43.60Middle 43.90End 43.70

(thermal efficiency) upper limit 38.65 average value 37.88 lower limit 37.10

(amount of change) upper limit 0.95 average value 0.96


(amount of change) upper limit 0.93 average value 0.28


(amount of change) upper limit 0.98 average value 0.30 Variation of thermal efficiency

Thermal efficiency

Table 2.5.5-2

Previous fiscal year

Utilization factor


Utilization factor


Utilization factor

84

Appendix 2.5-1

Q-1-7

Steam Power Stations Performance Test Manual

April 1, 1995

Revised June 1, 2004 (First revision)

(Jurisdiction) Thermal Power Department

(Contents)

I. General

1. Objective of Performance Test

2. Implementation of Performance Test

II. Methods for Performance Test

1. Operational Condition for Testing

2. Measurement of Test Data

3. Measuring Equipment

4. Measurement Data and Calculation Methods

Ⅲ. Analysis of Test Data

1. Calculation Processing and Control charts

2. Preparation of charts

Attachment

1. Steam Power Generation Steam Schematic

2. Thermal Efficiency Calculation Equations

3. Performance Test Results (Actual)

Q-1-7

Steam Power Stations Performance Test Manual

This manual is to introduce standardized procedure for performance test methods for steam power stations based on "Thermal Power Station Operation and Maintenance Regulations."

I. General (1) Objective of Performance Test

The objective of performance test is to grasp the performance of each steam power station, to use such information in daily operation and maintenance and to improve the energy efficiency in heat and electricity generated.

2. Implementation of Performance Test (1) Responsibility for Implementation

Planning, implementation, consideration for performance test is done by each steam power station. (2) Time and Number of Tests

a. Test time and number are shown in the table below. As for the load needed for operation, appropriate load

is be set based on the operational condition of each unit.

b. In the event a question arises against test results, re-test shall be conducted.

c. Flexible operation shall be done in case a test cannot be conducted in a certain load condition due to load

dispatching reasons and others, conducting such test on next occasion.

Test load Test time 4/4 load Load needed for operation (minimum)

Before periodic inspection (Note) One time - After periodic inspection (Note) One time One time

Note: Periodic inspection means regular maintenance company inspection and intermediate inspection.

(3) Performance Test Calculation methods of various efficiency indexes for grasping performance of steam power stations are as shown in

the table below, whereas heat input-output methods are primarily applied for heavy/crude oil, bituminous mixture and PFBC thermal units and loss methods for coal-fired thermal units.

Additional calculation methods are to be used as secondary methods, for reference in consideration of efficiency.

Items Plant applied

Test name (Primary)

Boiler room efficiency

Turbine room efficiency

Gas turbine room efficiency Plant efficiency

Heavy/crude oil Bituminous mix PFBC

Heat input/output

method standard

Heat input/output method

-

Heat input/output

Heat input/output method

Coal-fired thermal power

Loss method standard Loss method

Heat input/output

method -

(Boiler room efficiency) × (Turbine room

efficiency)

(4) Measurement of Data For testing, the main fuel is to be exclusively combusted and measurement of data is to be conducted after the

operational condition has become steady.

For more details, "II Methods for Performance Test;1.Operational Condition for Testing and 2.Measurement of Test

85

86

Data" is to be referred to. For measuring equipment largely affecting the test results, required precision needs to be ensured. (Confer II Methods for Performance Test;3.Measuring Equipment) (5) Analysis of Measured Data

Each thermal efficiency indexes are calculated from measured data and their results are analyzed using control charts. (6) Report and Response to Test Results

Test results are to be immediately reported related authorities along with considerations. In the event any major performance decrease is observed, necessary measures are taken.

II. Methods for Performance Test 1. Operational Condition for Testing

(1) Main fuel is to be exclusively combusted and operational condition shall be steady.

(2) Load shall be controlled to be constant by load limiter or the openness of control valve.

(3) The same burner is to be used for the same testing load.

(4) Auxiliary steam extraction to other units shall be stopped.

(5) Soot blower needs to be completed before test, otherwise efficiency correction for steam extraction is to be

done.

(6) Furnace bottom ash need be cleared before test if such affects the results.

(7) Pure water supply to make-up tank shall be stopped.

(8) Other matters are the same as normal operation.

2. Measurement of Test Data (1) One hour before measurement, operational condition is to be set in testing load, confirming the steady

condition of each part, measurement is to be commenced.

(2) Measurement of record is conducted for 2 hours, every 30 minutes. Measurement of fuel consumption,

however, is to be conducted for 4 hours for obtaining precise values.

(3) Measurement of Fuel Consumption

• Coal··········Sum of measurements of each coal scale, not taking into consideration the changes in coal

level in the hopper.

• Fuel oil ·····See flowmeter.

(4) Sampling of Fuel

• Coal··········Considering the coal consumed in one test as 1 log, sample out 60 units of 500g specimen for

1 lot using auto-sampler of each coal scale (or equal time interval) and prepare 1

specimen for one test.

In case specimen sampling is impossible due to structural reasons for coal scale such

as sealed type, sampling is done using other proper methods.

• Fuel oil ·····Sample out 1 specimen for one test from lines after the tank outlet.

(5) Measurement of generator output is done using signals from the generator input into the plant management

system. (When such plant management system in not installed, integrated power meter in central control

room is to be used)

(6) Sampling of Ash (Only for coal-fired thermal power plant)

1 specimen for one test is sampled out from EP representing hopper or furnace bottom. In case, unburned

matter for MC or PC collected ash cannot be ascertained by EP ash, sample should be taken from MC and

PC.

87

(7) Sampling of exhaust gas is to be done at Eco outlet and designated point of AH outlet for analysis by Orsat

method or corresponding methods.

For PFBC unit, analysis is conducted between boiler outlet and gas turbine inlet.

(8) Items for Specimen Analysis are as follows;

Analysis of specimen is based on “Fuel Quality Test Manual.”

Type of fuel Analysis items

Coal Heavy

crude oil

Bituminous mix Remarks

Calorific value High standard Density -

Humidity - - Moisture Industrial analysis

Fuel

Ash content - -

Carbon Elemental analysis

Hydrogen ″

Nitrogen ″ Ana

lysis

Combustive sulfur ″

CO2 Orsat corresponding methods

CO ″ Eco

Outlet O2 ″

AH outlet O2 ″

Exha

uste

d ga

s ana

lysis

Boiler outlet O2 - - PFBC Unit

Furnace clinker - -

EP ash - -

MC ash - -

PC ash - -

Unb

urne

d m

atte

r ana

lysis

(Note) : Items to be analyzed

: Items analyzed when loss method is applied

: Items analyzed as necessary

− : Items not analyzed

(9) Test procedure

It is as shown below:

Test Procedure

88

Time

Test load

Record

Coal sampling

Fuel consumption record

Heavy/crude oil, ash sample

Gas analysis

0 1H 2H 3H 4H 5H 6H

3. Measurement Equipment (1) Precision of Meters

Measuring equipment shall be arranged according to the table, grasping its precision.

Measurement items Unit Measuring

position

Input minimum

value (min. meter

reading)

Precision /

tolerance Remarks

Carbon % − 0.01% 0.03% No water base

Hydrogen ″ − 0.01% 0.15% ″

Nitrogen ″ − 0.01% 0.06% ″ Fuel

anal

ysis

…

…

…

…

…

…

AH outlet gas temp °C − (Central

control)

1°C ±0.5°C

FDF inlet air temp (dry ball) ″ ″ ″ ″

Boile

r

…

…

…

…

…

…

Main steam MPa − (Central

control) 0.01Mpa (1atg)*

±0.005Mpa

(±0.5atg)*

Reheat steam ″ ″ ″ ″ Pres

sure

…

…

…

…

…

…

Main steam °C − (Central

control)

1°C ±0.5°C

Reheat steam ″ ″ ″ ″

Turb

ine

Tem

p.

…

…

…

…

…

…

*The brackets show the minimum reading values of equipment for power stations requiring meter reading.

(2) Correction of Measuring Equipment The following correction shall be done to measuring equipment.

a. Until testing time conducted after periodic inspection

All measuring instruments used for measurement

b. Until other testing time

Coal scale and other instruments deemed necessary

89

4. Measurement Data and Calculation Methods

For calculation of each thermal efficiency figure, the measurement data and calculation methods shown in Appendix 5 are to be used. No irrelevant data need be used for calculation. III. Analysis of Test Data 1. Data Processing and Control charts

The measured data are to be filled in and gathered in Performance Test Measurement Record (Appendix 4), and each thermal efficiency figure in Performance Test Results (Appendix 1). In addition, Control charts (Appendix 2) are to be prepared for consideration of each unit’s performance.

2. Preparation of Control Charts Control charts are prepared to determine whether the plant is in a steady condition or not, using JIS Z-9021,

“Shewhart Control chart.” (1) Application of Control chart

a. Applied to 4 items, namely, gross efficiency, boiler room efficiency, turbine room efficiency, auxiliary

power ratio.

b. Control charts are prepared for each item above for load profile of 4/4 and needed.

(2) Control Limit For control limit used for control charts, 3 sigma method (allowing 3 times of standard deviation range above and

below expected value) is to be adopted. • Upper Control Limit (UCL) = Expected value + (3×Standard deviation)

• Lower Control Limit (LCL) = Expected value – (3×Standard deviation)

In order to obtain control values, test needs to be conducted a few times, and the estimated value from the

results can be used.

(3) Judgment by Control Chart Control chart is useful for recognizing unit’s deviation from controlled condition. Generally, when the measured

values are within the control limit lines, units are considered as normal. If these are beyond the limit lines, it is viewed as abnormal, requiring clarification. The following cases need caution.

a. One point is located beyond the control limit.

b. 9 points are on the same side of the center line.

c. 6 points have increased or decreased.

d. 14 points are rising and falling alternately.

e. Of the consecutive 3 points, 2 points are in the domain of 2 σ and 3 σ or beyond.

f. Of the consecutive 5 points, 5 points are in the domain of σ and 2 σ or beyond.

g. Consecutive 15 points are in the domain of ± σ.

h. Consecutive 8 points are in the domain beyond ± σ.

The conventional control lines (center line and control limit line) can be insufficient as a standard in case unit

condition changes. In such a case, a new control line needs to be provided using the recent data as auxiliary

data.

<Thermal Efficiency Calculation Equation> Appendix - 2 1. Definition of boiler room efficiency, turbine room efficiency, unit thermal efficiency (1) Boiler room efficiency (ηB)

Diagram 1 From unit thermal equilibrium line diagram, boiler room efficiency is defined as follows. Also, auxiliary input heat into boiler system QEX is defined as input heat or negative output heat in some cases. Here, the latter concept is adopted, viewing only fuel combustion heat as input heat.

Diagram 1 Unit Heat Equilibrium

Boiler room efficiency can be calculated as follows based on heat equilibrium of boiler system;

Qf + QEX = QO + QBS + QBL

Qf – QBL = QO + QBS – QEX

Boiler room efficiency f

EXBSOBLB

QQ-QQ)Qf

Q-(1 +==η

QTS (Output heat)

Turbine heat generating system Boiler system

QO (Output heat) Qf (Fuel combustion heat)

QTL (Heat loss) QBL (Heat loss)

QEX (Boiler auxiliary heat input)

QG

(Generator output)

QRS (Output heat)

Loss method Heat input-output method

(2) Turbine room efficiency (ηT) Consider turbine room input heat as boiler room output heat QO, focus only on generator output as turbine room

efficiency.

Turbine room efficiency can be calculated as based on heat equilibrium of turbine system; QO=QG+QTS+QTL

QO−QTS−QTL=QG

Turbine room efficiency TSO

G

TSO

TLT

Q-QQ)

Q-QQ(1 ==η

Loss method Heat input-output method

(3) Unit Thermal Efficiency (ηP)

91

Unit thermal efficiency is the product of boiler room efficiency multiplied by turbine room efficiency.

Unit thermal efficiency TSO

T

f

EXBSOTBP

Q-QQ

QQ-QQ

×+

=×= ηηη

(Heat input-output standard method)

TSO

EXBSO

f

G

Q-QQ-QQ

QQ +

×= ·································· (1)

(Note) Conventionally, Unit thermal efficiency by heat input-output method has been calculated as

f

GP

QQ

=η

However, the steam generated in the unit system is used outside, the heat value of such steam must be incorporated into the calculation. Therefore, Equation (1) can represent the heat input-output method unit thermal efficiency.

Theoretically, heat input-output method and loss method should compute out the same results. (4) Boundary of Boiler and Turbine Systems

Boundary of boiler and turbine systems are shown in Diagram 2.

Turbine system

WMS iMS

92

Diagram 2 Boundary of Boiler and Turbine Systems

SAH

SC

SH

RH

(qsc)

WEj iEj

WSS iSS

WHR iHR

WRS iRS

WLR iLR

WFW iFW

WSAH iSAH

WSAH iSAHD

WSC iSC

WSC iSCD

AH

Heavy oil heater

Atomize steam

Heavy oil

WSD iSD

Qf QEX

Heat loss

Drain

Boiler system

Exhaust gas

Combusted air

Heater

2. Calculation Method of Boiler Room Efficiency (1) Heat input-output method boiler room efficiency (ηBi)

[%]100Q

Q-QQf

EXBSOBi ×

+=η ff MHQf ⋅=

Qf :Fuel combustion heat [kJ/h]

QEX :Boiler auxiliary input heat [kJ/h]

QO :Boiler room output heat (For generation) [kJ/h]

QBS : ″ (Heating, etc) [kJ/h]

Hf :Fuel higher heating value [kJ/h]

Mf :Fuel consumption [kg/h]

QO=WMS · iMS+WHR · WEj · iEj–WSS · iSS–WRS · iRS–WLR · iLR–WFW ·

iFW–WSAH(iSAH–iSAHD)–WSC(iSC–iSCD)–QEX

WMS : Main stop valve inlet steam flow rate [kg/h]

iMS : ″ enthalpy [kJ/kg]

WHR : High temp reheat steam flow rate [kg/h]

iHR : ″ enthalpy [kJ/kg]

WEj : Ejector driving steam flow rate [kg/h]

iEj : ″ enthalpy [kJ/kg]

WSS : Superheater spray water flow rate [kg/h]

iSS : ″ enthalpy [kJ/kg]

WRS : Reheater spray water flow rate [kg/h]

iRS : ″ enthalpy [kJ/kg]

WLR : Low temp reheating steam flow rate [kg/h]

iLR : ″ enthalpy [kJ/kg]

WFW : Final feed water heater outlet flow rate [kg/h]

iFW : ″ enthalpy [kJ/kg]

WSAH : SAH heating steam flow rate [kg/h]

iSAH : ″ enthalpy [kJ/kg]

iSAHD : SAH drain enthalpy [kJ/kg]

WSC : SC heating steam flow rate [kg/h]

iSC : ″ enthalpy [kJ/kg]

iSCD : SC drain enthalpy [kJ/kg]

93

( ) ( )12BS qscqscQ −=

(qsc)1 : Heating value brought by feed water at SC inlet [kJ/h]

(qsc)2 : Heavy oil heating and atomizing steam generated at SC [kJ/h]

( ) ( )iSCDiSC(Note)

SCiSAHDiSAHSAHEX -W-WQ (Note) +=

(Note) WSAH and WSC show steam flow from other units, own unit being 0.

Main Stop Valve Inlet Steam Flow Rate (WMS)

CLBSBDEjSSFWMS W21-W-W-W-WWW +=

BSBDMUCL W-W-WW =

WBS : Boiler air ejecting heater etc. flow rate [kg/h]

WCL : Cycle leak rate [kg/h]

WBD : Continuous blow rate [kg/h]

WMU : Make-up water [kg/h]

Low Temp Reheat Steam Flow Rate (WLR)

HiHLMSLR W-W-WW Σ=

WHL : High pressure turbine leak [kg/h]

WHi : Leakage from low temp reheat steam pipe [kg/h]

High Temp Reheat Steam Flow Rate (WHR)

RSLRHR WWW +=

94

(2) Loss Method Standard Boiler Room Efficiency (ηB1)

EXATBDCLf

BL1B LLLL

QQ1 −−−−−=η

ΣLi : Boiler heat loss total [kJ/kg · fuel]

AHUBRdcoASHaswgLi LLLLLLLL +++++++=Σ

a. Lg Dry gas heat loss

( ) }( ){ agatgtgg ttM1mMCL −−+⋅= [kJ/kg · fuel]

Cg : Dry gas specific heat 1.38 [kJ/m3N · K]

Mgt : Theoretical combustion gas amount [m3N/kg · fuel]

m : Eco outlet air excess coefficient

Mat : Theoretical air amount [m3N/kg · fuel]

tg : AH outlet gas temperature [°C]

ta : Air temperature (FD inlet temperature) [°C]

b. Lw Loss due to Water Content, Hydrogen Combusted Water in Fuel

( )( )aghww tiWWL −+= [kJ/kg · fuel]

Ww : Water content in fuel [kg/kg · fuel]

Wh : Hydrogen combusted water in fuel [kg/kg · fuel]

ig : Steam enthalpy at steam pressure 10.1kPa, tg (AH outlet gas temperature) °C

[kJ/kg]

ta : Air temperature [°C] (same value as water enthalpy [kJ/kg]=ta)

c. Las Loss due to air humidity

( )agatas ttMm1.29ZL −⋅⋅= [kJ/kg · fuel]

Z : Absolute humidity [kg/kg]

Cs : Steam specific heat 1.88 [kJ/kg · K]

95

d. LASH Ash sensible heat loss

( ) ( ) (⎭⎬⎫

⎩⎨⎧ −

−+−⋅= ag

BOTa

BOTASHASH tt

Pt

PACL100

100800

100100)

}

[kJ/kg · fuel]

CASH : Ash specific heat 1.05 [kJ/kg · K]

A : Ash content in fuel [%]

PBOT : Furnace bottom ash falling rate [%]

e. Lco Heat loss due to unburned fuel

( ){ [ ]100COM1mMHL atgtcoco ⋅−+⋅= [kJ/kg · fuel]

Hco : CO combustion heat [kJ/m3N]

[CO] : Volume ratio of CO [%]

(Orsat analysis value at Eco outlet)

f. LRd Heat loss due to radiation

(According to A.M.B.A. Standard Radiation Loss Chart in ASME Power Test Code)

g. LUB Heat loss due to unburned matter in ash

u100u

100AHcL UB −

⋅⋅= [kJ/kg · fuel]

Hc : Carbon heating value 33,900 [kJ/kg]

u : Average unburned matter in ash [%]

h. LAH Heat loss due to AH air leakage

( ) ( ){ }( )agatgtaAH ttM1mM100

1.61Z1CL −−+⋅⋅+=ε

[kJ/kg · fuel]

Ca : Specific heat of air (=CS) 1.30 [kJ/m3N · K]

ε : AH inlet gas amount standard air leaking ratio [%]

96

i. LCL Cycle Leakage Heating Value Loss

( )f

aiFWCLCL Q

tW21L

−⋅=

WCL : Cycle leakage flow rate [kg/h]

iFW : Final feed water heater outlet feet water enthalpy [kJ/kg]

j. LBD Heat loss due to continuous blow

( )f

aiFWBDBD Q

tWL

−=

WBD : Continuous blow amount [kg/h]

iBD : ″ enthalpy [kJ/kg]

k. LAT Heat loss due to atomizing steam

( )f

aiFWATAT Q

tWL

−=

WAT : Atomizing steam flow rate [kg/h]

l. LEX Other heat loss

In case any loss is found other than a.~k., it is totaled and considered as other heat loss as a whole.

Theoretical air Mat

⎭⎬⎫

⎩⎨⎧ ′+⎟

⎠⎞

⎜⎝⎛ ′

−′+′= s3.338oh26.7c8.89

1001Mat [m3N/kg · fuel]

( )u100

uA100

100cc W1

−⋅−

−⋅=′ Combustion carbon amount [%]

( )100

100hh W1−⋅=′ [%]

( )100

100oo W1−⋅=′ [%] ⎟⎟

⎠

⎞⎜⎜⎝

⎛−

+++−=W1100

100Anhc100o [%]

( )100

100ss W1−⋅=′ [%]

97

c : Carbon

h : Hydrogen

n : Nitrogen

s : Combustive sulfur

o : Oxygen [%]

W1 : Fuel inherent moisture [%]

Air Excess Coefficient m

Fuel elemental analysis value (No water basis) [%]

( ) ( )( ) ⎭

⎬⎫

⎩⎨⎧ −

−=

2

2

NCO0.5O

7921

21m

In this regard, however,

(N2)=100−{(CO2)+(CO)+(O2)}

(O2) :

(CO2) :

(CO) :

(N2) : O2, CO2, CO are Orsat analysis

Theoretical Dry Gas Amount Mgt

⎭⎬⎫

⎩⎨⎧ ′+′+⎟

⎠⎞

⎜⎝⎛ ′

−′+′= n0.8s3.338oh21.1c8.89

1001Mgt [m3N/kg · fuel]

( )100

100nn W1−⋅=′

Hydrogen combustion moisture in fuel Wh and water content in fuel WW

100h9Wh′

= [kg/kg · fuel]

W2

W2W1W 100100

W−

+= [kg/kg · fuel]

W2 : Surface humidity of coal [%]

Indicating volume ratio in dry combustion gas [%]

98

Absolute Humidity Z

sa

s

PPP

0.622Z−

⋅= [kg/kg] ( )WdaWs TTP0.0008PP −⋅⋅−=

Pa : Atmosphere pressure [kPa]

Ps : Steam pressure [kPa]

PW : Saturated steam pressure for wet-bulb temperature [kPa]

Td : Dry-bulb temperature (=Ta) [°C]

TW : Wet-bulb temperature [°C]

AH Air Leakage Ratio ε (Eco outlet gas amount basis)

( ) ( )( ) 100

outO21inOoutO

2

22 ⋅−

−=ε [%]

(O2) out : AH outlet O2 [%]

(O2) in: Eco outlet O2 [%]

3. Calculation Method of Turbine Room Efficiency

100QQ

Q

TSO

GT ⋅

−=η [%]

QG : Generator output (=860 · PG) [kJ/h]

PG : ″ [kWh]

QTS : Turbine output heat [kJ/h]

4. Calculation Method of Unit Thermal Efficiency (1) Gross unit thermal efficiency (ηP)

a. Unit thermal efficiency based on heat input-output method (ηPi)

100KQQ

f

GPi ⋅⋅=η [%]

K : Modification coefficient (See IV, exposition, “calculation processing”)

TSO

EXBSO

QQQQQ

K−

−+=

b. Unit thermal efficiency based on heat loss method (ηP1)

100/TB1P1 ηηη ⋅= [%]

99

(2) Auxiliary Power Ratio (α)

100P

PP

PP

G

CMG

GGH

⋅⋅

∑+

=α [%]

PGH : House transformer power [kWh]

ΣPG : Total of generator output of each unit [kWh]

PCM : Common auxiliary power [kWh]

(Note) Auxiliary power consists of the common auxiliary power proportionately divided by each unit’s generator

output added by house transformer power.

(3) Net Unit Efficiency (ηP’)

⎟⎠⎞

⎜⎝⎛ −⋅=′

1001PP

αηη [%]

5. Correction of Calculated Thermal Efficiency The following correction is conducted for calculated thermal efficiency.

(1) Boiler room efficiency (ηB) a. Atmosphere temperature correction

b. Fuel surface humidity correction

c. Fuel hydrogen content correction

d. Fuel inherent moisture correction

(2) Turbine room efficiency (ηT) e. Main steam pressure correction

f. Main steam temperature correction

g. Spray water correction

h. Reheat system pressure loss correction

i. Reheat steam temperature correction

j. Condenser vacuum correction

k. Generator power factor correction

100

101

6. Various Constants in Calculation (1) Thermal efficiency is calculated with higher heating value standard.

(2) Standard temperature for thermal efficiency is FDF inlet and atmosphere temperature.

(3) Dry gas specific heat shall be 1.38 kJ/m3N · K from JIS B-8222.

(4) Specific heat for dry air and air shall be 1.30 kJ/m3N · K from JIS B-8222.

(5) Enthalpy for exhaust gas steam shall be calculated with steam partial pressure as 10.1kPa.

(6) Heating value of carbon shall be 33,900kJ/kg from JIS B-8222.

(7) Heating value of carbon monoxide shall be 12,610 kJ/kg from JIS B-8222.

(8) Specific heat of steam shall be 1.88 kJ/kg · K from “Heat Management Handbook.”

(9) Specific heat of ash is 1.05 kJ/kg · K from “Heat Management Handbook.”

(10) Cycle leakage loss shall be equally shared by boiler and turbine system, finally leaked to the outside of system at

final feed water heater outlet.

(11) Make-up water, air sensible heat and fuel sensible heat shall be 0.

7. Calculation Standard for Main Steam Flow Rate In this manual, feed water flowmeter standard shall be adopted. Other standards can be used provided sufficient

precision is ensured. (Grounds for adopting feed water flowmeter standard is as mentioned below)

Moreover, for grasping the deviation error of feed water flowmeter standard, it is desired that main steam flow

rate for high pressure turbine first-stage pressure standard, condenser flowmeter standard, etc is used as reference.

The calculation method of main steam flow rate using high pressure turbine first-stage pressure standard by means

of regression line will be explained later.

(1) Calculation Standards for main steam flow rate are as follows;

a. Main steam flowmeter standard

b. Condenser flowmeter standard

c. Feed water flowmeter standard (Adopted in JIS B-8222 and this manual)

(2) Comparison of each calculation standard

a. Main steam flowmeter standard has a weaker reliability than other methods since steam itself is compressive

fluid.

b. Condenser flowmeter standard ensures high precision due to its low temperature and pressure when used, but

the feed water heater drain flow rate needs to be calculated with low-precision flowmeter or heat balance

calculation, thus showing lower reliability.

c. Feed water flowmeter standard has a problem of deviation error caused by scale attaching to the flowmeter’s

flow nozzle, but precision is thought to be higher than the aforementioned standards.

8. AH Air Leakage According to the boiler boundary in Diagram 2, exhaust gas analysis is done at AH outlet, but in reality, to

eliminate the influence of combustion air leaking in, it is done at Eco outlet.

Along with this, AH air leakage ratio is measured to obtain the heat loss due to AH air leakage.

9. Calculation Method of High Pressure Turbine First-Stage Pressure Standard Steam Flow Rate by Regression Line

(1) Preparation Procedure a. At each generator output, high-pressure turbine firs-stage pressure (P) and feed water flowmeter standard main

steam flow rate (WMS) are measured.

(Note 1) High-pressure turbine firs-stage pressure is measured with meters capable of reading minute fluctuations

such as expanded pressure meter, transmitter output voltage.

(Note 2) Main steam flow rate is calculated after density correction of each flow rate.

b. Regression line for high-pressure turbine firs-stage pressure (P) and feed water flowmeter standard main steam flow

rate (WMS) are calculated.

This regression line is applied to performance tests conducted from this point on, calculating main steam flow

rate.

(2) Calculation Example Example of measurement results

WMS=WFW−WSS

SH spray (WSS)

Main steam flow rate (WMS) Generator

output

High-pressure

turbine

firs-stage

pressure Pi

[MPa]

Main steam

flow rate WMi

[t/h]

MCR 13.0 580.470

4/4 11.4 514.760

3/4 8.4 370.680

2/4 5.8 242.880

Minimum 3.5 152.810 Feed water flow rate (WFW)

Calculation procedure

a. Calculate S1=Σ Pi2−(Σ Pi)2/n. S1=60.928

b. Calculate S2=Σ (WMsi)2−[Σ (WMsi)]2/n. S2=128,557.61

c. Calculate S3=Σ Pi (WMsi)− Σ Pi (WMsi)/n. S3=2,796.953

d. Calculate P=Σ Pi/n. P = 8.42

e. Calculate WMS=Σ (WMsi)/n. WMS=372.32

f. From above,

1

3MS S

SW = ⎟⎟

⎠

⎞⎜⎜⎝

⎛−+ P

SS

WP1

3MS WMS=45.9059P−14.2074

Calculating regression line.

g. Calculating the correlation function γ,

21

21

23

⎟⎟⎠

⎞⎜⎜⎝

⎛

⋅=

SSS

γ γ =0.9994

102

103

2.6 COMBUSTION OF COAL Because coal has a variety of physical and chemical properties compared with other fossil fuels (heavy oil or

gas) according to the difference in generation conditions, the burning process (ignition and combustibility) and exhaust-gas composition after combustion vary with the type of coal.

In this seminar, pulverized coal combustion is described generally: how coal properties affect combustion, the concept of combustion, combustion equipment, and the development of combustion technology. 2.6.1 How Coal Property Affects Pulverized Coal Combustion

For the preliminary evaluation of coal as fuel, we generally conduct a proximate analysis, an ultimate analysis and an ash content analysis of coal. The detailed analyses of coal are described in “II-1 Coal”. This section discusses how the coal properties relate to combustibility, grindability, slagging/fouling and abrasion characteristics, etc. when coal is evaluated as a fuel burned in pulverized coal burning boilers. 2.6.6.1 Relation of Coal Property to Ignitability and Combustibility

Certain items are used to evaluate the ignitability and combustibility of coal: the fuel ratio and coal rank, the volatile matter and calorific value, the adhesiveness and agglomeration, etc. (1) Fuel Ratio and Coal Rank

The fuel ratio has traditionally been used as the simplest standard to evaluate the ignitability and combustibility of coal. The fuel ratio means the weight ratio of fixed-carbon to the volatile matter. Generally speaking, the higher the fuel ratio of coal, the poorer the ignitability and the slower the combustion speed. It can be said that coal with a fuel ratio 2.5-3.0 is preferable for pulverized coal burning boilers in order to lower unburned losses.

The coal rank means the degree of coalification, which is classified according to the physical and chemical properties of coal.

As shown in Table 1, the coal rank is categorized into brown coal, sub-bituminous coal, bituminous coal and anthracite coal according to the order of coalification, on the basis of a calorific value, fixed carbon amount, volatile matter amount, and agglomeration characteristic.

Table 1 Coal Rank (ASTM Standard) Class

Item Group

Range of fixed carbon

(dry coal/no-mineral base %)

Range of volatile matter

(dry coal/no-mineral base %)

Range of calorific value (constant wet

coal/no-mineral base kcal/kg)

Agglomeration characteristic

I. Anthracite coal 1. High anthracite coal 2. Anthracite coal 3. Semi-anthracite coal

98 ≤ 92 ≤ / <98 86 ≤ / <92

≤ 2 2 < / ≤ 8 8 < / ≤14

- - -

Not exist

II. Bituminous coal 1. Low volatile bituminous coal

2. Semi-volatile bituminous coal

3. A High volatile bituminous coal

4. B High volatile bituminous coal

5. C High volatile bituminous coal

78 ≤ / <86

69 ≤ / 78

< 69 - -

14 < / ≤ 22

22 < / ≤ 31

31 < - -

- -

7,780 ≤

7,220 ≤ / <7,780

6,390 ≤ / < 7,220 5,830 ≤ / < 6,390

Generally, exist

Exist III. Sub-bituminous

coal 1. A Sub-bituminous

coal 2. B Sub-bituminous

coal 3. C Sub-bituminous

coal

- - -

- - -

5,830 ≤ / < 6,390

5,280 ≤ / < 5,830

4,610 ≤ / < 5,280

Not exist

IV. Brown coal 1. A. Brown coal 2. B. Brown coal

- -

- -

3,500 ≤ / < 4,610 < 3,500 Not exist

104

Anthracite refers to coal with non-agglomeration characteristics, low volatile matter, and a fuel ratio of more than 6, and it is poor in ignitability and combustibility. Sub-bituminous coal and brown coal, whose fuel ratio is less than 1, are excellent in ignitability and combustibility, but poor in mill grindability (explained later) and have slagging/fouling characteristics. Therefore, bituminous coal, whose fuel ratio is intermediate, is generally used in pulverized coal burning boilers. The bituminous coal is classified into five types as below, and the higher the rank the poorer in ignitability and combustibility.

(1) Low volatile matter bituminous coal (the fuel ratio is approx. 4) (2) Medium volatile matter bituminous coal (the fuel ratio is approx. 2.8) (3) A high volatile matter bituminous coal (the fuel ratio is approx. 1.5) (4) B high volatile matter bituminous coal (the fuel ratio is approx. 1.2) (5) C high volatile matter bituminous coal (the fuel ratio is approx 1.1)

(2) Volatile Matter and Calorific Value Ignitability evaluation of coal itself is generally performed in accordance with the volatile matter amount and

the calorific value contained in coal. In general, when the volatile matter amount is less than 20%, it is necessary to consider some methods to stabilize the ignitability. The following expression has traditionally been used as the ignitability index:

%) (moisture + %)matter (volatile %)]carbon (fixed x 81 - kcal/kg) valuecalorific coal [(raw=index ty Ignitabili

The ignitability index, which can be used as a judgment criterion of the ignition difficulty of coal with much surface moisture, indicates discharged moisture and a calorific value of volatile matter. When the ignitability index is 35 or less, it is said some measures for ignitability improvement should be taken. (3) Adherence and Agglomeration Characteristics

Coal adherence means a property of the cake-like expansion of coal when it is heated, and is usually judged by a button index. Coal with a high button index requires special attention because fuel-fines adhere to or clog in a burner nozzle or unburned hydrocarbon increases due to fuel-fines blended in the process of combustion. For coal with a button index of 6-7 or more, it is necessary to consider special designs to prevent these problems. 2.6.1.2 Relation of Coal Property to Grindability and Dryness

In general, pulverized coal combustion is characterized by pulverizing coal to 50-100µm and drying and burning it. The point of this combustion lies in the selection of the coal pulverization degree so that the coal can be burned out in a combustion chamber. As aforementioned, the coal combustibility greatly varies with the coal rank. The following shows the type of coal and the grading required for combustion.

(1) Anthracite coal <10-15% (200 mesh = 74µm residual amount) (2) Bituminous coal <15-35% (-ditto-) (3) Semi-bituminous coal <35-45% (-ditto-) (4) Brown coal <45-55% (-ditto-)

The difficulty in coal grinding is usually evaluated by the HGI (Hardgrove Grindability Index) and the moisture based on the ASTM standard. (1) HGI

Because linking the coal component analytical values to the HGI tends to have many errors, it is preferable to directly measure the HGI to gauge coal grindability. The rough standard of grindability is as follows. The higher the HGI, the easier the grinding.

(1) Coal with a fuel ratio of approx. 1.0 is 35-45 in HGI (2) Coal with a fuel ratio of approx. 2.0 is 45-75 in HGI (3) Coal with a fuel ratio of approx 3.0 is 75-100 in HGI

Because the smaller the HGI, the poorer the grindability and because large-sized mills are required, a HGI of more than 40 is preferable. (2) Moisture

The mill grinding capability is affected by total moisture including surface- and inherent moisture. High-moisture content causes a lack of dryness in the mill, decreases the classification efficiency in the mill and accordingly lowers the mill grinding capability. From this viewpoint, the total moisture contained in coal is preferably 20% or less. 2.6.1.3 Slagging Characteristic and Ash Property

Slagging is a phenomenon whereby coal ash (slag) melted in the boiler furnace adheres to the radiant heat-transfer surface in the furnace, and is cooled, solidified, and built-up. The following coal properties relate to

105

the degree of slagging: (1) Ash Melting Temperature

Slagging results from the fact that coal ash melted in the furnace bumps against the heat-transfer surface and adheres to it before solidifying. Slagging is judged by whether the ash melting temperature is higher or lower than the gas temperature in the proximity of the heat-transfer surface. Such a problem is rarely seen with coal with a melting temperature exceeding 1300℃ in pulverized coal burning boilers. (2) Ash Content

In the case of coal with strong slagging characteristics, the slag accumulation amount is proportional to the ash amount input into the furnace. Because the ash amount input into the furnace is proportional to the ash-content amount per coal calorie, the coal with high ash-content and low calorie requires more attention. (3) Ash Alkaline Ratio

The ash alkaline ratio is defined by the following expression using the figures showing the ratio of the basicity component to the acidic component in ash.

2322

2232

TiOOAlSiO O)KONaMgOCaOO(Fe= ratio alkalineAsh

++++++

The large ash alkaline ratio means an increased slagging characteristic because low-melting oxides and compound salt are easily generated. It is generally said that the slagging characteristic is small if the ash alkaline ratio is 0.5 or less.

This is also identified by the color of ash: much SiO2 and Al3O3 show white, much CaO shows yellow, much Fe2O3 shows red, and much Fe2O3 and CaO show pink to purple. That is to say, as the ash color changes from white to reddish, the ash slagging characteristic becomes stronger. (4) Fe2O3/CaO Ratio and S-content in Coal

When the ratio of Fe2O3 to CaO in ash is approx. 0.3-3, low-melting compounds tend to be generated. This fact can become a supplementary judgment criterion of the ash alkaline ratio. Also, when the S-content in ash is large, Fe generates basicity components and low-melting sulfuric acid complex salt, increasing the slagging characteristic. The S-content in ash is preferably 2% or less for preventing slagging problems. 2.6.1.4 Fouling and Ash Property

Fouling means a phenomenon whereby coal ash in the gaseous or melting state condenses, adheres to and builds up on the convective heat-transfer surface of the superheater or the reheater at the rear of the furnace. The following coal content affects fouling: (1) Basicity component in Ash

The most influential on fouling is basicity substances including Na. Sufficient care should be taken over coal with a large content of Na2O, K2O, Cl, CaO, etc., especially that with a large Na2O content. (2) S-content in coal

S-content in coal develops the occurrence of fouling by generating basicity components and low-melting sulfuric acid complex salt. 2.6.1.5 Abrasion and Coal Properties

Pulverized coal burning boilers will cause the abrasion of grinders (mills) or pulverized coal pipes, and also of the backside convective heat-transfer surface by fly ash. The influential mineral matter causing mill abrasion is quartz, pyrite, etc. When judged from the analytical values, the content of quartz, Fe2O3 and S-content become its criterion. The abrasion degree by fly ash is largely affected by the hardness, density and granularity of fly ash. When judging the abrasion degree based on the coal properties, the following mineral matter in ash should be focused on:

(1) Quartz (α-SiO2: Mohs hardness = 7) (2) Cristobalite (SiO2: Mohs hardness = 7) (3) Mullite (3Al2O3 & SiO2: Mohs hardness = 7.5) (4) Hematite (Fe2O3: Mohs hardness = 6) (5) Anorthite (CaAl2Si2O3: Mohs hardness = 6)

106

2.6.2 Concept of Pulverized Coal Combustion When coal is pulverized in the grinder (mill) and float-fired in the pulverized state, the ignition time and

combustion time are extremely shortened and the burner combustion can become just like heavy oil or gas fuel is being burned. This is the greatest characteristic of pulverized coal combustion. In the following section, the combustion mechanism and characteristics of pulverized coal are explained. 2.6.2.1 Combustion Mechanism of Pulverized Coal

The model of pulverized coal burning flames is shown in Fig. 1. The primary air and pulverized coal blown into the furnace from the coal compartment are heated by radiant

heat from both the surrounding flames and the high-temperature slag adhering to the furnace wall, and then start igniting and burning, forming a primary combustion area. The primary combustion area is mainly an area where volatile matter in coal is burned. And there, CH4, H2, CO etc. volatized from coal grains are mixed with oxygen in the primary air diffused from the surroundings, forming flames around the grains. The secondary burning area is mainly a char burning area, where unburned gases and chars flowing from the primary combustion area are burned by a diffusive mixture with a secondary air blown from the supplementary air compartment.

Large grain size Ash + unburned hydrocarbon

Small grain size Ash

Combustion completion

Fig. 1 Model of pulverized coal burning flame

Char burning means the combustion of oxygen and carbon diffused from the surfaces or fine pores of chars, and

the burning velocity is extremely slow compared with that of volatile matter. Therefore, char burnout time accounts for approx. 80-90% of the total coal burnout time.

In the flame model in Fig.1, the points of pulverized coal combustion we must note are the ignitability, burnout characteristic and NOx generation characteristic.

These points are closely related to the performance and operability of pulverized coal burning boilers. The ignitability and burnout characteristic are discussed in this section and the NOx generation characteristic is discussed in Section 2.3. (1) Ignitability

The ignition difficulty in pulverized coal greatly varies with the coal properties. According to the individual coal properties, we will evaluate the burner type, selection of burner design specifications, necessity of auxiliary burners, and a minimum load which can completely burn coal.

The surface temperature of pulverized coal blown into the furnace rises by its own flame and by the radiant heat from other high-temperature heat sources in the furnace, and after it reaches a certain level, the coal is ignited, as commonly explained in the radiant ignition theories. This temperature causing ignition is defined as radiant ignition temperature. Coal with a higher ignition temperature needs radiant heat from a higher temperature heat source, and hence stable ignition in the furnace is difficult, causing unstable combustion or increased unburned hydrocarbon due to the fluctuation of the ignition point. Therefore, special design consideration is required.

Coal grains Char burning area Volatile matter burning area

Secondary burning area Primary burning areaVolatile matter discharge Char burning area(Volatile matter

burning area) Supplementary air compartment

Igni

tion

Burnout characteristic

NOx generation characteristic

Ignitability

Primary burning area Qpd [Primary air/coal ratio] Secondary burning area QS = [Q total = Qp] Q : Burning quantity

107

Rad

iant

igni

tion

tem

pera

ture

(°C

)

Mora

Daido

Drayton Mirror blend

Warkworth

Newlands

Optimum

The Pacific Ocean

Miike

Volatile matter (ash-free basis) (%)

Fig. 2 Relation between volatile matter and radiant ignition temperature

Figure 2 summarizes the relation between the volatile matter in coal and the radiant ignition temperature, when a small amount of pulverized coal is forcibly fed into the electric furnace in which the temperature can be freely changed, and is ignited instantly raising shining flames where the ignition temperature is defined as the radiant ignition temperature.

As shown in the Fig., the radiant ignition temperature drops along with the increase of volatile matter content. Though the coal with the same amount of volatile matter content shows a variation in ±30°C of the radiant ignition temperature, this variation is considered to be attributed mainly to the difference in the quality of the volatile matter or calorific values.

The rate of the volatile matter content in domestic coal used in thermal power stations in our country and of imported coal ranges from 30-50% based on the ash-free basis whereas the radiant ignition temperature ranges from 600-700°C. From our past experiences, ordinary pulverized coal burning boilers have almost no problem with the combustion of coal whose radiant ignition temperature is 750°C or less.

Figure 2 shows the comparison of ignitability among coal with different properties, but actual pulverized coal is transferred by the primary air and continuously blown into the furnace, as shown in Fig.1.

Now let’s consider the ignition of pulverized coal grain assemblages which float and flow with minute intervals in the primary air flow. The coal grain assemblages in the pulverized coal plume are initially ignited by an igniter. After the igniter goes off, the grains temperature rises with a time lapse under the heat balance, where the sum of the calorific value of own flame, the radiant heat from other heat sources and the chemical reaction in the coal grain assemblages is equivalent to the calorific value which can raise the temperatures of coal grain assemblages and the primary air around it.

Pulverized coal (200/mesh passes)

Symbol Brand

Pacific Ocean coal

Daido coal

Amount of coal supply

Igni

tion

dist

ance

(m/m

)

1. Air temperature Normal temperature

Air flow rate

Temperature in furnace (°C) Fig. 3 Relation between temperature in furnace and ignition distance

108

When the surface temperature of the grains in a coal grain assemblage exceeds the coal radiant ignition temperature, they are ignited, and this position is called the ignition distance from the burner. Because the smaller the grain intervals in the coal grain assemblage (the grains density is high), the larger the radiant heat from other burning coal grains, and the smaller the air heat capacity around the coal grains, so the coal grain temperature is apt to rise and the ignition distance becomes shorter. On the other hand, if the intervals among coal grains are too small (the coal grains density is too high), it is difficult for the radiant heat from other heat sources to penetrate the core, and because the oxygen consumption of the grain assemblage exceeds the oxygen amount supplied in the primary air, it is difficult for the combustion to continue. So the ignition distance, on the contrary, becomes larger.

Thus, the pulverized coal assemblage in the primary air flow has the optimum ignition point for the coal grain density (the inverse number of primary air/coal ratio).

Also, as you understand easily, pulverized coal ignition is strongly affected by ambient temperature. As shown in Fig.3, the ignition distance of coal with lower volatile matter drastically increases along with the

ambient temperature drop, compared with that of coal with high volatile matter. This ignition distance increases due to the ambient temperature drop coinciding with the fact that the lower the

load on the pulverized coal burning boiler, the worse the ignition stability.

Bur

ning

vel

ocity

coe

ffici

ent K

* (g

/cm

2 S)

H coal

G coal

Fig. 4 Relation between burning velocity coefficient and fuel ratio

(2) Burnout Characteristic of Pulverized Coal

The burnout characteristic of pulverized coal is important data to predict the amount of unburned hydrocarbon generated in pulverized coal burning boilers, to select the degree of necessary coal fineness to maintain unburned hydrocarbon at a low level, and to determine the furnace dimensions. The burnout characteristic of pulverized coal greatly varies with coal properties.

Figure4 shows the result when coal grains with various properties are suspended with platinum wire in an electric furnace, and their combustion-decrease characteristics are measured by microbalance under the condition of constant oxygen density and gas temperature.

The combustion velocity coefficient K* is represented in the following expression:

)1()(*2

⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅−

=TDn

WWKo

Eo

π

K*:combustion velocity coefficient (g/cm2•s) W: grain weight (g) D: grain size (cm) T: combustion period (s) n: the number of grains (pieces) Suffixes: O: before combustion E: after combustion

In this figure the larger the coal fuel ratio (the ratio of fixed carbon to volatile matter), the smaller the

combustion velocity coefficient. The coefficient of the coal with a high fuel ratio is approx. 1/2-1/5 that of the coal with a low fuel ratio.

Fuel ratio (-)

Ambient gas temperature = 1,200°C Ambient oxygen density = 0.04 ala

B coal

A coal D coal

109

Because, in actual pulverized coal burning boilers, the gas/coal grain temperature and oxygen density change when coal moves from the burner exit to the furnace exit, and the combustion is largely rate-controlled by diffusion resistance in the higher temperature area, as well as by chemical reaction resistance in the lower temperature area. So it is not appropriate to use the burning velocity coefficient K*, which has been measured under a certain condition, for the calculation of the burnout in the boiler furnace.

The combustion of pulverized coal grains in the furnace is as per the following expression, where the grain size is Dp:

)3(111

)2(6

23

⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅+=

⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅⋅••−=⎟⎟⎠

⎞⎜⎜⎝

⎛

fO

PP

KKK

PKDDrodd πθ

π

Where, the signs are as follows: K: general combustion velocity coefficient (g/cm2 s) Kf: combustion velocity coefficient when the oxygen diffusion density in

the gas film is dominant (g/cm2 s) Kc: combustion velocity coefficient when the chemical reaction rate of

the grain surface is dominant (g/cm2 s) P: oxygen pressure (atm) Dp: coal grain size (cm) ro: specific gravity of coal grain (g/cm3) θ: burning time (s)

The general burning velocity coefficient ‘K’ varies depending on the coal properties in addition to the grain size and burning area gas temperature. Therefore, in order to lower unburned losses in a pulverized coal burning boiler, we must know the characteristics of pulverized coal grain’s K, coal grain size Dp (coal fineness), in-furnace retention time θ, and gas temperature distribution and oxygen density distribution in the furnace, and then determine the furnace dimensions or pulverized coal facilities.

Figure 5 shows the trajectory of the flame axis obtained by simulations of heat-transfer flow in the furnace using the aforementioned expressions (2) and (3), and the calculation results of the unburned hydrocarbon by applying the calculation of the gas & oxygen density distribution. The combustion rapidly proceeds in the area approx. five meters high above the burner toward the furnace exit, but it becomes slower in the area approx. 10 meters high, and the combustion reaction almost does not proceed in the area exceeding 20 meters high due to the gas temperature drop. Therefore, this suggests that in order to improve the burning efficiency of pulverized coal, it is more effective to reduce the coal grain size by increasing the coal fineness rather than to lengthen the retention time in the furnace. 2.6.2.2 Combustion Calculation (1) Coal Calorific Value

The coal calorific value means calories (kcal) generated when a unit amount (1kg) is completely burned out, and is defined as two types below:

(1) High heating value (HHV) or gross calorific value (GCV) (2) Low heating value (LHV) or net calorific value (NCV)

110

Fuel ratio

Fig. 5 Relation between coal fineness and unburned hydrocarbon The coal calorific value generally means a high heating value, and the measuring method is stipulated in JIS M

8814. The high heating value includes the steam-condensing latent heat (approx. 600kcal/kg) generated by burning

water (W) and hydrogen (H) in coal. However, because in the actual combustion in boilers, this steam is discharged from the stack without condensing, the latent heat cannot be utilized and the actual coal calorific value reduces by this amount. The calorific value from which this latent heat has been subtracted is called a low heating value, and is calculated by the following expression without relying on the actual measurement. (H and W are wt%)

LHV = HHV – 6(9H + W) (kcal/kg) The calorific value is a very important item for combustion calculation. Especially, when it comes to coal, the

calorific values and individual components vary largely with the type of coal - even the same type of coal varies with the mining layers. So, we must use the results from the same sample for combustion calculation and for all analytical values.

Many types of calculation formulas can be considered to obtain the calorific value using the coal analytical values, but those formulas may have omitted complex, chemically-bound heat during coal combustion, or been determined by natural experiences. So they cannot be applied to every type of coal with high accuracy. Their values should only be utilized temporarily when the calorific value has not been calculated yet.

Table 2 Component characteristics related to combustion Molecular weight

Component Molecular symbol Approx.

value Exact value Specific weight

kg/Nm3Specific constitution

Nm3kg

Carbon Hydrogen Sulfur Oxygen Nitrogen Water vapor Sulfur dioxide Air Carbon dioxide

C H2S

O2N2

H2O SO2

- CO2

12 2 32 32 28 18 64 29 44

12.011 2.016 32.064 31.999 28.013 18.015 64.053 28.964 44.010

- 0.08997

- 1.42897 1.25041 0.80374 2.92659 1.29298 1.97682

- 11.12698

- 0.69980 0.79974 1.24419 0.34169 0.77341 0.50586

The following expressions are typical examples of calorific value calculation in the ultimate analysis and

proximate analysis of coal. 1. Dulong’s expression (from the result of the ultimate analysis of coal)

HHV = 81C + 342.5(H-O/8) + 22.5S (kcal/kg) Where, C, H, O and S show the wt% of carbon, hydrogen, oxygen and sulfur, respectively.

2. Kosaka’s expression (from the result of proximate analysis of coal) HHV = 81Cf + (96 - α W) (Vm + W) (kcal/kg) Where, Cf, W and Vm show the wt% of fixed carbon, moisture, and volatile matter, respectively, and α is the coefficient of moisture and is used as the following values:

Hei

ght f

rom

the

cent

er o

f the

bur

ner

Unburned carbon ratio

Coal fineness (200 mesh pass / 100 mesh residuum)

Air temperature

Primary 82°C/secondary 312°C

111

When W<5.0 α = 6.5 When W≥5.0 α = 5.0

(2) Combustion Air Flow Rate and Combustion Gas Flow Rate

In order to burn fuel completely, it is necessary to supply necessary and adequate air (oxygen) for combustion. In actual combustion, air and fuel are not mixed ideally and it is difficult to burn fuel completely by the theoretically necessary combustion air flow rate alone, hence a proper combustion air flow rate is supplied as an excess air flow rate depending on the fuel in addition to this theoretical combustion air flow rate. Especially, for pulverized coal burning, a more excessive air flow rate is needed (for bituminous coal with high volatile matter, it is approx. 1.2-1.25 in the air ratio) because the combustion characteristic is poorer than that of heavy oil or gas due to the larger-sized, solid grains with the slow combustion velocity.

Though the major components of coal consist of carbon (C), hydrogen (H), oxygen (O), nitrogen (N), sulfur (S) etc., the combustible components are carbon, hydrogen and sulfur, each of which is completely burned to become carbon dioxide (CO2), water vapor (H2O), and sulfur dioxide (SO2), respectively. The entire oxygen in coal is considered to become water (water vapor) by combining with hydrogen during the combustion.

Table 3 List of Component Combustion Values Theoretical dry air flow rate

O2 N2 Air Combustion

product Theoretical dry gas flow

rate

Moisture amount Component

Upper row: kg/kg Lower row Nm3/kg Carbon C

2.67 1.87

8.837.02

11.508.89

(CO2)3.671.87

12.50 8.89

--

Hydrogen H2

8.00 5.60

26.4821.06

34.4826.66

(H2O)9.00

11.19

26.48 21.06

9.0011.19

Oxygen O2 -1.00 -0.70

-3.31-2.63

-4.31-3.33

--

-3.31 -2.63

--

Sulfur S 1.00 0.70

3.312.63

4.313.33

(SO2)2.000.69

5.31 3.33

--

Nitrogen N2 - -

--

--

--

1.00 0.80

--

Moisture W - -

--

--

--

- -

1.001.24

1. Calculation expressions of combustion air- and gas-flow rates in the ultimate analysis of coal

The combustion air flow rate needed for coal combustion and the generating combustion gas flow rate can be calculated by the ultimate analysis using the list of component combustion values shown in Table 2. The calculation results of component combustion are summarized in Table 3. In this case, it is assumed that air consists of oxygen and nitrogen in a weight ratio of approx. 23.2% and

76.8% each and in a volume ratio of approx. 21% and 79% each. The following shows the calculation process of the combustion air- and gas- flow rates regarding carbon

in the list, as well as regarding other components. 1 mol C + 1mol O2 = 1mol CO212 kgC + 32 kgO2 = 44 kgCO2Necessary O2 for C 1kg is:

3Nm867.1429.1667.2orkg667.2

1232

==

CO2 generation by combustion of C 1kg is: 3Nm867.1

977.1667.3orkg667.3

1244

==

The theoretical dry air flow rate of C 1kg is:

3Nm891.821

100867.1

or496.112.23

100667.2

=×

=×

N2 in C 1kg of the theoretical dry air is:

112

3Nm024.72179867.1

or829.82.238.76667.2

=×

=×

Theoretically generating combustion gas flow rate of C 1kg is: CO2 + N2 = 3.667 + 8.829 = 12.496 kg Or = 1.867 + 7.024 = 8.891Nm3

From the component combustion values shown in Table 2, the theoretical dry air flow rate (Ado) per kg is represented in the following expression:

S31.480H5.34C50.11Ado •+⎥⎦⎤

⎢⎣⎡ −+= (kg/kg)

S33.380H7.26C89.8'Ado •+⎥⎦⎤

⎢⎣⎡ −+•= (Nm3/kg)

Likewise, the theoretical dry gas flow rate (Gdo) is obtained by the following expression:

NS31.580H5.26C50.12Gdo ++⎥⎦⎤

⎢⎣⎡ −+= (kg/kg)

or,

N80.0S33.380H1.21C89.8'Gdo ++⎥⎦⎤

⎢⎣⎡ −+= (Nm3/kg)

Supposing that the moisture included in the burning air is Xa (absolute temperature, kg/kg and dry air), the water vapor flow rate (Wa) is represented in the following expression:

Wa =Xa Ado (kg/kg) or Wa’ = 1.61Xa Ado’ (Nm3/kg)

The generating water vapor flow rate (Wf) by the combustion of moisture and hydrogen during burning is represented in the following expression:

Wf = 9H + W (kg/kg) or Wf’ = 11.19H + 1.244W (Nm3/kg)

The theoretical wet gas flow rate (Gwo) by which the theoretical dry gas flow rate and the entire water vapor flow rate are added up is obtained from the following expression:

Gwo = Gdo + W + Wa (kg/kg) or Gwo’ = Gdo’ + Wf’ + Wa’ (Nm3/kg)

Supposing that the aforementioned air ratio (actual combustion air flow rate plus excess air/theoretical air ratio) is m, the actual wet air flow rate (Aw) is represented in the following expression:

Aw = m(1 + Xa)Ao (kg/kg) or Aw’ = m(1+1.61Xa)Ao’ (Nm3/kg)

The actual dry gas flow rate (Gd) and wet gas flow rate (Gw) are obtained from the following expression: Gd = Gdo + (m-1) Ado (kg/kg) or Gd’ = Gdo’ + (m-1) Ado’ (Nm3/kg) Gw = Gd + Wf + m Wa (kg/kg) or Gw’ = Gd’ + Wf’ m Wa’ (Nm3/kg)

2. Exhaust gas component

As aforementioned, if O2 1mol is supplied to C 1mol, CO2 1mol is generated. However, if air is supplied, exhaust gas consisting of 21% of CO2 and 79% of N2 generates if C is completely burned because the air consists of 21% of O2 and 79% of N2 (volume ratio). Thus, if the fuel is C alone, the upper limit of CO2 in the exhaust gas becomes 21% theoretically. However, in fuel combustion, the exhaust gas component increases while the ratio of CO2 is relatively

smaller due to the other components (S, N, etc) or the excess air flow rate (O2, N2). In this case, the theoretical CO2 content ratio (CO2max) and the actual CO2 content ratio are obtained by the following expression. Here, CO is 0, and also what has been taken into account in the actual gas analysis (liquid absorption method) is that SO2 gas is absorbed together with CO2 and quantified.

CO2max = (1.867C + 0.69S)/Gdo’ × 100 (dry vol%) CO2 = (1.867C + 0.69S)/Gdo’ × 100 (dry vol%)

Also, the other composition in the actual burning gas is obtained from the following expression: O2 = 21(m-1)Ado’/Gd’ (dry vol%) N2 = (0.8N + 0.79m Ado’)/Gd’×100 (dry vol%)

113

H2O = (Gw’-Gd’)/Gw’×100 (wet vol%) 2.6.2.3 Generation Mechanism of Nitrogen Oxide

As shown in previous Fig. 1, the pulverized coal burning area is divided into the primary combustion area, where coal volatile matter is burned, and the secondary combustion areas, where mainly chars are burned. Each area contains Thermal NOx (NOx which is defined in the Zeldvich mechanism), Prompt NOx (NOx, which is oxidized after airborne nitrogen combines with hydrocarbon to become NHi compound, and then generates), and Fuel NOx (NOx which generates by the oxidization of N in fuel). These NOx, which generate in the above mentioned areas, have the potential to become an NHi compound and to be partially reduced to N2 under the intervention of hydrocarbon in the insufficient oxygen area at the rear of the combustion area.

N c

onte

nt (%

: daf

con

vers

ion)

Australian G coal

Japanese Acoal

Chinese D coal

Raw coal

Reactor temperature (°C) Fig. 6 Relation between the residual nitrogen content in chars and the primary reactor temperature

SymbolBase condition

Fig. 7 Relation between NOx generation amount and reactor temperature

Fuel ratio (-)

Reactor temperature = 1,350°CAir ratio in the primary reactor = 0.41 Residual O2 =3%

Japanese A coal

1.09%N

Australian C coal

1.59%N

Chinese D coal

0.85%N

Japanese B coal

1.1%N

South African coal

O1.56%N

Canadian F coal

1.03%N

Coal Japanese A coal Chinese D coal

Air ratio in the primary reactor = 0.41Residual O2 = 3%

Reactor temperature (%)

114

Fig. 8 Relation between NOx generation amount and coal properties

Japanese A coal Residual O2 = 3% Secondary reactor temperature = 1,350°C Air ratio in the primary reactor = 0.41

Fig. 9 Relation between Nox generation amount and primary reactor temperature Primary reactor temperature (°C)

Thus, the NOx generation characteristic of coal fuel, which includes much organic nitrogen, has an extremely complex reaction pattern compared with conventional gas or oil fuel. In this section, we will consider the NOx generation mechanism of fundamental pulverized-coal in the reactor pipe.

First, Fig. 6 shows the volatile matter of organic nitrogen included in coal and its content ratio to char. According to this Fig., the organic nitrogen ratio included in carbonized char is almost the same as that in raw

coal. This means that both the volatile matter in coal and the char include organic nitrogen almost evenly. Also, the following shows the investigation result of NOx generation characteristics when pulverized coal is burned in the primary- and secondary combustion areas separately with two electric-heating-type magnetic reactive pipes connected by a quartz joint.

Figure 7 shows the comparison of NOx generation amounts in these areas by using (Ar+O2) and (N2+O2) as combustion carrier gas.

This difference in both areas can be considered to be Thermal NOx (Prompt NOx is included). From the figure, it is considered that almost all generation is accounted for by Fuel NOx when the reactor temperature is below 1400°C while 25-30% is accounted for by Thermal NOx when the reactor temperature is 1600°C.

Figure 8 shows the comparison of NOx generation amounts when the type of coal is changed under the primary- and secondary reactors’ temperature of 1350°C.

The relation between the type of coal and the NOx generation amount cannot be determined by the organic nitrogen content alone in coal. Rather, it seems to be more understandable by the fuel ratio.

Figure 9 shows the relation between the primary reactor temperature and the NOx generation amount, where the primary reactor air ratio is set to 0.41.

According to this figure, in the volatile matter burning area of the primary reactor, the higher the reactor temperature, the lower the NOx generation amount. This phenomenon is seen only in an air-short reductive atmosphere. Because, generally, the higher the temperature, the greater the volatile amount of carbon hydride and organic nitrogen in coal, it is considered that when the actual air ratio in the burning area of the primary reactor further decreases, the NOx generation amount will be lowered.

Japanese A coal Residual O2 = 3% Secondary reactor temperature = 1,350°C Air ratio in the primary reactor = 0.41

Retention time (S) in primary reactor

Fig. 10 Relation between Nox generation amount and retention time in primary reactor

115

Symbol

Char

Fig. 11 Comparison of NOx generation amounts between coal and char

Figure 10 shows the variation of the NOx generation amount by setting the air ratio in the primary reactor to 0.41.

According to this, the longer the coal retention time in the volatile matter burning area of the primary reactor, the lower the NOx generation amount. This is likely because the organic nitrogen gas (NH3, HCN) etc. generated in the air-short volatile matter burning area is partially reduced to N2 due to the existence of unburned gas.

Figure 11 shows the relation between the NOx generation amount and the air ratio in the primary reactor. According to this, the NOx generation amount is largely changed by the air ratio in the primary reactor. 2.6.3 Pulverized Coal Combustion Equipment

The pulverized coal combustion equipment mainly consists of a stoker, coal pulverizer (mill), pulverized-coal pipe, pulverized-coal burner and furnace (these are fuel supply- and combustion equipment behind the bunker); and of a primary draft fan (PAF) and air preheater (AH) (these are primary draft equipment). The above equipments are described below: 2.6.3.1 Pulverized Coal Burning Method

The pulverized coal burning method generally employed is classified into two types: (1) according to the burner arrangement and (2) according to the method of pulverized coal feed (direct/indirect). (1) Classification according to burner arrangement

The combustion method is classified into the following according to the relation between the furnace and the burner arrangement.

Figure 12 shows the combustion method according to the burner arrangement.

Fig. 12 Combustion methods according to burner arrangement

1. Horizontal firing (horizontal combustion) The method, where burners are placed at the front or rear of the furnace wall, is called a front firing or rear

firing method, while the method, where burners are placed at both the front and rear sides of the walls, is

Coal Japanese A coal

Residual O2 = 3% Reactor temperature = 1,350°C

Air ratio (-) in primary reactor

(4) Vertical firing

(1) Front firing (2) Opposed firing

(3) Tangential firing

(Lat

eral

sid

e)

(Fro

nt s

ide)

(Lat

eral

sid

e)

(Sur

face

sid

e)

116

called an opposed firing method. In these methods, circling motions are given to combustion air to shorten flames and the fuel and air are circulated and mixed, thereby forming high temperature flames.

2. Tangential corner firing

In this method, burners are placed at the four corners of the furnace, from which pulverized coal and air are injected tangentially into a virtual circle in the center of the furnace. Each burner independently forms a flame while the entire flame is swirling slowly in the furnace to form a single flame (fireball), featuring a long flame trajectory and slow combustion.

Stack

Desulfurization equipment

Regenerative preheater Induced draft fan

Electric dust collector

Forced draft fan

Bunker Steam air preheater Secondary air

StokerPrimary draft fan

Coal pulverizer Coal pulverizer Seal air fan

Fig. 13 Direct combustion method Primary air

3. Vertical firing (vertical combustion) Burners are installed downward from the ceiling of the lower furnace, where pulverized coal and air are

injected downward once, but the flames flow upward while burning. Since the frame trajectory adopts a U-shape, it is also called U-firing. In this method, because the combustion time can be longer and the radiation from flames is received at the burner, the burner’s heat load becomes larger, and because the pulverized coal injection speed can be lowered, the combustibility and ignitability are better. This is generally suitable for coal such as anthracite whose combustibility is poor.

(2) Classification According to Pulverized Coal Feed Method

The pulverized coal burning system is classified into the following according to the difference in pulverized coal feed methods:

(1) Direct combustion method (direct system) (2) Storing combustion method (bin system)

The direct combustion system, which has had rich achievements, has generally been employed as a standard of boilers for bituminous coal with high volatile matter.

On the other hand, the bin system has been employed since long ago for the purpose of combustion improvement in boilers for anthracite coal with low volatile matter of approx. 15% or less. Each method has the following characteristics:

1. System of combustion method In the case of the direct combustion method (Fig.13), coal from the bunker is flow-controlled and fed to

the mill by the stoker. Next, the pulverized coal, which has been ground in the mill and dried, is directly transferred and fed to the burner by the primary air through the pulverized-coal pipe. Hence, the fuel system and arrangement after the mill are simple. Though, in the case of the bin system there are various patterns, this example (Fig.14) shows the system

which uses exhaust gas for transferring and drying pulverized coal in the mill. The bin system is fundamentally different from the direct combustion method in terms of the system after

the mill, and is more or less complex, having more devices. To dry pulverized coal in the mill, combusted exhaust-gases taken from the entrance and exit of the air preheater are utilized, and each amount of the

117

gases is adjusted so that they reach the necessary temperature at the mill entrance. The gas-mixed pulverized coal from the mill is separated into pulverized coal and exhaust gas when it

passes through the cyclone (primary) and the bag filter (secondary). The pulverized coal captured here is stored in the bin while the exhaust gas is returned to the air preheater exit by the exhaust fan. The pulverized coal is transferred by the pulverized-coal stoker from the bin to the burner entrance, where

it is blended with the primary air and fed into the burner.

2. Operability In the direct combustion method, the mill operation and burner operation are directly interlocked, and the

load operation is restricted both by the mill operation (the minimum mill load and the dynamics including mill startup) and by the combustibility at the burner.

Bag filter Bunker Stack

Cyc

lone

Des

ulfu

rizat

ion

equi

pmen

t Exhaust fan

Stoker Screw conveyor

Induced draft fan Coal

pulverizer

Regenerative air preheater Electric dust

collector Pulverized-coal

bin

Stoker Forced draft facfan Steam air preheater

Primary draft fan Distributor Secondary air

Fig. 14 Bin system for pulverized coalPrimary air

In the bin system, coal grinding and drying in the mill and combustion at the burner can be separated, so there is no operation restriction by the mill in terms of the load operation, but the combustion alone at the burner is restricted. This is a little more advantageous than the direct combustion method.

3. Combustibility

In the direct combustion method, when a mill load is low, the air/fuel ratio becomes larger as the load is lowered, thereby combustibility is apt to worsen. In the bin system, as aforementioned, grinding and drying in the mill and the pulverized coal input to the

burner can be independently operated (however, within the bin’s capacity), and the coal moisture evaporated in the mill is discharged outside the system. Therefore, the burner can ensure the optimal, dried primary air/ratio with high to low load. This is especially much better for combustibility with a low load than in the direct combustion method. However, the direct combustion method can also maintain combustibility equivalent to that in the bin system by employing a high turndown burner (where an air-pulverized coal mixture is separated into thick and thin types to burn).

4. Maintainability

In the direct combustion method, the greater the number of mills, the more frequent the maintenance and services of the mills, but it is possible to schedule the intervals of maintenance and services by installing backup mills. In the bin system, the mill’s maintenance and services become easier because the number of mills can be

reduced. And mills can be halted for a short time (depending on the bin capacity), during which maintenance is possible. However, the frequency of maintenance and services for other devices (a cyclone, bag filter, exhaust fan, etc) increases.

5. Safety

In the direct combustion method, special safety measures are not needed because there is no pulverized

118

coal storage, whereas in the bin system, strict safety measures (sealing the bin by inert gas, installing electrostatic, explosion-proof-type explosion doors, enhancing monitor systems, arranging fire extinguishing equipment, etc.) are required in order to prevent pulverized coal in the bin from sparking and exploding.

2.6.3.2 Furnace

Furnaces must fulfill certain functions: to convert the chemical energy of fuel into thermal energy effectively, that is to say, to have combustion equipment (a chamber) to burn fuel completely; and to let the internal can-water absorb generated heat through the surrounding water pipes. For these purposes, furnaces must be equipped with the proper type and quantity of burners according to the fuel, and have the appropriate shape and space to completely burn fuel, as well as the structure to withstand the thermal load.

Typical bituminous coal Heavy oil Gas

Fig. 15 Conceptual comparison of fuel and furnace size

Especially, because the coal (pulverized coal) combustibility is fairly inferior to that of other fuels (heavy oil, gas, etc.), a larger sized chamber (furnace) is required. The furnace size must be selected by taking into account the combustibility and also the slagging characteristic of coal (ash adherence to the furnace).

Figure 15 shows the comparison between the type of fuel and furnace size. As shown in the comparison between the type of coal (coal rank) and furnace size in Fig. 16, the furnace size

varies largely with the type of coal. The difference in some furnaces is larger than that in fuels (typical bituminous coal and heavy oil).

For recent furnace walls, a welded wall structure, where both pipes are welded by a fin or a weld metal to ensure air tightness of the furnace, has been employed to decrease heat losses and repair costs. 2.6.3.3 Pulverized Coal Burner

The coal combustion method generally employed is mainly classified into two types: the grate-type combustion method in which coal is not ground; and the burner combustion method in which coal is pulverized into minute grains by the coal pulverizer and float-fired in the air.

Though the former features relatively less power consumption and less flying ash, it is not suitable as combustion equipment for large capacity boilers.

On the other hand, the latter uses pulverized-coal burners to feed pulverized coal into the furnace and burn it. Compared with the grate-type combustion method, this has many advantages: (1) excess air is less and the combustion efficiency is high, (2) adjustment of load and combustion is easier and ignition and extinguishing time is shorter, (3) automatic control is easier, and (4) combustion by mixing with liquid- or gas fuel is easier.

119

Bituminous coal with medium

volatile matter

Fig. 16 Conceptual comparison of coal rank and furnace size

Semi-bituminous coal with high volatile matter

Brown coal with low Na

Brown coal with medium

Na

Brown coal with High Na

In the pulverized coal burner, a premixed airflow of both the pulverized coal ground by the pulverizer and the

primary air is injected into the furnace through a boxy or cylindrical nozzle, and from the vicinity of this nozzle, the secondary air heated by the air preheater is blown in. The pulverized coal, which has been injected together with the primary air, diffuses rapidly while slowing the speed after coming out of the nozzle, and is ignited and burned while mixing with the secondary air from the outside by receiving radiant heat from the high-temperature furnace wall and flames. The flow rate of the mixed gas of pulverized coal and primary air is set by taking into account the flame velocity and the pulverized coal settling velocity.

Figures 17-19 show the structures of typical pulverized coal burners. The burners in Figs. 17 and 18 have been designed so that the rotating device gives rotating motions to the mixed gas of pulverized coal and primary air.

The pulverized coal burner in Fig. 19, called a tangential tilting burner, has been designed so that the nozzle of the burner tip moves up and down each at the angle of approx. 30 degrees to adjust steam temperature.

Either burner is usually equipped with an ignition burner in the center or the side. The pulverized coal burner requires maintenance because the tip is especially apt to be deformed and damaged

by receiving radiant heat in the furnace and vulnerable to abrasion by pulverized coal. Therefore, recently new techniques have been developed for durability improvement, such as lining the burner with material (made into a tile form) - ceramic etc. with high heat and abrasion resistance -, or flame-spray coating the surface. Some of them have been practically used.

Air adjustment handle

Ele

ctro

de

Ignition burner Air cylinder

Transformer

Impe

ller

Air cylinder

Heavy oil burner

Pul

veriz

ed c

oal

burn

er Pulverized coal

entrance

Air register (circular type) Inspection window

Fig. 17 Circular burner

In addition to the abovementioned durability, the following functions are required for pulverized coal burners: (1) Low NOx combustibility (2) High turndown

The background is: nowadays we must comply with strict environmental regulations; our country has been importing coal from all over the world, hence we must deal with such various properties of foreign coal; the need for coal-fired power as intermediate-load thermal power has been rising because nuclear power generation has recently increased and the difference between the day and night power demands has increased.

Next, a representative low NOx burner is described below:

120

Figure 20 shows the structure of a DF inter-vane pulverized coal burner. The secondary air is supplied toward the burner throat through two independent channels so that flames are

stabilized and the mixture of fuel and secondary air can be adjusted. The circular nozzle, from which fuel is injected, consists of an outer casing and a combustion liner. Each end of the nozzle is narrowed down so that the fuel concentrates on the center of the axis. The end of the combustion liner can be moved toward the axis, thereby adjusting the mixture of fuel and secondary air.

Figure 21 shows the structure of the NR burner. The pulverized-coal nozzle is placed in the center of the burner. On the concentric circle of the outer periphery,

a cylindrical nozzle is mounted to supply inner-peripheral burning-air. Furthermore, outside of this, a burning-air-rotating device is installed to adjust outer-peripheral burning-air. Around the periphery of the pulverized-coal nozzle tip, a ceramic-made flame-stabilizer ring is mounted so that minute vortices can be generated in the pulverized coal flow, enabling quick ignition of the pulverized coal, and stabilizing high-temperature reduction flames of excess fuel.

Shroud ring

Pulverized-coal outer casing

Pulverized-coal combustion liner

Oil burner

Tertiary damper

Vane support plate

Front plate

VaneTertiary air pipe

Fig. 18 Inter-vane type burner

Secondary air (heavy oil burner)

Pulverized coal + primary air

Secondary air (heavy oil burner)

Fig. 19 Tangential tilting burner

Figure 22 shows a pulverized coal PM burner. This burner utilizes the characteristic that NOx generating during pulverized-coal combustion decreases at both

the thick/thin pulverized-coal density sides after the primary air/coal weight ratio reaches 3-4. That is to say, by installing a distributor at the burner entrance, the air-fuel mixture, whose usual primary-air/coal weight ratio is 2-3, is divided into the higher and lower mixtures of the pulverized coal density, and is fed into the furnace through separate nozzles and burned so that NOx becomes lowest.

The high-turndown burner, in principle, divides the air-fuel mixture of pulverized coal into thick and thin

121

mixtures. Though with common burners, the pulverized coal density becomes lower and the ignition stability worsens when the burner load is lower, this high-turndown burner maintains better ignition stability with this thick mixture even when the burner load is low.

Primary air + pulverized coal

Burner tile cooling air

Separate plate

Moving combustion liner

Combustion liner driving device Flow divider

Heavy oil entrance

Pitot tube Primary air + pulverized coal

Heavy oil burnerCombustion liner Inner secondary air

Fig. 20 DF inter-vane pulverized coal burner

Figures 23 and 24 show high-turndown burners. The aforementioned PM is also a high-turndown burner. The burner in Fig. 23 is called a split burner. The burner body has a diaphragm and the nozzle tip has a deflector.

When a primary-air-fuel mixture flows through the bend section of the burner entrance, the high mixture (bend outer-periphery side) and the low mixture (inner-periphery side) of the pulverized coal density are divided by the centrifugal force of the pulverized coal.

Fig. 21 NR burner

Purge air connection inlet Outer secondary air Outer casingSecondary-air vane

opening/closing device Inner-vaneFurnace front wall and furnace wall pipe

Tertiary air damper Heat sealed plate

Secondary-air vaneInner-vane opening/closing device Secondary air

Tertiary air pipe

Pulverized coal entrance manifold

Heat pipe

Pilot torch High-performance combustion-air circling path

Flame stabilizing ring (with ceramic parts)

Guide sleeve

Pulverized coal + primary air

Outer-periphery combustion air

Inner-periphery combustion air

122

Fig. 22 Pulverized coal PM burner

Burner side face

Fig. 23 Split burner

Burner front side Variable separator

Coal nozzle tip Horizontal diaphragmCoal nozzle Seal plate

Entrance elbow

Thick mixture

N b

Thin mixture
o kickerlock

123

Fig. 24 Wide-range burner

Pulverized coal entrance (primary air)

(1)

High load position

Low load position

Low load position High load

position

(2) (3)

(6)(5)(4)

(7)

(9)(8)

Secondary air Tertiary air

(1) Split damper (2) Traverse-mounted cyclone (3) Cyclone exit damper (4) Pilot torch (5) Swirler (6) Burner nozzle (7) Oil burner (8) Tertiary damper (9) Low load nozzle

In the wide-range burner in Fig.24, the traverse-mounted separator on the burner entrance separates the

pulverized coal flow into high-density and low-density.

Mill outlet damper

Classifier

Oil pressureload equipment

Separator body

Separator Body liner

RollPull ring segment

Fig. 25 Bowl mill 2.6.3.4 Coal Pulverizer (hereafter referred to as mill)

The coal pulverizer is the most important equipment to govern the operability and reliability of coal burning boilers. Therefore, an optimum mill type must be selected from the comprehensive viewpoint according to the coal properties and the operation conditions. The mills are classified broadly according to the grinding method, structure, and draft method. As far as the mills used in thermal power stations are concerned, they can be classified into the following:

(1) Upright mill

124

(2) Hammer mill and beater wheel mill Upright mills are suitable for bituminous coal, semi-bituminous coal and part of brown coal; tube mills and

beater wheel mills are used for high-ash content coal; and hammer mills are used for high-moisture brown coal. Nowadays, domestic coal burning boilers mainly use an upright mill for the following reasons: 1) It can be used for broad types of coal and is suitable for bituminous and semi-bituminous coal burned in

domestic boilers. 2) It needs low consumption power. 3) It is easy to adjust the pulverization degree and start/stop, and excellent in load responsiveness. 4) Necessary floor space is smaller and noise is smaller.

(1) Upright Mill 1. Structure

Figures 25-29 show the structures of various types of upright mills. The upright mills mainly consist of a reducer section, grinding and drying section, and coarse grain separator

section.

(1)Raw coal Pulverized coal

(2)

(3)

(4)(5)(6)

(7)

Hot air entrance

Fig. 26 Upright MBF mill: drawing of whole assembly

(1) Pulverized-coal pipe (2) Vane driving equipment (3) Coarse-grain separator vane (4) Reject shoot (5) Stoker pipe (6) Grinding roller (three pieces) (7) Roller pressurizer (8) Air port ring (9) Table segment (10) Grinding table (11) Foreign substance discharge scraper (12) Foreign substance discharge hole (13)Reducer

Coal, which is fed from the stoker through the stoker pipe positioned in the center of the mill, falls into the rotating bowl (table), and is spread by centrifugal force, forming a coal layer. This coal layer is inserted between the roll and the segment liner on the bowl (table), and ground by the roll with the grinding load applied to the roll by the loading device.

The pulverized coal is blown up by hot air, which is fed by the periphery of the grinding section, and classified by the upper classifier while being dried. There are two types of classifiers: a fixed type cyclone separator and a rotary separator. Nowadays, the rotary separator (Fig. 29) is often used because of high combustion efficiency and energy saving. This provides a high pulverization degree of more than 90% by 200-mesh passing.

The foreign substances and pyrite mixed in coal fall from the air blow section to beneath the bowl, and are discharged by the scraper into the pyrite hopper through the pyrite discharge pipe.

125

Coal entrance

Primary air inlet

Supply and drain water

Fig. 27 Cross-sectional view of large scale E mill

Mill exit stop-valveStoker pipe entrance section

Mill upper housing

Coarse grain separator (classifier)

Sealing air piping

Upper-housing disassembling support leg

Loading rod seal Spring frame

Fig. 28

Nowadays, coal burning boilers have often employed pressure mills whose abrasive exhausters need not be

repaired. For these mills, seal air is supplied to prevent pulverized coal leak. Also as a measure to prevent coal blockage in the stoker pipe, a rotary-type pipe is mounted.

Pressure frame Spring Grinding-roller

ring seat cover

Mill intermediate housing

Loading rod

Grinding ring Throat ring Lower housing Ring seat

Pyrite blow

Yoke Primary air inlet

Pyrite box

Yoke seal air Gear box

Pressure cylinder

126

Raw coal

Stoker pipe

Classifier driving equipment

Outlet port

Rotary type classifier

Hydraulic loading device Hot-air inlet

duct

Pull ring segment

Bowl

Fig. 29 MRS type bowl mill

2. Operation and maintenance

The operation of upright mills is simple and start/stop operation can be completely automated. Also, the wide range of the mill operation load adjustment is important for coal boiler operability. The upright mill is available for 40-50% turndown, but recently some types of upright mills have become

available for high-turndown operation up to 30% or less. For mills operation, the maintenance of abrasive parts is also extremely important. So, studies have been

conducted to develop abrasion-resistant materials and to simplify the replacement of roll rings, liners, etc. As for the material of rolls, in addition to conventional abrasion-resistant cast iron, curing cladding-welding material with several times abrasion-resistance of cast iron has also been used.

Because the life of the grinding section varies with the coal properties and the operation conditions, etc, it is necessary to measure periodically the abrasion depth of the rolls or segments of each plant and to schedule the intervals of replacement. Generally, rolls/rings/liners replacement is conducted in such a manner that one unit of extra mill per boiler is installed, and maintenance intervals are set, and each mill is maintained sequentially.

Fig. 30 Tube mill

127

Fig. 31 Structure of horizontal-type bowl mill

Pulverized coal + gas mixture

Hot gas + coal Pulverizer housing

Pulverizer wheel Hot air (for sealing)

Coal pulverizer gate mill gage Abrasion-resistant

platePrimary grinder

Bearing Driving machine

Fig.32 Beater wheel mill

(2) Hammer mill and beater wheel mill The hammer mill is a machine that smashes coal with the beating impacts of many hammers or heads rotated at

high-speed. This is used for inferior coal (high moisture coal, brown coal) or to grind coal coarsely. (Fig.32) Many hammer mills have been used for brown-coal burning boilers in Europe and Australia, but our country

has no application example. 2.6.3.5 Stoker

The stoker is equipment which plays an essential role to determine the combustion rate corresponding to the load variation and maintain the optimum air/fuel ratio in the coal combustion system.

The most important point when selecting a stoker is that it feeds the correct amount of coal into the pulverizer from the bunker or silo smoothly and uniformly according to the fuel demand signals.

The following are the types and characteristics of stokers commonly used for pulverized coal boilers. (1) Belt-type volumetric feeder

This stoker, using rubber belts, has a stable feeding capacity because coal is cut out equally in width and height. With little interruption of coal feeding and good maintainability, this is generally used for pulverized coal combustion equipment. Since this is a volume-control type, the coal weight sometimes varies according to the coal density variation.

128

(2) Belt-type gravimetric feeder Figure 33 shows the structure of the belt-type gravimetric feeder. This is a belt-type stoker equipped with a measuring mechanism with a load cell. Because the fuel demand can

be met based on the coal weight and the feeding is exact and stable, the fuel variation caused by the coal density is compensated.

Thus, because the fuel is correctly controlled and the weight and flow measurements are highly accurate and maintainability is also excellent, this is suitable for sophisticated plant control with a calculator. 2.6.3.6 Primary Draft Equipment

In the direct combustion method, the primary air is used for not only burning pulverized coal, but also drying and transferring it to the burner in the mill.

In the primary draft system, the primary draft fan (PAF) is placed in two methods relative to the air preheater (AH) according to the air temperature: a Cold Primary Air Fan method (PAF is installed upstream of the AH, dealing with cold air) and a Hot Primary Air Fan method (PAF is installed downstream of the AH in the upstream of the mill, dealing with hot air).

Figure 34 shows the comparison among these circuits. (1) Comparison between Cold PAF and Hot PAF methods 1. PAF capacity

Cold PAF has a capacity to deal with a primary air flow rate of all mills by one to two PAFs (depending on the number of draft circuits) regardless of the number of mills.

Fig. 33 Belt-type gravimetric feeder

Coa

l ent

ranc

e (fr

om b

unke

r)

Dresser coupling Downspout

Measuring module Puddle switch for on-belt coal shortage monitor

Illuminating lamp Head pulley Measuring roller

Measuring span roller

Entrance door Entrance gate (fixed type) End plate

Measuring span

Exit door

Belt scraper

Coa

l exi

t (to

mill)

Tension pulley Cell preening take-up pulley

Belt take-up adjust screw

Seal air manifold Cleaning conveyor Cleaning-conveyor

chain sprocket Support roller

Cleaning conveyor chain take-up

On the other hand, Hot PAF is installed in the one PAF - one mill base and the capacity is one mill’s worth of the primary air amount, so the same number of units as that of mills is required.

Comparing the total capacities (power) of each method, the Hot PAF method, which deals with hot air, has larger capacity. 2. AH type

In the Cold PAF method, the air pressure in the primary air circuit is higher than that in the secondary air circuit, so the AH flow path must be divided into two: for the primary and for the secondary.

The AH is mainly classified into two: an integrated type and a separate type, as shown in Fig. 35. For common pulverized coal burning boilers, the integrated AH type is often employed because the duct and AH placement become simpler and the necessary space is smaller.

In the Hot PAF method, the air pressure in the primary air circuit is lower than that in the secondary circuit, so the AH flow path need not be separated for the primary and the secondary. Figure 34 shows a standard type of AH, through which the total air flow rate of the primary and secondary air circuits passes AH and then the primary hot air diverges to be absorbed by PAF.

129

3. Operation power

Cold PAF method Hot PAF method

MillMill

Control damper Control

damper

Prim

ary

cold

air

Fig. 34 Comparison of PAF systems

When operated with high load using many mills, the Cold PAF method has high fan efficiency because fewer

PAFs deal with the primary air flow rate necessary for the operation of all moving mills, and the power consumption is smaller than that of Hot PAF since cold air is dealt with.

On the contrary, when operated with low load using fewer mills, the Hot PAF method consumes smaller power in total than that of the Cold PAF method (if the Cold PAF efficiency drops notably with low load) because the idling mill’s PAFs can be stopped and the fan efficiency of the moving PAFs is as high as that during high load operation with the high mill load. 4. Operability

Fig. 35 Comparison of AH types in Cold PAF method

When the mill load and moisture in coal are changed, the necessary temperature at the mill entrance is changed. The Hot PAF is affected directly by this temperature change and its operation point changes. However, the Cold PAF is always constant in cold air. Even when necessary temperature at the mill entrance is changed (a change in the ratio of hot air to cold air), the Cold PAF is less affected by air volume and air pressure fluctuation, and easily controlled.

Prim

ary

hota

ir

Sec

onda

ry a

ir

Com

bust

ion

gas

Prim

ary

cold

air

Prim

ary

hot

air

Sec

onda

ry a

ir

Com

bust

ion

gas

Integrated type Separate type Twin flow type Tri-sector type

System From boiler

To mill From boiler From boiler

To mill

To mill To boiler To boilerTo boiler

From PAF

From PAF

From PAF

From FDF From FDF

From FDF

From IDF From IDF From IDF

Primary air

Primary air Primary air

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Secondary air

Secondary air

Secondary air

Inner periphery

split wayOuter periphery

Three-

Distribution adjustment of gas flow rate to primary- and secondary AHs can be available

Primary air temperature control

Distribution adjustment of gas flow rate to primary- and secondary air sides can be available

Positive- and inverse rotations are available and large change alone is possible

Duct work Slightly complex Relatively simple Relatively simple

Construction cost, power cost and air leak amount Almost same

130

5. Economic efficiency As for equipment cost, AH is higher and PAF is lower in the Cold PAF method than in the Hot PAF method, but

these cannot simply be compared because, as a matter of fact, they largely vary with equipment arrangement, duct work, etc. As for operation power, the efficiency is reversed depending on the operation load area, as aforementioned, so it is necessary to estimate the economic effect comprehensively, including operation patterns, to decide the path to be taken.

Generally speaking, high-capacity, exclusive coal-combustion boilers often employ the Cold PAF method while small-capacity boilers with fewer mills or co-combustion boilers often employ the Hot PAF method. (2) PAF placement and type

In the Cold PAF method, there are two ways to place PAF: in series with FDF or in parallel with FDF. The comparison between them is shown in Table 4.

Regarding the PAF types, a centrifugal type has traditionally been used because the air pressure required by PAF is high and flat across the entire area as shown in Fig. 36 and because the conventional axial-flow fans could not be enlarged or improved in performance to prevent surging.

Nowadays, the axial-flow fans have been improved against surging characteristics, and some of them have been provided with a casing treatment suitable for the rotating-blade tips to enhance the fan efficiency.

2.6.3.7 Bunker

The design of bunkers must be fully considered so that they do not cause coal retention or blockage because such bunker problems are crucial issues causing a load decrease or unit trip in the power stations. (1) Design of bunker 1. Capacity

The bunker capacity is determined by the following expressions: The coal amount stored within an available feeding time is:

γ=

QTVc

Hence, the bunker capacity becomes )100/(

VcVη

=

However, V: bunker capacity (m3) Vc: storage capacity (m3) Q: feeding capacity (conveyor capacity) (t/h) T: available feeding time (h) γ: coal volume specific gravity (foreign coal generally has approx. 0.8) (t/m3) η: volumetric efficiency (the ratio of storage capacity to bunker capacity is generally 0.6-1.0)

(%) Table 4 Comparison between PAF layouts

System type PAF-FDF series configuration PAF/FDF parallel configuration

System structure

Fundamental characteristics

FDF air flow rate is larger but PAF air pressure decreases by the amount of FDF discharged air pressure compared with the method described at right.

FDF air flow rate decreases by the amount of PAF air flow rate compared with the method described at left.

Selection criterion

The method with a higher economic effect should be employed by taking into account the characteristics of primary- and secondary air flow rates and air pressure required by the pulverized coal combustion equipment as well as the characteristics of fans (varies with the types).

Boiler Mill Mill Boiler

131

2. Bunker shape Generally, there are two types of bunkers: a conical shape and a pyramidal shape. They are almost the same in

flow characteristics in a bunker, but the conical shape is excellent in the space-occupation rate while the pyramidal shape is excellent in strength. 3. Inclination angle of hopper wall face

In order for coal to assume an arch shape and not to cause blockage in the bunker, the arch bending moment must be large. Because the arch bending moment is proportional to the squared distance between the fulcrums and to the load applied to the arch, the cross-sectional area of the exit and the inclination angle of the wall face must be more or less large. Generally, an angle of more than 70 degrees has been employed.

Characteristic of conventional type PAF

(large type)

Fig. 36 PAF characteristic improvement provided with casing treatment 4. Bunker exit

Though the bunker exit is restricted by the diameter of the downspout or the stoker, the larger the bunker exit, the better blockage prevention. There is a method to enlarge the cross-sectional area of the main bunker exit by installing a sub-bunker under the bunker. 5. Material

Almost all bunkers are made of steel plates. The bunker exit, where blockage is most apt to occur, is usually provided with a lining of high corrosion resistant stainless steel or polymeric synthetic resin. Also, Gunite is sometimes used as a lining material on the vertical section by taking into account the resistance to abrasion.

Fig. 37 Plug flow and mass flow

(2) Flow form and the determination factors

There are two types of coal flow forms: a plug flow (core flow) and a mass flow. In the plug flow, as shown in Fig.37, the coal near the bunker wall does not move but the coal in or around the

center only flows out. On the contrary, in the mass flow, the coal in the bunker gradually flows out from the lower position of the bunker.

Air

pres

sure

H (m

mH

2O) (With casing

treatment)

Improved type

Necessary Q-H characteristic

Conventional type PAF (without casing treatment)

Air flow rate Q (m3/min.)

Adhesive coalNon adhesive coal

Mass flow Plug flow (core flow)

132

Therefore, the mass flow does not retain coal for a long time in the bunker, but the plug flow always retains coal in the lower position in the bunker.

The flow form is mainly determined by the following factors: 1. Type of coal

Adhesive coal is apt to take the plug flow pattern, causing blockage. 2. Inclination angle of hopper wall face

It is confirmed by the experiments that if the inclination angle of the wall face exceeds 65-70 degrees, the flow separates into a mass flow and a plug flow.

3. Material for bunker inner face When corrosion-prone material, such as steel plates, is used for a bunker inner face, corroded portions cause

an adherence phenomenon, resulting in the retention or blockage of coal. Hence, corrosion resistant material is usually used: the inner face is often provided with a lining of high corrosion resistant stainless steel or polymeric synthetic resin to prevent corrosion.

(3) Coal properties and blockage 1. Repose angle

The larger the coal grains the more often blockage occurs. The coal flow is affected by grain size distribution, ash and clay contents and moisture as mentioned below (Fig. 38).

Bun

ker d

isch

arge

flow

-rate

per

cr

oss-

sect

iona

l are

a of

the

exit

(gkm

3 s)

Rep

ose

angl

e (d

egre

e)

Moisture (%) Fig. 38 Repose angle and blockage

Repose angle (degree)

2. Grain size distribution

The finer the grains, the more blockage is apt to occur, though slightly different according to the moisture content. 3. Ash and clay contents

Ash and clay contents are no problem if their surface moisture is slight. But if it is large, adherence occurs, resulting in blockage. 4. Moisture

Moisture (especially surface moisture) is a crucial factor. The smaller the grain, the larger the influence, and 10-15% moisture has the highest possibility of causing blockage. However, when exceeding this rate, on the contrary, adhesiveness decreases. This means that when moisture is slight, it exists as a film over a grain surface, causing surface friction among coal grains, whereas when moisture increases, this film breaks, developing lubricating action. (4) Blockage prevention measures

As aforementioned, blockage can be significantly prevented by bunker specifications by considering the coal flow- and hopper discharge characteristics, but the following methods are also effective for blockage:

(1) Blending coal (2) Installing a corner plate (3) Providing a poking hole and a hammering seat (4) Installing an air-blaster (5) Installing a vibrator

2.7 Examples for the Operation of Soot Blowers

Reduction of Steam Volume by Revising the Operation of

Low Load Soot Blowers in Tsuruga Thermal Power Plant The Sun Shift C Power Generation Environment Section Tsuruga Thermal Power Plant Hokuriku Electric Power Co., Ltd.

◎ Keywords: radiation, prevention of thermal loss due to thermal conduction

◎ Outline of the Theme Rapid surges electric load are frequently observed early in the morning at coal thermal power plants. For

Unit 1 of Tsuruga Thermal Power Plant, when an electric load range of less than 250 MW continued for 8 hours or more, all soot blowers were activated to uplift the electric load. In this project, an examination was to determine which soot blowers should be turned on to improve the soot blower operations and maintain the electric load the volume of steam at appropriate levels.

◎ Period of the Study (April 2001 – March 2003) ･ Planning: 6 months (April – September 2001) ･ Measures Taken: 12 months (October 2001 – September 2002) ･ Assessment of Results: 6 months (October 2002 – March 2003) ◎ Outline of Tsuruga Thermal Power Plant ･ Production: Electricity (Unit 1: 500 MW, Unit 2: 700 MW) ･ Employees: 107 ･ Annual consumption of energy (as of FY2002) Coal: 2,294,398 (ton) Heavy Oil: 3,355 (kl) ◎ Outline of the Facility

High temperature reheated steam pipe

Detailed drawing of the boiler Main steam pipe

ehea

ter WW3 level

Turbine Generator

Low temperature reheated steam pipe Condenser

Main water Water feed

pump

Super-heater

R

Boiler

feed pipe

Fig. 1: Outline of the Facility

133

WW2 level

WW1 level

Soot blower

1. Background of the Theme Selection There is a growing gap in electricity consumption between daytime and nighttime. Even in coal thermal

power plants, electric load adjustment is frequently performed excluding the high electric load time. In Unit 1 of Tsuruga Thermal Power Plant, all soot blowers set up in the plant used to be turned on to uplift the power from the low electric load range to the high electric load range to compensate for the gap in the electric demand. Before doing so, the unit was subject to be in low electric load operation for 2 hours and 45 minutes before starting the blowers. The way the soot blowers are used is subject to a revision in this project to smoothen the shift from the low electric load to the high electric load range, to minimize the transition time of electric load restriction and to lower the volume of steam consumed.

2. Current Conditions and Analysis (1) Current Conditions a. Aim and Type of Soot Blowers Coal contains 10% ash, and combustion of coal generates even more ash. When the ash is deposited in the

steam pipe, the heat transfer performance decreases. The thicker the ash layer on the pipe, the greater the heat transfer performance deteriorates causing a decrease in steam temperature. The ash layer is not uniformly distributed throughout the pipe, but attaches in a random manner on the inner wall of the pipe. This causes difference in temperature of the metal surface of the pipe, increases thermal stress and may damage to the pipe. In order to remove the ash, a soot blower is used. As shown in Fig. 2 and 3, a lance tube rotates and moves forward driven by a motor and injects high pressure steam from the nozzle attached to it to clean the thermal transfer surface of the boiler.

Steam pipe Swivel tube

MotorSteam

Steamvalve Ash (deposits)

Fig. 2 Appearance of a Furnace Soot Blower

Motor Furnace

Ash (deposits) Lance tubeSteam valve

Fig. 3: Appearance of a Long Soot Blower Table 1 shows the types of soot blowers. The blowers are installed as shown in Fig. 1 considering the

balance of collecting thermal energy by the boiler.

Table 1: Types of Soot Blowers

Type Nos. of Units

Moving distance R.P.M. Steam

consumption Furnace soot

blower Furnace (WW) 54 290(mm) 1.0(rpm) 35.5(kg/pc.)

Superheater (SH) 16 Reheater (RH) 10 Long soot

blower Rear thermal transmission part 8

7,950(mm) 16.9(rpm) 656.5(kg/pc.)

Air preheater ＡＨ 2 2,540(mm) － 7,300(kg/pc.) Total 90 －－ 24,240(kg)

134

b. Operation of Soot Blowers Figures 4, 5 and 6 show the process of operating a soot blower, rotation mode and the relationship between

the stain indicator and the soot blower respectively. In the high electric load range (250 MW or above), the stain indicator is calculated to express the condition of ash deposited onto the thermal transfer surface, to automatically operate the soot blower to the ash deposit areas only. However, in the low electric load range (less than 250 MW), the stain indicator calculation is unreliable, necessitating operation of all soot blowers, otherwise ash cannot be removed completely from all the areas of the thermal transmission area, causing temperature surge of the metal surfaces and widened difference in the internal wall temperature of the furnace.

A

ttach

men

t of a

sh

to th

e th

erm

al

trans

mis

sion

surf

aces

Dec

reas

e of

ther

mal

tra

nsm

issi

on

perf

orm

ance

Incr

ease

of c

oal

cons

umpt

ion

Incr

ease

of m

etal

su

rfac

e te

mpe

ratu

re

Com

bust

ion

of c

oal

Soot

blo

win

g

Fig. 4: Process of Soot Blowing

Sequence Control

Automatic Combustion Control

Area of ash deposits (of over and above the designated stain indicator level) Load of 250 MW or above

All units

"Soot Blower to be Operated""Operation Mode"

Soot Blower Start Graph StartStop

Stain Indicator Graph

Fig. 5: Operation Mode of Soot Blowers Fig. 6: Soot Blower and Stain Indicators

(2) Analysis of the Current Conditions In the electric load range shown in Fig. 7, the thermal collection performance of the furnace is not balanced.

If a soot blower is used, the boiler is subject to a disturbance and hence, the areas for which soot blowing is prohibited are designated. If the low electric load condition continues for 8 hours or more after all soot blowers are operated before decreasing the electric load to the low electric load area, the thermal transmission surface is stained with uneven distribution of ash deposits. Thus, the duration of 2 hours and 45 minutes is set during which the low electric load condition is maintained, and, after 2 hours and 45 minutes, soot blowing is conducted using all soot blowers. (See Fig. 8)

The ranges in which soot blowing is prohibited

Gen

erat

or O

utpu

t (M

W)

Gen

erat

or O

utpu

t (M

W)

Starts all soot blowers


8 hours or more 2 hours and 45 minutes

Fig. 7: Soot Blowing Prohibition Zones Fig.8: Timing of Soot Blowing

135

3. Progress of Actions (1) Organization At Tsuruga Thermal Power Plant, ‘decreasing the power generation cost’ and ‘enhancing the reliability of the

power generation facilities’ prioritized. In line with this policy, a series of actions was implemented to further decrease the power generation cost.

(2) Setting Targets When an electric load is uplifted by starting soot blowers at a constant electric load of 125 MW after

confirming that the low electric load range of less than 250 MW continues for 8 hours or more, which soot blowers should be used is determined to reduce the number of soot blowers to be used for removing ash and hence to reduce steam consumption. The reduction target is set for each group of furnaces, superheaters and reheaters by considering the balance of thermal collection performance.

Target steam consumption: 8,500 kg/time

(reduction of 65%) Current steam consumption: 24,240 kg/time

(3) Challenges and Examinations Coal thermal power plants use various types of coal to generate electricity. The degree of ash deposited

and combustion performance greatly vary from coal-to-coal. An important indicator for determining the combustion performance of coal includes the combustion ratio, which is expressed by the ratio of fixed carbon and volatile matter content.

Combustion ratio = Fixed carbon/Volatile matter content Coals are categorized in terms of the combustion ratio to examine the part where soot blowing should be

conducted.

Table 2: Combustibility of Coal Coal Combustibility Ash content SH and RH sides

Highly combustible coal

Standard coal

Low combustible coal

Low

High

High

Low

SH/RH side

Furnace side 4. Measures Taken (1) Selection of Soot Blower Group After considering the coal categories and combustibility shown in Table 2, a soot blower operation test was

conducted to two patterns as shown in Fig. 9 and 10.

[Pattern 1] Test Group 1: (A), (E) and (C) [Pattern 2] Test Group 3: (A), (B) and (C) Test Group 2: (C), (D) and (F)

? WW3 level WW3 level

WW2 level WW2 level

WW1 level WW1 level

Fig. 9: Soot Blower Operation Pattern 1 Fig. 10: Soot Blower Operation Pattern 2 The coal shown in Table 3 was used as the representative coal categorized by the combustion ratio and the

test was conducted on Test Group 1, 2 and 3 to determine the response of automatic control of the boiler against a change in the electric load. In addition, refer to a Fig. 11 about Test Process.

136

Table 3: Representative Coal Categorized by Coal Type Highly combustible coal Standard Coal Low combustible coal Test Group 1 Test Group 2 Test Group 3

Mora Coal (Mra) Country of origin: Australia Combustion ratio: 1.99

Hunter Valley Coal (HV) Country of origin: Australia Combustion ratio: 1.57

Prima Coal Country of origin: Indonesia Combustion ratio: 1.21

(2) Test Process ･ All soot blowers are started at the electric load of 250 MW or above before decreasing it. ･ After decreasing the electric load, the electric load of 250 MW or below is maintained for at least 8 hours,

and then the electric load of 125 MW is maintained for at least 4 hours. ･ Soot blowing of either Pattern 1 or 2. ･ The electric load is uplifted up to 360 MW.

Confirm the response of automatic control of boilers

Maintain for at least 8 hoursMaintain for at least 4 hours Start a start blower of either

one of Test Group 1, 2 or 3.

- Remove ash on the thermal transmission surface


- To reduce the electric load retention time

- To reproduce stain condition of the thermal transmission surface under the low electric load range

Gen

erat

or O

utpu

t (M

W)

Fig. 11: Test Process (3) Criteria for Determining the Response of the Automatic Control of Boilers to the Shift of the Load ･ The temperature of the main steam must not deviate greatly from the set values along with the increase in

electric load. ･ The reheated steam temperature of which set values are subject to change along with the shift of the electric

load must not deviate greatly from the set values. ･ The difference of the internal wall temperature of the furnace must be within the controlled temperature of

150℃. (4) Examination of the Location of Ash Attachment Considering the characteristics of coal, ash is likely to attach to the locations shown in Fig. 12. In the low

electric load zone, air tends to be excessively supplied and combustibility is enhanced. Thus, ash generated from the combustion of even highly combustible coal is likely to deposit on the furnace side. For combusting highly combustible coal, it is effective to operate all soot blowers of the furnace shown in Pattern 2. However, the coal contains a lot of ash and soot blowing only on the furnace side involves decreasing the main steam temperature and widening the gap of the temperature on the surface area.

137

Highly combustible coal

Shift to the furnace in low electric load zone

Shift to the furnace in low electric load zone

Furnace

Low combustible coal

Fig. 12: Location of Ash Deposit Anticipated (5) Results Table 4 indicates the results of the test for highly combustible coal, standard coal and low combustible coal.

Table 4: Test Results by Coal Type Assessment

Highly Combustible Coal Standard Coal Low Combustible Coal Test group Soot blower group Mra Hv Pr

1 (A) → (E) → (G) × (*1) ○ － 2 (C) → (D) → (F) ○ ○ － 3 (A) → (B) → (C) ◎ ◎ ◎

* The temperature gap on the rear wall surface: 168.9℃ (max.)

Table 5: Burner Angle Change Program for Highly Combustible Coal

Upper limit: +30℃ 【Front View】【Side View】

Bur

ner A

ngle

(°)

Fine powder

coal Burner angle

Before changeAfter change

Lower limit: －30℃Fig. 13 Coal Burner Angle Change

Load (MW) a. Test Group 1

(a) Highly Combustible Coal The temperature difference on the surface exceeding its controlled value is largely attributable to the

burner angle when the electric load was increased from 180 MW to 250 MW, which caused a change in the flow of gas to affect the thermal collection performance on the furnace side. For the reason, the burner angle program was changed to that shown in Table 5 to remove such gaps and continue the following tests. In addition, coverage of coal burner angle change is shown in Fig. 13.

(b) Standard Coal Good results were obtained without any particular problems.

138

b. Test Group 2 and 3 (a) Highly Combustible Coal After the burner angle program was changed, the temperature gap on the surface area was able to be

restricted and good results were obtained.

(b) Standard Coal Good results were obtained without any particular problems.

(c) Low Combustible Coal For Test Group 3, good results were obtained without any particular problems.

(6) Assessment of the Response of Automatic Control of Boiler to the Load Shift As a representative of all coal categories, the response to the electric load shift for main steam temperature

(MST) and reheated steam temperature (RST) when all soot blowers are operated for highly combustible coal are shown in Table 6, 7 and 8. For Test Group 3, the soot blower of the furnace was operated only. Though the decrease in main steam and reheated steam temperature just after starting the soot blower was slightly larger than that when all soot blowers were turned on, the difference was narrowed gradually as the electric load went up. The performance was favorable with no adverse effects on the increase of the electric load.

Table 6: MST and RST before and after the Operation of Soot Blowers Set temperature

(℃) Temperature before

starting a soot blower (℃)Temperature after starting

a soot blower (℃) Temperature decrease (℃)

Soot blower group

MST/RST MST/RST MST/RST MST/RST All 552/525 529/495 ▲23/▲30

(A)→(B)→(C)

566 (constant)/ varies depending on

electric load 559/521 519/476 ▲40/▲45

Table 7: Response to the Load Shift of Table 8: Response to the Load Shift of

Main Steam Temperature Reheated Steam Temperature

Reh

eate

d St

eam

Tem

pera

ture

(℃)

Mai

n St

eam

Tem

pera

ture

(℃)

Good response observed. Good response observed.

Set Values for the Main Steam Temperature All soot blowers used. Furnace soot blower is used only.

Set Values for the Reheated Steam Temperature All soot blowers used. Furnace soot blower is used only.

Generator Output (MW) Generator Output (MW)

139

Table 9: Temperature Difference on the Surface in Increasing the Electric Load

Tem

pera

ture

Diff

eren

ce o

n th

e Su

rfac

e (℃

) All soot blowers used. Furnace soot blower is used only. All soot blowers of the

furnace can be applied.

Table 10: Steam Volume of Soot Blowers

Generator Output (MW)

Stea

m V

olum

e (k

g)

Decreased by 22,323 kg

Test Group 1

Test Group 2

Test Group 3

All

For all coal categories, it was confirmed that the response of automatic control of boiler against the electric load shift was good when all soot blowers of the furnace were used only. As to the temperature difference on the surface, the values were all within the controlled limit and good results were obtained.

5. Effectiveness of the Measures (1) Reduction of Steam Consumption used by the Soot Blowers

Table 11: Effects of Improving Soot Blower Operation Before After Results

Blowing time 2 hours and 45 minutes 45 minutes Curtailed by 2 hours Response of the main

steam temperature No problems No problems －

Response of the reheated steam temperature No problems No problems －

Steam consumption 24,240（ｋｇ） 1,917（ｋｇ） Reduced by 92% a. Reduction of Annual Steam Consumption

Reduction of 1,451,000 (kg) of annual steam consumption achieved. (equivalent to 130 kl/year of crude oil)

Calculation Formula of Converting Steam Consumption to Crude Oil Consumption

(kl/time)

(Calculation Conditions) ･ Enthalpy of the sot blower steam source: 3,140 (kJ/kg) ･ Calorific power of crude oil: 38.2×106 (kJ/kl) ･ Boiler efficiency: 90% ･ Number of times of changing the electric load: Once in two days or 65 times a year (except for summer

and winter time)

140

6. Summary For all coal categories, use of furnace soot blowers in low electric load conditions only in low electric load

conditions did not reveal any problems in increasing the electric load, and the automatic control of boilers functioned well. We were successful in reduction of soot blower steam consumption in response to the change of operation mode of the coal thermal power generation system.

7. Future Plans

To anticipate future diversification in coal procurement, we will attempt to achieve a stable power supply and reduce costs through energy saving after examining all operating conditions. At the same time, we will raise the mind toward energy saving and address measures against it.

141

2 Functional and Operational Control of Thermal Power Plants

Documents

Transcript of 2 Functional and Operational Control of Thermal Power Plants