系统概述en

Document NO.： 78. K156-2E

The reproduction, transmission or use of this document or its content is not permitted without express written authority. Offenders will be liable for damages. All rights, including rights created by patent, grant or registration of a utility, model or design are reserved. Copyrights STW all rights reserved.

N300-16.7/538/538 TYPE 300MW CONDENSING REHEAT

STEAM TURBINE

GENERAL DESCRIPTION AND OPERATION MANUAL

SHANGHAI ELECTRIC EQUIPMENT CO., LTD

SHANGHAI TURBINE WORKS



PROLEGOMENON

1．STW means Shanghai electric equipment co., ltd Shanghai turbine

works.

2．This information must be read prior to the performance of any

activity related to modification, operation, maintenance or repair. If the

contents should appear unclear or incomplete to the reader, STW must be

contacted prior to the performance of any such activity, and clarification

must be obtained in writing. Revisions to the documentation only can be

made in writing by personnel duty authorized by the STW.

These documents do not claim to constitute a complete description of

all system or component details or to cover all conceivable operating

conditions in connection with modifications, operation, maintenance or

repair. Such activities must therefore only be planned or performed in

strict compliance with these documents. Nonobservance of this

requirement can result in damage to property or in personal injury. Use

of a system or component together with products supplied by other

companies that do not comprise part of the system or component requires

the express prior approval of the STW.

3．This manual is provided for the introduced 300MW condensing

reheat wet condensation steam turbine (N300—16.7/538/538 or N300—

16.7/537/537), which will be used for customers and other units

concerned .



4．This is an all-purpose manual, which can be applied to typical

steam turbines made by STW, if some of the contents and data may

conflict with transmitted drawings, the drawings shall be taken as

authentic, and should be reported to STW .

5．The transmitted drawings are not included in the manual due to

their print limitation, therefore, readers should refer to some transmitted

drawings which supplied by STW when they read the manual.

6． The original manual is made of a leaflet book and bound up, each

of which is unattached, but the contents connected each other. The

speciality is still kept in the compiled manual.

7． While reading the manual, if readers find inconsistencies, please

contact with STW in order to revise and clarify them.

8．This manual will be made up as following parts:

· General Description and Operation Manual

· Control and Protect Manual

· Install and Assembly Manual

· Construct and Turbine System Manual



Table of Units Conversion

Units Used by STW Factor of Transformation Units Available

25.4 inch(in) Length millimeter (mm)

1.00E-01 decimillimeter(dmn)

1.00E-03 litre(L)

4.55E-03 gallon(UKgal)

3.79E-03 gallon(USgal) Volume cubic meter ( 3m )

1.00E-09 cubic millimeter(mL)

1.00E+03 tonne(t) Weight kilogram(kg)

0.45359 pound(LB)

1.00E-01 bar(bar)

1.00E-03 kilopascal(kPa)

9.80E-06 millimeter of water

( OmmH 2 )

1.30E-04 millimeter of mercury (mmHg)

6.90E-03 pound per square inch (psi)

0.101325 standard atmosphere (atm)

Pressure Mega Pascal(Mpa)

0.0981 engineering atmosphere (at)

Energy joule (J) 4170 kilocalorie (kcal)

Power watt (W) 746 horsepower

Force Newton(N) 4.45 pound force(lbf)

Note: G (Acceleration of gravity) = 9.8 2/ sm

(Units Used by STW) × (Factor of Transformation) ＝ (Units Available)

Document NO.： 78. K156-2E Page 1 of 3


CONTENTS

General Description OP.2.01.01E-00

Turbine Control Settings OP.2.03.01E-00

Turbine Cooling Steam System Checks OP.1.04.01E-00

Turbine Operation

Supervisory Instruments OP.1.05.01E-00

Turbine Steam and Metal Thermocouples OP.1.06.01E-00

Allowable Variations in Steam Conditions OP.2.08.01E-00

Turbine Steam Purity OP.2.02.01E-00

Operating Limits and Precautions OP.2.09.01E-00

Water in the Turbine OP.1.10.01E-00

Starting and Load Changing Recommendations OP.2.11.02E-00

Governor Valve Management (Single Valve-Sequential Valve)

OP.2.12.02E-00

Operation Modes

Preliminary Checks and Operations OP.2.13.01E-00

Starting Procedure before Admitting Steam OP.6.14.01E-00

Start Up With Bypass Off OP.2.15.01E-00

Start Up With Bypass in Service OP.2.16.01E-00



Load Changing OP.2.17.01E-00

Shut Down Procedure OP.2.18.01E-00

Turning Gear Operation during Shutdown OP.1.19.01E-00

Feedwater Heater Operation OP.2.20.01E-00

Periodic Functional Test OP.2.21.01E-00

Caution for ATC Operation OP.6.22.01E-00

Remote Automatic Modes of Operation OP.6.23.01E-00

Turbine Manual Mode of Operation OP.6.24.01E-00

Limits, Precautions and Tests OP.2.25.01E-00

Curve and Table of Turbine Operation

Turbine Speed Hold Recommendations OP.2.51.01E-00

Cold Start Rotor-Warming Procedure OP.2.52.01E-00

Start Recommendations for Rolling and Minimum Load

OP.2.53.01E-00

Startup Steam Conditions OP.2.54.01E-00

No-Load and Light Load Operation Guide for Reheat Turbines

OP.2.55.01E-00

Load Changing Recommendations OP.2.56.01E-00

Cyclic Index for Loading and Unloading At Different Rates

OP.2.57.01E-00

Gland Sealing Steam Temperature Recommendations



OP.2.58.01E-00

Cooldown Time for A Typical Fossil Hp Turbine OP.2.59.01E-00

Off-Frequency Turbine Operation OP.2.60.01E-00

Turbine System Description

LP Exhaust Spray SYS AS.4. MAC01.P001E-00

Turbine Drain System AS.4. MAL10.P001E-00

Lubrication Oil System AS.4. MAV10.P001E-00

Gland Seal Steam SYS AS.4. MAW10.P001E-00

Page 1 of 1


Compiled：Yu Yan 2008.09

General Description Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：

OP.2.01.01E-00 Approved：Peng Zeying 2008.09

General Description

These operating instructions are recommended for starting and putting the turbine in

operation; they do not apply to the initial start after erection. Any such instructions can

cover only the normal case and it will be recognized that under unusual circumstances,

variations from this program will have to be adopted and the procedure to be followed will

necessarily be determined by the best judgment of the operating engineers.

The turbine-generator unit has been designed to meet the contract rating or capability

requirements for continuous service during the design life of the unit. In order to meet such

contract requirements, design margin and manufacturing tolerances have been provided

which may make it possible to operate the unit at loads higher than the contract capability

requirements. The unit is designed for continuous operation at the conditions listed on the

maximum calculated heat balance diagram.

If the unit is operated at other than normal cycle conditions: by such actions as removing

feed water heaters from service, using reheat attemperating sprays, changing the amount of

steam shown on the contract heat balance to be extracted for air heating, etc.; it could result

in greater than design flows passing through the turbine down-stream of where the cycle

changes occur. Turbine damage could eventually result if load is not sufficiently reduced to

prevent exceeding the design conditions.

Operation of the turbine-generator beyond the conditions specified above may result in

equipment malfunction, will eventually affect the unit's reliability by increasing

maintenance and reducing the design life, is not sanctioned by Turbine Manufacturer, and

is at the purchaser's risk.


Compiled：Yu Yan 2008.09Turbine Control Settings Checked：Zhang Xiaoxia 2008.09

Countersign：Sheng Chaojun,

Tang Jun, Zhang D.M 2008.09


Contents Turbine Control Settings ...................................................................................................1

1 OIL PRESSURE INFORMATION ........................................................................1

2 E.H. FLUID INFORMATION ................................................................................1

3 TRANSDUCER INFORMATION..........................................................................2

4 GOVERNOR VALVE ..............................................................................................2

5 THE GOVERNOR VALVE OPENING SEQUENCE AND ARRANGEMENT 3

6 ROTOR POSITON（THRUST BEARING TRIP） ............................................4

7 DEFERENTIAL EXPANSION ...............................................................................4

8 SUPERVISORY INSTRUMENT INFORMATION .............................................4

9 PRESSURE SWITCH INFORMATION ...............................................................5

10 TEMPERATURE SWITCH INFORMATION ...................................................6

11 DIAPHRAGM.........................................................................................................7

12 DEH CONTROLLER SETTING .........................................................................7

13 GAP SETTING .......................................................................................................7

14 LUB OIL TANK LEVEL SWITCH......................................................................8

15 EH FLUID RESERVOIR LEVEL SWITCH ......................................................9

Page 1 of 10


Turbine Control Settings

1 OIL PRESSURE INFORMATION

SYM SETTING MPa(g)

DISCHARGE——AT RATED SPEED A 1.442～1.8* SUCTION——ON A.C. D.C. EMERG OIL PUMP A 0.069～0.1373* MAIN OIL PUMP

SUCITON——AT SPEED A 0.069～0.31*

H.P. SEAL OIL BACKUP PUMP DISH A 0.838～0.896

A.C. BEARING OIL PUMP A 0.096～0.124

D.C. EMERGENCY OIL PUMP A 0.096～0.124

AUXILIARY PUMPS

A.C. BEARING LIFT PUMP RELIEF VALVES A 8～12

BEARING OIL A 0.096～0.124 MECH OSPD MAN TRIP HDR RELIEF VLV NO.1 0.69～0.76

PRESS SET （AT SPEED）

MECH OSPD MAN TRIP HDR RELIEF VLV NO.2 0.86～0.93

OVERSPEED PROTECTION TRIP SETTING 3330r/min

SYM A——ALL PRSSURES ARE READ AT TURBINE CENTERLINE BEFORE

MAKING PRESSURE SETTINGS OIL TEMPERATURE MUST BE 32°C OR ABOVE.

*——IT IS NOT LIMITTED IF THE OIL SYSTEM PRESSURE CAN ENSURE THE

DESIGN OIL PRESSURE.

2 E.H. FLUID INFORMATION

MIN. EH FLUID SUPPLY HEADER PRESS 14MPa(g)

RELIEF VALVE 16.2MPa(g)

ACCUMULATOR CHARGING（NITROGEN GAS PRESS）

CHARGE H.P. ACCUMULATORS TO 9.3 MPa(g)

RECHARGE ON DECREASE TO 8.27MPa(g)

CHARGE DRAIN ACCUMULATORS TO 0.21MPa(g)

Page 2 of 10


RECHARGE ON DECREASE TO 0.165MPa(g)

FLUID OPERATION TEMP RANGE AT RESERVOIR 37～60℃

3 TRANSDUCER INFORMATION

SYN XD TITLE CALIBRATED RANGEOUTPUT/SCALE M.A.

DC TP THROTTLE PRESSURE 0～19.6MPa 4～20 IP FIRST STAGE PRESSURE 0～14.7MPa 4～20

OPC CROSSOVER

PRESSURE(ABSOLUTE)0～1.47MPa 4～20

CP CONDENSER PRESSURE

ABSOLUTE 0～101.3kPa 4～20

HPE HP TURBINE EXHAUST

PRESSURE 0～4.9MPa 4～20

GS GLAND STEAM SEAL HEADER PRESSURE

0～0.15MPa 4～20

LP exhaust spray controller’s setting is 0.186MPa(g) plus .0093MPa/m multiply elevation

difference. The elevation difference means the difference between the condenser neck

tube and spray controller when the controller lower than condenser neck interface.

4 GOVERNOR VALVE

The Data in Governor Valve Management

（* Variable name in DEH）

total flow（FDCF*）% coordinate value for coefficient of flow

（COEF*）

0.000 1.000

No. GV.NO.

1 31

2 30

3 30

4 31

SERVO AMPLIFIERADJUST

0%

100%

0V 10V

SERVO AMPLIFIER INPUT

VALVE TRAVLE

Page 3 of 10


50.00 1.000

75.00 0.991

80.02 0.961

84.94 0.923

90.06 0.864

95.38 0.790

100.00 0.707

5 THE GOVERNOR VALVE OPENING SEQUENCE AND

ARRANGEMENT

Page 4 of 10


6 ROTOR POSITON（THRUST BEARING TRIP）

INSTRUMENT SCALE 1.25 — 0 — -1.25mm

COIL GAP (MW)PU/

SET POINTS RP1A and RP1B

RP2A and RP2B

ATC FLOW CHART (P-11)

DESIGNATION

INPUT MA INSTRUMENT READING (mm)

GOV TRIP(TB) 1.5 TRIP LIM 6 5.6 1.0 GOV ALARM 1.6 ALM LIM 6 6.4 0.9 ZERO SET* 2.5 12 0

GEN ALARM 3.4 ALM LIM 5 17.6 0.9

CH

AN

NO

.1

GEN TRIP(TB) 3.5 TRIP LIM 5 18.4 1.0 GOV TRIP(TB) 1.5 - 5.6 - GOV ALARM 1.6 - 6.4 - ZERO SET* 2.5 - 12 -

GEN ALARM 3.4 - 17.6 -

CH

AN

NO

.2

GEM TRIP(TB) 3.5 - 18.4 -

* THRUST ROTOR DISC CENTERED BETWEEN GOV AND GEN END THRUST

BRG SERFACES.

7 DEFERENTIAL EXPANSION

DEFERENTIAL EXPANSION——（LP CYL END）

INSTRUMENT SCALE 0～20mm.

SET POINT INPUT mA INSTRUMENT READING

mm TRIP 16.74 15.92 ROTOR

LONG ALARM 16.14 15.17 COLD 6.02 2.52

TRIP 5.5 1.88 ROTOR SHORT ALARM 4.9 1.12

8 SUPERVISORY INSTRUMENT INFORMATION ECCENTRICITY

ALERT (ALARM) 0.076mm

Page 5 of 10


VIBRATION

ALERT(ALARM) 0.127mm

TRIP 0.254mm

CASING EXPANSION 0～50mm

SPEED 0～5000r/min

RELAY SETTINGS

14-1/SD SPEED≤1r/min（TSI TO TURNING GEAR）

14-2/SD SPEED≤200 r/min（TSI TO TURNING GEAR）

9 PRESSURE SWITCH INFORMATION

N.O.CONT* N.O.CONT* SYM

63 SW NO. INCR

PRESS DECR PRESS

DESIGN MPa(g)

SYM 63

SW NO. INCR

PRESS DECR PRESS

DESIGN MPa(g)

1 OPEN 0.035～0.048 1 OPEN 0.069～0.075 2 OPEN 0.035～0.048 2 OPEN 0.069～0.075

-1、3/LB

O

-1～2/EOP

1 OPEN 0.035～0.048 1 CLOSE 9.30 2 OPEN 0.045～0.062 2 CLOSE 9.30

-2、4/LB

O

-1/ASP

1 CLOSE 0.0203(ABS) 1 OPEN 4.14 2 CLOSE 0.0169(ABS) 2 OPEN 4.14

-1/LV≠

-2/ASP

1 CLOSE 0.0203(ABS) 1 OPEN 6.89 2 CLOSE 0.0186(ABS) 2 OPEN 6.89

-2/LV≠

1 CLOSE 0.0203(ABS) 3 OPEN 6.89 -3～

4/LV≠ 2 CLOSE 0.0203(ABS)

-1～2/AST

1 OPEN 9.31 1 CLOSE 6.89 2 OPEN 10

/OPC2 CLOSE 6.89 -1/LP

1 OPEN 9.31 1 CLOSE 0.069～0.075 2 OPEN 9.31

/BOR2 CLOSE 0.069～0.075

-2～4/LP

Page 6 of 10


1 OPEN 0.075 1 CLOSE 0.069～0.075 2 OPEN 0.082

/EPR 2 CLOSE 0.069～0.075

-1～2/BOP

1 MAX 1 CLOSE 0.14

/EHS 2 CLOSE 0.14

/TGI MAX

1 OPEN 0.021 1 OPEN 11.03 /BLS

2 OPEN 0.048 /MP

2 OPEN 11.03

1 CLOSE 4.2 1 CLOSE 0.031 /BLD1及BLD2 2 CLOSE 6.5

/TG 2 CLOSE 0.031

/MPF1

CLOSE 0.69(VAC) 1 CLOSE 0.0395 Ο

/MPF2

CLOSE 0.69(VAC) 2 CLOSE 0.0492 Ο

/MPF3

CLOSE 0.69(VAC)

/XO

3 MAX

1 CLOSE 0.21

/PR 2 CLOSE 0.21

Ο——ABSOLUTE PRESSURE

≠——Absolute pressure switch at 0mm HG abs. (0MPa absolute pressure). A N.O.

contact is open (N.C. contact closed）.When the absolute pressure is increased to the

pressure switch set point, A N.O. contact will closed（N.C. contact opens）.

*——All pressure switch setting instructions are referred to the normally open (N.O.)

contact of each switch without regard to whether the N.O. or N.C. contact is used in a

specific application.

When “MAX” appears in column, it means to adjust switch out of operating range in

order to provide a minimum ON-OFF differential to other operating switches in the same

housing.

10 TEMPERATURE SWITCH INFORMATION

N.O.CONT* SYM

23 SW NO.

TEMP INCR TEMP DECR DESIGN ℃

1 MAX

2 OPEN 21 /ORR

Page 7 of 10


1 CLOSE 65

2 OPEN 21 /EHR

1 CLOSE 55

2 OPEN 23 /TCD

11 DIAPHRAGM Opens on decrease auto stop oil pressure 0.36MPa(g) at 14MPa(g) HP fluid auto stop

emergency trip(AST) header press.

Closes on increase auto stop oil pressure 0.12MPa(g) at 0MPa(g) HP fluid auto stop

emergency trip(AST) header press.

12 DEH CONTROLLER SETTING

a SPD<600 SPEED≤600r/min ACTION（DEH to jacking oil circuit）

SPD>2600 SPEED≥2600r/min ACTION（DEH to water spray circuit）

b Overspeed trip setpoint is 3330r/min.

c OPC speed setpoint is 103% of rated speed (3090r/min).

Mechanical overspeed trip setpoint is 3300r/min

ETS overspeed trip setpoint is 3300r/min

13 GAP SETTING

SYMBOL PICKUP FIG. NO.

PU/RX

PU/MPW

PU/VB1 TO VB7

PU-1 TO 4/SD

PU/ZS1 和 2

ROTOR ECCENTRICITY

TSIMARKER（Kφ）

ROTOR VIBRATION

SPEED

ZERO SPEED

3*

3

3

3

3

Page 8 of 10


PU/DE

PU/RP1A AND B

PU/RP2A AND B

PU/OS1 AND 2

DIFFERENTIAL

EXPANSION ROTOR POSITION NO.1

ROTOR POSITION NO.2

OVERSPEED

1,4**

2

2

3

* Check the output voltage of froximeter, after installing. It should be in range of

-11~-12V, if not, change probe clearance to meet.

**There are two types of fig 1and fig 4 according to different configuration of rotor.

FIG. NO.3

PICKUP

ROTOR

ROTOR

PU/DEA PU/DEB

TURBINE END

4

FIG. NO.1

GEN END

ROTOR

19

PICKUP DEVIATION

(MM)

PU/DEB

FIG. NO.4

TURBINE END

PU/DEA

GEN. END

PICKUP

FIG.NO.2

ROTOR

14 LUB OIL TANK LEVEL SWITCH Level switch to actuate when oil reached oil level of dimensions shown.

OIL LEVEL mm CAPACITY

m3 A B C D

24 1333 152.4 152.4 563

Page 9 of 10


15 EH FLUID RESERVOIR LEVEL SWITCH Level switch to actuate when fluid reaches level of dimensions shown.

LOWLOW

LOW

LEVEL SWITCH

HOUSING

COUPLING

TOP OF

RESERVOIR

SHELL DISPLACER

(TYP)

OPERATING

LEVEL

A

D

B

C

HIGH

Page 10 of 10


Page 1 of 1


Compiled：Zhang D.M 2008.09Turbine Cooling Steam System Inspection Checked：Huang Q.H 2008.09

Countersign：Yu Yan 2008.09

Countersign：


Turbine Cooling Steam System Inspection

A steam cooling system reduce the temperature of the reheat steam which bathes the

blade roots and rotor at the inlet to the intermediate pressure turbine (IP). This cooling

steam is required to improve the creep strength of the blade roots and rotor in the affected

area and to reduce the likelihood of rotor bowing. Considering the serious consequences of

having insufficient cooling steam, it is essential that an adequate supply be provided

whenever the unit is in operation and reheat temperature is above 482℃.

The cooling steam flow paths of combined high pressure-intermediate pressure turbine

elements are internal and cannot inadvertently be blocked (unless altered during a

shutdown for repairs). Separate IP turbine elements have a combination of internal and

external flow passages for cooling steam which can be blocked by closed valves, by

flanges containing blanks for blowdown, or foreign material in the passages. For this

reason manufacturer recommends that:

1. There are no valves in cooling steam pipes.

2. There are no flow restrictions in cooling steam pipes except the flow measuring

device provided by manufacturer.

3. There be a complete check of the cooling steam system before initial startup of the

unit, before any restart following disassembly of the IP element, and before restart after

maintenance which otherwise disturbs the cooling steam flow passages. This check is to

ensure that the cooling system does not contain closed valves, solid spacers in flanges or

other foreign material that blocks or restricts flow. The portion of the system inside the IP

cylinders must be inspected after the IP is assembled and before the cooling steam pipes

are connected to the cylinder.

If a preheating system is used on a unit which requires a valve in the cooling steam pipe,

it is imperative that the purchaser consult manufacturer about essential protective

provisions.

Page 1 of 4


Compiled：Zhang D.M 2008.09Supervisory Instruments Checked：Huang Q.H 2008.09

Countersign：Yang H.Y 2008.09

Countersign：Yan W.Ch 2008.09


Supervisory Instruments

The following supervisory instruments are furnished with this unit and are to be

observed during start-up, operation, and shut down when applicable. The outputs of these

instruments are displayed on chart recorders. Refer to “Operating Limits and Precautions”

section and “Control Setting Instructions” for supervisory instrument alarm and trip limits.

A complete description of each instrument will be found under a separate tab in the

instruction book.

1) CASING EXPANSION

As a unit is taken from its cold condition to its hot and loaded state, the thermal changes

in the casings will cause it to expand. The casing expansion instrument measures axial

expansion from the anchor point in middle pedestal towards the governor pedestal. The

governor pedestal is designed to move freely along lubricated longitudinal keys. If the free

end of the unit is hampered from sliding smoothly along the guide keys as the casings

expand, serious damage to the unit may result.

The casing expansion meter measures the movement of the governor pedestal relative to

a fixed point (the foundation). It indicates expansion and contraction of the casings during

starting and stopping periods, and for changes in load, steam temperatures, etc. Should it

fail to so indicate during these transient conditions, the situation should be investigated.

The relative position of the governor pedestal, as indicated by this instrument, should be

essentially the same for similar conditions of load, steam conditions, vacuum, etc.

2) ROTOR POSITION

Two rotor position instruments (two dual voting Thrust Position Monitors) measure the

Page 2 of 4


relative axial position of the turbine rotor thrust collar with respect to the thrust bearing

support. The thrust collar exerts a pressure against the thrust shoes, which are located on

both sides of the thrust collar. Wear on the thrust shoes results in an axial movement of the

rotor and is indicated on these instruments. Each instrument is equipped with an alarm

which is activated if the rotor moves beyond a predetermined distance. Continued

movement beyond a second predetermined distance activates rotor position trip relays

which trip the turbine via the Emergency Trip System. Two rotor position pickups are

provided for each instrument. Each instrument provides a two out of two (2/2) detection

logic to prohibit false trips.

3) DIFFERENTIAL EXPANSION

When steam is admitted to a turbine, both the rotating parts and the casings will expand.

Because of its smaller mass, the rotor will heat faster and therefore expand faster than the

casings. Axial clearances between the rotating and the stationary parts are provided to

allow for differential expansion in the turbine, but contact between the rotating and

stationary parts may occur if the allowable differential expansion limits are exceeded.

The purpose of the differential expansion meter is to chart the relative motion of the

rotating and stationary parts. It gives a continuous indication of the axial clearance while

the turbine is in operation. The instrument is equipped with alarm and trip alarm relays

which are activated if the limits of axial clearances are approached. As the rotating and

stationary parts become equally heated after a transient condition, the differential

expansion will decrease, resulting in larger axial clearances. The steam flow and the

temperature to the turbine can then again be changed.

4) ROTOR ECCENTRICITY

When a turbine has been shut down, the rotor will tend to bow due to uneven cooling if

the upper half of the casing enclosing the rotor is at a higher temperature than the lower

half. By rotating the rotor slowly on turning gear, the rotor will be subjected to more

uniform temperatures, thereby minimizing bowing.

This bowing of the rotor is recorded continuously as eccentricity from turning gear speed

to approximately 600 r/min and as vibration at higher speeds (see vibration instrument

description).

Page 3 of 4


The eccentricity instrument is equipped with an alarm signal which is activated when the

eccentricity limit is reached.

Another output signal of the eccentricity instrument is the instantaneous eccentricity.

This signal is displayed on a vertical meter located on the turning gear console. When the

turbine is on turning gear, the meter displays the periodic variation of the instantaneous

rotor-to-pickup gap.

If it becomes necessary to remove the unit from turning gear operation, it is desirable to

stop the rotor with the rotor bow in the down position in order to reduce the thermal

gradient between the upper and lower portions of the rotor.

The optimum rotor position can be achieved by stopping the rotor when the

instantaneous eccentricity meter reads a minimum value.

NOTE

The eccentricity pickup is located at the top vertical centerline of the turbine

governor pedestal. The minimum meter reading indicates minimum rotor-to-pickup

gap. In this position, the upper half of the rotor (cooler portion) is exposed to the

warmer ambient temperature, thus tending to reduce the bow.

5) VIBRATION

The vibration instrument is used of measure and record vibration of a turbine rotor at

speeds above 600 r/min; below this speed, rotor bowing is recorded as eccentricity (see

Item 4). The vibrations are measured on the rotor near the main bearings. Excessive

vibrations serve as a warning for abnormal and possible hazardous conditions in the turbine.

Each vibration instrument is equipped with alarm and trip relays which are activated when

excessive vibrations are measured at any one of the bearings.

6) PHASE ANGLE

A phase angle instrument is provided which displays the angular relationship between

the "hing spot" on a particular bearing and the turbine rotor reference, namely the No. 1

balance-hole. A selector scotch located on the front face of the phase angle instrument

permits selecting the readout of phase angle for any one pickup at a time.

7) VALVE POSITION

Page 4 of 4


The valve position signal is provided by the DEH Controller and is wired to record this

signal continuously.

8) ZERO SPEED

The zero speed instrument provides relays which are activated when the unit speed

below 1r/min. The instrument utilizes two zero speed pickups which read the rotation of a

rotor mounted notched wheel in the governor pedestal. The instrument includes two

separate detection channels. The relay outputs are used for turning gear engage functions

and are available for annunciation purposes.

9) SPEED

The speed instrument utilizes one of the zero speed pickups (see Item 8) as an input

device. An analog output signal of speed is wired to the recorder for continuous recording

of this speed. Additional outputs are in the form of relays which are activated above a

predetermined setpoint speed. There are two independent setpoints and one relay per

setpoint. The relays are used for turning gear control, exhaust hood spray control, and

bearing lift pump control.

Page 1 of 3


Compiled：Zhang D.M 2008.09Turbine Steam and Metal Thermocouples Checked：Huang Q.H 2008.09

Countersign：Tang Jun 2008.09

Countersign：


TURBINE STEAM AND METAL THERMOCOUPLES

Locations of the thermocouples listed below are shown on the drawing "Thermocouple

Locations"

Item TC No. Thermocouple Location MeasuresTemp. of:

Comments

015 TC 3010 Steam Chest-Deep-LH

016 TC 3020 Steam Chest-Deep-Rh

017 TC 3030 Steam Chest-Shallow-LH

018 TC 3040 Steam Chest-Shallow-RH

Metal

Use with chart" Startup Steam Conditions " for adequate warming of steam chest before transferring speed control from TV to GV (see section " Operating Limits and Precautions") Use to insure that temperature difference between deep and shallow thermocouples does not exceed 83℃

049 TC 3241 Reheat valve casing -Deep -LH

051 TC 3251 Reheat valve casing

-Deep-Rh

050 TC 3242 Reheat valve casing -Shallow-LH

052 TC 3252 Reheat valve casing -Shallow-RH

Metal Use to insure that temperature difference between deep and shallow thermocouples does not exceed 83℃

039 TC 3051

038 TC 3052

HP inner casing Metal

Compare with temperature of Item 041 to determine : a) Whether COLD or HOT start b) Rotor-warming time if COLD start. Colder temperature takes precedence (see chart" Cold Start Rotor-Warming Procedure" ) c) Total roll time to rated speed if HOT start (see chart "Start Recommendations").

Page 2 of 3



Comments

Refer to section "Starting and Load Changing Recommendations."

041 TC 3091 IP #1 Ring Metal

Compare with temperature of Item 038,039to determine : a) Whether COLD or HOT start b) Rotor-warming time if COLD start. Colder temperature takes precedence (see chart" Cold Start Rotor-Warming Procedure" )

037 TC 3070 First Stage Steam Use with Item 038,039 to compare actual with predicted temperatures based on these operating instructions.

028 TC3331 IP Exhaust Steam Used by the ATC Program for IP rotor stress calculations.

021 TC 3210

022 TC 3220

HP-IP End Wall-Gov. End

Metal

Use with Item 023 to monitor temperature difference between gland steam and rotor metal in the gland areas (see chart "Gland Sealing Steam Temperature Recommendations").

023 TC 3230 HP Gland Steam Header (Common line to the HP and IP Glands)

Steam Indicates sealing steam temperature in glands. Use with Items 021 and 022.

024 TC 3240 IP Inlet-RSV-LH

025 TC 3250 IP Inlet-RSV-RH

Steam

Start counting rotor-warming time after this temperature reaches a minimum of 260℃(see chart "Cold Start rotor- Warming Procedure"). Max. temperature difference between RSV inlets is 14℃ (see section "Allowable Variations in Steam Conditions”).

033 TC 3261 HP Exhaust Zone-Base

034 TC 3271 HP Exhaust Zone-Cover

026 TC 3320 IP Exhaust Zone-Base

027 TC 3330 IP Exhaust Zone-Cover

031 TC 3333 IP #1 Extraction Zone- Base

032 TC 3334 IP #1 Extraction Zone-

Metal Water Detection Thermocouples. Used in pairs in temperature zones indicated. Alarm when base in 42℃ colder than cover. Trip if base reaches 56℃ colder than cover or take other suitable action as recommended in section "Water in the

Page 3 of 3



Comments

Cover

064 TC 3337 IP Inlet Zone-Base

040 TC 3338 IP Inlet Zone- Cover

Turbine. "

029 TC 3760 Throttle Valve Inlet-LH

030 TC 3770 Throttle Valve Inlet-RH

Steam

Indicates steam temperature at each throttle valve inlet. Max. temperature difference between TV inlets is 14℃ (See section" Allowable Variations In Steam Conditions").

019 TC3110 LP Exhaust -Gov. End

020 TC3120 LP Exhaust-Gen. End

Steam

Record LP exhaust steam temperature, alarm in 79℃, Max. 121℃, 15min duration. Trip if the temperature exceed 121℃.(See section " Operating Limits and Precautions")

043 TC3500 LP Gland Steam Steam Record LP gland steam temperature, alarm over 177℃ or under 121℃

042 TC3580 HP Extraction Metal

035 TC3335 HP Exhaust Zone-Cover- LH

Steam

036 TC3336 HP Exhaust Zone-Cover- RH

Steam

Record HP Exhaust steam temperature, alarm over 400℃ and trip over 427℃

Page 1 of 3


Compiled：Yu Yan 2008.09Allowable Variations in Steam Conditions Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


Allowable Variations in Steam Conditions

The turbine rating, capability, steam flow, speed regulation and pressure control are

based on operation at rated steam conditions. The turbine-generator unit is capable of

operation under the following variations in steam pressure and temperature. These

allowable variations are intended to provide for operating exigencies and it is expected that

such abnormal operation will be kept to a minimum, especially the occurrence of

simultaneous variations in pressures and temperatures.

1. Initial Pressure

The average initial pressure at the turbine inlet over any 12 months of operation shall not

exceed the rated pressure. In maintaining this average, the pressure shall not exceed 105%

of the rated pressure. Further accidental swings not exceeding 120% of the rated pressure

are permitted, provided that the aggregate duration of such exceed 105% of the rated

pressure swings over any 12 months of operation does not exceed 12 hours.

An increase in initial pressure will normally permit the turbine to generate power in

excess of its normal rating, unless action is taken through the control system to restrict the

steam flow rate. The generator and associated electrical equipment may be unable to accept

such additional output, and undesirable stresses may also be imposed on the turbine; the

purchaser shall accordingly provide load-responsive protective means to limit the turbine

output under such circumstances.

2. Reheat Pressure

The pressure at the exhaust connection of the high pressure turbine shall not be greater

than 25% above the highest pressure existing when the high pressure section of the turbine

is passing the maximum calculated flow with rated pressure and normal operating

conditions. Suitable relief valves must be provided by the Purchaser.

Page 2 of 3


3. Initial Temperature

The steam temperature at the turbine throttle valve inlet connection shall average not

more than rated temperature over any 12 month operating period. In maintaining this

average the temperature shall not exceed rated temperature by more than 8℃.

During abnormal operating conditions, the temperature at the turbine throttle valve inlet

connection shall not exceed rated temperature by more than 14℃ for operating periods not

more than 400 hours per 12 month operating period, nor rated temperature by more than 28

℃ for swings of 15 minutes duration or less aggregating not more than 80 hours per 12

month operating period.

In maintaining the temperatures specified in the preceding paragraphs, the steam

delivered through any turbine main inlet valve must be within 14℃ of the steam delivered

simultaneously through any other main inlet valve. During abnormal conditions, this

difference may be as high as 42℃ for periods of 15 minutes maximum duration providing

such occurrences are at least 4 hours apart.

4. Reheat Temperature

The steam temperature at the turbine reheat admission shall average not more than rated

reheat temperature over any 12 month operating period. In maintaining this average the

reheat temperature shall not exceed rated reheat temperature by more than 8℃.

During abnormal conditions reheat temperature shall not exceed rated reheat temperature

by more than 14℃ for operating periods totaling not more than 400 hours per 12 month

operating period, nor rated reheat temperature by more than 28℃ for swings of 15 minutes

duration or less aggregating not more than 80 hours per 12 month operating period.

In maintaining the above reheat temperature averages, the steam delivered through any

hot reheat inlet zones in the turbine must be within 14℃ of the steam delivered

simultaneously through any other hot reheat zone.

During abnormal conditions this difference can be as high as 42℃ for periods of 15

minutes maximum duration providing the occurrences are at least 4 hours apart.

5. HP-IP Combined Turbine

Where the main steam inlet and hot reheat inlet connections are arranged in the same

turbine casing, temperature differences between the main steam and reheat steam inlets

Page 3 of 3


must be controlled to optimize the design life of the apparatus. The difference between the

main steam and hot reheat temperatures should not deviate from the difference at rated

conditions by more than 28℃. During abnormal conditions, deviations as large as 42℃

are acceptable provided the differences are limited to a reduction of the hot reheat

temperature with respect to the main steam inlet temperature.

These limits, in general, are assumed to apply at operating conditions near full load. As

the load reduces, it is assumed that the hot reheat temperature will be below the main steam

inlet temperature, in which case, the difference may approach 83℃ as the load approaches

zone. Short time cyclic temperature fluctuations are to be avoided.

Page 1 of 7



Turbine Steam Purity Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


Turbine Steam Purity

NOTE: This recommendation is based upon current STW experience and engineering

judgment with respect to turbine steam purity. The information provided should not be

considered to be all inclusive or to supplant any specification for other parts of the steam

and water cycle. The Purchaser, being solely responsible for the control of turbine steam

purity, assumes all risk and liability for use of this information or the results obtained

therefrom, and STW NEITHER ASSUMES NOR AUTHORIZES ANY PERSON TO

ASSUME FOR IT ANY RESPONSIBILITY OR LIABILITY WHATSOEVER FOR

SUCH USE WHETHER THE CLAIMS OF THE PURCHASER ARE BASED IN

CONTRACT, IN TORT (INCLUDING NEGLIGENCE) OR OTHERWISE.

1. General

The presence of corrosive impurities in steam can cause damage to turbine components

by corrosion, stress corrosion, corrosion fatigue and erosion-corrosion. Caustic, salts, and

acids (including organic acids and carbon dioxide) must be strictly controlled. Deposition

of impurities can also cause thermodynamic losses and distress by lowering the efficiency

of blades, upsetting pressure distributions and clogging seals and clearances in valves. If

the extensive damage, lengthy outages and costly repairs caused by these occurrences are

to be avoided, the purity of the steam throughout the turbine must be rigorously controlled.

In addition, positive steps must be taken to assure that impurities from chemical cleaning

procedures for plant piping and equipment do not get into the turbine.

For the best control of steam purity, continuously or routinely analyze the parameters in

Table 1. Samples should be collected from the high pressure turbine inlet steam for most

units. The location of the sampling (tap) point should ensure that all influences on steam

quality will be included (e.g. downstream spray water injection). Water injections should

Page 2 of 7


utilize condensate quality water. Therefore, hot reheat inlet steam is additionally

recommended as a control point for reheat units. When steam enters the turbine at multiple

pressures from separate steam sources, as in combined cycle units, each source should be

individually monitored, and the steam at any location in the turbine must conform to these

recommendations. Since multiple sources will rarely have the same value for any steam

purity parameter, mass weighted averaging is permitted. (See Mass Weighted Averaging)

However, it is simpler and better if all individual steam sources conform to this

recommendation. When a steam source is operating outside the steam purity

recommendations the reason should be determined since it may indicate a need for

corrective action.

2. Normal Operation

Recommended limits for impurities commonly found in turbine steam are given in Table

1. The normal limit values represent Turbine Manufacturer recommendations for reliable

turbine operation. These values are limits where experience has shown minimal deposition

of salts in the dry regions of the turbine. The reasonably achievable values provide extra

assurance that corrosive impurities will not deposit and every reasonable effort should be

made to operate at these values. The recommendations apply whenever steam is admitted

to the turbine. Low load does not protect the turbine from deposition.

The parameters given in Table 1 are for the impurities commonly found in steam power

systems. If other impurities (not including the PH control agent and oxygen during

oxygenated water treatment) are known to be present above 5µg/kg (ppb), please consult

Turbine Manufacturer for guidance on setting limits for those impurities.

Table 1 Normal limit values and reasonably achievable values in normal operation for condensed steam sample

Parameter Units Normal limit1)

Reasonably Achievable Value 2) (for condensing power plants)

Conductivity at 25°C downstream of strongly acidic sampling cation exchanger, continuous measurement at sampling point

µS/cm <0.2 0.1

Sodium 3) (Na) µg/kg * <5 2

Silica (SiO2) µg/kg <10 5

Total iron (Fe) µg/kg <20 5

Page 3 of 7


Total copper4) (Cu) µg/kg <2 1 1) To avoid any corrosion or loss of efficiency, it is advisable to keep the actual values below the Normal

Limit values, preferably within the range of the Reasonably Achievable Values for normal operation. 2) The values in Reasonably Achievable Values are only achievable in continuous operation. In all other

cases, the respective normal limit value is regarded as a maximum value for normal operation. 3) If solid alkalizing agents (NaOH, Na3PO4) are used only in case of abnormal operating conditions,

continuous monitoring of sodium is not imperative. (See discussion of sodium). 4) No copper monitoring is necessary if the steam-water cycle is free of copper alloys (see discussion of

Total Copper). * 1 µg/kg = 1 part per billion (ppb)

3. Action Levels

It is not always possible to meet the normal values at justifiable expense, particularly

during start-up of a plant. Therefore, action levels have been set up to rate the urgency of

action to correct deviations from normal operating conditions. The action levels represent

undesirable conditions that should be corrected to normal within the time periods indicated.

During start-up and chemical upset, the values and time limits listed in Table 2 apply.

Operating longer than the time limits associated with the action levels will degrade the

turbine and shorten its life. It is not always required to shut the turbine down when the time

is expended. It must simply be realized that life has been expended or that efficiency might

be lost. Excessive operation of the turbine in the action level ranges represents the

economic trade-off between immediate revenue and future repair costs.

It is advisable to target the values listed in Action Level 2 or below during start-up to

avoid any loss of efficiency or impairment of service life. If the values are above normal

values, the values must show a noticeable downward trend. The time limits in the Action

Levels still apply. Commissioning shall be limited to one annual allowance as noted in

Table 2 for initial start-up of the plant. The annual clock resets to zero at commercial

acceptance.

Table 2 Limit values exclusively for start-up operation1) and cases of deviation from the values recommended for continuous operation

Parameter Units Action level 1 Action level 2 Action level 3 Action level 4 = immediate

shutdown Conductivity at 25 °C downstream of strongly acidic sampling cation exchanger, continuous measurement at sampling point

µS/cm ≥ 0.2 < 0.35 ≥ 0.35 < 0.5 ≥ 0.5 < 1.0 ≥ 1.0

Page 4 of 7


Sodium3) (Na) µg/kg ≥ 5<10 ≥ 10 < 15 ≥ 15 < 20 ≥ 20

Silica (SiO2) µg/kg ≥ 10 < 20 ≥ 20 < 40 ≥ 40 < 50 ≥ 50

Total iron (Fe) µg/kg ≥ 20 < 30 ≥ 30 < 40 ≥ 40 < 50 ≥ 50

Total copper4) (Cu) µg/kg ≥ 2< 5 ≥ 5< 8 ≥ 8<10 ≥ 10 Period of time per event, during which the turbine may remain in operation with the respective values

h ≤ 100 ≤ 24 ≤ 4 02)

Cumulative time per year h/a ≤ 2000 ≤ 500 ≤ 80 02) 1) In order to avoid any drop in efficiency or impairment of service life, it is advisable to operate below the action

level 2 values during start-up of the turbine. The values must show a noticeable downward trend. 2) Action Level 4: The values indicate that the steam quality is substantially impaired and could quickly result in

damage to the turbine (corrosion and/or deposits). Turbine shutdown is urgently recommended. 3) If solid alkalizing agents (NaOH, Na3PO4) are used only in case of abnormal operating conditions, continuous

monitoring of sodium is not imperative. (See discussion of sodium). 4) No copper monitoring is necessary if the steam-water cycle is free of copper alloys (see discussion of Total

Copper). In general: Once any parameter has reached or proceeded beyond a given action level, the next-higher action

level shall apply.

4. Auxiliary Boiler Steam

Steam from auxiliary boilers may be used for brief periods at startup or to maintain

vacuum during longer outages. Its purity has usually not been a problem. Table 3 gives

relaxed limits for auxiliary boiler steam during this time. Steam conforming to Table 3

minimizes deposits and corrosion on turbine parts, but it should be understood that

contaminants in the auxiliary steam are ultimately sent to the main steam condenser and

may make cleanup of the main cycle more difficult. Whenever possible, the auxiliary boiler

steam should conform to the normal limits found in Table 1. Steam from a main boiler

where pressure is reduced to provide gland and other auxiliary steam during startup will be

of adequate purity for those uses.

Table 3 Target values for condensed auxiliary boiler steam sample for seal steam supply with main steam valves closed.

Parameter Units Normal limit

Auxiliary Steam

Action Level 1

Auxiliary Steam

Action Level 2

Auxiliary Steam

Action Level 3

Auxiliary Steam Action

Level 4 = immediate shutdown

Page 5 of 7


Conductivity at 25°C downstream of strongly acidic sampling cation exchanger, continuous measurement at sampling point

µS/cm < 0.5 ≥ 0.5 < 1.0 ≥ 1.0 < 2.0 ≥ 2.0 < 5.0 ≥ 5.0

Period of time per event, during which the turbine may remain in operation with the respective values

h ≤ 24 ≤ 4 ≤ 1 01)

Cumulative time per year h/a ≤ 500 ≤ 80 ≤ 20 01)

1) Auxiliary Steam Level 4: Theses values indicate that the steam quality is substantially impaired and could quickly result in damage to the turbine (corrosion and/or deposits). Immediate shutdown of the seal steam supply is recommended.

5. Monitors, analyses and data storage

Data from continuous monitors should be recorded, either on chart recorders or in a data

acquisition system. Grab sample data should be recorded with time of sampling. Data

should be saved for a minimum of two turbine inspection cycles and preferably for the life

of the unit.

* Conductivity downstream of strongly acidic cation exchanger (hydrogen cation

exchanged conductivity):

Electrical conductivity is the most important parameter for monitoring the purity of

steam. Due to the use of a strongly acidic cation exchanger in the hydrogen form

(connected upstream of the instrumentation unit), any alkalizing agents present in the

steam-water cycle are extracted from the sample, and their conductivity is suppressed. At

the same time, any impurities, e.g., salts, which may be present are converted into their

corresponding acids. The higher specific conductivity of the latter increases the sensitivity

of the measurement. The electrical conductivity is not substance-specific, i.e., the further

identification of any impurity requires application of suitable analytical methods. Degassed

cation conductivity is a different parameter and requires different values than those

included in the tables in this document. On-line conductivity is recommended.

* Silica (SiO2):

Silica is volatile in steam. The actual concentration of silica in steam depends on such

factors as the boiler pressure and the alkalinity and the silica concentration of the boiler

water. Silica and silicates form very adherent deposits on turbine blades. Silica can not be

Page 6 of 7


monitored via conductivity measurement, because it is very weakly dissociated.

Consequently, individual analysis (laboratory testing or on-line monitoring) is necessary.

* Sodium (Na):

Sodium hydroxide and sodium salts promote stress corrosion cracking within the turbine.

Whenever solid alkalizing agents (NaOH, Na3PO4) are fed, the steam must be monitored

for sodium. On-line sodium monitoring is recommended. When AVT (All Volatile

Treatment) is used, there is less necessity for monitoring steam sodium. However, sodium

may also enter the steam-water cycle as an impurity due to cooling water leakage or

leaching from faulty ion exchange systems (e.g. condensate polishers). The sodium salts

associated with condenser leaks may be detected as the anions with the conductivity

measurements downstream of a strongly acidic cation exchanger. Sodium hydroxide is not

detected by conductivity downstream of a strongly acidic cation exchanger nor can it be

detected by pH or specific conductivity in the presence of ammonia or amines. Therefore,

if sodium is not monitored in the steam, other means to detect sodium hydroxide ingress

into the steam-water cycle must be present.

* Total Iron (Fe):

The total iron concentration is an indicator for corrosion processes. As such, it provides

information on corrosion-product transport rates. Normally, the iron content of the steam

remains well below 2µg/kg where conditions for continuous operation are constant. An

elevated iron content is mostly likely to occur during start-up, especially in the case of cold

starts. In order to avoid the deposition of iron oxides on the blades and/or related erosion

processes, the total iron concentration prior to start-up of the turbine should not exceed

50µg/kg. Iron is usually a laboratory analysis.

* Total Copper (Cu):

The total copper concentration, like the total iron concentration, is an indicator for

corrosion process. Deposits containing copper can stimulate other corrosion processes.

Copper will also deposit on the inlet blading of the turbine and reduce capacity and

efficiency. If the feedwater heater and condenser turbine were originally of Cu-free

material (stainless steel, titanium, carbon steel, etc.) there is no need to monitor the copper

concentration. After conversion from a copper alloy to all-ferrous system, copper should be

monitored until it is shown that all copper has been removed from the system. Copper is

usually a laboratory analysis.

Page 7 of 7


6. Mass Weighted Averaging

Mass weighted averaging of steam purity parameters is permitted to allow for multiple

steam sources. For example, when a second boiler is being brought into service, its steam

purity may be mass averaged with the steam purity of the boiler already in service to

determine whether the steam meets the purity required. Similarly, when the higher pressure

steam is purer than required, lower pressure steam that does not conform may be added to

the stream, provided the mass weighted average meets the recommendations in this

document. In general, a parameter a may be calculated as

i ii

ii

m aa

m=∑∑

Where i runs over all streams, mi is the mass of the stream (flow rate) and a ai is the

value of parameter a for that stream. Remember that extracted steam must be removed at

its average purity. Thus a calculation may be required upstream of an extraction to provide

the averaged purity of the extracted steam. Lower pressure steam may then be blended

using the remaining mass and purity. Mass weighted averaging is a complex procedure and

must be carefully documented. Operating each source within the steam purity

recommendations is preferable.

7. Other Suggestions

For the water PH value is mainly affected by Steam Generator Feedwater System, the

ideal PH value should be more than 9.6 in order to decrease the erosion of whole cycle

system.


Compiled：Yu Yan 2008.09 Operating Limits and Precautions Checked：Zhang Xiaoxia 2008.09

Countersign：Yan Weichun,



Contents

OPERATING LIMITS AND PRECAUTIONS ...........................................1

1 GENERAL PRECAUTIONS ...............................................................1

2 ABNORMAL OPERATING CONDITION ........................................4

3 OFF-FREQUENCY TURBINE OPERATION ..................................5

4 GLAND SEALING STEAM ................................................................5

5 LP EXHAUST AND LP EXHAUST HOOD SPRAYS ......................6

6 WATER INDUCTION ..........................................................................9

7 DRAIN VALVES..................................................................................10

8 SUPERVISORY INSTRUMENTS ....................................................11

9 TURBINE BEARINGS AND OIL SYSTEM....................................11

10 EMERGENCY POWER ..................................................................13

11 BYPASS OPERATION .....................................................................14

12 MISCELLANEOUS..........................................................................14

Page 1 of 15


OPERATING LIMITS AND PRECAUTIONS

1 GENERAL PRECAUTIONS 1. Follow cold start or hot start procedure as determined by initial rotor metal

temperatures before admitting steam to the turbine. Turbine starting procedures are

defined in the section “Starting and Load Changing Recommendations.”

2. When following cold start procedures, determine the length of time for rotor

warming from the chart “Cold Start Rotor Warming Procedure.” It is important that

this time period, as determined by initial rotor metal temperatures on the first attempt to

roll, not be reduced in an emergency situation, where there may be a strong desire on the

part of the operator to put the unit on the line in a shorter time.

Refer to the chart “Turbine Speed Hold Recommendations” for the allowable rotor

warming soak speed range for the warming period.

3. When following hot start procedure, control the steam conditions at the throttle

valve inlet to achieve an exact match of first stage steam and metal temperatures. At no

time should the first stage steam temperature be more than 111 ℃ above or 56 ℃

below the first stage metal temperature (see chart “Start Recommendations”).

4. Operation of the turbine with excessive backpressure can damage blading and cause

rubbing between rotating and stationary parts. The maximum allowable backpressure is

load dependent and is shown on chart entitled“Exhaust Pressure Limitation”.

5. LP turbine blade resonant speed ranges for this turbine-generator unit are shown on

the chart “Turbine Speed Hold Recommendations.” If, during acceleration of the turbine,

it becomes necessary to hold the speed, be sure that the speed hold is not in a resonant

range. If it is, reduce the speed below the resonant range.

6. For adequate warming of the steam chest before transferring from throttle valve

control to governor valve control, the temperature of the steam chest inner surface (as

measured by the inner wall deep thermocouple) should be equal to or greater than the

saturation temperature corresponding to the prevailing steam pressure ahead of the

throttle valves. This will prevent the formation of water when the steam chest pressure is

raised as a result of transferring control to the governor valves. This heating may be

more difficult to accomplish when the throttle valve pilot values. The chart “Start-up

Steam Conditions at Turbine Throttle” shows the relationship between pressure and

Page 2 of 15


temperature that must prevail at the inlet to the throttle valves if steam chest temperature

is to reach the desired value. For example, with 6.89MPa steam inlet pressure, a

minimum temperature of 357℃ at the throttle valve is required. The use of reduced

pressure steam at startup is recommended.

7. The maximum temperature difference between deep and shallow thermocouples in

the steam chests should not exceed 83℃.

8. Observe the limits of the steam and metal thermocouples throughout the operation of

the turbine. Refer to the section “Turbine Steam and Metal Thermocouples.”

9. The appropriate final governor valve opening sequence as shown on “Control

Setting Instructions” must be strictly followed. Operation at any other sequence may

result in first stage blading problems.

10. Do not operate the turbine with the throttle valve (s) on one steam chest open and the

throttle valve(s) on the opposite steam chest closed. This restriction does not apply for

very short periods of time such as when the valves are being tested for stem freedom.

11. Do not operate the turbine with the reheat stop and/or interceptor valves on one side

of the turbine open and those on the opposite side closed. This restriction does not apply

for very short periods of time such as when the valves are being tested for stem freedom.

12. If reheat spray attemperating water is used, the following operating conditions must

be observed:

Using the maximum calculated heat balance as a base, the quantity of reheat spray

attemperating water must be measured. The load must be reduced from the load shown

on this heat balance by 0.6% for each 1% of reheat spray attemperating water measured

as a percentage of the throttle flow shown on this maximum calculated heat balance.

13. Two major aims of the Operations section of the instruction book are to limit the

thermal stresses in the turbine and limit interference of parts due to differential thermal

expansion. It is important to limit the temperature differences within various parts to

avoid thermal stresses and fatigue. Differences in thermal expansion can cause rubs.

Additionally, some parts of the turbine have maximum temperature limits. It is important

to adhere carefully to the temperature limits given in “Starting and Load Changing

Recommendations” chart and the charts pertaining to these instructions. Additional

important temperature limits are given in “Turbine Steam and Metal Thermocouples”

and “Water in the Turbine” leaflets.

Page 3 of 15


14. During turbine operation, do not operate portable radio equipment other than sound

powered telephones near or in the same room with the DEH controller if the controller’s

cabinet doors are open.

15. If the throttle pressure controller (or limiter) is out of service and the throttle steam

pressure falls uncontrolled below 90% of rated pressure for units with a drum type boiler

(95% for units with a once-through type boiler), or if throttle or reheat steam temperature

falls uncontrolled more than 83℃, remove the load and trip the turbine. Refer to the

section “Shutdown Procedure” for instructions if the throttle pressure controller (or

limiter) is in service.

16. Do not motor the turbine-generator unit for extended periods. We recommend that

inadvertent motoring operation be limited to less than one minute to prevent overheating

the turbine blading due to windage and lack of ventilation. Deliberate motoring is not

recommended at any time.

17. Overspeed Trip Mechanism

17.1 When starting the turbine initially, after any major overhaul, or after work is

performed on the governor pedestal which may affect the overspeed trip setting, the

turbine should be overspeeded to insure that the overspeed trip mechanism will operate.

The overspeed test should then be made periodically every six month, unless sooner

required by another such occurrence.

17.2 The overspeed trip setting is specified in the “Turbine Control Settings” leaflet.

17.3 The overspeed trip mechanism is described in a separate leaflet “Overspeed Trip

Mechanism”.

18. During shutdown periods, keep the turning gear in operation, except as noted in the

“Turning Gear Operation During Shutdown” section.

19. Do not admit steam to the turbine with the rotor at rest.

20. When conducting field hydrostatic tests of the main steam inlet piping between the

steam generator outlet and the turbine during which the throttle valve is expected to

function as a stop valve, the affected metal and water temperatures must be determined.

This is especially important in the event of a unit shutdown to effect boiler repairs. The

temperature of the throttle valve body at the inner wall, a measured by a thermocouple

installed in a boss provided for that purpose, must be within 83℃ of the temperature of

the water used for the test. This temperature differential must not be exceeded in order to

Page 4 of 15


avoid distortion of the throttle valve body and internals due to high thermal gradients.

The throttle valve should be on its seat when conducting the hydrostatic test. Some

leakage of water can be expected past the seated valve depending on the present

condition of the contact surfaces.

21. Process extraction flow must not exceed contract specifications. The customer is

responsible for monitoring extraction flow and determining that it is within this limit.

2 ABNORMAL OPERATING CONDITION 1. For operation of the turbine under other than rated steam conditions, refer to the

section “Allowable Variations in Steam Conditions.”

2. The turbine may be continuously operated at the conditions shown on the "Turbine

Maximum Calculated Load—Not Guaranteed" heat balance (refer to Thermal

Performance Data). If the unit is operated at other than normal conditions by such actions

as:

·removing feedwater heaters from service,

·using reheat attemperating sprays for injecting greater quantities than shown on the

heat balance,

·reducing the amount of steam shown on the heat balance to be extracted for air

heating, etc.

It could result in greater-than-design flows passing through the main turbine blading

downstream of where the cycle changes occur. Turbine damage-in particular, blade

damage could eventually result if load is not reduced sufficiently to prevent exceeding

design conditions. The large last three blading stages of the LP elements (s), in particular,

can be damaged if subjected to conditions that exceed their maximum allowable design

loading limits-sometimes expressed as “maximum allowable end loading.”

Various operating rules are located in other areas of the operation leaflet to guide the

operator in reducing unit load to avoid damage due to some of the abnormal conditions

listed.

3. Avoid operation at less than 5% rated load. However, when necessary, auxiliary load

may be carried indefinitely on the main generator following rejection of the main load

provided:

3.1 Limitations on reheat temperature and LP exhaust pressure as specified on the chart

Page 5 of 15


“No-Load and Light Load, Operation Guide” are maintained.

3.2 LP turbine exhaust temperatures do not exceed the limits and conditions specified in

sub-section 5, “Low Pressure Exhaust and Exhaust Hood Sprays,” item 4.

3.3 All supervisory instrument readings are within allowable (alarm) limits: (Pay

particular attention to differential expansion readings. Rapid or continued changes in

readings may require timely action to avoid exceeding allowable limits. Such action

would include removal from service or application of sufficient load to reestablish safe

operating conditions).

3 OFF-FREQUENCY TURBINE OPERATION Avoid off -frequency operation in order to prevent the probable occurrence of turbine

blade resonance. Prolonged periods of operation at certain off-design frequencies could

cause excessive vibratory stresses which could eventually generate fatigue cracking in

the blades.

Off-frequency operation is permitted to the degree and time limit specified on the

chart “Off-Frequency Turbine operation” located in the "Curve and Table of Turbine

Operate" section of the Operation leaflet.

4 GLAND SEALING STEAM

1. Steam supplied to the turbine glands should contain not less than 14℃ superheat.

2. Do not place the gland sealing steam system in service until the unit is placed on

turning gear operation. This is to avoid bowing the rotor (s).

3. The temperature limits of steam in the low pressure turbine glands are 121℃

minimum and 177℃ maximum. It is suggested that the gland system temperature

controller be set at 149 ℃.

4. To protect against rotor damage in the gland zones resulting from thermal stresses,

keep the difference between gland sealing, steam temperature and rotor surface

temperature to a minimum when starting or shutting down. The estimated number of

cycles to start rotor cracking due to thermal stresses at temperature differences between

gland sealing steam and rotor surface metal can be determined from the "Gland Sealing

Steam Temperature Recommendations" chart. As a guide to the operator, a cycle fatigue

Page 6 of 15


capacity of 10,000 cycles is recommended.

5. Where auxiliary boilers are used to furnish gland steam for hot starts, care must be

exercised to ensure that the auxiliary boiler is furnishing steam to the glands at a

temperature such that the maximum allowable difference between the gland sealing

steam and the rotor metal temperature is not exceeded.

5 LP EXHAUST AND LP EXHAUST HOOD SPRAYS 1. Do not operate air ejector or vacuum pumps without sealing steam on the turbine

glands.

2. LP exhaust hood sprays are provided, which， when placed under automatic control,

commence operation when the rotor speed reaches 2600 r/min and continues until the

unit has been loaded to 15%. The control switch should always be in the “automatic”

position during start-up. The switch also has a “manual” position.

3. The operator must be certain that water is available to the exhaust hood spray control

valve whenever the turbine is rolling over 3 r/min.

4. With LP exhaust hood sprays out of service, the LP exhaust hood steam temperature

limits are 79℃ for continuous service (alarm at 79℃) or 121℃ for short periods (15

minutes). If 121℃ reached, and the temperature cannot be reduced promptly, trip the

turbine and correct the trouble. If 121℃ is exceeded, trip the turbine and correct the

trouble.

NOTE:

With the exhaust hood spray in service, the high exhaust temperatures will be

eliminated; however, high blade path temperatures may exist and observance of the

back pressure limit is required to avoid temperatures in the blading that are

unacceptable.

5. We do not expect overheating of the LP exhaust hood with no-load steam flow, low

absolute condenser pressure, and the LP exhaust hood sprays out of service. High

absolute condenser pressure will cause overheating, as will less than no-load steam flow

(at rated speed) which would result if the unit were allowed to motor.

6. If the LP exhaust hood steam temperature reaches 79℃ the operator must lower the

temperature gradually by increasing load or improving the vacuum.

Page 7 of 15


7. With the LP exhaust hood sprays in service, operation at high absolute condenser

pressure can cause high blade-path steam temperature. Care must be taken to insure that

operation under these conditions does not cause unacceptable differential or radial

expansion problems between rotating and stationary parts of the LP turbine.

8. When operating with high exhaust temperature, pay particular attention to

differential expansion, vibration, bearing metal temperature changes, etc. With the LP

exhaust hood sprays out of service, temperatures may be determined by exhaust hood

thermometers and thermocouples. If the exhaust hood steam temperature alarm of 79℃

is reached, the operator should attempt to lower this temperature by any of the following

means:

8.1 Improve vacuum.

8.2 If at low load, increase load above 15% of rating.

8.3 If not on line, reduce speed to warming speed.

8.4 If at warming speed, go back to turning gear speed.

8.5 Put exhaust hood spray system into operation.

9. The exhaust hood spray regulating valve has a bypass valve which should only be

used in the event of regulating valve failure or servicing. The bypass should only be

opened enough to maintain the calculated control water pressure. See “Turbine Control

Settings.”

CAUTION

To prevent possible damage to the turbine it is important that this valve is not left

open when operating the turbine in the range that LP exhaust hood sprays are not

required.

10. The chart "No Load and Light Load Operation Guide" specifies exhaust pressure

limits at no load (full speed) and at 5% load as a function of reheat temperature.

11. Set the vacuum trip to trip the unit at the setting shown in “Turbine Control

Settings.”

12. Vacuum Breaker Operation.

12.1 When more than on LP element is used, vacuum should be broken

simultaneously in all elements.

12.2 Vacuum should be maintained on a trip out, or normal shutdown, until the unit

coasts down to about 10% of rated speed or until the unit is placed on turning gear

Page 8 of 15


provided that no emergency is involved in the trip out, or shutdown, that requires

vacuum to broken immediately after the main turbine valves close. Making a practice of

opening the vacuum breaker valve immediately after tripping a unit could result in blade

damage due to the braking action imposed by the suddenly created dense exhaust

medium. Vacuum should be broken immediately after a unit is tripped if any condition

exist where possible damage to the unit can be reduced by shortening coast down time.

Examples of incidents requiring vacuum to be broken immediately after a trip include,

but are not restricted to: loss of ac power, loss of dc power, low bearing oil pressure, loss

of lubricating oil, loss of cooling water to turbine oil coolers, thrust bearing trip, water in

the turbine, any indication of rubbing between rotating and stationary parts, and

excessive vibration on coast-down.

12.3 Vacuum must not be broken at any speed until:

a. The turbine is tripped;

b. The turbine throttle valves are closed;

c. The generator is separated from the system;

d. The turbine-generator unit is in a free coast-down condition.

12.4 Vacuum must not be broken when the unit is tied to the system and

turbine-generator speed is maintained by the system even though the throttle valves are

closed. This condition occurs when a unit is motoring.

12.5 Vacuum must not be broken when load is rejected on the unit, but turbine speed

is maintained by the governing system to carry auxiliary load. In this case, the throttle

valves are not closed nor are the turbine-generator unit in free coastdown even though

the generator is separated from the system.

12.6 If gland sealing steam is lost, trip the turbine and break vacuum as soon as the

conditions of Item 12.3 above are satisfied.

12.7 Vacuum should be dissipated before gland sealing steam is shut off to avoid

pulling cool air into turbines across heated glands and rotors.

12.8 Each LP turbine vacuum must be broken at the same time if more than one LP

turbine used.

13. The maximum permissible back pressure for on-line operation is 18.6kPa at loads

above 10% of rated load up to 100% load. At lower loads, and at the rated speed-no load

condition, substantially lower back pressures are required. Such operation should be in

Page 9 of 15


accordance with the chart, “No load and Light Load Operation Guide.” Failure to

observe specified back pressure limits may result in blade failures or rubbing between

rotating and stationary turbine parts with serious damage to turbine components.

14. If multiple condensers or a zoned condenser is provided:

14.1 The temperature difference between multiple condensers (or condenser Zones)

should not exceed 17℃, alarm at 11℃ differential and trip the unit at 17℃ differential.

The permissible pressure difference between multiple condensers (or condenser Zones)

is 8.6kPa(a); alarm at 6.9kPa(a) differential and trip the unit at 8.6kPa(a).

14.2 Temperature and pressure differences between active and inactive condenser result

in uneven flow distribution to the low pressure turbine blading resulting in possible

operating difficulties. We recommend that the turbine be removed from service if it is

necessary to remove one full condenser from service.

6 WATER INDUCTION 1. Cool water introduced into a hot casing may cause rubs, possible vibration and loss

in performance. If severe enough, it will necessitate an extended outage for repair of

damaged parts. The operator must ensure that the turbine drains and also the drains from

the main steam, hot reheat, cold reheat, and extraction lines are not blocked during

start-up. In addition, the operator must ensure that power station systems including the

feed water heaters, boiler flash tank system, and the reheat attemperation system are

functioning properly.

2. Water detection thermocouples are installed in pairs in the turbine cylinders (one in

the bottom of the cylinder base and one in the cover) to monitor the temperature

difference between base and cover metal in selected temperature zones. The maximum

permissible temperature difference between base and cover is 56℃, with the base colder.

An alarm is activated if the temperature difference reaches 42℃. If the difference

exceeds 56℃ by any amount, trip the turbine immediately. A sudden increase in the

normal temperature difference indicates the pressure of water in the bottom of the outer

cylinder. All turbine drains should be checked and opened immediately. All power

station systems that could be introducing water into the turbine should be checked for

proper operation. These include feedwater heaters, boiler flash tank systems, reheat

Page 10 of 15


attemperation systems and the drains from the main, hot and cold reheat and extraction

steam lines.

NOTE

The turbine can remain in service with a 56 ℃ temperature difference if there is

no instrument indication or other sign of distress that would necessitate tripping.

This will give the operators time to isolate and dispose of the water, allowing heat

from the normal steam flow through the turbine to straighten distorted stationary

parts. It is of utmost importance, however, that if the temperature difference

exceeds 56℃ by any amount, the turbine be tripped immediately regardless of the

consequences.

3. It is essential that the turbine operator be thoroughly familiar with the information

contained in the section “Water in the Turbine.”

7 DRAIN VALVES 1. Operation of the turbine drain valves is normally automatic, but if manual operation

becomes necessary, all turbine drains and other drains critical to turbine safety must:

1.1 Be open until the turbine is cold when unit shut down.

1.2 Be opened before the turbine is started and before gland steam is supplied to the

glands.

1.3 Remain open on increasing load until the unit is carrying 10 percent of rated load for

drains from sources upstream of the turbine reheat stop valves.

1.4 Remain open until the unit is carrying 20 percent of rated load for drains from

sources downstream of the turbine interceptor valves.

1.5 Open on decreasing load at 10% of rated load and remain open below 10% of rated

load for drains from sources upstream of the turbine reheat stop valves.

1.6 Open on decreasing load at 20% of rated load and remain open below 20% of rated

load for drains from sources downstream of the turbine interceptor valves.

2. Avoid breaking vacuum before critical drain valves are open. This recommendation

does not apply in emergencies requiring vacuum to be broken immediately nor does it

apply to the purchaser's main steam pipe drains.

3. On initial start-up, read and record the pressure gauge indication on each drain

manifolds with the unit on turning gear and at each speed and load hold while the drains

Page 11 of 15


are open (usually up to 10-20% load.) If the pressure in any manifold exceeds the

pressure of the lowest pressure source routed to that manifold, shut the unit down and

correct the problem.

8 SUPERVISORY INSTRUMENTS 1. Before the unit is rolled from turning gear speed, the portable rotor truth dial

indicator measurement at any bearing oil ring should not exceed 0.0254mm double

amplitude. In addition, the rotor eccentricity should not exceed 0.076mm double

movement.

2. Rotor position is based on a nominal thrust bearing clearance of 0.38mm. The alarm

limit and trip limit consult “Turbine Control Settings”.

3. Vibrations Limits (double amplitude-mm).

3.1 0.076mm-satisfactory.

3.2 0.127mm-alarm (investigation is needed if vibration is continuous and of the

unbalanced type).

3.3 0.254mm-trip or other suitable action (which may be load change, speed change,

etc., according to specific conditions).

4. Differential expansion limits. Refer to the “Turbine Control Settings” leaflet for the

alarm and trip settings as these values vary with turbine configuration.

5. There are no “Alarm” or “Trip” features on the Casing Expansion.

9 TURBINE BEARINGS AND OIL SYSTEM NOTE

For generator and exciter bearing temperature limits, see Generator Instruction

Book.

1. Bearing Metal Temperature Limits

l.1 The babbitt temperature of turbine journal bearings will normally range between 66℃

and 112℃ depending on such variables as inlet oil temperature, oil flow, bearing size,

bearing load, etc. The alarm is set at 107℃ operation above this temperature should be

carefully monitored until the reason for abnormal temperature is determined. Trip the

unit if the metal temperature exceeds 113℃.

Page 12 of 15


CAUTION

Whenever any bearing exhibits erratic temperature changes, investigate the cause

immediately. Trip the turbine if necessary. Inspect the bearing and make whatever

repairs are needed. Comply with the appropriate instructions in the section

“Turning Gear operation During Shutdown” depending on the extent of the

damage.

1.2 Thrust bearing babbitt temperature can range from slightly inlet oil temperature to

99℃ depending chiefly on thrust load. The alarm setting is 99℃ and the trip setting is

107℃. Operation between the alarm and trip temperature should be carefully monitored

until the reason for the abnormal temperature is determined.

2. Oil Pressure Limits

Low bearing oil pressure alarm and trip settings for this unit are shown on the Turbine

Control Settings (Control Setting Instructions) leaflet.

3. Oil Temperature Limits

3.1 Do not start the motor-operated bearing oil pump if the oil temperature at the oil

reservoir is less than 10℃.

3.2 Do not start the turning gear until the oil temperature at the oil reservoir reaches 21

℃ minimum. This is also the minimum oil temperature for turbine operation.

3.3 Bearing (turbine) oil discharge temperatures should not exceed 82℃. Alarm at 77℃

and trip at 82℃.

3.4 During turbine operation, an oil temperature of 38℃ to 49℃ is considered normal.

When starting the turbine, shut off the water supply to the oil coolers until the oil

temperature within this range.

3.5 During turbine operation, leave the oil cooler interchange valve open to ensure that

the standby cooler will be filled with oil and ready for service at all times.

4. Oil Vapor Extractors

4.1 The oil vapor extractors for the generator loop seal tank and turbine oil reservoir

must be in service when starting and operating the turbine-generator unit.

4.2 The vapor extractors vacate gases (hydrogen and air) from the lubricating and seal

oil systems and prevent the discharge of oil vapor to atmosphere along the rotor by

establishing and maintaining a slight negative pressure throughout the turbine-generator

Page 13 of 15


lubricating and seal oil systems.

4.3 The loop seal vapor extractor performs these functions for the generator exciter

while the vapor extractor on the oil reservoir serves the turbine pedestals, bearing

housings, reservoir and the remainder of the oil piping.

4.4 If either vapor extractor malfunctions or is shut off during turbine-generator

operation, there is a possibility that some hydrogen, oil vapor and/or lubricating oil may

escape from the oil seal rings and be discharged into turbine room. Under these

conditions, the turbine-generator unit should be shut down until the vapor extractor

system is restored to service.

10 EMERGENCY POWER It is essential that a reliable source of emergency power be available whenever a

turbine is in operation at any speed above turning gear speed. Manufacturer normally

supplies two bearing oil supply pumps, one driven by an ac motor and the other, an

emergency backup pump, driven by a dc motor. Under certain emergency conditions,

such as loss of ac power, a continuous source of emergency power is required for a

period of time not less than the turbine-generator coast-down time to ensure safe

shutdown.

It is the purchaser's responsibility to provide the continuous supply of power to these

pumps and damage resulting to units from a failure to have such a continuous supply

shall be the purchaser's responsibility.

Where batteries are provided for the emergency power supply, they must be capable of

providing rated emergency oil pump power for approximately 45 to 60 minutes with the

power supply lasting for the duration of the coast-down period.

The unit should not be started if sufficient emergency power is not available for safe

shutdown under emergency conditions. The batteries must be continuously monitored to

ensure adequate dc power supply for a safe emergency shutdown. They will most likely

be discharged following a coastdown on dc power or when dc power is used to test

emergency equipment or systems (such as the dc emergency oil pump), which do not

turn off automatically. The dc emergency oil pump imposes a heavy drain on the battery

system. Thus, following operation of this pump, the adequacy of the dc power must be

checked.

Page 14 of 15


CAUTION

Shut off the dc emergency oil pump following testing of this pump and associated

pressure switches. The switch must then be returned to the AUTO position.

11 BYPASS OPERATION When the turbine bypass system is in service, the following restrictions should be

observed:

1. The turbine control system must be in the BYPASS ON mode whenever the plant

bypass system is on. Similarly, the plant bypass system must be on whenever the turbine

control system is in the BYPASS ON mode.

2. At synchronization and at low loads, a maximum cold reheat pressure of 0.828MPa(a)

is recommended to prevent overheating of the HP turbine.

3. The high temperature alarm limit for HP turbine exhaust steam is 400℃, If the HP

exhaust temperature alarm of 427℃ , the operator should attempt to lower the

temperature by the following means:

3.1 Decrease reheat pressure

3.2 Increase load

If the HP exhaust steam temperature reaches 427℃, the turbine will be tripped

automatically.

12 MISCELLANEOUS 1. Lift major turbine parts in accordance with the “Lifting Gear Instructions” drawings.

Use only the recommended cable sizes, turnbuckles and hooks.

2. Keep a complete record of all steam pressures and temperatures. Any deviation from

normal should be investigated and corrected immediately. This applies in particular to

variations in steam pressure distribution throughout the turbine at any given load.

3. Keep the lube oil system clean and free of water. It is suggested that a small quantity

of oil be drained from the bottom of the lube oil reservoir after long shutdown periods

during which water and sediment may be settled to the bottom. If preferred, the lube oil

may be drained and batch-treated before returning it to the system.

4. Oil leaks are unsightly and dangerous and constitute a hazard when close to parts

Page 15 of 15


carrying hot steam. Correct all such leaks immediately.

5. Ensure that the entire area around and beneath each bearing oil seal is clean and free

of dust, chunks of thermal insulation and other foreign material or debris which could

absorb oil and act as fuel or a wick to support combustion. The area that must be clean

includes, but is not limited to centering beams, structural supports, walkways, platforms,

top of the foundation, and piping located below the pedestal and bearing housing which

tend to collect this debris. Insulated parts (piping and cylinders) in these areas should be

protected by an appropriate covering to prevent absorption of oil into the insulation.

6. Slop drains are provided to drain the cavities formed by the bearing housing, LP

exhaust cone and the LP turbine base structure at each end of each LP turbine element.

Customer’s connections to these slop drains are provided at the bottom of each LP

turbine element base and these drains should be routed out of the condenser neck to a

waste pit at atmospheric pressure. This pit should be protected against fires since oil may

be dumped to waste through the slop drains. To reduce the hazard of fires at the turbine,

cavities in bearing housing areas must be kept clean of all dirt and debris and slop drains

must be kept open. Therefore, a periodic check should be made to ensure that the slop

drains are not plugged so that oil or water that collects in these cavities will drain to

waste promptly. To ensure that the slop drains are open, MANUFACTURER

recommends that a check be made every 3 months. This check consists of pouring a

gallon of clean water in each cavity containing a slop drain to ensure that the water

drains out promptly and that the drain is functioning properly.


Compiled：Zhang D.M 2008.09

Water in The Turbine Checked：Huang Q.H 2008.09

Countersign：Yan W.CH 2008.09



Contents Water in The Turbine........................................................................................1

1 OPERATION...........................................................................................1

1.1 General .................................................................................................1

1.2 Drain System ........................................................................................3

1.3 Main Steam System..............................................................................4

1.4 Reheater Attemperating Station ...........................................................5

1.5 Unit on Turning Gear ...........................................................................5

1.6 Cold Reheat Piping System..................................................................6

1.7 Extraction and Feedwater Heaters .......................................................7

1.8 Gland System .......................................................................................8

1.9 Attemperating Sprays ...........................................................................8

1.10 Feedpump Turbine Steam Supply ......................................................9

2 MAINTENANCE....................................................................................9

2.1 Startup Periods .....................................................................................9

2.2 Once per Month....................................................................................9

2.3 Every 3 Months ..................................................................................10

2.4 Annual Inspection...............................................................................11

Page 1 of 11


Water in The Turbine

1 OPERATION Once water enters a turbine it is extremely unlikely that all damage can be prevented.

Possible damage to turbines by water includes, but is not restricted to, blading and

shroud failures, thrust bearing failure, rotor cracks, blade ring cracks, permanent blowing

of rotors, permanent distortion of stationary parts, and crushed (blading and gland) seal

strips.

The degree of damage is a function of many factors including point of water entry,

quantity of water, length of induction period, turbine metal temperatures, speed and/or

load on the unit, steam flow, relative position of rotating and stationary parts and action

taken by the operators. So many factors are involved that no single set of operating

instructions will be adequate for every incident. However, we believe that power

companies can devise operating instructions for each unit and train operators to use these

instructions to minimize damage in most water incidents. The following

recommendations are provided for this purpose.

1.1 General 1. Train operators to handle water induction incidents.

2. Insist that operators follow prescribed procedures whenever an alarm or instrument

indicates that water induction is in progress or imminent.

3. Take action immediately when water induction is indicated.

4. Provide alarms and use a recorder in the control room for all water detection

thermocouples in the heat power cycle.

5. When an alarm sounds do not depend solely on automatic operation of critical

valves. Actuate these valves remotely and check visually to be sure they are in the

correct position.

6. If there is faulty protective equipment associated with a water source, isolate the

source from the turbine and adjust operating conditions as required by loss of the

equipment.

7. When a water induction incident occurs analyze the incident and make required

corrections to equipment not only in the affected zone, but in all other zones susceptible

to the same type of incident. Correct operating procedures and operator training

Page 2 of 11


deficiencies if corrections are needed.

8. A water induction incident is considered to be in progress if abnormal or final high

level in a heater is indicated, if the purchaser's water detection sensors in extraction pipes

indicate water or if any pair of turbine water detection thermocouples indicates a

difference between cylinder base and cover metal of 42℃ or more with the base colder.

If this temperature difference exceeds 56℃ by any amount the unit must be tripped

immediately. If the temperature difference does not exceed 56℃, and there are no

instrument indications or other signs of distress which indicate the unit must be tripped,

the unit can be kept in service to isolate and dispose of the water. A water incident is also

considered to be in progress if there is vibration or swaying of pipes which did not exist

before and for which there is no acceptable explanation. Obviously there may be

acceptable causes: but if these are not readily discernable, operators should assume a

water incident is in progress and take necessary protective steps. Should any of these

conditions develop, emergency operating procedures must be instituted immediately.

9. We generally agree with the concept of detection, isolation, and removal of water

with the turbine in service, experience to date indicates that once water is in a hot turbine,

distress which exceeds allowable operating limits usually occurs and the unit must be

tripped. Therefore, turbine operators must be trained to handle both contingencies. The

automatic protective schemes recommended are necessary for rapid action to attempt to

keep the temperature difference between turbine cylinder base and cover from exceeding

56℃.

The operating instructions that follow are based on the premise that drain and shutoff

valves are power operated and remotely or automatically actuated. These instructions can

be used with manual valves, but in those cases where quick action is an absolute

necessity to minimize damage; manual valves may not be operable in the time available.

If valves are automatically actuated the step-by-step operating procedure should be

followed as a backup for possible malfunction. To avoid numerous repetitions of the

basic procedure in the specific instructions, it is presented below and referred to hereafter

as the “Basic Isolation Procedure for Feedwater Heaters.” The procedure is based on

water from feedwater heaters since most incidents involve the heaters. Rapid execution

of the procedure is essential.

Basic isolation procedure for feedwater heaters:

Page 3 of 11


a. Close the shutoff valve in the extraction pipe. [*①]

b.Open all drain valves in the extraction pipe and affected turbine zone.

c. Check all shutoff and drain valves visually for correct position.

d.Reduce heater level to normal elevation.

e. Determine and correct the cause of the incident.

f. If the cause of the incident cannot be corrected immediately, the unit may be

operated providing that:

1) All water is removed from the turbine as evidenced by a difference of less than

42℃ between cylinder base and cover.

2) All water is removed from the extraction pipe.

3) The unit can be operated safely without the faulty equipment and that this

equipment is completely isolated so that the incident will not recur.

4) All instrument indications, especially metal temperatures, eccentricity, vibration

and differential expansion, demonstrate that conditions are satisfactory for operating the

unit.

5) All extraction pipe drains remain open on the turbine and heater sides of the

shutoff valve.

6) There were or are no indications of damage or distress that preclude operation

and necessitate disassembly of one or more turbine elements for immediate repairs.

① Bypass condensate around feedwater heaters that do not have shut off valves in

the extraction pipes.

10. Regardless of preventive equipment furnished and precautions taken, occasional

water incidents can and will occur. Attempts to restart units too quickly following a

water incident may result in sufficient damage to keep the units out of service for 6

months or more. Therefore, operators must recognize that once it is established that a

water incident has occurred, or that there is reason to believe that an incident occurred, it

is unlikely that the unit involved can be restarted safely for at least 24 hours or more. See

paragraphs 1.5 2 and 1.5 3 below.

1.2 Drain System 1. All turbine drains and other drains which critical to turbine safety should be:

a. Be opened when the unit is out of service until the turbine is cold.

b. Be opened before the turbine is started and before sealing steam is supplied to the

Page 4 of 11


glands.

c. Remain opening on increasing load until the unit is carrying 10% of rated load FOR

DRAINS FROM SOURCES UPSTREAM OF THE TURBINE REHEAT STOP

VALVES(See the Note after paragraph 1.5 below).

d. Remain opening until the unit is carrying 20% of rated load FOR DRAINS FROM

SOURCES DOWNSTREAM OF THE TURBINE INTERCEPTOR VALVES.

e. Opened on decreasing load at 10% of rated load and remain opening below 10

percent of rated load FOR DRAINS FROM SOURCES UPSTREAM OF THE

TURBINE REHEAT STOP VALVES.

f. Opened on decreasing load at 20% of rated load and remain opening below 20% of

rated load FOR DRAINS FROM SOURCES DOWNSTREAM OF THE TURBINE

INTERCEPTOR VALVES.

Note: On units with only one load-sensing switch for drain valves, it is acceptable

for the higher pressure drain valves to be open to 20% load. However, this

procedure wastes steam. If the unit is operated for any appreciable time below 20%

load, it is likely that the cost of adding the second load-sensing switch and

associated writing will be recovered quickly

2. Avoid breaking vacuum before critical drain valves are opened. This

recommendation does not apply in emergencies requiring vacuum to be broken

immediately nor does it apply to the purchaser's main steam pipe drains.

1.3 Main Steam System 1. Trip the unit if there is an indication that water is entering or about to enter the

turbine from the boiler.

2. Main steam pipe drains should remain open on startup until metal temperatures and

boiler conditions indicate that there is no chance that water is present or will form in the

system and be injected into the turbine.

3. Operation with the initial pressure regulator out of service for long periods is not

recommended. With this regulator out of service there is greater hazard to the turbine

from the increased possibility of water carryover should boiler pressure decrease for any

reason. Normally this instrument is only out of service during startup and load ramping

when main steam pressure is less than the rated value.

4. Main steam drains should either be opened immediately after the turbine trips, or if

Page 5 of 11


this practice creates a condition that is contrary to recommended operating procedures

for boilers, the power plant designer should have contacted STC and a mutually

acceptable procedure developed for use by the operators before initial startup.

5. DO NOT ADMIT STEAM TO THE TURBINE AFTER BOILER FIRES

HAVE GONE OUT.

1.4 Reheater Attemperating Station 1. If this system malfunctions so that the turbine is endangered by insufficient spray

water, trip the turbine immediately. If excess water is the problem, follow instructions

for operating with water in the cold reheat pipes.

2. Attemperating sprays are usually not required at rated speed-no load. Therefore, the

spray, bypass, and blocking valves should be closed automatically whenever the unit is

not carrying load and when the turbine trips. The power plant designer must determine if

this procedure can be used without endangering equipment.

If the boiler manufacture permits attemperating sprays to be blocked out of service at

low loads, close the spray, bypass, and block valves automatically at this low load rather

than at rated speed-no load as recommended above.

3. If there is water in the reheater or hot reheat pipes, trip the turbine immediately and:

a. Close the reheater attemperating spray bypass and block valves.

b. Open all drains in the reheat pipes.

c. Do not restart until all water is removed from the reheater and/or hot reheat

piping and the cause of the incident has been corrected.

1.5 Unit on Turning Gear 1. Do not roll the turbine with steam if a water induction incident is in progress, or if

water detection thermocouples in any turbine zone indicate that the cylinder base is

colder than the cover by 42℃ or more.

a. Accomplish the basic isolation procedure for feedwater heaters.

b. If the cold reheat pipes are involved, close the reheater attemperating spray, bypass

and blocking valves.

2. If a cylinder is bowed by water, do not restart the unit until rotor eccentricity is within

acceptable limits and the difference between all pairs of cylinder base and cover

thermocouples is less than 42℃. If there are no water detection thermocouples in

cylinder metal in the affected zone, remain on turning gear for not less than 18 hours. If

Page 6 of 11


water detection thermocouples are used to determine if a cylinder is bowed, they must be

located in the cylinder base and cover approximately diametrically opposite and properly

installed in cylinder metal.

CAUTION: Remain on turning gear for 18 hours before restarting a unit after a

cylinder is bowed. When restarting a unit after a bowed cylinder has straightened, use a low acceleration

rate and close supervision of the restart. Trip the unit at the first sign of distress remains

on turning gear for 6 additional hours and restart following the same procedure.

3. If the rotor is locked, attempt to place the unit on turning gear once an hour. When

the rotor moves freely, place the unit on turning gear and proceed carefully as outlined in

paragraph 1.5 2 above.

CAUTION: Do not attempt to turn a locked rotor by admission of steam to the

unit or by use of a crane or other auxiliary methods. Such an attempt could cause

serious damage to the seals, blading, and other internal parts.

1.6 Cold Reheat Piping System 1. If water enters, or might enter, the cold reheat pipes or the high pressure turbine

exhaust when the unit is below rated speed, trip immediately and:

a. Close the reheaters attemperating spray, by-pass, and block valves.

b. Accomplish the basic isolation procedure for feedwater heaters.

c. Place the unit on turning gear and follow instructions for startup from turning gear.

2. If water enters, or might enter, the cold reheat pipes or the high pressure turbine

exhaust when the unit is at rated speed-no load, or carrying load, trip, the unit

immediately if required by vibration, differential expansion, metal temperature

differences exceeding 56℃, or other signs of distress of sufficient magnitude to warrant

tripping and:

a. Close the reheater attemperating spray, by pass, and blocking valves.

b. Accomplish the basis isolation procedure for feedwater heaters.

c. Place the unit on turning gear and follow instructions for startup from turning gear.

3. If water enters, or might enter, the cold reheat pipes or the high pressure turbine

exhaust when the unit is at rated speed-no load, or carrying load, do not trip if vibration,

differential expansion are satisfactory and there are no other signs of distress of sufficient

Page 7 of 11


magnitude to warrant tripping and providing that the temperature difference between

cylinder base and cover does not exceed 56℃, proceed as follows:

a. Hold at rated speed or load.

b. Accomplish basis isolation procedure for feedwater heaters.

c. Close the reheater attemperating spray, bypass and blocking valves if the unit is at

rated speed or low load not requiring sprays.

WARNING: DO NOT LATCH UP A TURBINE FOR STARTUP, OR FOR ANY OTHER

REASON, IF THERE IS WATER IN THE COLD OR HOT REHEAT PIPES, REHEATER,

OR HIGH PRESSURE TURBINE CASINGS. WATER IN ANY OF THE ABOVE COULD

CAUSE INJURY TO PERSONNEL AND SERIOUS DAMAGE TO THE SEALS,

BLADING, AND OTHER INTERNAL PARTS. 4. When a turbine is latched, interceptor, reheat stop and governor valves go open.

When this occurs with water in any of the zones listed above, and the temperature of this

water is above the saturation temperature of condenser pressure, steam will flash and

follow through the intermediate and low pressure turbine elements to the condenser.

Under these circumstances the turbine often accelerates to some speed, depending on the

amount of steam flashed, and there may be damage to the turbine or plant equipment. In

particular, water hammer may occur in the cold reheat pipes causing damage to both the

turbine and cold reheat piping system including broken pipes, hangers and supports. Also,

pipes, cables, equipment or station steel in the vicinity of whipping pipes may be

damaged and personnel may be injured.

Water hammer can occur in steam pipes that are partly full of water with steam

flowing over and accelerating this water to bends and valves in the piping system.

Whether the source of steam accelerating the water is from flashing, pressurized reheat

sections or open inlet valves, these phenomena can damage turbines, plant equipment

and piping.

Therefore, before latching the turbine be sure that the cold and hot reheat pipes,

reheater and turbine casings are properly drained and free of water.

1.7 Extraction and Feedwater Heaters 1. If water enters, or might enter, the turbine when the unit is below rated speed, trip

immediately and:

Page 8 of 11



b. Place the unit on turning gear and follow instructions for startup from turning gear.

2. If water enters, or might enter, the turbine when the unit is at rated speed-no load, or

carrying load, trip the unit if required by vibration, differential expansion water detection

thermocouples or other signs of distress of sufficient magnitude to warrant tripping and:


b. Place the unit on turning gear and follow instructions for startup from turning gear.

3. If water enters, or might enter, the turbine when the unit is at rated speed-no load, or

carrying load, do not trip if vibration and differential expansion are satisfactory and there

are no other signs of distress of sufficient magnitude to warrant tripping and providing

that the difference between cylinder base and cover does not exceed 56℃, proceed as

follows:

a. Hold at rated speed or load.

b. Accomplish the basic isolation procedure for feedwater heaters.

4. Whenever a heater is out of service, drain valves in the associated extraction line

should be open.

1.8 Gland seal System 1. When a turbine is hot and it is necessary to transfer to an auxiliary source of gland

sealing steam, be sure that:

a. The steam is superheated. the superheate should be more than 14℃ .

b. The steam temperature is within 111℃ of rotor metal temperature in the gland

area.(the temperature difference should be lesser). The temperature of LP gland seal will

be set between 121℃ and 177℃, the setting valve is 149℃.

c. The supply piping from the auxiliary source to the turbine gland system is warm so

that steam is not condensed and injected into the gland system in liquid form.

d. The pipe upstream of the gland regulating valve is dry (drain valve open or

continuous drain in service).

1.9 Attemperating Sprays Sprays provided to desuperheat steam to the condenser from any steam dump valve

should be shut off whenever the dump valves are closed or pressure ahead of the valves

reach a preset low value. This will prevent possible back flow of water into the turbine

Page 9 of 11


when condenser vacuum is broken. If the system malfunctions so that the turbine is

endangered by water, trip the unit immediately.

1.10 Feedpump Turbine Steam Supply Drain from the feedpump (FP) turbine throttle steam supply line should be opened

automatically when the FP turbine trips. If the FP turbine is out of service, all steam

supply valves should be closed.

2 MAINTENANCE In order to be sure that instrumentation and equipment provided to protect the turbine

against water damage are in working order when needed, we recommend the

establishment of a list of critical items to be checked once every 30 days to insure proper

and reliable operation. In the event that actual experience indicates the need for more

frequent inspections on specific items, the 30-day period can be adjusted as required.

When testing critical equipment every effort should be made to test in a manner that is as

close as possible to the actual operation of the equipment providing this can be done

without endangering the turbine or other station equipment and without removing the

unit from service. Control loops and redundant control loops should be completely

tested.

2.1 Startup Periods 1. Clean all traps, orifices, and drip pots during the initial startup period after the first

thirty days of operation unless there are indications that these devices must be cleaned

sooner.

2. Clean traps, orifices, and drip pots approximately two weeks after startup following

disassembly of the unit, or of a turbine element.

2.2 Once per Month 1. Check turbine supervisory instruments including differential expansion, casing

expansion, eccentricity, vibration, rotor position, and metal temperature recorder. These

instruments should be cleaned, checked electrically and any questionable components

replaced during the inspection period.

2. Check all turbine metal temperature thermocouples. These instruments should be

inspected and maintained on an every 30-day basis; but

Page 10 of 11


a. Replace faulty thermocouples immediately. Usually this can be done with the unit in

service.

b. Maintain spare thermocouples for replacement of critical water detectors.

3. Check all extraction line valves. Check all of the controls associated with these

valves including switches, solenoid valves, air filters, air supply, air sets, etc. Most of

these valves can be tested in operation; they should be tested with the same frequency as

the main valves on the turbine.

If possible, develop procedures to check nonreturn valves for leakage since there have

been difficulties caused by leaking nonreturn valves. Where there are two valves in a

pipe, it may be possible to pressurize the pipe between valves with air to check for

leakage.

4. Check all heater level control and alarm systems to insure proper operation. These

instruments should be cleaned and questionable equipment replaced during the

inspection period.

5. Check all heater drain valves to insure proper operation. Clean each valve assembly

externally and replace questionable components.

2.3 Every 3 Months 1. Check all drain lines (and valves) from the turbine and associated piping. This

includes main steam, extraction, and hot and cold reheat piping. Drain lines and valves

should be checked by the temperature method.

2. Check all orifices and traps by measuring the pipe temperature upstream and

downstream of the trap or orifice.

3. Testing of drain valves and drain lines by the temperature method refers to a

procedure utilizing a contact pyrometer or thermocouples to determine by temperature

difference whether or not a drain line is open. We recognize that this method is not

completely reliable but is better than no check at all. It is made in operation on normally

closed valves by first measuring the temperature on the upstream side of the valve close

to the line source. Next, measure the temperature downstream of the valve on the drain

line. The valve is then opened and these two temperatures are again checked. If they are

then close to one another, we can assume that the line is open and functioning properly.

If the temperatures show the same differential relationship as with the valve closed, the

line is fully plugged. For best results from the temperature test, the drain line should be

Page 11 of 11


insulated from the source (at least) to the drain valve. We cannot cover every possible

case that will occur; however, station operating personnel can work out temperature

check procedures for each critical valve and with proper education, reasonable checks

can be made to increase safe, reliable operation of the equipment.

4. For drain valves, check that threads on manual and pneumatic valves are clean and

lubricated. Manual valves should have a hand wheel or handle which is properly attached

to the valve stem. Power operated drain valves should be checked completely for proper

functioning of all components. Stems should be cleaned and the valves lubricated as

required. Replace all questionable components during this inspection.

2.4 Annual Inspection 1. Internal inspection, cleaning and maintenance of critical valves, traps and orifices

should be made at each major inspection but not less than once a year.

2. Clean drip pots at each major inspection, but not less than once each year.


Compiled：Jiang Jianfei 2008.09Starting and Load Changing Recommendations Checked：Yu Yan 2008.09

Countersign：Zhang Haiyan 2008.09

Countersign：He Xiaozhong 2008.09

Countersign：

OP.2.11.02E-00

Approved：Peng Zeying 2008.09

Contents

STARTING AND LOAD CHANGING RECOMMENDATIONS .................1

1 OBJECTIVES .........................................................................................1

2 THERMAL STRESSES IN TURBINE ROTORS .................................2

3 TURBINE STARTING PROCEDURES ................................................2

3.1 Cold Start Procedure ............................................................................3

3.2 Hot Start Procedure ..............................................................................3

4 LOAD CHANGING RECOMMENDATIONS ......................................4

4.1 Load Changing-General .......................................................................4

4.2 Changing Load Using Sequential Valve and Single Valve Modes ......5

4.3 Changing Load Using Sliding Pressure and Sequential-Valve Modes

(Hybrid Mode)............................................................................................7

5 DETERMINATION OF ROTOR FATIGUE CAPACITY DEPLETION

....................................................................................................................7

Page 1 of 8


STARTING AND LOAD CHANGING RECOMMENDATIONS

1 OBJECTIVES The general objective in formulating starting and load changing recommendations is the

protection of turbine parts against thermal fatigue cracking caused by internal temperature

variations. The charts “Start Recommendations”, “Load Changing Recommendations”,

and “Cyclic Index for Loading and Unloading” provide guidance for selecting appropriate

starting and load-changing rates based on thermal stresses developed in the turbine rotor.

The rotor is identified as the most critical element with respect to thermal stress because

of its large diameter. The stationary parts, having smaller radial thickness and so

constructed as to allow unrestrained thermal expansion, are subjected to lower thermal

stresses than those developed in the rotor. Operating procedures designed to protect the

rotor from thermal fatigue cracking will also protect the stationary parts from this type of

failure.

The specific objective of these recommendations is to provide for the desired number of

cycles of general turbine operation before the appearance of fatigue cracking. Operating at

conditions which result in a less than desired number of cycles fatigue capacity will

accelerate the accumulation of thermal fatigue and result in the earlier initiation of cracks.

Rotor cracks, when developed, appear in fillets, radii, and blade-attachment grooves at the

rotor surface. Once initiated, cracks generally propagate slowly. Their removal by

machining in the early stages of development restores the fatigue capacity of the rotor.

The purpose of adhering to the recommendations for starting and load changing is to

maximize turbine availability by avoiding or minimizing corrective maintenance. The

turbine-generator unit may be operated in the AUTOMATIC TURBINE CONTROL

(ATC), OPERATOR AUTO or MANUAL mode of control. In the ATC mode, the unit

can be automatically controlled on the DEH control system from turning gear to

synchronous speed to full load. Whenever possible this mode should be used especially

during startups since it continuously monitors various turbine-generator parameters and

controls the turbine accordingly to maximize turbine availability. Further description of

the Automatic Turbine Control mode is given in a separate chapter. In the TURBINE

MANUAL and OPERATOR AUTO modes of control, the process is entirely under the

control of the turbine operator. The operator is urged to study the following explanatory

Page 2 of 8


material for an understanding of the intent of the recommendations and the use of the

operating charts.

2 THERMAL STRESSES IN TURBINE ROTORS A change in blade-path steam temperature will produce thermal stresses in the rotor

which persist as long as there is a difference between the surface and interior temperature

of the rotor body. Such a difference exists during and immediately following a rapid

change in surface temperature because of the time required for heat to flow from the

surface into the interior. The stress is proportional to the temperature difference and is

greatest at the rotor surface. It is called a transient stress because it ceases to exist when

the surface and interior temperatures have equalized.

A heating of the rotor surface followed by an equal cooling constitutes a thermal cycle

and imposes on the rotor a cycle of alternating stress. The rotor material has a limited

capacity for withstanding stress cycles. Cracks will ultimately develop after a number of

cycles which depends on the severity of the stress. The relationship between alternating

stress and cyclic capacity is a material property and it is possible to predict the number of

stress cycles necessary to initiate a rotor crack.

For a particular temperature change, the greatest thermal stress is developed when the

change is made instantaneously. The stress can be considerably reduced by accomplishing

the change over a period of time, thereby increasing the number of stress cycles available

before crack initiation, For large changes, the stress can be limited to any desired level by

choosing an appropriate time period to make the change.

3 TURBINE STARTING PROCEDURES The criterion for determining starting procedure is the temperature of the HP and/or IP

turbine rotor metal before admitting steam to the turbine.

COLD START procedure is to be followed when the initial temperature of either the

HP or IP rotor metal is less than 204℃.

HOT START procedure is to be followed when the initial temperatures of both the HP

and IP rotor metal are 204℃ or higher.

HP rotor metal temperature is measured by the inner cylinder metal base thermocouple.

Page 3 of 8


IP rotor metal temperature is measured by the IP turbine blade ring thermocouple. See

chapter “Turbine Steam and Metal Thermocouples”.

3.1 Cold Start Procedure

Steam is admitted to the turbine with a minimum of 56℃ superheat at the throttle valve

inlet, but not more than 427℃ total temperature. Throttle valve inlet temperature and

pressure conditions should be in the area shown on curve “Startup Steam Conditions”.

These steam conditions provide uniform heating and optimum differential expansion and

avoid thermal shocking of the steam chests when speed control is transferred from throttle

valves to governor valves.

The unit is accelerated to a speed within the rotor-warming soak speed range specified

on the chart “Turbine Speed Hold Recommendations”. The turbine is held at that speed

long enough to warm the HP-IP rotor bore(s) to at least the transition temperature (121 ℃)

before continuing to synchronous speed. And rotor-warming is not necessary for no-bore

rotor from thermal stress side.

Following the rotor-warming hold period, the turbine is accelerated to synchronous

speed, synchronized and initially loaded in accordance with the loading instructions.

3.2 Hot Start Procedure

Steam is admitted to the turbine with 56℃ minimum superheat. The curve “Startup

Steam Conditions” shows the throttle valve inlet temperature and pressure conditions that

should exist prior to transferring speed control from throttle valves to governor valves.

The time required for accelerating the turbine from turning gear to synchronous speed is

a function of the mismatch between the initial temperature of steam and metal. The

appropriate accelerating time is determined from the chart “Start Recommendations”.

To minimize the rolling time, the throttle steam conditions should be adjusted so that

the throttle temperature at 5% load throttle temperature and first stage steam temperature

that is within ±56℃ of the rotor metal temperature that existed prior to rolling. In this

case, the recommended acceleration time is only ten minutes. With good matching,

bringing the rotor to synchronous speed in zero time is theoretically possible from the

standpoint of thermal stresses, but ten minutes is selected as a minimum for practical

considerations.

When synchronous speed is attained, the turbine is synchronized and initially loaded as

Page 4 of 8


determined from the chart “Start Recommendations.”

4 LOAD CHANGING RECOMMENDATIONS

4.1 Load Changing-General Load changes are accompanied by changed in blade-path steam temperature. Thermal

stresses are developed in the rotor which depend on both the magnitude and the rate of

change of the load. There is no single rate of change that can be applied uniformly to all

turbine operations if the objective is to limit stress to the level corresponding to the

selected fatigue capacity. Small changes can be performed instantaneously when followed

by a stabilization period without exceeding the limitation, whereas large changes must be

performed less rapidly.

The greatest variation of steam temperature over the load range occurs at the first stage

of the HP turbine. The first stage steam temperature changes with load. The amount of

temperature change is dependent upon the mode of governor valve operation. The various

possible modes of changing load are: (1) “sequential-valve” mode where multiple

governor valves are sequenced to open or close in a determined order at either constant or

changing inlet throttle steam conditions: (2) “single valve" of “throttling” mode where a

group of governor valves open or close in unison to change the amount of valve flow

passage area and; (3) “sliding pressure” mode where a group of governor valves are fully

open or maintained at a constantly partially open position while inlet throttle pressure is

changed to vary the flow through the turbine.

The governor valves regulate the steam flow to separate nozzle chambers arranged

circumferentially to admit steam in a 360º full arc to the first stage blading when all the

valves are open. Thus, each governor valve feeds steam to a portion of the full 360º arc. In

the “sequential valve” mode, the governor valves, as they open and close in sequence,

feed steam through a changing circumferential admission arc to the blading. The size of

the arc passing steam can be expressed as a percent of full arc admission. In the “single

valve” mode, all the governor valves operate in unison to vary the flow by changing the

amount of valve opening while feeding steam to a full 360º arc of admission. In the

“sliding pressure” mode, the governor valves remain at a fixed opening and feed steam

through a constant arc or percent of admission.

Operating the turbine in the “single valve” mode subjects the control stage to more

Page 5 of 8


moderate loading at part load than operating in the “sequential valve” mode. It also

subjects this blading to higher temperatures, which is beneficial in regard to achieving

uniformity in the mechanical load distribution at the blade/rotor interface with time.

Therefore it is recommended that the turbine be operated as a “single valve” unit during

initial operation. If after that time the purchaser is satisfied that all station controls are set

correctly and that all systems are functioning properly, he should change the unit to a

proper mode of operation in accordance with the actual conditions.

“Sequential valve” operation is thermally a more efficient mode of operation at lower

loads than the “single valve” and “sliding pressure” modes. However, with the “sequential

valve” mode, first stage steam temperature changes the greatest amount as load is varied

and，therefore，requires a longer time to make load changes. Operating in the “sliding

pressure” mode, where all governor valves are maintained in the full open position and the

throttle pressure are varied, results in the smallest change in the first stage temperature and

thus permits faster load changing rates. However, the ability to operate with a “sliding

pressure” mode depends upon the boiler and its boiler-turbine control system.

First stage temperature change when varying load in the “single valve” mode is less

than that experienced using the “sequential valve” mode, but greater than the temperature

variation resulting from the above described “sliding pressure” operational mode. Load

changing charts are provided for the operators guidance for turbine operation over the

5-100% load range for these various modes. These charts permit the operator to select

load change rates corresponding to any desired number of available life cycles.

All load changes are assumed to take place from initially steady-state metal

temperatures at the first stage zone and to be accomplished at a uniform rate. Steady

turbine metal temperatures and steady differential expansion, casing expansion and rotor

position readings indicate that steady-state conditions exist. See operation sections

“Turbine Steam and Metal Thermocouples” and “Supervisory Instruments” concerning

the instrumentation that provides this information.

4.2 Changing Load Using Sequential Valve and Single Valve Modes Refer to the “Load Changing Recommendations” charts to determine the length of time

to change load and thereby determine a uniform load changing rate. Load changes at

lower loads are generally accompanied by changes in inlet steam pressure and temperature

both of which affect first stage temperature. Because of the variability of boiler

Page 6 of 8


characteristics at low loads, it is not possible for the turbine manufacturer to devise a

uniform rule for operation in the low load range. To select load changing rates consistent

with the 10,000 cycle recommendation or other selected cyclic life, the influence of inlet

steam conditions on first stage temperature must be considered. Figures 1 and 2 of the

chart “Load Changing Recommendations” provide the information necessary to

determining first stage temperature changes for any combination of load and inlet steam

conditions. The curves for “sequential valve” mode in Figure 2 are for a particular

minimum admission in which the governor valves are set to open in a definite sequence to

admit steam through the nozzles of first stage of blading in an arc great enough to prevent

overstressing the first stage blading. The curves for “single valve mode” are for 100%

admission where all governor valves open together.

Figure 2 determines the change in first stage steam temperature when changing load.

By projecting this temperature change to the selected cyclic index line in Figure 4, the

operator can determine the length of time to take in making the load change. The selected

time period applies to both increasing and decreasing loads.

It can be noted from Figure 4, that a load change resulting in an internal temperature

change of 70 ℃ or less be made instantaneously without exceeding the stress

corresponding to 10,000 cycles of fatigue capacity as indicated by the intersection of the

10,000 cycle line with the zero time axis. This does not imply that a series of load changes

can be made in a short period of time in increments or steps in which the first stage

temperature change is 70℃ or less. For example, if a 40% load increase causes a 70℃

change in first stage temperature, load should not be increased another 40% (also causing

a 70℃ rise) 15 minutes later. Steady-state temperature conditions would not be reached

in the 15 minutes period between load changes. The operator should instead determine the

time or rate to make the total load change (80% in the example) from the curves.

“Single valve” operation allows more rapid load changes than “sequential valve”

operation. This can be seen from Figure 2 by noting the narrower band of the first stage

steam temperature change across the load range for “single valve” compared to

“sequential valve” operation. If, during operation, the mode of operation is switched from

“sequential valve” to “single valve” using the DEH controls, the first stage steam

temperature will immediately increase by the difference in the levels of these two modes

shown on Figure 2.

Page 7 of 8


Refer to the “Governor Valve Management” content for further information on the

different modes of governor valve operation.

4.3 Changing Load Using Sliding Pressure and Sequential-Valve Modes

(Hybrid Mode) Refer to chart “Load Changing Recommendations (Fig.3)” to determine the length of

time and load changing rate to change load by sliding or ramping throttle pressure. Finger

3, while basically for sliding pressure operation, also contains curves for the “throttling”

and “sequential valve” mode of load changing, In the example shown on this chart, all

three modes of governor valve operation are used in increasing load from 5 to 100%. This

use of a mixture of modes is also referred to as using a “hybrid” mode of operation. The

throttling mode is used to increase load from the 5% level; the sliding pressure mode in

used to increase load while ramping throttle pressure from the minimum pressure to rated

pressure at a specific governor valve opening; and the sequential-valve mode is used to

further increase to 100% load at constant rated throttle pressure.

Figure 3 determines the first stage steam temperature change between the highest and

lowest temperatures occurring during the load changing. This temperature change is based

on the throttle temperature being constant during the load change. Therefore, this

temperature change between load levels must be corrected by using the temperature

change for any change in throttle temperature that occurs. By projecting this temperature

change in Figure 4 to the desired cycles to fatigues guideline, the operator can determine

the length of time to take in making the load.

Referring to Figure 3, the change in first stage temperature can be noted when operating

with the various modes of governor valve operation. It can be seen that the change in first

stage steam temperature is much greater than that experienced through the “hybrid" mode

if load was changed using the throttling mode followed by the sequential valve mode at

constant rated throttle pressure. The “hybrid” mode permits a faster load change.

5 DETERMINATION OF ROTOR FATIGUE CAPACITY

DEPLETION The various cyclic capacity lines of Figure 4 permit the assessment of fatigue

accumulation. For example, a change of 139℃ in one hour falls almost on the 5000 cycle

Page 8 of 8


line and therefore accounts for 1/5000 or 0.02 percent of the total fatigue capacity of the

rotor. One hundred cyclic repetitions of such a heating phase coupled with an equal and

opposite cooling phase would result in 100×0.02= 2% depletion of total fatigue capacity,

leaving 98% capacity available for other operation.

A cycle consists of both a heating phase and a cooling phase. Thus, the 10,000 cycle

line on Figure 4 represents 10,000 times the turbine first stage is heated held at steady load

until temperature equalization takes place, and then cooled at the same rate and amount as

load is increased and then decreased. If the unit is operated such that the unloading phase

is done at a DIFFERENT rate than the loading phase, the cyclic index can be determined

by using curves “Cyclic Index for Loading and Unloading at Different Rates" in

conjunction with Figure 4. This index can then be used to determine the depletion of the

total fatigue capacity.

As an example, if the unit is started where load is increased over an 80 minute period

during which the first stage steam temperature rises 144℃, Figure 4 indicates a 10,000

cycle index. If the unit is then shutdown at a rate where the first stage steam temperature

drops 144℃ in 30 minutes, Figure 4 indicates a 2000 cycle index. Letting the index

during the loading period = 10,000cycles and the index during the unloading period =

2000 cycles, enter the “Cyclic Index for Loading and Unloading at Different Rates”

curves to find the equivalent full cycle index = 3820 cycles. This type operation accounts

for 1/3820 or 0.026% of the total fatigue capacity of the rotor. Five such cyclic repetitions

in a year for 20 years results in 5×0.026×20=2.6% depletion of the total fatigue, leaving

97.4% capacity available for other operation cycles.

The example shows that occasional departures from the selected fatigue capacity can be

tolerated without serious consequence.

A suggestion for planning turbine operation is to perform the more frequent small load

changes at rates corresponding to a large number of available cycles. Less frequent major

load changes may be made more rapidly with lower cyclic capacity.

The user is urged to maintain a record of fatigue accumulation and to schedule

corrective maintenance for the rotor when the total accumulation approaches 100%.

Page 1 of 5


Compiled：Jiang Jianfei 2008.09Governor Valve Management (Single

Valve-Sequential Valve)

Checked：Yu Yan 2008.09


Countersign：He Xiaozhong 2008.09


GOVERNOR VALVE MANAGEMENT

(Single Valve-Sequential Valve)

This is a sub-mode associated with the Governor Valve Management (VM) Program. It

may be selected in OPER AUTO or TURBINE MANUAL, but if selected in TURBINE

MANUAL, transfer of the valve mode will not be initiated until OPER AUTO is

subsequently selected.

The function of this SINGLE VALVE-SEQ VALVE is to enable the operator to select

either the single valve or sequential valve mode of control for the Turbine-Generator unit

governor valves. Additional description of the various control modes is given in the

operation section entitled “Starting and Load-Changing Recommendations.” Control mode

selection is predicated on the resulting first stage discharge steam temperature of the

turbine since this temperature will vary according to the control mode used. The operator

can shift valve modes at any time during operation of the unit. However, he should be

aware that an instantaneous temperature change will occur at the moment of transfer. At

low loads the first stage temperature will be approximately 42℃～56℃ higher using the

single valve mode than the sequential valve mode. This difference will decrease to zero

degrees at the “valves wide open” condition where the modes are identical.

By proper selection and use of valve control modes, the operator can minimize the first

stage temperature change during various stages of operation. This results in minimizing

thermal stresses in the HP turbine element. The following guidelines can be applied to the

various stages of operation.

Page 2 of 5


1. ROLLING AND MINIMUM LOADING

Generally the single-valve mode should be used during the rolling to speed,

synchronization and minimum load hold periods. This mode provides steam through all the

control valves and nozzle chambers resulting in steam flowing in a 360°full arc of

admission to the control stage blading. Thus, these parts heat up and expand more

uniformly. There may be occasions when sequential valve control, depending upon existing

throttle steam conditions, will provide a better match of first stage steam temperature with

the metal temperature and permit faster startups. The operator may determine this by

referring to the “Hot Start Recommendations for Rolling and Minimum Load” charts.

The single valve mode should definitely be used during the initial break-in period of

operation. During this period, it is not uncommon for abnormal pressure and temperature

excursions to occur until all station controls are set correctly and all systems are

functioning properly. In order to assure the maximum reliability of the turbine-generator

unit, it is desirable to minimize the effect of such abnormal conditions on the turbine.

Operating the turbine in the full arc admission mode subjects the control stage to more

moderate loading at part load than operating in the partial are admission mode. It also

subjects this blading to higher temperatures, which is beneficial in regard to achieving

uniformity in the mechanical load distribution at the blade/rotor interface with time.

Therefore, it is recommended that the turbine be operated as a full arc admission unit

during initial operation If, after that time, the purchaser is satisfied that all station controls

are set correctly and that all systems are functioning properly, he should choose a proper

mode of operation.

2. LOAD CHANGING

During the loading period, if load is to be changed quickly or load level is to be changed

frequently, the single valve mode should be used to minimize temperature changes in the

HP turbine and thereby minimize thermal stresses. The sequential valve mode should be

used to obtain higher thermal efficiency when operating below rated load for extended

period.

Page 3 of 5


2.1 Increasing Load

If the unit is on single valve control and it is desired to increase load as quickly as

possible and hold load at the higher level for a period of time in the more efficient

sequential valve mode, the transfer from single valve to sequential valve control should be

made immediately after reaching the higher load level. This procedure will keep the

temperature change in the rotor interior to a minimum. This can be confirmed by observing

Chart “Load Changing Recommendation” and following the changes in first stage steam

temperature that occur. It is assumed that steady state conditions exist when the internal

rotor temperature is the same as the surface temperature before increasing load. During the

load increase using the single valve mode, the first stage steam temperature increases from

the low load single valve level to the high load single valve level. The internal rotor

temperatures will increase at a slower rate and lag behind the surface temperature. During

the transfer to the sequential valve mode, the first stage steam temperature decreases to the

sequential valve level corresponding to this load. The lagging internal temperature should

more closely match the steam temperature at the surface at the new load level. If the

transfer to the sequential valve mode was made before increasing load, the first stage steam

temperature would decrease to the sequential valve level driving the internal rotor

temperatures downward. The steam and rotor surface metal temperatures would then

increase from the lower level to the sequential-valve level when load is increased to the

higher load. Thus, the internal rotor temperature cycling would be greater if transfer to the

sequential valve mode was done at the low load before increasing load.

2.2 Decreasing Load

If the unit has been operating in single valve control for a period and it is desirable to

reduce load quickly to a load which will be held for a long period, the transfer from single

valve to sequential valve control should be made after first stage steam and metal

temperatures have reached steady state conditions at the lower load. Refer to the decreasing

load example in “Load Changing Recommendation”. Delay in switching modes will permit

the internal rotor temperature to decrease to the low load surface temperature level before

the surface temperature decreases further along with the rotor internal temperatures after

switching. If operation at low load is to be of short duration and to be followed by a rapid

Page 4 of 5


return to high load, stay in the single valve mode to minimize HP turbine cooling.

2.3 Sliding Pressure and Hybrid Operation Load Changing

If boiler operation permits varying throttle pressure to change load then the “sliding

pressure” mode can be used to permit fast load changing. The operator may place the

governor valves in the sequential valve mode and hold the governor valve opening constant

while throttle pressure is ramped to change load. A “hybrid” sliding pressure mode can be

used to permit fast loading changing and provide high thermal efficiency at below rated

load. The “hybrid” operation involves sliding or ramping throttle pressure at a fixed

governor valve setting and obtaining further load changes in the sequential valve mode by

changing governor valve opening at fixed throttle pressures. In order to maintain a fixed

valve position during the sliding pressure mode, the operator should reset the throttle

pressure correction in the valve management program and remove the MW and impulse

pressure feedback loops from service.

3. SHUTTING DOWN

The governor valve mode to use in a planned shutdown is predicated on the desired

quickness to remove load, the expected length of the shutdown, and the subsequent

conditions to be encountered on the return to operation. The load is to be reduced

according to the “Load Changing Recommendations”. Shutting down using the single

valve mode can be done at a more rapid rate for a given HP rotor thermal stress and

provides more uniform temperature reduction in the first stage zone. It will also result in

higher first stage metal temperatures following tripping of the unit. This higher metal

temperature may permit a faster restart and return to load conditions depending on startup

steam conditions and length of shutdown. This condition could be encountered on a unit

being operated with cyclic duty where the unit is shutdown for a few hours during off-peak

hours and returned quickly to load levels existing prior to shutdown.

The sequential valve mode can be used during a controlled shutdown in order to cool the

HP turbine to a lower lever than with single valve control. This is a benefit if the shutdown

is for maintenance on the HP turbine since while on turning gear cool down will begin at a

lower level and be shortened.

Page 5 of 5


4. CONTROL MODE TRANSFER

Assuming that the turbine is operating SINGLE VALVE, this operating mode will be

indicated on LCD. Subsequently, the operator may transfer to SEQUENTIAL VALVE

operation by selected on LCD. Transfer from one mode to the other requires several

minutes. After completion of the transfer, the operating mode of SEQ VALVE will be

indicated on LCD. The procedure for switching from SEQUENTLAL VALVE to SINGLE

VALVE operation is similar.

Page 1 of 5


Compiled：Yu Yan 2008.09Preliminary Checks and Operations Checked：Zhang Xiaoxia 2008.09




PRELIMINARY CHECKS AND OPERATIONS

1. Energize the electronic governor at least two hours before admitting steam into the

turbine.

2. Turn on supervisory instruments. Check that they are recording normally.

3. Start oil vapor extractors (oil reservoir and generator loop seal tank). Loop seal tank

extractor should be operated continuously when hydrogen gas pressure is maintained in the

generator.

4. Place generator seal oil unit and generator hydrogen supply system in normal operating

condition. (See Generator Instruction Book)

5. Check lube oil reservoir level, if too low, an alarm will indicate this condition. Restore

to normal with oil pump running.

5.1 Oil temperature 10℃ minimum before starting oil pumps.

5.2 Bearing oil discharge temperature 21℃ minimum before placing unit on turning gear.

6. Start ac auxiliary oil pumps. Establish 0.07-0.1MPa (g) bearing oil pressure. Check

bearing thermometer and thermocouple readings. This pump's starting switch is interlocked

with the seal oil backup pump HP startup oil pump) which will start at the same time and

establish sufficient pressure to enable the overspeed trip device to be latched.

CAUTION

Before the initial starting of the Seal oil Backup pump（HP startup oil pump), ensure

that the pump is filled with dean oil. Starting or running a dry pump will cause

galling, seizing or destructive wear between gears, side plates and pump body. Also

ensure that the shutoff valve in the vent line between this pump and the top of

reservoir is locked open.

Page 2 of 5


7. Turn the dc emergency oil pump motor control switch to the AUTO position.

8. For units so equipped start the hydraulic bearing lift system by turning the selector

switch to the AUTO position. Refer to the “Hydraulic Bearing Lift System” content for

additional operation information.

9. Make certain that cooling water to the oil coolers is shut off.

10. Place the turning gear control switch in the AUTO position. Sufficient bearing lift oil

pressure must be established before the turning gear will operate. Pressure switches prevent

the turning gear motor from starting until bearing oil pressure has reached

0.021~0.0345MPa(g) and bearing lift oil pressure has reached 5.512MPa(g).

11. Observe the eccentricity indicator to assertion that the rotor is straight. Before starting

the turbine the rotor-eccentricity should not exceed 0.076mm double amplitude. For the

original startup and subsequent startups after major overhauls, shaft outages should be

measured at each bearing by inserting a truth (dial) indicator at each bearing oil ring. The

movement on these indicators should be less than 0.0254mm before the turbine is started.

12. Establish water circulation through the main condenser.

13. Start the condensate pumps and establish flow through the gland condenser.

14. Turn on air supply to the desuperheater control valves.

15. Turn on air supply to the gland steam control (regulator) valves. (Shutoff and bypass

valves must be closed.)

16. After ensuring that the steam lines are free of water (see “Water in the Turbine”

section) and that the gland steam contains not less than 14℃ superheat open the shutoff

valves in the following sequence:

a. Spillover

b. Cold Reheat Supply

c. Auxiliary Supply (if applicable)

d. High Pressure Supply

The bypass valves should remain closed.

17. Just prior to opening the auxiliary (or HP) supply shut-off valve start the gland

condenser exhauster. Make sure there is a slight vacuum at each turbine gland. Also be sure

turbine cylinder drains are open prior to pressurizing the gland steam header.

18. Steam pressure will be established in the gland steam header when the auxiliary (or HP)

Page 3 of 5


supply shutoff valve is opened. A check valve in the cold reheat steam supply line prevents

steam from entering the turbine cylinders.

19. Maintain temperature difference between gland steam and metal to a minimum (see

chart “Gland Sealing Steam Temperature Recommendations”).

20. Close the vacuum breaker valve, start the air removal equipment and establish as high

a vacuum as possible in the main condenser.

21. Make certain all the turbine main steam, hot reheat, cold reheat, and extraction line

drain valves are open as soon as vacuum has been established on the condenser. Operation

of the turbine drain valves is normally done automatically, however, should it be necessary

to manually control the drain valves, see “Drain Valves” in the section “Operating Limits

and Precautions.” And refer to the “Steam, Drain and Gland Piping Diagram” for drain

locations.

22. While on turning gear, check the operation of the bearing oil pumps and pressure

switches by turning the ac oil pump switch from the AUTO to the stop position and

holding it there. The dc oil pump should start. Visually check the pump discharge gauges

mounted on the reservoir to assure that pressure has been established. The rotor may trip

off the turning gear momentarily. Turn the ac pump to the AUTO position. The ac pump

should not start if the dc pump is operating satisfactorily. Turn the dc pump switch to the

STOP position and hold. The ac pump should now start. After the ac pump starts, release

dc pump control switch and it should automatically return to the AUTO position. Make

certain that all pump switches are in the AUTO position before proceeding with the startup.

NOTE

The switches controlling each of these pumps will start the pump on falling pressure

but will not stop the pump on rising pressure. To stop the pump, after the bearing oil

pressure has risen above the point at which the switch doses, it is necessary to turn

the switch from the AUTO to the STOP position. The pump will stop and the switch

will return to the AUTO position when released, thus leaving the pump under control

of its pressure switch in case of a drop in pressure.

23. The operator should not depress the LATCH push button preparatory to opening the

reheat stop and interceptor valves until arc-check is made to determine that ALL drain

valves are open.

24. Observe the bearing oil pressure and insure that the pressure is within 0.07-0.1MPa (g)

Page 4 of 5


range.

25. Start the EH fluid supply system in the following steps:

NOTE

The specific instructions which are outlined in the content “Care, Handling and

Application of Control System Fluid” are to be followed when adding fluid to the

system as well as initial charging of the fluid system. Only fluids meeting military

specification MIL-H-19457B may be used.

25.1 Check reservoir fluid level.

25.2 Check fluid temperature which should not be less than 10℃ before the system is

placed in operation. Prolonged operating with fluid temperature below 21℃ is not

recommended. See “the DEH fluid supply system describing” for additional operating

instructions.

25.3 Open suction valves for both pumps and start the No. 1 fluid pump. (Positive means

should be provided to insure that these valves are open at all times during operation of the

turbine except when intentionally closed during maintenance periods.) The slight noise

which may be experienced when starting with low fluid temperatures will disappear as the

fluid approaches the normal operating temperature range. Place the No. 2 fluid pump on

AUTO control.

25.4 When the fluid temperature reaches 43℃,adjust the cooling water flow to the heat

exchangers to maintain a system fluid operating temperature of 43℃-54℃.

25.5 The bypass valve to the fuller's earth filters should be fully closed.

25.6 When the bulk fluid reaches normal operating temperature range, check operation of

the low fluid pressure switch by opening the manually-operated drain test valve. After

several minutes operation, shut down the No. 2 pump and place the pump switch on AUTO

control. With accumulators and fluid lines fully charged, the fluid system is now ready for

normal operation.

PRECAUTIONS AND RECOMMENDATIONS

1. During operation, note the pump loading and unloading cycle. An abnormal change

indicates excessive high pressure fluids leakage either in the line or through the component,

or loss of gas charge in accumulators. Excessive pump wear will reflect a gradual change.

Page 5 of 5


2. Correct any fluid leaks immediately. This is of utmost importance. Fluid leaks may

create loss of pressure.

3. Maintain a record of filter maintenance. Change the servo actuator filters at least once

a year. Change the pump discharge filters when the pressure drop is excessive as indicated

by the differential pressure switches. Keep the filters in sealed containers until ready to

install.

4. This is a closed system requiring a high degree of system cleanliness. A thorough

understanding of the content covering the fluid control system and the care and handling of

the system fluid will contribute much to trouble free operation.

Page 1 of 2


Compiled：Tang Jun 2008.09Starting Procedure before Admitting Steam Checked：Wang Zurong 2008.09

Countersign：

Countersign：


Starting Procedure before Admitting Steam

OPERATOR AUTO is the turbine generator's primary control mode. Except for

contingency operation, the unit should always be in this mode or in a remote automatic

mode if the unit is so equipped.

Before latching the unit, the turbine operator should see that the LCD is displaying

normal conditions.

CAUTION

During turbine operation do not operate portable radio equipment (other than

sound powered telephones) near the DEH controller if the controller's cabinet doors

are open, a 5 watt transmitter can cause a 10 to 15% change in governor valve

position unless the cabinet doors are closed.

When the preliminary checks and operations have been satisfactorily completed, proceed

as follows:

1. Push OPER AUTO.

2. Check VALVE POSITION LIMIT DISPLAY Read present valve position limit set

point in the LCD, SHOULD BE ZERO.

3. Push LATCH and hold for two seconds. When the turbine is latched, the TURBINE

TRIPPED status lamp will go off and the TURBINE LATCHED status lamp will light.

4. Check the Valve Test Page on the LCD sure that RSV open, IV open, GV closed and

TV closed.

5. Push VPL RAISE and hold until the value reaches 120% and the governor valves are

wide open (100% position).

6. Trip the throttle, governor, reheat stop and interceptor valves with the remote trip push

button or by operating the hand trip lever on the governor pedestal to activate over-speed

Page 2 of 2


trip mechanism. Be sure that all valves close freely.

7. RELATCH the unit as described in step 3 above and then repeat steps 4 and 5.

7.1 When step 5 has been repeated, the governor, reheat stop and interceptor valves

will be fully OPEN and the throttle valves will be fully CLOSED.

8. TESTING THE OVERSPEED PROTECTION CONTROLLER (OPC).

8.1 Push “OPC TEST” button in the “MANUAL PANEL”. The GV and IV should

close rapidly (within two seconds). The power-assisted non-return valves (PANRV) will

also close.

8.2 Push the “NORMAL” button. The GV, IV and PANRV should reopen.

8.3 This test should be made each time the turbine is started from turning gear.

9. TESTING THE ELECTRICAL MONITORING AND TRIPPING FUNCTIONS

OF THE EMERGENCY TRIP SYSTEM.

9.1 The test procedure is fully described in the content “Emergency Trip System”. The

test may be conducted at the operator's convenience either on the line or off the line.

9.2 It is recommended that this test be made on every start-up and monthly thereafter.

10 The turbine is now ready to be rolled with steam. Refer to the section “Starting

and Load Changing Recommendations”. The next section is for a “Cold Start”. If it has

been determined that “Hot Start” procedure may be used, skip the next section and turn to

section “Start Rolling with Steam”.


Compiled：Yu Yan 2008.09 Start Up With Bypass Off Checked：Zhang Xiaoxia 2008.09


Tang Jun, Zhang D.M

2008.09


Contents START UP WITH BYPASS OFF......................................................................................1

1 COLD START-ROLLING WITH STEAM ...........................................................1

1.1 STATUS BEFORE ADMITTING STEAM.........................................................1

1.2 ROLLING WITH STEAM...................................................................................2

1.3 AVOIDING LP TURBINE BLADE RESONANT SPEEDS DURING SPEED

HOLDS .........................................................................................................................2

1.4 COLD START ROTOR-WARMING (HEAT SOAK) PROCEDURE.............2

1.5 TRANSFERRING CONTROL FROM THROTTLE TO GOVERNOR

VALVES........................................................................................................................3

1.6 SYNCHRONIZING AND INITIAL LOADING ................................................5

1.7 OVERSPEED TRIP TEST ...................................................................................6

2 HOT START-ROLLING WITH STEAM ..............................................................8

2.1 STATUS BEFORE ADMITTING STEAM.........................................................8

2.2 ROLLING WITH STEAM...................................................................................9

2.3 AVOIDING LP TURBINE BIADE RESONANT SPEEDS DURING SPEED

HOLDS .........................................................................................................................9

2.4 TRANSFERRING CONTROL FROM THROTTLE TO GOVERNOR

VALVES......................................................................................................................10

2.5 SYNCHRONIZING AND INITIAL LOADING .............................................. 11

Page 1 of 13


START UP WITH BYPASS OFF

1 COLD START-ROLLING WITH STEAM Refer to the section “Starting and Load Changing Recommendations” to determine

when to use cold start procedure. And determine when to use start up with bypass off

procedure according to operating requirements.

The instructions below assume that the operator is thoroughly familiar with the

information about “DEH System”

1.1 STATUS BEFORE ADMITTING STEAM 1. Turbine is rolling on turning gear.

2. Throttle valves are fully closed.

3. Governor valves, reheat stop valves and interceptor valves are fully open.

4. Throttle steam conditions are in accordance with the chart “Start-up Steam Conditions

at Turbine Throttle”.

5. Vacuum breaker valve(s) is closed.

6. All turbine drain valves are open.

7. Back pressure (absolute) is as low as possible, and not greater than the combination of

reheat steam temperature and LP exhaust pressure limits given by the curve for “Full

Speed-No Load” on chart “ No-Load and Light Load Operation Guide for Reheat

Turbines” (refer to index). The limits for reheat steam temperature and LP exhaust

pressure at 5% Maximum Guaranteed Load are also shown on this chart.

CAUTION

The maximum allowable back pressure for on-line operation is 0.0186MPa at

loads above 10% of rated load up to 100%load. At lower loads, and at the full (rated)

speed-no load condition, substantially lower back pressure are required. Such

operation should be in accordance with the chart, “No Load and Light Load

Operation Guide.” Failure to observe specified back pressure limits may result in

blade failures or rubbing between rotating and stationary turbine parts with serious

damage to turbine components.

CAUTION

The operator must be certain that water is available to the exhaust hood spray

control valve whenever the turbine is rolling over 3 r/min.

Page 2 of 13


8. Turbine controls and bypass system controls must both be in BYPASS OFF mode.

1.2 ROLLING WITH STEAM 1. After performing the operations described in the section “Starting Procedure before

Admitting Steam,” accelerate the turbine at 100 r/min. to a target speed of 600 r/min.

2. When the operator pushes the GO button, the DEH controller will open the throttle

valve pilot valves and, after a few seconds, the turbine speed will begin to increase until it

reaches 600 r/min. The turning gear will automatically disengage as described in the

content “Rotor Turning Gear.”

WARNING

To avoid injury, keep clear of turning gear operating lever which is moved to

“DISENGAGE” position by air pressure.

3. Keep the turbine rolling at 600 r/min long enough to permit a check of all turbine

supervisory instruments to insure that conditions are satisfactory. The eccentricity monitor

should show a steady value of less than 0.076mm before the turbine speed is increased to

above 600 r/min. Monitor vibration at speeds above 600 r/min. A vibration reading of not

more than 0.076mm is considered satisfactory (see “Supervisory Instruments” in the

section “Operating Limits and Precautions”)

1.3 AVOIDING LP TURBINE BLADE RESONANT SPEEDS DURING

SPEED HOLDS 1. If a speed hold is required at any time during the acceleration of the turbine, push

HOLD. The acceleration will stop and the turbine will continue to roll at the held speed.

CAUTION

If the contingency requires a speed hold, refer to the chart “Turbine Speed Hold

Recommendations” to be sure that the hold is not in a resonant speed range. If it is,

decrease the speed below the resonant range.

2. To proceed with the acceleration routine after a hold period, push Go.

1.4 COLD START ROTOR-WARMING (HEAT SOAK) PROCEDURE CAUTION

Page 3 of 13


On the initial start-up not utilized the ATC program (if so equipped) during the heat

soak period. Use the curve “Cold Start Rotor-Warming Procedure”.

1. Enter a target speed on CRT within the “rotor-warming soak speed range” shown on the

chart “Turbine Speed Hold Recommendations.”

2. Push Go. When the selected target speed is reached, hold the turbine at that speed for a

heat soak period determined from the curve “Cold start rotor-Warming Procedure.”

Begin the heat soak period after the reheat stop valve inlet steam temperature exceeds 260

℃. Rotor-Warming is not needed for no-bore rotor.

CAUTION

It is important that this time period not be reduced in an emergency situation when

there may be a strong desire by the operator to put the unit on the line in a shorter

time.

3. While the rotor heat soak is in progress, limit the throttle inlet steam temperature to 427

℃ maximum and maintain the reheat inlet steam temperature above 260℃. Refer to the

chart “Start-up Steam Conditions at Turbine Throttle” to determine the throttle steam

conditions that should exist before transferring from throttle to governor valve control.

4. Maintain the turbine steam and metal thermocouple limits and the turbine supervisory

instrument limits throughout the operation of the turbine.

1.5 TRANSFERRING CONTROL FROM THROTTLE TO

GOVERNOR VALVES 1. Accelerate the turbine at 100 r/min to the “inlet valve transfer speed” shown on the

chart “Turbine Speed Hold Recommendations.” Before transferring control from the

throttle valves to the governor valves, verify that the steam chest inner wall temperature is

at least equal to saturation temperature corresponding to the throttle pressure. The chart

“Start-up Steam Conditions at Turbine Throttle” shows the desirable relationship between

throttle valve inlet pressure and temperature that should prevail if the steam chest

temperature is to reach the desired value.

NOTE

If the temperature measured by the steam chest shallow thermocouple (T1) is lower

than the temperature measured by the steam chest deep thermocouple (T2), the

Page 4 of 13


temperature at the inner surface of the steam chest (Ts,) will be higher than that

indicated by the deep thermocouple. The temperature at the inner surface of the

steam chest (Ts,) can then be calculated by this formula:

Ts=T1 + 1.36(T2 - T1)

2. When the unit reaches transfer speed and step 1 is verified. Transfer control of the

turbine from throttle valves to governor valves as follows:

2.1 Push “TV-GV TRANSFER”

2.2 Observe transfer from throttle to governor valve control by TV and GV position

indicating on the CRT.

2.3 When the transfer is completed, the TV full open, the turbine is now under control of

the governor valves.

3. Observe the SINGLE VALVE &. SEQUENTIAL VALVE status on CRT, If it is not

in the desired mode of valve control. Select the desired mode on CRT. For more

information about the modes of valve control refer to the sections “Governor Valve

Management” and “Starting and Load Changing Recommendations.”

4. Accelerate the turbine to 3000 r/min at 100 r/min.

5. It is recommended as good practice to trip the turbine after full speed is reached to be

sure that the overspeed trip mechanism and steam valves are functioning normally. Push

the “trip” push button in the turbine control room or operate the overspeed trip mechanism

with the hand trip lever on the governor pedestal. Be sure that all main and reheat steam

valves close fully. Following the trip, the values in the REFERENCE and TARGET will

reset to zero.

6. If, for any reason, the control system switches to TURBINE MANUAL after the trip,

reset it to OPER AUTO.

7. To relatch the turbine “on the fly”, proceed as follows:

7.1 Push LATCH continuously for a few seconds. The values in REFERENCE and

TARGET will increase to the actual turbine speed and a speed hold will be instituted

(assuming that the control system is in OPER AUTO).

7.2 Increase the acceleration value from 100r/min to 200-250 r/min.

7.3 Enter the transfer speed value (assuming the turbine speed has decreased to below this

value) into the TARGET.

7.4 Push GO. When the unit reaches transfer speed, transfer from TV to GV as previously

Page 5 of 13


described.

7.5 Accelerate the unit to 3000 r/min at 200-250r/min.

8. Before synchronizing, test the “Overspeed Trip Mechanism Oil Pressure Check

Device”.

9. Shut off the ac bearing oil pump and the seal oil backup pump and set on AUTO

control. Turn on the water to the oil coolers, when required, and regulate the flow of water

to maintain the temperature of the oil leaving the hottest bearing at less than 71 ℃.

10. Turn on water to the generator hydrogen coolers following the specific instructions

outlined in the Generator Instruction Book.

11. Maintain the “no load” limits expressed by the chart “No Load and Light Load

Operation Guide”. Refer to “Low Pressure Exhaust and Exhaust Hood Sprays” in the

section “Operating Limits and Precautions”.

1.6 SYNCHRONIZING AND INITIAL LOADING 1. Synchronize and promptly load to 5% of rated capacity. The time that hold at 5% load

refer to Chart “Star Recommendations for Rolling & Minimum Load”.

NOTE

When load is initially applied, the OPC MONITOR light may be lit. This is normal

and cannot be avoided due to the failure detection scheme for a zero based signal. As

soon as the generator in initially loaded to at least 5% load, this monitor light should

go out. If the light remains lit when load has been increased above 10% of rated load,

the turbine has lost one of its main overspeed protection devices. Maintenance

Personnel should take the following action immediately.

a. Check MW transducer.

b. Check OPC pressure transducer.

c. Check OPC speed pickups and speed signals.

If an automatic synchronizer is to be used to place the unit in the line, the turbine must be

on speed control at a speed of 3000r/min ±50r/min.

The control of the turbine speed may then be transferred to the automatic synchronizer by

depressing the AUTO SYNC push button. This push button will light and OPER AUTO

will go off. The automatic synchronizer now has access to the DEH speed reference by

means of Raise/Lower contact closure inputs to bring the turbine-generator to

Page 6 of 13


synchronous speed and to synchronize the unit. After the main generator breaker is closed,

the AUTO SYNC push button light will go off and control of the unit will automatically

return to the OPERATOR AUTO control mode.

2. With the closing of the generator breaker the REFERENCE and TARGET windows

will display a value in megawatts which will automatically position the governor valves at

a position equivalent to 5% load at the existing throttle pressure.

3. Push IMP IN to place the impulse chamber pressure feedback loop in service. (When

in the IMP OUT mode, the megawatt REFERENCE value displayed does not match the

actual load displayed by the megawatt meter on the monitor panel. When in the IMP in

mode the megawatt REFERENCE value displayed will be reset to a new value which will

approximately match the actual megawatts generated.)

4. Push MW IN to place the megawatt feedback loop in service. (When in the MW IN

mode, the megawatt REFERENCE value displayed will be trimmed to accurately match

the megawatts generated.)

4.1 Transferring between IMP IN and OUT and MW IN and MW OUT is bumpless and

does not affect the load level.

4.2 Transferring from MW OUT to MW IN to MW OUT while the REFERENCE is

counting towards the TARGET results in halting the REFERENCE count and makes the

TARGET equal to the REFERENCE.

4.3 Similar action will result when transferring from IMP IN to IMP OUT or vice versa

with the megawatt feedback loop out of service (MW OUT).

1.7 OVERSPEED TRIP TEST When starting the turbine initially, after any major overhaul, or after work is performed

on the governor pedestal which may affect the overspeed trip setting, the turbine should be

overspeeded to insure that the overspeed trip mechanism will operate. The overspeed test

should then be made periodically every six months, unless sooner required by another

such occurrence.

The test must be performed using the parameters shown on the chart “No-Load and

Light-Load Operation Guide” for reheat steam temperature and back pressure. If the test

takes longer than fifteen minutes, the operator must exercise extreme care to insure safe

operating conditions are not exceeded.

Page 7 of 13


CAUTION

During this test, have an “operator stand by the hand lever ready to trip the unit by

hand instantly.

1. After synchronizing and applying initial 5% load, increase load to 10% of rated

capacity. Hold at this load for at least four hours immediately before overspeeding the

turbine in order to test the overspeed trip mechanism.

CAUTION

When this test is performed on a periodic basis after normal operation of the turbine

at load, the load should be removed in accordance with the chart “Load Changing

Recommendations”. Do not hold 10% load if the turbine has already been on the line

and carrying at least 10% load for four hours prior to the test.

2. Proceed with overspeed trip test as follows:

2.1 Remove the load at a normal rate not exceeding that specified on the chart “Load

Changing Recommendations.”

2.2 Open the line breakers. The values displayed in the TARGET and REFERENCE

display will change from load (in megawatts) to speed (in r/min).

2.3 To enable the turbine to overspeed:

a) Deactivate the overspeed protection controller by turning the OPC key switch (on the

OPERATOR control panel) to the OVERSPEEED DISABLE position.

b) Deactivate the electrical emergency trip system by turning the OVERSPEED TRIP

key switch (on the emergency trip test panel) to the INHIBIT position.

2.4 Accelerate the unit at 50r/min to 2% below the overspeed trip setting.

2.5 Enter a speed of 2% above the overspeed trip setting and accelerate the unit toward

this speed.

2.6 Observe the turbine speed meter and record the speed at which the unit trips. Be

prepared to trip the unit by hand.

3. If the speed at which the unit trips is satisfactory and it is desired to continue

operation relatch the unit. If the trip speed is not satisfactory, adjust the trip weight before

returning the unit to service.

4. The values displayed in the REFERENCE and TARGET will increase from 0000

until they match the speed of the turbine. The REFERENCE and TARGET displays will

then stop counting and the turbine speed will be controlled by the throttle valves.

Page 8 of 13


5. If it is desired to continue with the start-up, relatch the unit “on the fly” and proceed

as described above in the subsection “Transferring Control from Throttle to Governor

Valves,” item 7.

2 HOT START-ROLLING WITH STEAM Refer to the section" Starting and Load Changing Recommendation" to determine when

to use hot start procedure. And determine when to use start up with bypass off procedure

according to operating requirements.

The instructions below assume that the operator is thoroughly familiar with the

information in the content “DEH system”.

2.1 STATUS BEFORE ADMITTING STEAM 1. Turbine is rolling on turning gear.

2. Throttle valves are fully closed.

3. Governor valves, reheat stop valves are fully open and either interceptor valves are

fully open for “Bypass Off” mode.

4. Throttle steam conditions are in accordance with the chart “Start Recommendations”.

5. Vacuum breaker valve(s)is closed.

6. All turbine drain valves are open.

7. Back pressure (absolute) is as low as possible, but not greater than combination of

reheat steam temperature and LP exhaust pressure limits given by the curve for “Full

Speed-No Load” on Chart “No-Load and Light Load Operation Guide for Reheat

Turbines” (refer to index). The limits for reheat steam temperature and LP exhaust

pressure at 5% Maximum Guaranteed Load are also shown on this chart.

CAUTION

The maximum allowable back pressure for on-line operation is 0.0186Mpa (absolute)

at loads above 10% of rated load up to 100% load. At lower loads, and at the full

(rated) speed-no load condition, substantially lower back pressures are required.

Such operation should be in accordance with the chart, “No Load and Light Load

Operation Guide.” Failure to observe specified back pressure limits may result in

blade failures or rubbing between rotating and stationary turbine parts with serious

damage to turbine components.

CAUTION

Page 9 of 13


The operator must be certain that water is available to the exhaust hood spray

control valve whenever the turbine is rolling over 3 r/min.

2.2 ROLLING WITH STEAM 1. After performing the operations described in the section “Starting procedure Before

Admitting Steam”, determine the accelerate value required based on throttle inlet steam

conditions before admitting steam to the turbine. Use the chart “Hot Start

Recommendations.”

2. Accelerate the turbine at the selected value to a target speed of 600r/min. The DEH

system content gives step by step instructions for entering values of acceleration

3. When the operator pushes the GO button, the DEH controller will open the throttle

valve pilot valves and, after few seconds, the turbine speed will begin to increase until it

reaches 600 r/min. The turning gear will automatically disengage as described in the

content “Rotor Turning Gear.”

WARNING

To avoid injury, keep clear of turning gear operating lever which is moved to

“DISENGAGED” position by air pressure.

4. Keep the turbine rolling at 600 r/min long enough to permit a check of all turbine

supervisory instruments to insure that conditions are satisfactory. The eccentricity monitor

should show a steady value of less than 0.076mm before the speed is increased to above

600 r/min. Monitor vibration at speeds above 600 r/min. A vibration reading of not more

than 0.076mm is considered satisfactory (see “Supervisory Instruments” in the section

“Operating Limits and Precautions”).

2.3 AVOIDING LP TURBINE BIADE RESONANT SPEEDS DURING

SPEED HOLDS 1. If a speed hold is required at any time during the acceleration of the turbine, push

HOLD. The acceleration will stop and the turbine will continue to roll at the held speed.

CAUTION

If the contingency requires a speed hold, refer to the chart “Turbine Speed Hold

Recommendations” to be sure that the hold is not in a resonant speed range. If it is,

Page 10 of 13


decrease the speed below the resonant range.

2. To proceed with the acceleration routine after a hold period, push GO.

2.4 TRANSFERRING CONTROL FROM THROTTLE TO

GOVERNOR VALVES 1. Accelerate the turbine at the previously selected rate to “inlet valve transfer speed”

shown on the chart “Turbine Speed Hold Recommendations.” Before transferring control

from the throttle valves to the governor valves, verify that the steam chest inner wall

temperature is at least equal to saturation temperature corresponding to the throttle

pressure. The chart “Start-up Steam Conditions at Turbine Throttle” shows the desirable

relationship between throttle valve inlet pressure and temperature that should prevail if the

steam chest temperature is to reach the desired value.

NOTE

If the temperature measured by the steam chest shallow thermocouple (T1) is lower

than the temperature measured by the steam chest deep thermocouple (T2), the

temperature at the inner surface of the steam chest (Ts) will be higher than that

indicated by the deep thermocouple. The temperature at the inner surface of the

steam chest (Ts) can then be calculated by this formula:

Ts = T1 + 1.36 (T2- T1)

2. When the unit reaches transfer speed and step 1 is verified, transfer control of the

turbine from throttle valves to governor valves as follows:

2.1 Push “TV-GV transfer”.

2.2 Observe transfer from throttle to governor valve control by TV and GV POSTION

Indicating on the CRT.

2.3 When transfer is complete, TV fully open and the turbine is now under control of the

governor valves.

3. Observe the SINGLE VALVE / SEQUENTIAL VALVE status on the CRT. If it is

not in the desired mode of valve control, select the desired mode. For more information

about the modes of valve control, refer to the sections “Governor Valve Management” and

“Starting and Load Changing Recommendations”.

4. Accelerate the turbine to 3000 r/min at the previously selected rate.

5. It is recommended as good practice to trip the turbine after full speed is reached to be

Page 11 of 13


sure that the overspeed trip mechanism and steam valves are functioning normally. Push

the “trip” push button in the turbine control room or operate the overspeed trip mechanism

with the hand trip lever on the governor pedestal. Be sure that all the main and reheat

steam valves closed fully. Following the trip, the values in the REFERENCE and

TARGET will reset to zero.

6. If for any reason, the control system switches to TURBINE MANUAL after the trip,

reset it to OPER AUTO.

7. To relatch the turbine “on the fly”, proceed as follows:

7.1 Push LATCH continuously for a few seconds. The values in REFERENCE and

TARGET will increase to the actual turbine speed and a speed hold will be instituted

(assuming that the control system is in OPERATOR AUTO).

7.2 Set the acceleration in accordance with the chart “Hot Start Recommendations.”

7.3 Enter the transfer speed value (assuming the turbine speed has decreased to below this

value) into the TARGET

7.4 Push GO. When the turbine reaches transfer speed, transfer from TV to GV as

previously described.

7.5 Accelerate the unit to 3000 r/min as previously described.

8. Before synchronizing, test the “Overspeed Trip Mechanism Oil Pressure Check

Device”. Follow instructions given in corresponding content.

9. Shut off the bearing oil pump and the seal oil backup pump and set on AUTO control.

Turn on the water to the oil coolers, when required, regulate the flow of water to maintain

the temperature of the oil leaving the hottest bearing at less than 71 ℃.

10. Turn on water to the generator hydrogen coolers following the specific instructions

outlined in the Generator Instruction Book.

11. Maintain the “no load” limits expressed by the chart “No Load and Light Load

Operation Guide.” Refer to “Low Pressure Exhaust and Exhaust Hood Sprays” in the

section “Operating Limits and Precautions.”

2.5 SYNCHRONIZING AND INITIAL LOADING When starting with reduced or rated throttle pressure, synchronize and promptly load to

5% of rated capacity in the following sequence:

1. Synchronize the unit.

Page 12 of 13


If an automatic synchronizer is to be used to place the unit on the line, the turbine must be

on speed control at a speed of 3000 r/min±50r/min.

The control of the turbine speed may then be transferred to the automatic synchronizer by

depressing the AUTO SYNC push button. The automatic synchronizer now has access

to the DEH speed reference by means of Raise/Lower contact closure inputs to bring the

turbine generator to synchronous speed and to synchronize the unit. After the main

generator breaker is closed, the control of the unit will automatically return to the

OPERATOR AUTO control mode.

2. With the closing of the generator breaker, the REFERENCE and TARGET will

display a value in megawatts which will automatically position the governor valves at a

position equivalent to 5% load the existing throttle pressure.

NOTE

When load is initially applied, the OPC MONITOR light may be lit. This is normal

and cannot be avoided due to the failure detection scheme for a Zero based signal. As

soon as the generator is initially loaded to at least 5% load, this monitor light should

go out. If the light remains lit when load has been increased above 10% of rated load,

the turbine has lost one of its main overspeed protection device. Maintenance

Personnel should take the following action immediately.

a. Check MW transducer.

b. Check OPC pressure transducer.

c. Check OPC speed pickups and speed signals.

3. Push IMP IN to place the impulse chamber pressure feedback loop in service. (When

in the IMP OUT mode. the megawatt REFERENCE value displayed does not match the

actual load displayed by the megawatt meter. When in the IMP IN mode, the megawatt

REFERENCE value displayed will approximately match the actual megawatts generated.)

4. Push MW IN to place the megawatt feedback loop in service. (When in the MW IN

mode, the megawatt REFERENCE value displayed will be trimmed to accurately match

the megawatts generated.

4.1 Transferring between IMP IN and IMP OUT and MW IN and MW OUT is bumpless

and does not affect the load level.

4.2 Transferring from MW OUT to MW IN to MW OUT while the REFERENCE is

Page 13 of 13


counting toward the TARGET results in halting the REFERENCE count and makes the

TARGET equal to the REFERFNCE.

4.3 Similar action will result when transferring from IMP IN to IMP OUT or vice versa

with the megawatt feedback loop out of service (MW OUT).

5. Hold at 5% load for the period of time determined from the chart “Hot Start

Recommendations.”

NOTE

If the throttle steam conditions are controlled to produce a first stage steam and

metal temperature below the “EXACT MATCH LINE” shown on the chart “Hot

Start Recommendations”, a hold period is not required. By keyboard entry, apply

minimum load as show on the chart. Further loading is to be in accordance with the

section “Load Changing.”


Compiled：Yu Yan 2008.09 Start Up and Operation With Bypass in Service Checked：Zhang Xiaoxia 2008.09


Tang Jun, Zhang D.M

2008.09


Contents

START UP AND OPERATION WITH BYPASS IN SERVICE .................. 1

1 TURBINE STARTUP WITH BYPASS IN SERVICE ......................... 1

1.1 THE STATUS OF THE TURBINE BEFORE ADMITTING

STEAM........................................................................................................ 1

1.2 ROLLING WITH STEAM.................................................................. 3

1.3 SYNCHRONIZATION AND INITIAL LOADING.......................... 6

2 LOAD CHANGING ................................................................................ 8

2.1 LOAD CHANGING (LOW CONSTANT MAIN STEAM

PRESSURE)................................................................................................ 8

2.2 LOAD CHANGING (SLIDING PRESSURE) ................................ 10

2.3 LOAD CHANGING (RATED PRESSURE).................................... 11

3. LOAD REJECTION WITH BYPASS................................................ 11

Page 1 of 13


START UP AND OPERATION WITH BYPASS IN SERVICE

1 TURBINE STARTUP WITH BYPASS IN SERVICE

1.1 THE STATUS OF THE TURBINE BEFORE ADMITTING STEAM The status of the turbine before admitting steam should be as follows:

1. The turbine must be rolling on turning gear.

2. The following throttle and reheat steam conditions must be present (refer to "Startup

Steam Conditions at Turbine Throttle" and "Reheat Steam Conditions at Interceptor Valve

Inlet" charts):

a. Not less than 56℃ superheat.

b. If the initial HP or IP turbine rotor metal temperature is less than 204℃, the inlet steam

conditions should be in the "Cold start" region. The throttle temperature should not be

higher than 427℃. The reheat steam temperature should be in the "Cold Start" region.

c. If the initial HP turbine rotor metal temperature is 204°C or higher, the throttle valve

inlet steam temperature should be above the curve labeled "Minimum Throttle Valve Inlet

Steam Temperature at Transfer" before transferring throttle valve to governor valve

control.

3. Backpressure (absolute) must be as low as possible, but not be greater than the

combination of reheat steam temperature and LP exhaust pressure limits given on the

chart "No-Load Light Load Operation Guide".

4. The DEH should be in OPERATOR AUTO mode.

5. Refer to Figure 1 for bypass system description, and Table 1 for Turbine and Bypass

system status.

Page 2 of 13


Figure 1- Turbine Bypass System Schematic

Table 1: Turbine and Bypass System Status Before Rolling Turbine

SYSTEM/VALVE STATUS Throttle Valves Fully Closed

Governor Valves Run fully open by operator with Valve Position Limiter (Single Valve Mode)

Interceptor Valves Fully Closed Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve Open to keep HP turbine under vacuum

HP Exhaust Check Valve Closed due to pressure difference between Cold Reheat and HP exhaust.

HP Drain Valves Open IP Drain Valves Open Inlet Loop Vent Valves Open LP Exhaust Hood Sprays Off

HP Bypass Controlling Main Steam pressure at its setpoint (specified by boiler supplier). Attemperator sprays keeping the Hot Reheat temperature within plant design limits.

LP Bypass Controlling Hot Reheat pressure at its setpoint (specified by boiler supplier). Attemperator sprays keeping the exit temperature within condenser design limits.

Page 3 of 13


1.2 ROLLING WITH STEAM After performing the operations described in the “Starting Procedure-Operator Automatic

Mode” leaflet proceed as follows:

1. Determine the rolling time from the "Startup Recommendations" chart. Convert the

rolling time to an acceleration rate in r/min.

2. Accelerate the turbine to the supervisory instrument check speed 600r/min.

WARNING

TO AVOID INJURY, KEEP CLEAR OF THE TURNING GEAR OPERATING

LEVER, WHICH IS MOVED TO “DISENGAGED BY AIR PRESSURE”.

WARNING

WATER MUST BE AVAILABLE TO THE EXHAUST HOOD SPRAY CONTROL

VALVE AND LUBE OIL COOLER WHENEVER THE TURBINE IS ROLLING

OVER 3r/min.

3. Refer to Table 2 for the Turbine and Bypass system status during turbine roll up to

600r/min.

Table 2: Turbine and Bypass System Status Up to Supervisory Instrument Check Speed

SYSTEM/VALVE STATUS Throttle Valves Fully Closed Governor Valves Fully open (Single Valve Mode)

Interceptor Valves Half of the valves will be throttling in speed control (demand to valve has a small bias)

Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve Open to keep HP turbine under vacuum

HP Exhaust Check Valve Closed due to pressure difference between Cold Reheat and HP exhaust

HP Drain Valves Open IP Drain Valves Open Inlet Loop Vent valves Close at 600 r/min LP Exhaust Hood Sprays Off



4. Hold the turbine at 600 r/min long enough to check all supervisory instruments to

Page 4 of 13


ensure that conditions are satisfactory before proceeding. The eccentricity recorder should

show a steady value of less than 0.076 mm before the turbine speed is increased above

600 r/min. Monitor vibration at speeds above 600 r/min.

5. Select the IV to TV/IV transfer speed as the target speed and accelerate the turbine at

the previously determined acceleration rate.

6. Refer to Table 3 for the Turbine and Bypass system status during the turbine speed

ramp up to the IV to TV/IV transfer speed.

Table 3: Turbine and Bypass System Status During Speed Ramp

(Up to IV to TV/IV Transfer Speed)

SYSTEM/VALVE STATUS Throttle Valves Begin opening to take control of speed Governor Valves Fully Open (Single Valve Mode)

Interceptor Valves

Half of the valves will be throttling in speed control (demand to valve has a small bias) until IV to TV/IV transfer speed is reached. Once transfer is complete, IV's will throttle along with TV's to hold speed.

Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve Open


HP Drain Valves Open IP Drain Valves Open Inlet Loop Vent Valves Closed LP Exhaust Hood Sprays On at 2600 r/min.

HP Bypass Controlling Main Steam pressure at its setpoint (specified by boiler supplier) Attemperator sprays keeping the Hot Reheat temperature within plant design limits.

LP Bypass Controlling Hot Reheat pressure at its setpoint (specified by boiler supplier) Attemperator sprays keeping the exit temperature within condenser design limits.

7. At the IV to TV/IV transfer speed, the control system will automatically hold speed

using the interceptor valves long enough to "memorize" its stabilized flow demand (Fl),

and thereafter the turbine speed will be controlled by modulating both the throttle valve

pilots and the interceptor valves. The demand to both sets of valves will be common, but

with a bias put on the interceptor valve flow demand to ensure that the flow through the

Page 5 of 13


interceptor valves will always be Fl% greater than the flow through the throttle valves.

8. Select the TV/IV to TV transfer speed as the target speed and accelerate the turbine at

the previously determined acceleration rate.

9. During this segment of control, if the speed reference reaches the setpoint or the

operator presses HOLD, the interceptor valves will "freeze" in the position at which this

occurs, and all speed control will be done using the throttle valves. High and low limits

that are variable as a function of the speed reference will limit the maximum and

minimum positions of the interceptor valves.

10. At the TV/IV to TV transfer speed, the control system will stop controlling speed with

the TV/IV valves and will hold the IV valves position at a pressure compensated value.

Speed control will then be transferred to the TV's only.

Table 4: Turbine and Bypass System Status at TV/IV to TV Transfer Speed.

SYSTEM/VALVE STATUS Throttle Valves Open and controlling speed Governor Valves Fully Open (Single Valve Mode)

Interceptor Valves

Half of the valves will be throttling in speed control to hold speed at the IV to IV/TV transfer speed (half of the valves will remain closed because of a bias in control). Once the interceptor valve position is memorized, they will be frozen at that position, moving only in response to a change in hot reheat pressure to maintain a constant total flow to the IP t biReheat Stop Valves Open.

HP Turbine Exhaust Vent

Open

HP Exhaust Check Valve

Closed due to pressure difference between Cold Reheat and HP exhaust.

HP Drain Valves Open IP Drain Valves Open Inlet Loop Vent Valves Closed LP Exhaust Hood Sprays On at 2600 r/min.



Page 6 of 13


11. After verifying that the throttle steam conditions and the steam chest temperature meet

the requirements shown on the chart "Startup Steam Conditions at Throttle Valve Inlet",

transfer control of the turbine speed from the throttle valves to the governor valves.

12. During the TV to GV valve transfer, the governor valves will begin closing until the

speed drops to 30 r/min. The throttle valves will be opened fully after the speed drops 30

r/min.

13. The governor valves are now in control of speed and will maintain speed at the TV to

GV transfer speed. Refer to Table 5 for the turbine and bypass system status during the

TV to GV speed control transfer.

Table 5: Turbine and Bypass System Status at TV/GV Transfer

SYSTEM/VALVE STATUS

Throttle Valves Throttling in speed control to hold turbine at the TV/GV transfer speed, then opened fully after closing of governor valves causes a drop in speed of 30 r/min.

Governor Valves Begin closing to take control of speed Interceptor Valves Holding pressure compensated position Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve Open

HP Exhaust Check Valve Closed due to pressure difference between Cold -Reheat and HP exhaust.

HP Drain Valves Open IP Drain Valves Open Inlet Loop Vent Valves Closed LP Exhaust Hood Sprays On.

HP Bypass Controlling Main Steam pressure at its setpoint (specified by boiler supplier. Attemperator sprays keeping the Hot Reheat temperature within plant design limits.

LP Bypass Controlling Hot Reheat pressure at its setpoint (specified by boiler supplier. Attemperator sprays keeping the exit temperature within condenser design limits.

14. Accelerate the turbine to synchronous speed at the previously selected rate.

1.3 SYNCHRONIZATION AND INITIAL LOADING 1. At synchronous speed, speed control will be done solely by the governor valves. Steam

passing through the HP exhaust vent valve.

2. Turbine and bypass system status at synchronous speed, but prior to synchronizing the

Page 7 of 13


generator is as follows (Table 6):

Table 6: Turbine and Bypass System Status at Synchronous Speed (Before Synchronizing)

SYSTEM/VALVE STATUS Throttle Valves Fully opened Governor Valves Throttling to hold synchronous speed Interceptor Valves Holding pressure compensated memorized position Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve Open


HP Drain Valves Open IP Drain Valves Open Inlet Loop Vent Valves ClosedLP Exhaust Hood Sprays On



3. Before synchronizing the unit, the cold reheat pressure downstream of the HP exhaust

check valve must be as low as possible. If the pressure is above 0.828MPa(a), the HP

exhaust temperature may exceed allowable limits causing a turbine trip.

4. Synchronize the unit.

5. The governor valves and interceptor valves will quickly open to a position calculated to

hold 5% load.

6. The HP exhaust vent valve will close after the unit is synchronized for 60 seconds.

Pressure will build up in the HP exhaust until it is sufficient to open the HP exhaust check

valve. If the pressure ratio across the turbine blade path is less than 1.7 for more than 60

seconds, the control system will recommend a trip of the turbine. If the HP exhaust

temperature is greater than 427℃, Emergency Trip System will trip the turbine.

7. The status of the turbine and bypass system valves after synchronization up to

minimum load is described in Table 7.

Table 7: Turbine and Bypass System Status After Synchronization Up to Minimum Load

SYSTEM/VALVE STATUS

Page 8 of 13


Throttle Valves. Fully opened

Governor Valves Opened to 5% rated load position (pressure compensated) immediately on synchronization

Interceptor Valves Opened to 5% rated load position (pressure compensated) immediately on synchronization

Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve Closes after synchronization for 60 seconds.

HP Exhaust Check Valve Open when HP exhaust pressure exceeds cold reheat pressure after HP vent valve is closed.

HP Drain Valves Open IP Drain Valves Open Inlet Loop Vent Valves Closed LP Exhaust Hood Sprays On.



2 LOAD CHANGING

2.1 LOAD CHANGING (LOW CONSTANT MAIN STEAM

PRESSURE) 1. As the load is increased, the governor valves open to admit more steam to the turbine

and increase the load. The HP Bypass valves will close to maintain the main steam

pressure at the HP Bypass setpoint value.

2. The interceptor valves will open as a function of the load. As the interceptor valves are

opened, the LP Bypass valves will close to maintain the reheat steam pressure at the LP

Bypass setpoint value. At 30~40% rated load, the interceptor valves will be fully opened

and the LP bypass valves will go closed.

3. As load is increased, the plant will operate at a fixed low main steam pressure with the

pressure being controlled by the bypass system.

4. The turbine and bypass system status during load changing from minimum load up to

the point where the Bypass valves are fully closed is described in Table 8.

Table 8: Turbine and Bypass System Status from 5% rated load until Bypass Valves are

Fully Closed

Page 9 of 13


SYSTEMIVALVE STATUS Throttle Valves. Fully opened

Governor Valves Controlling load with impulse pressure (throttle flow) feedback and/or MW loop feedback, if desired.

Interceptor Valves

Controlling load using same demand signal as governor valve. Interceptor valve will be adjusted so that they are fully opened at the load at which the bypass valves are fully closed.

Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve Closed.

HP Exhaust Check Valve Open. HP Drain Valves Close at 10% rated load. IP Drain Valves Close at 20% rated load. Inlet Loop Vent Valves Closed LP Exhaust Hood Sprays Off at 15% rated load.



5. Once the HP and LP Bypass valves are fully closed, the HP and LP Bypass valve

controls will be automatically placed in standby mode.

6. Throttle pressure control will be done by modulating the governor valves, with the

loading rate controlled by the boiler firing rate (Turbine Follow mode). From this point

until the plant is put into the sliding pressure mode, the turbine and bypass system valves

will be operated as described in Table 9.

Table 9: Turbine and Bypass System Status During Load Changing (Constant Pressure)

SYSTEM/VALVE STATUS Throttle Valves. Fully opened Governor Valves Controlling a constant low throttle pressure.

Interceptor Valves Fully open at approximately the same load as bypass valves are fully closed.

Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve Closed.

HP Exhaust Check Valve Open. HP Drain Valves Close at rated 10% load.

Page 10 of 13


IP Drain Valves Close at 20% rated load. Inlet Loop Vent Valves Closed LP Exhaust Hood Sprays Off above 15% rated load. HP Bypass Closed (in standby mode). LP Bypass Closed (in standby mode).

2.2 LOAD CHANGING (SLIDING PRESSURE) 1. When the governor valves have reached their optimum position, the load will be

controlled by varying the main steam pressure (sliding pressure operation). One of the two

control schemes described below may be followed:

a. The turbine is left in OPERATOR AUTO and all pressure, flow, or MW loops are out of

service, with the frequency loop left in service so that the plant will respond to electrical

system frequency disturbances.

b. The DEH is put into REMOTE which disables all feedback loops, including frequency

compensation. The boiler controls begin sliding pressure control, with the turbine valves

essentially not moving. The boiler controls must include frequency compensation logic

that will adjust the turbine valves quickly upon a system upset.

2. During sliding pressure operation, the turbine and bypass valve positions will be as

described in Table 10.

Table 10: Turbine and Bypass System Status During Load Changing (Sliding Pressure)

SYSTEM/VALVE STATUS Throttle Valves Fully opened

Governor Valves Fixed at optimum position, except in response to frequency disturbances.

Interceptor Valves Fu1ly opened. Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve Closed.

HP Exhaust Check Valve Open. HP Drain Valves Closed IP Drain Valves Closed Inlet Loop Vent Valves Closed LP Exhaust Hood Sprays Off HP Bypass Closed (in Standby mode). LP Bypass Closed (in Standby mode).

Page 11 of 13


2.3 LOAD CHANGING (RATED PRESSURE) 1. As load ascension continues in the sliding pressure mode, the main steam pressure will

reach rated pressure, signifying the end of sliding pressure operation.

The operator may choose to continue the load ramp in the Turbine Follow mode as

described previously. Alternatively the operator may choose to control the load ramp

using the turbine controls to open the governor valves, with the boiler controls holding the

throttle pressure at rated pressure (Boiler Follow mode).

2. If boiler follow mode is chosen, the turbine valves will be operated as described in

Table 11.

Table 11: Turbine and Bypass System Valve Status During Load Changing (Rated

Pressure)

SYSTEM/VALVE STATUS Throttle Valves Fully opened

Governor Valves Controlling load with Impulse pressure (throttle flow) and/or MW feedback, if desired.

Interceptor Valves Fully opened. Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve Closed.

HP Exhaust Check Valve Open. HP Drain Valves Closed IP Drain Valves Closed Inlet Loop Vent Valves Closed LP Exhaust Hood Sprays Off HP Bypass Closed (in Standby mode). LP Bypass Closed (in Standby mode).

3. LOAD REJECTION WITH BYPASS 1. Upon receipt of a load rejection signal from the generator breaker, the turbine control

system will initiate rapid closure of the governor valves and the interceptor valves to

prevent an overspeed condition, as per the normal load drop anticipator (LDA) logic.

2. The bypass valves will be opened quickly to route excess boiler steam to the main

condenser, up to the capacity of the bypass system. The setpoint of the HP bypass will be

set at the last throttle pressure setpoint prior to the load rejection.

Page 12 of 13


3. The OPC action ceases when the turbine speed drops below 103% of rated speed. This

enables the control logic of the feedback loops in the DEH. With the BYPASS ON, when

the unit drops below rated speed, the interceptor valves will quickly ramp open to control

speed, up to a position that is a function of the house load left on the generator, as

measured by the plant instrumentation. The interceptor valve demand will be hot reheat

steam pressure compensated.

4. During this portion of the transient, the valve positions will be as described in Table 12.

Table 12: Turbine and Bypass System Status Following Load Rejection

(After OPC Action Ceases)

SYSTEM/VALVE STATUS Throttle Valves Fully opened Governor Valves Closed

Interceptor Valves Throttling in speed control to hold rated speed, up to the limiting position (corrected for hot reheat pressure)

Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve

Opened on generator breaker opening to allow HP exhaust to vent to condenser.

HP Exhaust Check Valve

Assist closed during OPC action. In free swing position to close on reverse flow following OPC action. Should be closed because cold reheat pressure is higher than HP exhaust pressure.

HP Drain Valves Open IP Drain Valves Open Inlet Loop Vent Valves Opened during OPC action. Closed following OPC action. LP Exhaust Hood Sprays On when breaker opens and if speed is above 2600 r/min.

HP Bypass Fully opened to limit throttle pressure at the throttle pressure setpoint prior to breaker opening.

LP Bypass Fully opened to limit hot reheat pressure at LP bypass setpoint.

5. The flow admitted to the IP and LP turbines through the partially open interceptor

valves is enough to supply sufficient cooling steam to the IP and LP turbines or to achieve

proper distribution of the house load; it will not be sufficient to hold rated speed.

6. The governor valves will open to hold rated speed. Flow through the HP turbine will be

vented to the main condenser through the HP exhaust vent valve. A portion of the HP

turbine flow may also exhaust through the check valve to the cold reheat, depending on

the HP exhaust and cold reheat pressures. During this portion of the transient, the turbine

Page 13 of 13


and bypass valve positions will be as described in Table 13.

Table 13: Turbine and Bypass System Status Following Load Rejection

(House Load Operation)

SYSTEM/VALVE STATUS Throttle Valves Fully opened Governor Valves Throttling in speed control to hold rated speed Interceptor Valves At limiting position (corrected for hot reheat pressure) Reheat Stop Valves Open. HP Turbine Exhaust Vent Valve

Opened on generator breaker opening to allow HP exhaust to vent to condenser.

HP Exhaust Check Valve In free swing position to close on reverse flow. Should be closed because cold reheat pressure is higher than HP exhaust pressure.

HP Drain Valves Open IP Drain Valves Open Inlet Loop Vent Valves Closed LP Exhaust Hood Sprays On when breaker opens and if speed is above 2600 r/min.

HP Bypass Fully opened to limit, throttle pressure at the throttle pressure setpoint prior to breaker opening.

LP Bypass Fully opened to limit hot reheat pressure at LP bypass setpoint

7. If the pressure ratio across the turbine blade path is less than 1.7 for more than 60

seconds, the control system will recommend a trip of the turbine. If the HP exhaust

temperature is greater than 427℃, the Emergency Trip System (ETS) will trip the turbine.

8. The function of the bypass system during and immediately following a load rejection is

to allow the boiler load to be transferred from the turbine to the bypass system to avoid a

boiler trip. In most cases, the operator must run back the boiler load to a lower level

before normal operation can be resumed.

9. When the unit is resynchronized, the governor valves and interceptor valves will be

automatically raised to a position equivalent to 5% rated load above the flow required to

maintain rated speed with house load. Valve positions will be corrected for measured

throttle and reheat pressures.

Page 1 of 2



Load Changing Checked：Zhang Xiaoxia 2008.09


Countersign：


LOAD CHANGING

With the turbine control in the OPERATOR AUTO or TURBINE MANUAL mode, the

chart, “Load Changing Recommendations,” should be followed at all times while changing

load (increasing or decreasing). See the sections entitled “Staring and Load Changing

Recommendations” and “Governor Valve Management” for additional load changing

information.

The Automatic Turbine Control (ATC) Program provides load control capability when

the main generator breaker is closed and the unit is the ATC mode of control. All load

changes are intended to be completed in the ATC mode since the load control program

automatically optimizes the turbine loading rate. The ATC program continually monitors

various turbine parameters, calculates rotor stresses, and selects the optimum loading rate

based on the current conditions. This rate is limited to the lowest of either the optimum rate

as determined by rotor stress calculations, an operator selected rate, or a loading rate

received as an input from an external source. The operator controls the rotor stress limits

and also the maximum load in terms of megawatts. In a combined mode of control the

ATC program determines if a load hold condition is required and if the remote source

attempts to change load more rapidly than the lowest available rate, the remote raise or

lower inputs are blocked.

For load changes in any mode of control, it is assumed that the feedwater heaters and

auxiliary equipment for the particular heater arrangement used are operating normally. The

steam drains are to remain open on increasing load until the unit is carrying 10 percent of

rated load for drains from sources upstream of the turbine reheat stop valves and 20 percent

of rated load for drains from sources downstream of the turbine interceptor valves, at which

time they will close automatically. Also, on decreasing load or when the turbine is tripped,

Page 2 of 2


drains will open automatically at 20 percent of rated load for drains from sources

downstream of the interceptor valves and 10 percent of rated load for drains from sources

upstream of the reheat stop valves. The operator must be certain that the drain valves

function automatically, otherwise he must operate them manually.

CAUTION

The operator must be certain that the OPC monitor light is off; otherwise the turbine

has lost one of its main overspeed protection devices. The trouble should be corrected

immediately.

LOAD CHANGING PROCEDURE

1. When rated throttle steam pressure has been achieved, put the impulse pressure

feedback loop in service by depressing IMP IN.

2. Put one of the throttle pressure controllers in service by depressing either FIXED TPC

IN, OPER ADJ TPC IN, or REMOTE TPC IN. (“Throttle Pressure Controller Set Point”

should always be at least 10% below existing throttle pressure.)

3. Obtain the recommended time to change load from the chart “Load Changing

Recommendations” and determine the loading rate in terms of percent of guaranteed

capacity per minute.

4. Enter the loading rate determined above.

5. Enter the desired load in the TARGET.

6. It is recommended that all load changes be performed in the ATC or combined mode

of control. Depressing AUTO TURBINE CONTROL will put the unit in the ATC mode

which will control the load change through completion. If ATC is not used, depress the Go

push button. The REFERENCE will count towards the TARGET at the selected load rate

and indicating that load is being changed.

7. If a hold is required during a load change, depress the HOLD push button and the load

change will stop. To continue, depress the GO push button. The load change will proceed

at the previously selected loading rate.

8. The load change is completed when the valve in the REFERENCE is equal to the

value in the TARGET.

Note:

When on load control with Impulse Pressure Feedback and MW Feedback in service,

the DISPLAY STATION window will display actual megawatts.

Page 1 of 7


Compiled：Yu Yan 2008.09Shut Down Procedure Checked：Zhang Xiaoxia 2008.09




SHUT DOWN PROCEDURE

. NORMAL SHUTDOWNⅠ

Except in an emergency, load should be removed gradually. The rate of decrease for the

particular turbine operating conditions should be within the guidelines specified on the

chart “Load Changing Recommendations.” For additional information or load changing.

refer to the section “Starting and Load Changing Recommendations” and, if provided,

“Governor Valve Management.”

1. To decrease load:

1.1 Obtain the recommended time to decrease the load from the chart “Load Changing

Recommendations” (see Example 2 on the chart) and determine the load changing rate in

terms of percent of guaranteed capacity per minute.

1.2 Enter the MW/min value obtained above.

1.3 Enter the desired load.

1.4 It is recommended that the load reduction be performed in the ATC mode. Depressing

AUTO TURBINE CONTROL will put the unit in ATC mode which will control load

reduction through completion. If ATC is not used, depress GO push button. The

REFERENCE will count toward the TARGET at the selected load rate and indicating the

load is being reduced.

1.5 If a hold is required during the load reduction, depress the HOLD push button and the

load reduction wills stop. To continue, depress the GO push button. The load reduction will

proceed at the previously selected loading rate.

1.6 The load change is completed when the value in the REFERENCE is equal to the

value in the TARGET.

Page 2 of 7


1.7 When the load has decreased to 20% of rated load. Assure that the drains from sources

downstream of the interceptor valves are open. When the load has decreased to 10% of

rated load, assure that the drains from sources upstream of the reheat stop valves are open.

The drain valves normally function automatically; however, if necessary, the operator

should operate them manually.

1.8 When all load has been removed, shut the unit down by tripping the overspeed trip.

This closes the throttle valves, governor valves, reheat stop valves and interceptor valves.

2. The vacuum breaker valves should not be opened until the turbine unit has coasted

down to about 400 r/min, or until the unit is placed on turning gear, depending on operating

preference. Vacuum breaker valves should not be opened immediately following tripping

of the unit except for emergency requirements to reduce rolling time. Opening the vacuum

breaker valve immediately after tripping a unit could result in blade damage due to the

braking action imposed by the suddenly created dense exhaust medium. Vacuum should be

dissipated before gland sealing steam is shut off.

3. Be sure that the bearing oil pump starts when the bearing oil pressure drops to the

value shown in the “Turbine Control Settings”.

4. For units so equipped, be sure that the bearing lift oil pump selector switch is turned to

the AUTO position. Refer to the Bearing Lift System for operation information.

5. Shut down the air removal equipment.

6. Shut off the cooling water supply to the generator hydrogen coolers, following the

specific instructions given in the Generator Instruction book.

7. When the vacuum reaches zero, shut off the sealing steam to the gland steam control

valves. Shut down the gland steam condenser exhauster. Shut down condensate pump.

8. In order that the turning gear will be automatically engaged, be sure the control switch

is turned to the AUTO position.

9. Shut down circulating water pumps.

10. Regulate the water to the oil coolers to maintain the oil temperature leaving the coolers

between 35 and 38 .℃ ℃

. EMERCENCY SHUTDOWNⅡ

A. Loss of Electrical Tie to the System

In the event of the complete or partial loss of electrical load, energy in the entrapped

Page 3 of 7


steam will cause the rotor to accelerate. The amount of acceleration is a function of the

load level at the time of the load separation.

1. An Overspeed Protection Controller (OPC) is incorporated in the DEH Control System.

This device performs the following functions:

1.1 The load drop anticipator function of the OPC senses complete loss of load and rapidly

closes all governor valves and interceptor valves to limit the overspeed of the turbine. This

function is normally activated only if load is greater than 30% of rated load and the main

breaker is open.

With the opening of the main generator breaker the DEH speed reference is

automatically reset to rated speed and the turbine controlled in OPERATOR AUTO mode.

After a time interval, the speed of the unit will decrease below the setting of the

governor which in turn permitting the interceptor valves to open slowly.

The entrapped steam in the reheat system will cause a second speed rise causing the

OPC governor to again closing the interceptor valves. This mode of control is follow until

all of the entrapped steam is dissipated through the interceptor valves. The governor valves

will remain closed for speed greater than rated speed due to the speed error.

After the entrapped steam in the reheat system is dissipated, the interceptor valves will

stay open and the speed of the unit will decrease towards rated speed. At rated speed, the

governor valves will take over the control of the turbine and keep the unit at rated speed.

1.2 The auxiliary governor function of the OPC senses excess turbine speed and closes all

governor and interceptor valves when the speed is greater than 103%. The auxiliary

governor function causes the same type of governor and interceptor valve operation to

dissipate the reheater steam and achieve synchronous speed as described for the load drop

anticipator function.

1.3 The “fast valving” functions of the OPC:

Senses partial loss of load by comparing turbine input power (IP exhaust pressure) with

generator electrical output power (from the Mw transducer). When turbine power exceeds

generator power by about 60% to 80% (which would typically occur during a phase fault

close to the generating station) the fast valving logic rapidly closes only the interceptor

valves. This will give a corresponding momentary reduction in turbine input power and

consequently a momentary reduction in generator output power to enable the unit to remain

synchronized with the system. Fast valving components are supplied as standard with this

Page 4 of 7


unit. The fast valving function is inhibited unless a specific request is received from the

customer to enable it.

2. After a load drop anticipator or auxiliary governor action. The unit if desired may be

resynchronized and load applied as follows:

2.1 If the unit can be synchronized within 15 minutes after loss of electrical tie, load may

be applied up to the load previously carried as rapidly as desired. Further increases in load

should be applied in accordance with the chart “Load Changing Recommendations.”

2.2 If there is more than a 15 minute delay in re-synchronizing, load should be applied in

accordance with the chart “Load Changing Recommendations.”

2.3 If it is decided not to put the unit back on the line, the normal shutdown procedure

previously outlined should be followed.

3. If the cause of the load dump cannot be determined such that there is a delay in

re-synchronizing, the unit and boiler fires should be tripped automatically after a specific

time delay and the operating procedures described under “Loss of Pressure or

Temperature” should be followed.

B. Loss of Pressure or Temperature

Operation of the Throttle Pressure Limiters (TPL). The DEH controller includes three

throttle pressure controllers: a fixed set point TPL, a variable set point remote TPL, and an

operator adjustable set point TPL. Only one of these may be placed in service at any one

time.

1. Fixed Set Point TPL

1.1 This TPL set point is a fixed value stored in the DEH controller. It is set equal to either

90% or 95% of rated throttle pressure depending on the boiler construction. See the

“Turbine Control Settings” for the exact set point. A 90% set point is assumed for the

following discussion.

1.2 The TPL can be put in service or taken out of service by pushing the FIXED TPL IN

/OUT on the DEH Operator manual panel. If in an automatic mode, the operator must

ensure that the existing throttle pressure is above the TPL set point before placing the TPL

in service. In addition the variable set point remote TPL and the adjustable set point TPL

must be out of service.

1.3 If this TPL is out of service and the control system is transferred from an automatic

Page 5 of 7


mode to TURBINE MANUAL or from TURBINE MANUAL to an automatic mode, the

TPL will remain out of service. Similarly, if this TPL is in service during a mode transfer,

it will remain in service.

1.4 Should a loss of throttle pressure occur while the fixed set point TPL is in service, the

following will occur:

1.4.1 For any throttle pressure below the TPL set point, the throttle pressure controller will

operate.

1.4.2 The load will be reduced until the throttle pressure is restored to the throttle pressure

control set point or a minimum governor valve opening of 20% is reached.

1.4.3 During any loss of throttle pressure such that the valves close to their 20% valve

position, the operator should decide whether the operating pressure or temperature can be

maintained. If not, he must trip the turbine.

1.4.4 If the boiler pressure has increased sufficiently, the operator can increase the

REFERENCE setting to the load value held before the loss of pressure. If the TPL (either

the fixed set point or the variable set point) was placed in service, it may be taken out of

service by the operator.

2. Variable Set Point Remote TPL

2.1 This TPL set point is a variable value obtained from a remote source in the room of an

analog input to the DEH controller.

2.2 The variable set point remote TPL can be put in service or taken out of service by

depressing the REMOTE TPL IN/OUT. The control system must be in an automatic mode

of operation, and the fixed TPL set point must be out of service. In addition, the remote

TPL permissive must also be closed. The operator must also ensure that the existing

throttle pressure is above the variable remote TPL set point.

2.3 If this TPL is out of service and the control system is transferred from an automatic

mode to TURBINE MANUAL or from TURBINE MANUAL to an automatic mode, the

remote TPL will remain out of service. If the remote TPL is in service during an automatic

mode of operation and a transfer to TURBINE MANUAL is initiated, the variable set point

remote TPL will be taken out of service and it will remain inoperable during operation in

the manual mode.

2.4 Should a loss of throttle pressure occur while the variable set point remote TPL is in

service, the following will occur:

Page 6 of 7


2.4.1 For any throttle pressure below the remote TPL set point, the throttle pressure

controller will operate.

2.4.2 The load will be reduced until the throttle pressure is restored to the remote

throttle pressure control set point or a minimum governor valve opening of 20% is reached.

2.4.3 During any loss of throttle pressure such that the valves close to the 20% valve

position, the operator should decide whether the operating pressure or temperature can be

maintained. If not, he must trip the turbine.

2.4.4 If the boiler pressure has increased sufficiently, the operator can increase the

REFERENCE setting to load value held before the loss of pressure. If the TPL (either fixed

set point or variable set point remote) was placed in service, it may be taken out of service

by the operator.

3. Operator Adjustable Set Point TPL

3.1 This TPL set point is a variable value that the operator enters from the operator's

control panel.

3.2 The operator adjustable set point TPL can be put in service or taken out of service by

depressing the OPER AD TPL IN/OUT. The control system must be in an automatic mode

of operation, and the fixed TPL set point must be out of service. The operator must ensure

that the existing throttle pressure is above the set point value entered by the operator.

3.3 Once the set point is established, the operator adjustable set point TPL operates in the

same manner as the fixed set point TPL whose operation is described in a preceding

paragraph.

4. If the Fixed Set Point TPL, Operator Adjustable Set Point TPL, and Variable Set Point

TPL are out of service, the following procedure will apply when actual throttle pressure

drops in an uncontrolled fashion:

4.1 The operator will begin to reduce load in an attempt to maintain pressure above 90%

of rated pressure.

4.2 If the pressure falls below 90% of rated pressure, remove the load and trip the unit.

Check the turbine drain valves downstream of the interceptor valves when the load has

decreased to 20% of rated load. When the load has decreased to 10% of rated load, check

the drain valves from sources upstream of the reheat stop valves. Check the bypass valves

around traps on all drain lines from stage extraction heaters. Place unit on turning gear and

listen for rubs. If everything is normal follow the applicable “Hot Start” or “Cold Start”

Page 7 of 7


procedure to bring the unit up to speed and synchronize.

4.3 For the case where the pressure can be held above 90% of rated pressure, bring the unit

up in normal manner after temperature and pressure have been restored to normal.

C. Emergency Trip System Function

This unit is equipped with an emergency trip system (protective trip devices) which will

automatically trip the turbine in the event of certain for separate content describing the

various devices which comprise the system.) An inadvertent trip can occur during the oil

pressure method of testing the overspeed trip mechanism if the test level is released

prematurely.

1. If the turbine is tripped as not noted above, the trouble has been recognized and

corrected, and the vacuum has been maintained, relatch the unit and proceed to

synchronize.

2. If the turbine is tripped and the vacuum is lost. Let the rotor come rest following

normal shutdown procedure. After the trouble has been corrected, restart the unit in

accordance with the applicable “hot start” or “cold start” procedure.

Page 1 of 5


Compiled：Zhang D.M 2008.09Turning Gear Operation During Shutdown Checked：Huang Q.H 2008.09

Countersign：Yan W.CH 2008.09



TURNING GEAR OPERATION DURING SHUTDOWN

The turbine-generator rotor is driven by a single speed turning gear at a nominal speed of

3r/min for units having a rated speed of 3000 r/min.

Following a shutdown, the turbine-generator unit turning gear should engage

automatically as soon as the unit stops rolling. The operator should verify that the turning

gear is rolling the turbine. In order to facilitate restarting the unit, it is recommended that it

be rolled by the turning gear throughout the shutdown period. Continuing turning gear

operation after the turbine is comparatively cool, greatly increases the likelihood that

eccentricity will be within acceptable limits for start-up by preventing bowing of the rotors

if steam should leak into the turbine duping the shutdown period.

Normally a unit should remain on turning gear flowing a hot shutdown until the rotors

have cooled to 149℃~204℃. This might require 10 to 15 days depending upon the internal

temperature level prior to the shutdown. This time can be reduced considerably by “steam

cooling” before the shutdown as described in Part 7 of this section. Maintaining turning

gear operation for this duration will prevent a rotor bow and assure the availability of the

unit for start-up without delay.

The rate of heat conduction through the gland ends of the turbine rotors to the journals is

low. The normal oil circulation around the journals is sufficient to keep the journals cool

whether the unit is at rest or on turning gear. If lubricating oil is shut off, the journal

temperatures will rise at a rate depending on the turbine internal temperature. When there is

no oil circulation. a journal temperature in excess of 149℃ may cause damage to the

bearing babbitt. Bearing metal temperatures should be closely monitored during this time

and oil circulation restored if excessive temperatures result.

If the unit is hot (average internal temperature above 204℃ and not in excess of 454℃)

Page 2 of 5


and for some reason not turning, oil may be shut down for 2 to 3 hours before the journal

temperatures become excessive. If the turbine is allowed to cool to 204℃, the oil supply

could be shut down for approximately 10 hours.

When it can be arranged without delaying work schedules, the turning gear and the oil

circulatior system should be kept in operation for not less than 48 hours after shutdown. If

continuous rolling during shutdown is not practical, the turning gear should be restarted

and remain in operation for a sufficient length of time before admitting steam to the turbine

to allow rotor straightening as determined by stable eccentricity within the limits noted in

the section “Operating Limits and Precautions”.

The preceding operating recommendations for the shutdown period may not be practical

to follow when repairs or adjustments are to be made to the turbine. In these cases the

following recommendations apply.

1. THE TURBINE IS TO BE DISMANTLED

The turning gear should be kept in operation until the dismantling program requires that

it be stopped. If an emergency necessitates it, the turning gear may be shut down

immediately: however, it must be recognized that this may subject the rotor to severe

bowing. Bearing oil circulation must be maintained after shutdown to protect the bearings

against overheating. The minimum circulation period should be 24 hours after shutdown.

During this period, the oil temperature leaving the coolers should be held between 21℃

and 35℃, if possible.

2. SHUTDOWN FOR EXTENSIVE REPAIR OR ADJUSTMENT

Both the turning gear and the bearing oil circulation system should be kept in operation

for a minimum of 24 hours. Oil temperature from the cooler should be maintained between

21℃ and 35℃, if possible, both the turning gear and the oil circulation may then be shut

down. When operation is to be resumed, the unit should be placed on turning gear prior to

turning on gland steam and establishing vacuum, and can be rolled with steam upon

attaining stable eccentricity conditions within acceptable limits.

These recommendations also apply to the situation where rotor bearings are to be

inspected or repaired and it is necessary to shut off oil circulation. Metal temperatures at all

the bearings should be monitored during this period. To avoid overheating the bearings,

restore oil circulation as soon as possible.

Page 3 of 5


3. SHUTDOWN FOR MINOR REPAIR OR AJUSTMENT

Depending upon the nature of the work to be done. The following schedule may be

adopted:

a. Keep the turning gear and the bearing oil circulation system in operation for a

minimum of 3hours. Both may then be shut off for a period of not more than 15 minutes. If

practical, however, oil circulation should be maintained.

b. Following the 15 minute shutdown period in (a) above roll the turbine on turning gear

for 2 hours or until stavle eccentricity conditions exist, whichever occurs first. Both turning

gear and oil circulation may then be stopped for not more than 30 minutes; however, 15

minutes after stopping, the rotor is to be turned 180 degrees with the turning gear. Oil

circulation should be on during the 180 degree turns to lubricate the bearings.

c. Following the 30 minute shutdown period in (b) above the turbine should again be

rolled on turning gear with oil circulation for 2 hours or until stavle eccentricity conditions

exist, whichever occurs first. The system may be shut down indefinitely, provided that the

rotor is turned 180 degrees at 30-minute intervals for the next 6 hours. Oil circulation

should be on during the 180 degrees turns to lubricate the bearings.

4. EMERGENCY TURNING GEAR OPERATION

If for any reason the turbine unit is tripped and the rotor comes to rest, the unit should be

placed on turning gear operation immediately. If turning gear operation is impossible

because of interference between rotating and stationary parts due to thermal shock and

consequent distortion, try jogging the turning gear motor after a one hour interval. If

unsuccessful, repeat the attempt after another one hour interval. If unsuccessful after the

second attempt, the rotor (or blade ring) may be bowed and/or stationary parts distorted to

the extent that one or two days soaking in the arrested condition may be necessary before

making another attempt to break the rotor loose by turning gear operation.

WARNING

Under no circumstances should an attempt be made to free the rotor by admission of

steam to the unit or by use of a crane. Such an attempt could have disastrous results

such as increased blade seal strip clearances, shroud or rotor gouging, broken blades,

etc.

If turning gear power is not available and the rotor remains at rest, a rotor bow can be

expected. Experience indicates, however, that a one to two hour period on turning gear

Page 4 of 5


prior to start-up will roll the rotors straight. By turning the rotors 180 degrees in 15 to 20

minute intervals, the severity of the bow can be reduced and thus reduce the required

turning gear operating time period to start-up. In cases such as a water incident where both

rotor and cylinder might be bowed, cranking must not be attempted in order to break bound

parts loose.

5. TURNING GEAR OPERATION WITH ONE OR MORE BEARING LIFT

ASSEMBLIES INOPERABLE

As the turbine coasts to a shutdown, the hydraulic bearing lift system will begin to

operate when the rotor speed decreases to a predetermined level (see lubrication oil system

introduction” about Lifting oil system .) The unit will go on turning gear even if one or

more of the bearing lift assemblies is inoperable. If that is the case, “stick-slip” may occur.

If stick-slip does occur, do the following until the bearing lift system can be back in

operation:

a. Start the dc emergency oil pump to provide additional oil flow and reduce bearing oil

temperature as much as possible but not less than 21 ℃.

b. Wait one minute. If stick-slip is still occurring stop the turning gear for 15 seconds and

then restart the turning gear.

c. If stick-slip continues, stop the turning gear again. Every 10 minutes rotate the rotor

180 degree to keep the rotor straight. Continue until the rotor can be placed on turning gear

without stick-slip occurring.

CAUTION

To avoid discharging the batteries to an unacceptable level, do not operate the dc

emergency oil pump for extended periods to overcome stick-slip. Test and recharge

batteries as required immediately after using the dc emergency oil pump for turning

gear operation.

For additional information refer to the “Hydraulic bearing lift System” leaflet.

6. COOLDOWN TIME FOR A TYPICAL HP TURBINE

Information on the cooling of the high pressure turbine while on turning gear following a

trip from load operation is shown in the curve entitled “Cooldown Time for A Typical

Fossil HP Turbine” (see index). This information is useful in pre-planning warm or hot

restarts or planning maintenance during the shutdown period.

Page 5 of 5


This curve is based on cool down information accumulated from field operating data and

can be used as reference information until the Purchaser in able to plot, based on operating

experience, the actual temperature decay of his unit.

7. STEAM COOLING OPERATION

If it is desired to expedite cooling of the turbine elements in order to perform

maintenance quickly, the unit load can be reduced and held at a low level for a period of

time to “steam cool” the metal prior to shutdown. Reducing main and reheat steam

temperature during the load reduction also aids in lowering the internal temperatures. In the

case of fossil turbine units with governor valve management capability, the HP element

will reach a lower temperature in the sequential governor valve mode compared to the

single valve mode at the lower loads (Refer to section “Governor Valve Management”).

The Load Changing Recommendations charts and other specified temperature change

limits still apply during this shutdown operation.

8. REMOVAL OF INSULATION

The cylinder insulation should not be removed from the turbine elements until they have

cooled for 24 hours or longer. This delay is necessary to avoid thermally stressing the

cylinders, locally cooling and deforming the cylinders and exceeding the allowed

differential cooling of the cylinder parts relative to the rotor.


Compiled：Yu Yan 2008.09 Feedwater Heater Operation Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


Contents

FEEDWATER HEATER OPERATION ......................................................1

1 Introduction ...........................................................................................1

2 Sequence of Placing Feed Water Heaters In and Out of Service......1

3 Effects of Removing Feedwater Heaters from Service ......................2

4 Criteria of Operation with Feedwater Heaters Out of Service.........3

5 Rules for Operation with Heaters Out of Service ..............................3

6 General Notes on Heater Operation ..................................................10

Page 1 of 14


FEEDWATER HEATER OPERATION

1 Introduction Modern-day power plant units utilize the regenerative feedwater heating cycle in which

steam is extracted from the turbine at intermediate stages and is condensed in feedwater

heaters. A major portion of heat content of the extracted steam (including the heat of

condensation) is transferred to the feedwater passing through the feedwater heater. The

final temperature of the feedwater returned to the steam generator is considerably higher

than that obtained in the straight condensing cycle having no feedwater heaters, thereby

reducing the energy requirements of the boiler with a resulting improvement in overall

cycle efficiency. Compared with the same throttle flow in a straight condensing turbine,

less work output will be developed because all the steam does not expand entirely through

the turbine; however, the improvement in performance (heat rate) overbalances the effect

of lower work output.

Unless special contract provisions were made, the turbine design is based on the blade

path steam flows, pressure and temperatures distributions, extraction flow rates and the

turbine exhaust flow condition with the configuration shown on the heat balance in the

“Thermal Performance Data”. Normally, the heat balance is calculated with all of the

feedwater heaters in operation. Check the “Thermal Performance Data” package for other

special heat balances that might have been calculated as a result of unit specific contract

requirements. The configuration shown on any special heat balance is not superceded by

the rules that are presented below. Unless special instructions are supplied, all load

restrictions specified may be considered a percentage of that shown on the special heat

balance diagram, if higher than the others.

2 Sequence of Placing Feed Water Heaters In and Out of Service During unit start-up and shutdown, isolate the feedwater heaters from the turbine.

Heaters that are located in the condenser neck normally cannot be isolated from the turbine

on the steam side. These low-pressure heaters are removed from service by .diverting the

flow of condensate around the heater by use of a bypass system. Heaters that have shutoff

valves in the extraction pipes should not be placed in service until the pressure on the

turbine side of the isolation valve is greater than the heater shell pressure. During unit

Page 2 of 14


start-up, feed water heaters should be placed in service in sequence starting with the lowest

pressure heater. During unit shutdown, heaters should be removed from service in sequence

starting with the highest pressure heater.

3 Effects of Removing Feedwater Heaters from Service Removal of one or more heaters from service will cause perturbations, which may or

may not be acceptable, in the turbine and in the heater cycle, depending upon which heaters

are inactive:

A. If one or more heaters are isolated and no higher pressure heater is in service, the

steam which is normally extracted to these heaters flows through the downstream stages of

turbine blading to the condenser. Assuming constant throttle flow, this path increases the

steam flow in the turbine downstream of the inactive extraction point(s) and increases the

KW output of the unit. It also distorts the normal flow, pressure, temperature and work

distribution throughout the turbine. The removal of any heater from operation decreases the

efficiency of the thermal cycle. In addition, when a unit is operated with-the top heater(s)

out of service, the feedwater returning to the steam generator is at a lower temperature;

consequently, additional energy must be supplied in the steam generator by means of

higher fuel consumption to compensate for the colder feedwater.

B. If one or more heaters are out of service while a higher pressure heater remains in

service, there will be a substantial increase in extraction flow to the next higher pressure

active heater. Depending upon the number of heaters removed, the total steam flow to the

active heater will now be a significantly high percentage of the sum of the normal

extraction flow to this heater, plus the normal extraction flows to all adjacent inoperative

lower pressure heaters. The added extraction flow will tend to overload both the steam and

drain sides of the active heater, increase the steam velocity and pressure drop in the

extraction piping and increase the steam velocity in the turbine extraction slot. Additionally,

the pressure at the turbine zone supplying extraction steam will decrease, since the flow to

the downstream blading group is reduced by virtue of the greater extraction flow. These

changes to the steam flow distribution in a turbine can increase the work, flow, temperature,

and the pressure drop across the stages of turbine blading. These parameters are the major

factors which determine blade stress.

Page 3 of 14


4 Criteria of Operation with Feedwater Heaters Out of Service In general, unless special design considerations are made, removing one or more heaters

from service requires a reduction in load when the load generated is at or near the

maximum capability of the unit. Heaters should be removed from service only in

emergency situations, such as equipment malfunction, maintenance or repair. HEATERS

MUST NOT BE TAKEN OUT OF SERVICE FOR THE PURPOSE OF OBTAINING

ADDITIONAL LOAD.

Normally, operation with heaters out of service is acceptable, providing that the work,

flow, temperature and the pressure drop across the individual stages of blading do not

exceed the values incurred at the maximum MW load calculated on a heat balance in the

“Thermal Performance Data”. The contract for some units specifies that they be capable of

operation with the top heater out of service for the purpose of obtaining additional load.

These turbines are specifically designed for this purpose and are guaranteed to operate

safely under this condition.

5 Rules for Operation with Heaters Out of Service 5.1 Sequencing Feedwater Heaters

Feedwater heaters should be placed in service in sequence starting with the lowest

pressure heater. Heaters should be removed from service in sequence starting with the

highest pressure heater. This rule is mandatory when the unit is operating at high loads and

is primarily intended for this load condition. If load is sufficiently low, the rule is not

applicable.

5.2 Emergency Operation

For emergency operation, heaters may be removed from service provided that the flow,

pressure drop, and work across each stage of blading does not exceed that indicated on the

heat balance for the maximum MW load calculated on a heat balance in the “Thermal

Performance data”. Since the operator cannot easily determine the values of these

parameters, emergency operation with heaters out of service will be governed by the rules

noted below. When the rules necessitate a load reduction, whenever possible reduce the

load before removing the heater from service; if this is not possible, the load must be

Page 4 of 14


reduced promptly.

(1) Nonadjacent Heaters Out of Service

One or more nonadjacent heaters may be removed from service provided the unit output

is adjusted so that it does not exceed a reference load which has design margin (see Figure

1). Load is to be reduced to this level for the first heater removed, regardless of size or

position in the feed water heating cycle. This reduction in load is required for removing a

full or partial size heater. The reference load is defined as the maximum guaranteed load of

the turbine operating at rated inlet, reheat, exhaust and makeup conditions. (See maximum

guaranteed rating and the heat balances in the “Thermal Performance data”.)

Page 5 of 14


Figure 1 EXAMPLES

Example 3: One or More Non-Ajacent Partial Heaters Out of Service Permissible Load = Maximum Guaranteed Load

Example 2: Two or More Non-Ajacent Heaters Out of Service Permissible Load = Maximum Guaranteed Load

Example 1: Single Heater Out of Service Permissible Load = Maximum Guaranteed Load

Page 6 of 14


(2) Adjacent Highest Pressure Heaters Out of Service

Fossil units may be operated with up to three of the highest pressure heaters out of ser-

vice provided the unit output is adjusted so that it does not exceed the reference load

defined above (see Figure 1). Additional adjacent heaters may be removed from service

provided the output is reduced by 5 percent below the reference load output for each

additional adjacent heater which is removed from service. Thus, if a fossil unit is operated

with the four highest pressure heaters out of service, the unit output must be adjusted so

that it does not exceed 95 percent of reference load.

(3) Adjacent Lower Pressure Heaters Out of Service with Higher Pressure Heaters In

Service

If it becomes necessary to remove adjacent lower pressure heaters from service at rated

or higher load while higher pressure heaters remain in service, the load on the unit must be

reduced by adjusting the throttle flow. For the first such heater removed from service, the

maximum load should be the reference load (see Figure 1). For each successive adjacent

heater removed from service, the load must be further reduced by 10 percent of the

reference load. For example, if two lower pressure adjacent heaters are removed while a

higher pressure heater remains in service, the load must be reduced to 90 percent of the ref-

erence load. If three adjacent heaters are removed, the load must be reduced to 80 percent.

The maximum reduction necessary is 50 percent of the reference load for any combination

of heaters taken out of service.

5.3 Multiple Strings of Heaters

With the increase in size of units, the condensate flow and the volumetric flow of extrac-

tion steam become too large to be handled by a single string of heaters. Consequently,

many power plants with larger units use multiple strings of heaters. Due to physical

constraints in plant piping systems, heaters operating at the same pressure zone mayor may

not be manifolded.

The definition of manifolding in this context must be viewed in terms of how the turbine

is affected. The steam supply to partial-size heaters is defined to be manifolded if the

isolation of one heater in the string results in continued, but reduced extraction steam flow

from a particular turbine zone (see Figure 1). Conversely, if the isolation of one heater

results in complete cessation of extraction steam flow from a particular zone in a turbine or

Page 7 of 14


from one side of a double flow turbine element, the extraction is not manifolded.

An example of external manifolding is the extraction from the same pressure zone in

separate LP turbine elements where the external piping is interconnected between the

turbine elements and the partial-size heaters. The isolation of one partial-size heater results

in continued but reduced extraction steam flow from each of the affected zones in the

turbines.

An example of non-manifolding of partial-size heaters can be found in the lowest

pressure extraction zone from separate LP turbine elements. When the extraction steam

flow from each LP element is taken to separate partial-size heaters, the extraction steam

flow from one LP element would be completely stopped if one of these heaters is isolated.

Therefore, the effect on that particular LP turbine element would be the same as if a

full-size heater were taken out of service, and such an extraction steam supply is not

considered to be manifolded.

Page 8 of 14


Figure 1(Continued). EXAMPLES

Example 7: Four Ajacent Low Pressure Heaters Out of Service with Higher Pressure Heaters in Service Permissible Load = 70% Maximum Guaranteed Load

Example 6: Two Ajacent Low Pressure Heaters Out of Service with Higher Pressure Heaters in Service Permissible Load = 90% Maximum Guaranteed Load

Example 5: Two Ajacent Highest Pressure Heaters Out of Service Permissible Load = Maximum Guaranteed Load

Example 4: Highest Pressure Heater Out of Service Permissible Load = Maximum Guaranteed Load

Page 9 of 14


Figure 1(Continued). EXAMPLES

Example 9: Not Manifolded

Example 8: Manifolded

Example 10: Not Manifolded

Page 10 of 14


(1) Manifolded Partial Size Heaters

When multiple strings of feedwater heaters are utilized and a manifolded heater of less

than full size in one string is removed from service, the rules noted in Paragraphs 5.2.(2)

and 5.2.(3) apply, except that the load reduction required for a full-size heater may be

multiplied by the percentage reduction in extraction flow from the affected turbine zone.

The required load reduction for a partial-size heater can be determined on the basis of

actual size of the heaters remaining in service at the affected turbine extraction zone. (For

example: assume that 10 percent load reduction is required by Paragraph 5.2.(3) for a

full-size heater. If one of three 1/3-size heaters is taken out of service, reduce load by 3.3

percent; if one of two 1/2-size heaters is taken out of service, reduce load by 5 percent; if

one of two 3/4 size heaters is taken out of service, reduce load by 2.5 percent. )

(2) Non-Manifolded Partial Size Heaters

When multiple strings of feedwater heaters are utilized and a non-manifolded heater of

less than full size in one string is removed from service, the rules noted in Paragraphs

5.2.(2) and 5.2.(3) apply. As noted above, the effect on the turbine of isolating such a

partial-size heater is the same as isolating a full-size heater.

6 General Notes on Heater Operation 6.1 Heater Pressure at Start-Up

AT NO TIME SHOULD THERE BE ANY FLOW FROM A HEATER TO THE

TURBINE. To avoid this condition on start-up, heaters must not be placed in service until

the extraction zone in the turbine is at or above the associated heater pressure.

6.2 Heater Isolation

There are two effective ways to isolate a heater from the cycle: (1) shut off the source of

extraction steam, or (2) stop the flow of water through the heater.

6.3 Water Induction into The Turbine

Prevent the harmful effects of water in the heater flashing into steam, and consequent

potential induction of water or injection of cool vapor into the turbine at a heater extraction

zone. To provide this protection, it has become industry practice to install shutoff and

non-return valves in the extraction lines. The shutoff valves can be used to isolate the

heater from the turbine.

To protect the turbine from water induction, the shutoff and non-return valves installed

Page 11 of 14


in the extraction lines of each heater must close automatically on high level alarms. The

control system responsible for sensing this condition and removing the feedwater heater

from service must respond quickly enough to prevent water from entering the turbine. This

recommendation applies whether a heater is rendered inoperative by closing the shutoff

valve in the extraction line or by bypassing the water flow around the heater. Either method

is effective in removing the heater from service, although the use of a shutoff valve is the

only positive way of preventing backflow into the turbine.

To protect the turbine against water induction due to backflow from the heaters

following a turbine trip, the power operated shutoff valves in the extraction pipes should

automatically close on a turbine trip. Circuits and controls used to close extraction line

shutoff valves following a turbine trip must operate so that a malfunction of these controls

will not cause all of these valves to close when the turbine-generator is at high load. Should

this type of malfunction occur, damage to the turbine-generator unit may result.

6.4 Heaters in Condenser Neck

Most modern power plants have the lowest pressure feedwater heaters located in the

neck of the condenser. Due to the physical arrangement of the heaters in the condenser

neck, it is very difficult to install shutoff or non-return valves in these extraction lines.

Those heaters which are not provided with shutoff or non-return valves in the extraction

piping are removed from service by diverting the flow of water around the heater through

the use of a bypass system.

6.5 Heater Drains

No heater should be placed in service until the shell drain system can handle the

condensed extraction steam, cascading flow from higher pressure heaters, any tube leakage

that may exist, and any other miscellaneous flows routed to the heater. The major

indication of the adequacy of the heater drain system is its ability to maintain the proper

water level in the heater.

If the water in the heater causes the protective devices to generate frequent high level

alarms, the effectiveness of these devices for prevention of water induction or backflow of

cool vapor into the turbine will be impaired. Experience has demonstrated that false alarms

from heater level controls negate the effectiveness of the level alarm system. There is a

tendency to ignore alarms which frequently give false signals.1t must also be remembered

that the startup can be hot or cold, and in either case the induction of cold fluid is very

Page 12 of 14


dangerous to the turbine.

6.6 Tube Leaks

Although units should not be operated with heaters having tube leaks, they are often

operated with this defect. Frequently, it is not easy to tell if tube leaks exist except by

specific testing methods or if a high level alarm sounds. Obviously, tube leaks that occur

between tests, or are small, may not be detected for some time. In any case, when tube

leaks are known to exist, the heater should not be brought into service unless the normal

drain system can handle the leakage plus all the various flows piped to this heater.

6.7 Heater Vents

The heater vent system must be functioning properly to avoid pressurization of heaters

by air binding. Any external steam supply that is used to pressurize a heater must be at a

lower pressure than the turbine zone or the turbine must be isolated from the source. This

includes deaerators pressurized (pegged) to heat water for deaeration.

6.8 Deaerating Heaters

It may not be practice in some power plants to take deaerator type heaters out of service.

Even for water induction protection, drain flow from these heaters cannot be dumped to the

condenser as this is the full condensate flow. Dumping of this flow to the condenser would

starve the feed pumps with possible serious damage to the pumps. If such a situation

inadvertently did occur it would be expected that protective relays in the plant would cause

the unit to trip. In addition, if the deaerator is removed, deaeration of the condensate may

not be possible unless the condenser design includes provisions for deaeration.

Failure to deaerate the condensate is undesirable since the non-condensables would go

through the rest of the cycle downstream of the deaerator including the turbine.

6.9 Flash Tanks

Pressurization of some or all HP heaters, especially the top or top two heaters, is

common practice on once-through boiler installations utilizing a start-up cycle with or

without a flash tank. Steam and water from the start-up cycle are dumped to the two top

heaters to recover heat; these heaters may become pressurized to full flash tank pressure

(6.68MPa(g)) while the turbine is under vacuum. From the standpoint of water or cool

vapor induction into the turbine, this is an extremely dangerous situation and stringent

precautions must be taken to prevent flow into the turbine through the extraction pipes by

closing the shutoff valves. Fortunately, as the unit comes up in load, a transfer is made from

Page 13 of 14


the start-up cycle to the normal cycle. Flash tank pressure decreases as load increases, and a

point will be reached when turbine pressure is above heater pressure and the shutoff valves

can be opened.

6.10 Turbine Thrust

Avoid extremely abrupt isolation of heaters. Such action causes an abrupt change in

pressure throughout the turbine. Units with a combined pressure element (VHP-HP, HP-IP)

and units with a split flow design use dummies to counterbalance any axial thrust on the

rotor incurred from the balding. Some of these designs incorporate piping to transmit the

pressure at a particular zone in the blade path to the dummy. If the rise in pressure in the

blade path is too rapid to permit equalizing the pressures at the face of the dummy and in

the blade path through the piping, an unbalanced thrust condition could occur. This

condition would cause the rotor to "bump" the thrust bearing.

On symmetrical turbine elements a similar unbalanced thrust condition could occur as a

result of heater out of service operation. If heaters, operating at the same pressure zones at

opposite ends of the same element, are not interconnected, a potential thrust unbalance does

exist. Removal of one of these heaters from service will impart a thrust imbalance on the

rotor since the flow through the blades on opposite ends of the same element will be

different. Unlike the combined pressure element, operating in this mode will continuously

generate a thrust imbalance. Providing an adequate cross tie in the extraction lines for these

heaters will prevent this difficulty.

6.11 Other Plant Equipment

The heater out of service restrictions discussed in this leaflet do not account for the limi-

tations on steam generators, boilers, heaters, pumps, or other cycle hardware. The power

plant designer is responsible for obtaining and incorporating other equipment

manufacturer's limitations into the final operating rules for his plant.

In fossil-fuel fired plants, the removal of feedwater heaters from service may result in

thermal shocks which may exceed the operating limits of the boiler.

The rules formulated for each plant must consider conditions over the entire load range

and attempt to minimize overloading and shocking of all components involved, not just the

turbine. Although protection of the turbine is our major consideration, protection of

associated hardware in the turbine cycle must be considered.

In some situations, shocks which occur to other equipment may also have a harmful

Page 14 of 14


effect on the turbine-generator. Therefore, formulate rules to protect other auxiliary

equipment.


Compiled：Yu Yan 2008.09 Periodic Functional Test Checked：Zhang Xiaoxia 2008.09




Contents

PERIODIC FUNCTIONAL TEST ................................................................. 1

1 WEEKLY ................................................................................................. 1

1.1 Main and Reheat Steam Inlet Valves............................................... 1

1.2 Auxiliary oil Pumps and Controls ................................................... 3

1.3 Auxiliary Oil Pump Pressure Switch Setting.................................. 4

1.4 E-H Fluid System .............................................................................. 4

1.5 Extraction Non-Return Valves ......................................................... 5

2 MONTHLY .............................................................................................. 5

3 SEMIANNUALLY .................................................................................. 5

3.1 Overspeed Trip Mechanism (Overspeed Trip Test) .......................... 5

3.2 Overspeed Protection Controller ........................................................ 7

3.3 Remote Trip (By Actually Tripping The Unit) .................................. 7

Page 1 of 7


PERIODIC FUNCTIONAL TEST In addition to the tests performed during startup, functional tests of equipment at

prescribed intervals are essential to insure maximum operational reliability. Test the

equipment more frequently than recommended below if operating experience indicates it

is advisable.

Some of the leaflets in this book describe both the equipment and the test procedure.

They are noted below by title and may be found in the Instruction Book “Contents.”

1 WEEKLY

1.1 Main and Reheat Steam Inlet Valves A functional test of the turbine steam inlet valves can only be made while the unit is

carrying load, and the BYPASS OFF mode is selected. The purpose of this test is to

ensure proper operation of the main steam throttle valves, governing valves, reheat stop

valves, and interceptor valves. These vital control devices might otherwise remain

motionless through long periods of operation.

The operation of the valves should be observed during the tests by an operator stationed

at the valve locations. Movement of the valves should be smooth and free. Jerky or

intermittent motion may indicate a buildup of deposits on shafts. As proper operation of

these valves is vital, prompt remedial action is imperative if difficulty of any type is

indicated during these tests.

(1) Main steam inlet valve The throttle valve stem freedom test is to be made with the Megawatt Feedback loop in

and the Impulse Pressure Feedback loop out of service. The Megawatt Feedback loop in

can regulate steam valve which is not tested through the steam flow that is shutdown by

the governor valve, so this will adjust the governor valves to maintain constant load

during the test.

Note

Main steam inlet valve testing is allowed only when the controller is in single valve

mode. If Main steam inlet valve testing is allowed when the controller is in sequence

valve mode, the stress of control stage is too big.

For safe and reliable operation of the turbine, the main steam inlet valve test can be

allowed based on the turbine manufacturer's stated recommended load range. The

minimum load for testing in the single valve mode is usually imposed only to eliminate

Page 2 of 7


the possibility of motoring the turbine. The test load in the sequence valve mode should

be greater than the minimum load corresponding throttle pressure to prevent overstressing

the control stage blading.

If the valves are tested above the turbine manufacturer’s stated maximum

recommended load, the load will drop during the test to a level that corresponds to the

maximum flow that can be passed through the governor valves in one steam chest.

The stem freedom test should be made in the following steps every week:

a. Press the VALVE TEST button to start test sequence of No.1 main steam valves and

corresponding governor valve. VALVE TEST and VALVE STATUS display.

b. Select the TV1 to (ENTER).

c. Valve-Position of the main steam valves (opening percentage) will be displayed.

Press (CLOSE) button.

d. The left main steam valve will be closed momentarily after the left governor valve

closed.

e. The main steam valves will be reopened.

f. Press OPEN button, to make governor valve back to its original position.

g. Repeat the above test for the No.2 throttle valves and associated governor valves.

h. The electrical test circuits are interlocked so that it is not possible to test both

governor valves at the same time.

Page 3 of 7


If the valves test is to be made with the Megawatt Feedback loop out of service, the

unit could not reach load quick feedback. Then the governor valves will not adjust

automatically to maintain constant load. Therefore, if the test is made at this condition, a

major load will reduce.

To avoid a major load reduction, operator should comply with the recommended load

range shown on above chart.

(2) Reheat steam inlet valve This test can usually be conducted at any load up to maximum load with

approximately 2% load reduction during the test.

The test should be made in the following steps:

a. Press the test button of the corresponding valve that to be tested to close RSV and IV.

The actual procedure is the same as the main steam valve test.

b. Press Open button. After the RSV is fully open, the IV will reopen.

c. After the two valves are all fully open, repeat the test for another group of the RSV

and the IV.

d. The electrical test circuits are interlocked so that it is not possible to test the RSV and

the IV valves in the other side at the same time.

1.2 Auxiliary oil Pumps and Controls Auxiliary oil Pumps and Controls during normal operation of the turbine, the oil

system requirements are supplied by the main oil pump. Therefore, the procedure for

testing the auxiliary oil pumps with the turbine at synchronous speed differs from the

procedure with the turbine on turning gear (see “Preliminary Checks and Operations”).

During normal operation, test the pumps as described below.

To remotely test the oil pumps, the bearing oil piping is provided with test solenoids

which, when energized, locally reduce the pressure and activate the pressure switches.

(1) AC Bearing Oil Pump

Energize the solenoid valve. This reduces the pressure to a point where the pressure

switch makes contact. After verifying that the bearing oil pump motor has started,

deenergize the solenoid valve.

(2) DC Emergency Oil Pump

To test the DC emergency oil pump, follow the same instructions given above for the

AC bearing oil pump.

Page 4 of 7


Once the pressure switches have operated satisfactorily, verify that the pumps are

pumping oil and record the output pressures. Pump discharge pressure taps, located on the

lube oil reservoir, are provided for gauges (usually supplied by the purchaser). Compare

the pump output pressures with the output pressures recorded during the initial start-up of

the turbine.

NOTE

The auxiliary oil pump output pressures measured with the turbine in normal

operation are expected to be somewhat higher than the same pressures measured

with the turbine on turning gear.

To stop the pumps, turn each control switch to the “Off” or “Stop” position and release.

The switch should return to the “Auto” position.

1.3 Auxiliary Oil Pump Pressure Switch Setting The bearing oil piping is provided with bleed-off valves which are used to reduce the

oil pressure locally and activate the pressure switches.

(1) Open the bleed-off valve for the bearing oil pump (BOP) to locally reduce the

pressure to a point where the pressure switch (63/BOP) makes contact, thereby

completing the circuit to the BOP motor. Observe the setting at which the switch makes

contact and the pump starts. Compare this reading to the setting given on the “Turbine

Control Settings“drawing. Close bleed-off valve.

(2) To check the emergency pump pressure switch setting (63/EOP), follow the same

instructions given above for the BOP pressure switch.

(3) To stop pumps, turn each control switch to the “Off” or “Stop” position and release.

The switch should return to the “Auto” position.

1.4 E-H Fluid System The items below are identified on the content describing the EH fluid system.

(1) Start the EH fluid backup pump (one of the two identical pumps located near the base

of the EH fluid reservoir)at least once a week.

(2) Check the pressure drop across the pump discharge filters. Replace the filters when

the differential pressure switch alarms.

(3) Check the pressure drop across the reservoir drain return filter. Reposition the

selector valve at the reservoir to the alternate filter and heat exchanger when the alarm

indicates excessive pressure drop.

Page 5 of 7


(4) Check gas pressure in accumulators once a week following procedures outlined in the

EH System.

Additional tests and checks as well as those listed above are discussed in greater detail

in other sections of the instruction book.

1.5 Extraction Non-Return Valves It is recommended that the extraction nonreturn valves be tested weekly with the unit

below 10% load. It is necessary to test at low loads to obtain low flow and low steam

density for the nonreturn valve clapper shaft to rotate an amount which will be visible to

the operator stationed at the valve. The valve will close only a slight amount during the

test. Test trip valves are used to perform the valve tests.

Complete the testing by returning the test trip valves to normal operating position and

witness that the nonreturn valves return to their full open position.

2 MONTHLY 1. Overspeed Trip-Electrical (see “Emergency Trip System”).

2. Overspeed Trip Mechanism Oil Pressure Check Device (see separate content with

same title).

3. Low Vacuum Trip (see “Emergency Trip System”),

4. Low Bearing Oil Pressure Trip (see “Emergency Trip System”).

5. Low EH Fluid Pressure Trip (see “Emergency Trip System”).

6. Thrust Bearing Trip (see “Emergency Trip System”).

7. Remote Trip (if remote trip test capability is available ).

8. Pressure switch settings for auxiliary oil pumps. Compare oil pressures at which the

switches actually operate with the settings shown in the leaflet “Turbine Control

Settings”.

9. Bearing Lift Oil Pumps. The test is described in the content “Hydraulic Bearing Lift

System.”

3 SEMIANNUALLY

3.1 Overspeed Trip Mechanism (Overspeed Trip Test) During the life of a turbine, the set point of the overspeed weight must be verified by

Page 6 of 7


actually overspeeding the unit at least once every six months. Also verification must be

made during the initial start-up period, after any major overhaul, and after work is

performed on the governor pedestal which may affect the overspeed trip setting.

Prior to overspeeding the turbine to check the operation of the overspeed trip

mechanism, it is necessary to heat soak the unit to stabilize rotor temperatures. This

procedure must be followed to avoid developing thermal stresses due to unstable

temperature distributions existing in the rotor which would add to the high centrifugal

stresses which occur in the rotor bores during the overspeeding. To avoid overheating the

LP exhausts during the overspeed trip testing, the back pressure should be stable and not

exceed the limits specified for full speed and no load.

(1) Initial Start or After Overhaul

When making the initial start after installation or a major overhaul, the turbine should

be overspeeded to check the overspeed trip mechanism. Using the start-up

recommendations for rolling the unit to rated speed, synchronizing and applying the initial

load of 5% of rated capacity, the load should be increased to 10% of rated capacity and

held for a minimum period of 4 hours immediately prior to running the overspeed trip test.

The 10% load level is used for soaking because this load provides enough heat, flow, and

temperature to obtain the desired temperature distribution.

For testing during the initial start, the 10% load is low enough to minimize damage

should the unproven emergency trip system fail to close the main steam and reheat valves

following a load rejection and turbine trip. Soaking at higher load levels increases the

likelihood of property damage and increases the risk of injury to persons. In fact, on some

units the steam supply, equivalent to 25% load, is enough to drive the unit to destructive

overspeed. Thus, it is recommended that the load not exceed 10% until the overspeed trip

system is checked. Maximum of 15% of rated load can be raised for the soaking load, but

only if absolutely necessary. During the soaking period at load, it is important to have

stable load, main steam and reheat temperature, main steam pressure, back pressure (LP

exhaust),and cycle conditions.

When the soaking period is completed, reduce load promptly, in 5 minutes or less, to

5% of rated load, trip the unit, and complete the overspeed test in 15 minutes to minimize

chilling of the rotors.

If it is necessary to shut down the unit after the soaking period at load prior to running

Page 7 of 7


the over-speed test, the overspeed trip test may be performed within two hours following

the trip from 5% load. If the shutdown is longer, the load must be returned to 10% for

several hours to achieve stable temperature conditions be fore running the overspeed test.

(2) Semiannual Test

Prior to the overspeed test, the heat soak with stable conditions is to be made a not less

than 10% of rated load, and not more than the amount of load that and be removed (to 5%

load)in 5 minutes without violating the "Load Changing Recommendations " curves. Trip

the unit and complete the overspeed test in 15 minutes. This procedure must be followed

to avoid chilling the rotors.

The overspeed trip mechanism is described in a separate content “Overspeed Trip

Mechanism”. The procedure for testing this mechanism is described in detail in the

section “Startup-rolling with steam bypass off” and “Turbine startup with bypass in

service”.

3.2 Overspeed Protection Controller The OVERSPEED PROTECTION CONTROLLER should be tested when starting the

turbine initially, after any shutdown or every six months whichever occurs sooner.

The test can be performed in either TURBINE MANUAL or in OPER AUTO and is

described in the section “Starting Procedure Before Admitting Steam.” The overspeed

protection controller may be tested at any speed up to rated speed. The control system

inhibits the test when the generator is synchronized to the line.

3.3 Remote Trip (By Actually Tripping The Unit)

Page 1 of 1


Compiled：Tang Jun 2008.09Caution for ATC Operation Checked：Wang Zurong 2008.09

Countersign：

Countersign：


Caution for ATC Operation

When the turbine-generator is operated in the Automatic Turbine Control (ATC) mode,

the operator must assure that the recommended operating limits and precautions, load

changing rates, speed hold ranges, etc., are adhered to. The operator should observe the

monitored turbine variables such as the turbine steam and metal temperatures, bearing

vibration, differential expansion, rotor position, etc., to assure that they are within the

allowable limits. If there is any indication that the ATC program is not properly responding,

such as could be caused by a malfunction in an input device, an erroneous input signal, etc.,

the control of the turbine-generator should be returned to the Operator Automatic Mode,

and the problem should be corrected as soon as possible.

On the initial start of the unit, the rotor soak period must conform to the “Cold Start

Rotor Warming Procedure” curve. The hold period specified by the ATC is to be ignored.

Page 1 of 2


Compiled：Tang Jun 2008.09Remote Automatic Modes of Operation Checked：Wang Zurong 2008.09

Countersign：

Countersign：


Remote Automatic Modes of Operation

With the unit under the OPERATOR AUTOMATIC mode of operation, control of the

turbine generator may be transferred to any one of the following remote control systems.

1 AUTOMATIC SYNCHRONIZER (AUTO SYNC)

The automatic synchronizer is an electronic package located apart from the DEH

controller.

If the automatic synchronizer is to be used to place the unit on the line, the turbine speed

must be within ± 50 r/min of synchronous speed. The control of the turbine speed may then

be transferred to the automatic synchronizer by depressing the AUTO SYNC push button.

The automatic synchronizer now has access to the DEH speed reference by means of

Raise/Lower contact closure inputs to bring the turbine-generator to synchronous speed and

to synchronize the unit. After the main generator breaker is closed, the control of the unit

will automatically return to the OPER AUTO control mode.

2. REMOTE

When remote control of the turbine-generator load is desired, depress the REMOTE

push button. The load of the turbine-generator is now under control of the dispatching

system through Raise/Lower contact closure inputs.

The operator can regain control of load at any time by depressing the OPER AUTO push

button.

Page 2 of 2


2. AUTOMATIC TURBINE CONTROL (ATC)

The control of the turbine may be transferred to the ATC mode from any other automatic

mode by depressing the AUTOMATIC TURBINE CONTROL push button. The transfer

may be made at any time without any bump in speed or load.

The selection of this mode enables the ATC program to accelerate the unit from turning

gear operation to synchronous speed while continually monitoring the system parameters

and alarms. It checks the pre-roll conditions, determines if a rotor heat soak period is

required, selects the optimum acceleration rate, transfers control from the throttle valves to

the governor valves, checks the pre-synchronizing conditions and engages the automatic

synchronizer. It also automatically avoids speed holds in any LP blading resonant speed

ranges.

In addition to providing speed control capability, the ATC program also provides load

control capability when the main generator breaker is closed. The load control program

automatically optimizes the turbine loading rate for either an operator initiated load change

or an external source initiated change. In a strictly ATC mode of control, the loading rate is

the lowest of either the optimum rate as determined by rotor stress calculations, operator

selected load rate, or the loading rate as an input from an external source. See the ATC

content for additional information.

During the operation of the turbine, whether during the acceleration period or under load,

the computer will monitor the various parameters of the turbine, compare their values with

limit values and print messages to inform the operator about the conditions of the machine

to guide him in the operation of the unit. These messages are presented on a typewriter and

on a LCD.

Page 1 of 2


Compiled：Tang Jun 2008.9 Turbine Manual Mode of Operation Checked：WangZurong 2008.9

Countersign:

Countersign： OP.6.24.01E-00 Approved：Peng Zeying 2008.9

Turbine Manual Mode of Operation

TURBINE MANUAL mode has been provided to enable power generation capability

under certain contingencies. It is an open loop type of control in which the operator

position the valves (by means of the “Turbine Manual” push buttons), observes the results,

corrects the valve Position if necessary until the desired result is achieved. Therefore, the

turbine speed, acceleration, load and loading rate are all directly managed by the operator,

depending on how he maneuvers those valves.

Since the burden on the operator is greatly increased during TURBINE MANUAL

operation, the operator should not start the turbine in the manual mode unless it is

unavoidable.

It is assumed that the turbine operator is thoroughly familiar with the information about

the control system.

STARTING PROCEDURE

TURBINE MANUAL operation is initiated by depressing the LATCH push button

while the TURBINE MANUAL push button is lit, and holding it for two seconds. The

procedure from that point on is essentially the same as for OPERATOR AUTO, keeping in

mind that the digital display and data entry system is not available in the manual mode.

Then proceed as follows:

1. Open governor valves to wide open position by depressing the GV RAISE.

2. The speed of the unit can now be controlled by means of the TV RAISE and TV

Page 2 of 2


LOWER push buttons and brought to a rotor-warming speed at an acceleration rate of 100

r/min. Maintain this rotor warming speed for a period indicated by the chart "Cold Start

Rotor Warming Procedure”.

3. Increase the turbine speed to the TV to GV transfer speed shown in the section

“Cold Start Rolling with Steam” at an acceleration of 100 r/min. Before transferring

control from the throttle valves to the governor valves, verify that the steam chest inner

wall temperature is at least equal to saturation temperature corresponding to the throttle

pressure. See chart “Startup Steam Conditions at Turbine Throttle.”

4. Transfer control from throttle valves to governor valves in the following sequence:

a) Push GV LOWER until the speed of the unit is affected by the closing of the

governor valves.

b) Slowly open the throttle valves by depressing the TV RAISE push button. The TV

RAISE push button must be held in the depressed position until the TV RAISE and TV

LOWER push buttons light go off.

c) The throttle valves will be in the wide open position and the turbine speed is now

controlled by the governor valves.

5. Increase the speed of the turbine to 3000r/min.

6. Synchronize and load in accordance with the section “Starting and Load Changing

Recommendations.”


Compiled：Yu Yan 2008.09Limits, Precautions and Tests Checked：Zhang Xiaoxia 2008.09




Contents

LIMITS, PRECAUTIONS AND TESTS .....................................................1

1 SUPERVISORY INSTRUMENTS ALARM AND TRIP

SETTINGS ................................................................................................1

2 BEARINGS TEMPERATURE AND PRESSURE.............................2

3 STEAM CONDITIONS TEMPERATURES PRESSURES AND

MOISTURE ..............................................................................................3

4 CONDENSER VACUUM (TURBIBE BACKPRESSURE)............10

5 WATER INDUCTION ........................................................................12

6 CONTROL SYSTEM TEST ..............................................................13

7 GENERAL ...........................................................................................14

Page 1 of 21


LIMITS, PRECAUTIONS AND TESTS

1 SUPERVISORY INSTRUMENTS ALARM AND TRIP SETTINGS 1.1 ROTOR ECCENTRICITY

With the rotor on turning gear, a rotor truth dial indicator reading taken at any bearing

oil ring should not exceed 0.025mm total indicator reading (TIR). At shaft speeds up to

600 r/min the alarm point for shaft eccentricity at the governor pedestal is 0.076mm

double amplitude. Eccentricity should be observed up to 600 r/min. Vibration is observed

above 600r/min. These limits apply to 3000r/min units.

1.2 ROTOR VIBRATION

The following vibration limits are recommended, measured in mm, double amplitude

(peak-to-peak amplitude):

3000r/min

Satisfactory 0.076

Alarm 1 0.127

Trip or other 0.254

Suitable action 2 1 Rebalancing is indicated if vibration is continuous and of the unbalanced type. Under

special conditions, the turbine may be run at higher vibration levels for short periods of

time under close supervision. 2 Other suitable action may be load change, speed change, etc., according to specific

conditions.

1.3 ROTOR POSITION

Based on a nominal thrust bearing clearance of 0.38mm and a maximum expected

thrust bearing load of 4.13MPa, the alarm limit and trop limit are reached when the thrust

bearing move a distance of 0.89 mm from the middle of thrust bearing tile at any

directions. Trip limit value is defined of a distance of 1.0 mm. If the thrust bearing

clearance is less than or greater than 0.38mm, adjust the alarm and trip limit using 1/2 of

the difference between actual value and 0.38mm.

1.4 CASING EXPANSION

There are no "Alarm" and "Trip" limits established for casing expansion. Turbine

expansion values from this instrument should be compared to previous readings at the

Page 2 of 21


same operating conditions. Large deviations from previous values should be explained

and corrected usually by greasing the sliding surface between the pedestal base and sole

plate. Sometimes it is also necessary to bump the pedestal.

1.5 DIFFERENTIAL CASING AND ROTOR EXPANSION

The alarm and trip settings vary with turbine configuration. Specific values will be

provided in the “Turbine Control Settings”.

2 BEARINGS TEMPERATURE AND PRESSURE 2.1 METAL TEMPERATURE-TURBINE

(1) The alarm and trip limits for bearing Babbitt temperatures depend on the type of

bearing.

For the Viscosity-pump journal bearing, bearing babbitt temperatures up to 91℃ are

considered normal. The alarm should be set at 107℃, and the trip at 113℃.

(2) Tilting-pad journal bearings have the same temperature limits as the viscosity-pump

journal bearings above.

(3) For thrust bearings, babbitt temperatures up to 85℃ are considered normal. The alarm

setting is 99℃, and the trip setting is 107℃. The thermocouples used to measure thrust

bearing temperatures are at the center of two shoes at the governor end and two at the

generator end of the bearing. Each of these four shoes contains a center and a leading edge

thermocouple. Temperatures from the center of the shoes should be recorded continuously

on a printing recorder. The leading edge thermocouples should be monitored in case

problem diagnosis is required.

2.2 OIL TEMPERATURES-TURBINE

(1) Do not start the motor-operated bearing oil pump if the temperature of the oil in the oil

reservoir is less than 10℃. For turning gear operation and during the turbine rolling

period, oil temperature should be a minimum of 21℃. If oil temperature is between 10℃

and 21℃, the auxiliary oil pumps should operate till oil temperature more than 21℃.

(2) For continuous operation, bearing oil drain discharge temperatures should not exceed

71℃. The alarm should be set at 77℃. Trip at 83℃.

(3) EH Fluid Temperature

a. Normal 38- 60℃

Page 3 of 21


b. High Temperature Alarm 60℃

c. Trip Temperature None

d. The pumps should not be started until fluid is 10℃ or higher.

e. The fluid system should not be operated until fluid is 21℃ or higher.

f. Tubing should not be routed in areas having an ambient temperature greater than 68℃.

2.3 OIL PRESSURE-TURBINE

(1) Units using the supervisory instrument have thrust alarms and trips initiated by the

rotor position instrument. Set point refers to "Turbine Control Settings".

(2) Bearing oil pressure at the centerline of the turbine-generator unit should be

0.083~0.124MPa(g). Alarm at 0.048~0.062MPa(g). Trip at 0.034~0.048MPa(g).

(3) EH fluid Pressures

a. Normal 12.41~15.17MPa(g)

b. Low Pressure Alarm 10.68~11.38MPa(g)

c. Trip Pressure 9.3MPa(g)

2.4 OIL AND METAL TEMPERATURES-GENERATOR/EXCITER

Type of Measurement r/min Normal up to℃ Alarm℃ Trip℃

Metal 3000 85 99 107

Oil Drain 3000 71 77 --

Oil and metal temperatures-generator/exciter just for information, detail specifications

refers to Generator Instruction book.

3 STEAM CONDITIONS TEMPERATURES PRESSURES AND

MOISTURE (1). Initial first stage metal temperature and/or IP blade ring metal temperature below 204

℃ defines the condition when “cold starting procedures” apply.

(2). When starting a warm or hot turbine unit (initial first stage metal temperature of 204

℃ or higher), it is recommended that the steam conditions at the throttle valve inlet be

controlled to produce first stage steam temperatures which are within a range of not more

than 56℃ below or more than 111℃ above the initial first stage metal temperature.

(3). To facilitate matching of first stage metal and steam temperatures on start up, start up

steam conditions at the throttle valves should be selected on the following basis:

Page 4 of 21


a. . For cold starts use steam at the pressures and temperatures shown on “Startup Steam

Conditions”. Starting conditions for a cold turbine should be selected so that there is at

least 56℃ of superheat in the steam to the throttle valves.

b. . For hot starts use steam in the acceptable range, but at low pressure and high

temperature to minimize the temperature loss from throttling the steam through the

throttle and/or governor valves.

(4). The allowable temperature differences in steam chest metal, measured by deep and

shallow thermocouples in the steam chest wall, are shown on Figure 1 for fossil units.

Figure 1 Steam Chest Metal Temperature Allowable Difference-Deep and Shallow

Thermo-couples

EXAMPLE 1. WHEN THE STEAM CHEST DEEP METAL THERMOCOUPLE INDICATES A

TEMPERATURE OF 316°C THE ALLOWABLE DIFFERENCE BETWEEN DEEP AND

SHALLOW TEMPERATURES IS 113°C.

(5). The steam delivered through any turbine throttle valve must be within 14℃ of the

steam delivered simultaneously through any other throttle valve. During abnormal

conditions, this difference may be as high as 42℃ for periods of 15 minutes maximum

duration provided that such occurrences are at least four hours apart.

(6). The steam temperature at the turbine throttle valve inlet connections shall average not

more than rated temperature over any 12-month operating period. In maintaining this

average the temperature during normal operating conditions shall not exceed rated

Page 5 of 21


temperature by more than 8℃.

During abnormal operating conditions the temperature at the turbine throttle valve inlet

connection shall not exceed rated temperature by more than 14°C for operating periods to-

talling not more than 400 hours per 12 month operating period, nor exceed rated

temperature by more than 28°C for swings of 15 minutes duration or less aggregating not

more than 80 hours per 12- month operating period.

(7). The steam temperature at the turbine reheat stop valve inlet connections shall average

not more than rated reheat temperature over any 12- month operating period. In

maintaining this average the reheat temperature during normal operating conditions shall

not exceed rated reheat temperature by more than 8°C.

During abnormal conditions reheat temperature shall not exceed rated reheat temperature

by more than 14°C for operating periods totaling not more than 400 hours per 12- month

operating period, nor exceed rated reheat temperature by more than 28°C for swings of 15

minutes duration or less, aggregating nor more than 80 hours per 12- month operating

period. In maintaining the above reheat temperature averages the steam delivered through

any hot reheat stop valve must be within 14°C of the steam delivered simultaneously

through any other hot reheat stop valve. During abnormal conditions the difference can be

as high as 42°C for periods of 15 minutes maximum duration providing the occurrences

are at least four hours apart.

(8). For adequate steam chest warming prior to transferring from throttle valve speed

control to governor valve speed control the temperature of the inner surface of the steam

chest measured by the thermocouple closest to the inner wall (deep thermocouple) should

be equal to or greater than the saturation temperature corresponding to the prevailing

steam pressure ahead of the throttle valves. At transfer, the temperature of steam to the

throttle valves should equal or exceed values given by the curve labeled “MINIMUM

THROTTLE VALVE INLET STEAM TEMP. AT TRANSFER” in “Startup Steam

Conditions”. These temperatures should help prevent the formation of large quantities of

water when the steam chest pressure is raised as a result of transferring speed control to

the governor valves. An alternate method of arriving at the steam chest inner surface

(metal) temperature to determine if the speed control transfer can be made is to solve the

following equation which is also used in the DEH computer software:

Ts=T1+1.36(T2-T1)

Page 6 of 21


Where Ts = Steam Chest Inner Surface Metal Temperature

T1 = Shallow Thermocouple Temperature Reading

T2 = Deep Thermocouple Temperature Reading

(9). Where the main steam inlet and hot reheat inlet connections are arranged in the same

turbine casing, temperature differences between the main steam and reheat steam inlets

must be controlled to optimize the design life of the apparatus. The difference between the

main steam and hot reheat temperatures should not deviate from the difference at rated

conditions by more than 28 . During abnormal conditions, deviations as large as 42 ℃ ℃

are acceptable provided the differences are limited to a reduction of the hot reheat

temperature with respect to the main steam, inlet temperature.

These limits, in general, are assumed to apply at operating conditions near full load. As

the load reduces, it is assumed that the hot reheat temperature will be below the main

steam inlet temperature, in which case the difference may approach 83 as the load ℃

approaches zero. Short time cyclic temperature fluctuations are to be avoided. When the

unit is at full load, the 28℃ limit can be with either the main steam or hot reheat 28"C

higher than the other. See Figure2.

All other temperature limits 42°C and 83°C apply only with reheat temperature lower than

main steam temperature. IN ADDITION, NONE OF THESE ALLOWANCES CAN

BE USED TO EXCEED THE LIMITATIONS PLACED ON MAIN AND REHEAT

STEAM DEVIATIONS FROM RATED CONDITIONS.

Page 7 of 21


(10). The temperature difference between the cylinder cover inner surface and the cylinder

base inner surface of the HP and IP inner and outer cylinders should not exceed 56°C with

the base colder. Alarm at 42°C; trip at 56°C. Sudden increases in the normal temperature

difference between a cylinder base and cover with the base colder indicates the presence

of water in the base of the cylinder. Drains should be opened immediately.

When an extraction connection is in the turbine cylinder cover instead of the base,

consult manufacturer for the temperature difference limits between the base and cover and

the thermocouples to be used for the comparison to determine if water is present.

(11). Steam supplied at any turbine gland should contain at least 14 of superheat℃ .

(12). The temperature limits for steam measured in LP turbine gland cases are 121 ℃

minimum and 177 maximum. The gland system desuperheater should be set℃ at 149 . ℃

These limits cannot be applied to steam throttled to lower temperatures to seal low

Page 8 of 21


pressure turbine glands.

(13). The temperature difference between sealing steam and rotor metal in glands of HP,

IP or HP-IP turbines should be limited to 111 . F℃ or the effects of greater differences

refer to Chart “Gland Sealing Steam Temperature Recommendations”.

(14). Manufaturer recommends that the gland system spillover steam be routed to the

main condenser as insignificant heat rate loss is involved. However, the purchaser may

elect to route the spillover steam to an LP heater. If the heater option is selected, it is the

purchasers’ responsibility to limit the temperature of the spillover steam, or steam from

any source, when the heater is out of service so that the temperature of steam back

flowing to the turbine through the extraction pipe is not more than 56 higher than the ℃

temperature of the turbine extraction zone where the steam enters the turbine cylinder.

(15). On fossil units, primary desuperheating of steam to low pressure turbine glands is

accomplished by heat loss from the bare, unsinuated gland steam supply piping in the

condenser space to minimize the use of spray water. The final increment of

desuperheating, and the control of steam temperature in the glands, is accomplished by the

use of a (water) spray desuperheater mounted in the common gland steam supply header

to the low pressured turbine glands. To permit this system to function effectively, steam to

the desuperheater should be about 315 to ensure that the main unit LP glands can ℃

operate in the range of 121 To 177 .℃ ℃

If boiler feed pump turbine (BFPT) and main turbine are used together, gland steam for

the BFPT is taken from the low pressure turbine gland steam header upstream of the

desuperheater and cooled enroute to the BFPT glands by a separate desuperheater.

Should the purchaser attempt to desuperheat the gland sealing steam for this turbine by

taking it from the common gland steam supply header downstream of the desuperheater

for the LP turbine glands, steam at this location may range from 260℃-315℃ depending

on the amount of desuperheating in the gland steam supply lines in the condenser neck.

This is too hot for the glands of the BFPT. Hence, a separate desuperheater is used. When

the BFPT is furnished by another manufacturer for use with a main unit, and gland steam

is to be supplied to the BFPT from the main unit gland system. The purchaser should

provide a separate desuperheater for the BFPT glands.

(16). To avoid heating the turbine exhaust beyond allowable limits, apply gland sealing

steam, start air removal equipment and maintain as high a vacuum as possible during the

Page 9 of 21


starting period. Exhaust temperature limits are as follows:

a. Turbine exhaust temperature (steam) should not exceed 79 for continuous operation ℃

or 121 for periods of about 15 minutes. Should temperature above the continuous ℃

operating limit occur, reduce these temperatures to the continuous operating range in

fifteen minutes or trip the unit. These limits apply with the exhaust hood sprays out of

service. The LP turbine exhaust steam temperature limit with the exhaust hood sprays in

service is the saturation temperature corresponding to condenser pressure.

b. Turbine exhaust temperature (steam) for unusual conditions should not exceed 121 . ℃

For example, if steam is bypassed to the condenser before the turbine is rolled, the

maximum, allowable exhaust temperature is 121 providing no problems develop. ℃

However, experience shows that under some conditions (such as cold start) heat rising

from the condenser will cause a "rotor short" differential expansion condition which

results in rubs between rotating and stationary parts. In the past this has usually been

detected with the unit on turning gear when the rotor locked with turbine exhaust steam

temperatures less than 93 .℃

c. A separate exhaust hood spray system is provided for each low pressure cylinder. The

purchaser must furnish an individual on-auto-off switch for each spray system to facilitate

use of the sprays to handle certain abnormal operating conditions that may occur in

individual low pressure cylinders.

d. The temperature difference between multiple adjacent or nonadjacent LP outer casings

should not exceed 17℃, alarm at 11℃ differential and trip the unit at 17℃ differential.

(17). The average initial pressure at the turbine inlet over any 12 months of operation shall

not exceed the rated pressure. In maintaining this average, the pressure shall not exceed

105% of the rated pressure. Further accidental swings not exceeding 20% of the rated

pressure are permitted, provided that the aggregate duration of such swings over any 12

months of operation does not exceed 12 h.

An increase in initial pressure will normally permit the turbine to generate power in

excess of its normal rating, unless action is taken through the control system to restrict the

steam flow rate. The generator and associated electrical equipment may be unable to

accept such additional output, and undesirable stresses may also be imposed on the

turbine; the purchaser shall accordingly provide load-responsive protective means to limit

the turbine output under such circumstances.

Page 10 of 21


(18). The pressure at the exhaust connection of the high pressure turbine shall not be

greater than 25% above the highest pressure existing when the high pressure section of the

turbine is passing the maximum calculated flow with rated pressure and normal operating

conditions. Suitable relief valves must be provided by the Purchaser.

(19). If an initial steam pressure limiter [Throttle Pressure Limiter (TPL)] is used it is

usually set to cut in on decreasing throttle pressure at 90% to 95% of rated pressure. With

the regulator in service, load reduction is proportional to pressure reduction to a preset

minimum limit of 20% to 25% load. If the throttle pressure falls below 80% of rated

pressure, or if throttle or reheat temperature drops uncontrolled more than 66 (℃ 66 in ℃

less than 30 minutes) remove load and trip the unit.

4 CONDENSER VACUUM (TURBIBE BACKPRESSURE) (1). Maximum allowable low pressure turbine exhaust pressure for continuous on-line

operation above 10 percent load is 18.6kPa abs. Alarm and trip settings for units are:

Description Unit (kPa abs)

Alarm 16.9

Trip Alarm 18.6

Automatic Trip 20.3

(2). Vacuum should be maintained on a trip out or normal shutdown until the unit coasts

down to about 10% of rated speed provided that no emergency is involved in the trip out

or shutdown that requires vacuum to be broken immediately after the turbine throttle,

governor, interceptor, and reheat stop valves close. Vacuum should be broken

immediately after a unit is tripped and in free coastdown if any condition exists when

possible damage to the unit can be reduced by shortening coastdown time. Examples of

incidents requiring vacuum to be broken immediately after a trip include, but are not

restricted to: loss of AC power, loss of DC power, low bearing oil pressure, loss of

lubricating oil, loss of cooling water to turbine oil coolers, thrust bearing trip, water in the

turbine, any indication of rubbing between rotating and stationary parts, or excessive

vibration on coastdown.

(3). Avoid breaking vacuum before critical drain valves are open. This recommendation

does not apply in an emergency requiring vacuum to be broken immediately.

(4). Avoid at all times leakage of steam into the turbine casings with the rotors at rest.

Page 11 of 21


(5). Avoid air being drawn through the glands with the rotors at rest. Therefore, do not

operate the air ejectors or vacuum pumps without sealing steam on the turbine glands. The

unit should always be put on turning gear before admitting steam to the turbine glands.

(6). The Purchaser must provide an adequate supply of steam to seal the turbine glands at

all times, including during coastdown following a unit trip. This is essential to insure that

air does not leak into the turbine through the rotor glands causing thermal distortion

(chilling) of the gland cases which may result in damage from rotor vibration induced by

rubs between gland seals and the rotors.

(7). On some units using seawater for circulating water, condenser circulating water

channels are periodically back flushed with warm water (about 46℃-49 ) to kill some ℃

marine life. To do this, the circulating water is heated in the condenser tubes by raising

low pressure turbine exhaust pressure. Before committing to such a procedure, obtain

approval of the specific details from manufacturer as there are limits on turbine operation

for this procedure, including load and exhaust pressure.

(8). The large blading at the exhaust end of the LP turbine blade path passes through

several resonant speed ranges whenever the unit is rolled to rated speed. Do not hold

speed in these resonant ranges for extended periods as extensive blade damage may result.

The magnitude of the condenser pressure may have a significant influence on the possible

damage resulting from operating in blade resonant speed ranges. The actual resonant

range for each unit will be in the instruction book.

(9). Pressure differences between active and inactive condenser result in uneven flow

distribution to the low pressure turbine blading resulting in possible operating difficulties.

The maximum permissible pressure difference between multiple condensers (or condenser

Zones) is 8.6kPa(a); alarm at 6.9kPa(a) differential and trip the unit at 8.6kPa(a). We

recommend that the turbine be removed from service if it is necessary to remove one full

condenser from service.

(10). If detail announce received in advance, the unit which has multiple LP turbines can

be operated with one full or part condenser out of service. Necessary limits should be put

before operating as following:

a. The area of the condenser or part condenser in and out of service should be large

enough to meet all operating limits and precautions.

b. Comply with the load limits. Nominal minimum load is 20% rated load, and maximum

Page 12 of 21


load is 80%. The unit precise load limit should be determined before operating at this

abnormal condition.

c. The LP turbine exhaust pressure must be limited in normal range.

d Should comply with other operation limits, precautions of turbine and cycle systems.

5 WATER INDUCTION (1). For detailed design recommendations see “Water in The Turbine” of this manual.

(2). Drain Systems-Fossil-Fueled Units

A. All turbine drains and other drains critical to turbine safety must:

a. Be open when the unit is out of service until the turbine is cold.

b. Be opened before the turbine is started and before gland steam is supplied to the

glands.

c. Remain open on increasing load until the unit is carrying 10% of rated load for

drains from sources upstream of the turbine reheat stop valves.

d. Remain open until the unit is carrying 20% of rated load for drains from sources

downstream of the turbine interceptor valves.

e. Open on decreasing load at 10% of rated load and remain open below 10% of rated

load for drains from sources upstream of the turbine reheat stop valves.

f. Open on decreasing load at 20% of rated load and remain open below 20% of rated

load for drains from sources downstream of the turbine interceptor valves.

B. Drain pipe thermocouples should be provided for startup by the purchaser as a

permanent installation. On every startup, monitor each drain pipe thermocouple over the

operating load range up to the point where drains are closed. These thermocouples should

be the strap-on, spring loaded type that press against the outside of the pipe. It is not

necessary to penetrate the pipe or peen the thermocouple into a small hole drilled into the

pipe wall. The thermocouples should be located at least 1220 mm but not more than 1830

mm downstream of each drain valve including the two drain valves for the turbine steam

inlet loops. Each (turbine) steam inlet loop drain should also have a thermocouple

installed at about the mid-point between the source and the orifice block. The drain lines

and valves should all be insulated from the source to a point 915 mm past the

thermocouples. Insulation thickness should be that required for the maximum temperature

of the drain source at any operating condition regardless of whether or not normal

Page 13 of 21


operating procedures require the drain valves to be open when these maximum condition

exists.

(3). On initial startup, read and record the pressure gauge indication on each drain

manifold with the unit on turning gear and at each speed and load hold while the drains

are open (usually up to 20% load). If the pressure in any manifold exceeds the pressure of

the lowest pressure source routed to that manifold, shut the unit down and correct the

problem.

(4). When the boiler is tripped through loss of firing or other causes, the turbine unit

should be tripped immediately.

(5). Do not admit steam to the turbine after the boiler fires have gone out.

(6). A number of cold reheat piping systems and turbines have been damaged by water

hammer in steam (clod reheat) lines when turbines were latched-up for startup. Therefore,

do not latch-up a fossil turbine if there is water in the cold reheat lines.

6 CONTROL SYSTEM TEST The frequency of the periodic functional tests listed below should be increased if

operating experience indicates that more frequent testing is required.

TEST OFF LINE

ON LINE

TEST FREQUENCY

OVERSPEED Mechanical Overspeed × Twice a year Overspeed Trip Mechainsm Oil Pressure Check × Monthly

Overspeed Protection Controller × Twice a year Solenoid Trip × Twice a year

STEAMINAET VALVES

Throttle Valves × Weekly

Governor Valves × Weekly

Reheat Stop Valves × Weekly Interceptor Valves × Weekly

Throttle Pressure Controller × Twice a year

PROTECTIVE TRIP SYSTEM Low EH Fluid Pressure × Monthly

Page 14 of 21


TEST OFF LINE

ON LINE

TEST FREQUENCY

Low Bearing Oil Pressure × Monthly

Low Vacuum × Monthly

Turbine Overspeed-Electrical × Monthly Purchaser’s Remote Trip (Optional) × Monthly Thrust Bearing Trip × Monthly

PROTECTIVE TRIP SYSTEM SETPOINTS Low EH Fluid Pressure × Twice a year Low Bearing Oil Pressure × Twice a year Low Vacuum × Twice a year

Electrical Overspeed × Twice a year

LUBRICATION OIL SYSTEM

Bearing Oil Pump (BOP) Running × Weekly

Seal Oil Backup Pump (SOB) Running × Weekly

Emergency Oil Pump (EOP) Running × Weekly

Oil Pump Pressure Switch Setpoints × Monthly Bearing Lift Pumps × Twice a year

SEAL OIL SYSTEM Air Side Seal Oil Backup Pump × Weekly Pressure Switch Setpoints × Monthly Backup Tests × Monthly

EH FLUID SYSTEM EH Fluid Standby Pump × Weekly

ETRACTION SYSTEM VALVES Air Test × Weekly Mechanical Test × Monthly

7 GENERAL (1). Avoid all excessive and unnecessary thermal cycling of heavy metal parts.

(2). The damaging effect of transient operation on the rotor is dependent on the magnitude

of change in steam temperature at the rotor, the rate of this change and the number of

repetitions of heating and cooling cycles.

Page 15 of 21


(3). The overspeed trip will normally be set to trip the unit at 111% of rated speed. Some

turbines may require other overspeed trip settings.

(4). Immediately prior to making the initial check of the emergency overspeed rip devices,

operate units at 10 percent of rated load for 4 hours. The purpose of this load hold is to

stabilize rotor temperatures at the 10 percent load level to avoid adding the thermal

stresses inherent in an unstable condition to the higher stress from increased centrifugal

forces generated at overspeed.

Ten percent load is both a minimum and maximum for the initial check of emergency

trip devices and subsequent checks following maintenance that physically disturbs these

devices. Values above 10 percent may lead to increased damage in the event of a

malfunction which causes all or some of the main and reheat steam valves to remain open

should a trip occur during the pre-overspeed rotor soaking period. Values of less than 10

percent may require substantially longer rotor soaking times to stabilize temperatures,

increase the likelihood of motoring the turbine and increase the likelihood of unacceptably

high blade path temperatures in the low pressure turbine. THE PURCHASER SHOULD

ENSURE THAT THE START UP STEAM SUPPLY IS ADEQUATE AND

CONTROLLABLE SO AS TO PERMIT OPERATION AT 10 PERCENT OF

RATED LOAD FOR INITIAL START UP AND THEREAFTER FOR ALL

STARTUPS in accordance with recommended rolling and loading rates.

If the temperatures of high and intermediate pressure rotors are above 121 , normal ℃

operating loads greater than 10 percent can be used for rotor soaking after the initial

startup. However, unstable rotor temperatures may exist during the overspeed test if there

is no hold at low load to allow temperatures to stabilize after reducing load from the

operating value in preparation for a trip from low load to make the overspeed check.

Therefore, if rotor temperatures are not above 121 , reduce load to 10 percent of rated ℃

load in accordance with information in the turbine instruction book and soak at 10 percent

load for the required period. Whether or not a heat soak is required, once started, the test

should be made promptly to reduce the chilling effect of the steam flow during the test.

(5) A flow of 2 to 3% of the maximum calculated throttle flow should be adequate to

bring a unit to rated speed. However, we recommend that 5% of the maximum calculated

throttle flow be used when sizing equipment or providing steam generation capacity for

start up.

Page 16 of 21


(6) It is recommended that minimum load for normal on-line operation be 5% of rated

load.

(7) Auxiliary load may be carried on manufacturer turbine-generator units after a major

load loss in which the generator separates from the system providing the purchaser is

willing to accept the reduction in rotor life inherent in such operation. Most

turbine-generator units are designed to withstand complete isolation from the system and

remain in service at no load or at an auxiliary load level. However, it should be

recognized that some of the larger plants now in operation, and under construction, have

plant control interlocks which automatically trip the complete plant in the event of load

separation.

The transient thermal stress in the turbine rotor is a factor to be considered when

suddenly dropping from full power output to auxiliary load and the subsequent rapid

application of load after the connection to the system is reestablished. The immediate

effect is an instantaneous drop in first stage temperature of about 139 , followed by a ℃

further decrease of 111 in about 15 minutes as the superheater outlet temperature ℃

adjusts to the newly established firing rate. This drop in first stage temperature produces a

peak stress in 10 to 15 minutes after initiation of the transient which decays slowly to zero

in about one hour. If auxiliary load is maintained for an hour or more, the rotor is

force-cooled to a new equilibrium state. The subsequent reloading should then be

performed at a moderate rate in order to avoid a large thermal stress in the opposite

direction.

For a typical 3000 r/min rotor, the peak stress associated with dropping from full load

to a auxiliary load can be expected to initiate cracking in the rotor after 100 to 400 cycles

of complete stress reversals. A single cycle of this magnitude would, therefore, account

for approximately 0.25% to 1% of the total fatigue capacity of the rotor for normal load

changes, but this reduction is not excessive unless many such transients occur. To

minimize the accumulation of rotor fatigue damage, it is recommended that auxiliary load

operation following a load loss occur only when the system conditions make it absolutely

necessary.

If auxiliary load is carried on unit turbine-generator, instruments should be closely

observed during these periods of light load operation, particularly the turbine differential

expansion meter (s). If the instruments indicate that continued operation at light load will

Page 17 of 21


cause allowable operating limits to be exceeded, the unit must be removed from service or

sufficient load applied to reestablish safe operating conditions.

The minimum allowable load when connected to the system is 5 percent of rated load.

The minimum allowable load when disconnected from the system is auxiliary load as

described below. Loads of less than 5 percent are allowed when the generator is

disconnected from the system because the turbine cannot be motored. Hence, while

overheating of low pressure end blading is a concern at the low flows involved in either

case, unacceptable overheating of low pressure end blading and other blading in the unit is

much more likely when operating at very low loads connected to the system than when

operating at the same low loads disconnected from the system. When carrying auxiliary

load disconnected from the system, the governor valves control turbine speed. Should the

governor valves close for any reason, steam flow is cut off and turbine speed decreases

until steam flow is restored or the unit comes to rest. This is not the case when the

generator is connected to the system. In this case, any perturbation that increases system

frequency can cause the governor valves to move in the closed direction.

If throttle steam flow is cut off or reduced too much, the generator will act as a motor to

drive the turbine at rated speed, but overheating of blading is likely because of insufficient

cooling steam flow through the turbine. When a generator acts as a synchronous motor to

drive the turbine, this is called conventional motoring which should not be confused with

the condition that exists when the generator is connected to the system at other than

synchronous speeds. To minimize the likelihood of conventional motoring we recommend

a minimum load of 5% of rated load when the generator is tied to the system.

(8). Coastdown time following a turbine-generator trip differs significantly from unit to

unit for a number of reasons with inertia of the rotors and condenser pressure during the

coastdown having the greatest influence. Batteries for emergency DC power should be

sized for coastdown time based on maintaining vacuum in the condenser. To assist our

customer with sizing these batteries, we will provide DC power requirements for the

turbine-generator-exciter during coastdown along with the calculated time to bring the

rotors to rest both when maintaining vacuum and breaking vacuum.

(9). Crossties for flow equalization may be required between the purchaser’s main steam

pipes for fossil units and between hot reheat pipes of fossil units. These crossties may be

needed for valve testing or normal operation or both. Whether or not crossties are needed

Page 18 of 21


depends on a number of factors such as steam generator design, the number of pipes and

piping arrangement.

(10) A turbine-generator unit should not be motored for extended periods. It is

recommended that such operation be limited to not more than 1 minute of inadvertant

motoring.

(11). Anti-motoring schemes which emphasize overspeed protection should be designed

not only to provide assurance that throttle, governor, interceptor, and reheat stop valves

are closed before the generator is separated from the system, but also to provide assurance

that feedwater heaters or extraction system are not supplying sufficient fluid to the turbine

to cause unacceptable overspeed. Out of 14 reported overspeed incidents, 5 were caused

by extraction non return valve malfunctions or failures and none were attributed to turbine

main steam or reheat valves vailing to close. Therefore, manufacturer does not

recommend valve limits witches in anti-motoring schemes devised primarily for

overspeed protection. These switches do not protect against the feedwater heater,

extraction system or any external steam supply that can bypass the turbine main steam or

reheat steam valves and enter the turbine. In addition, some limit switches may not be

sufficiently reliable for this application. When the experience of a specific operating

company indicates that limit switches are sufficiently reliable to meet their requirements,

and they elect to use them, they should be arranged with the throttle and governor valve

switches paralleled and in series with paralleled interceptor and reheat stop valve switches.

In addition, protection against fluid flow from the feedwater heaters and extraction system

must be included in the scheme. Reverse current relays are preferred for this duty. The

current trend in anti-motoring circuits is to emphasize overspeed protection at the expense

of motoring protection. For years, motoring for more than 1 minute has been unacceptable.

Nothing has changed. Motoring in excess of 1 minute should be avoided, but if it is done

for overspeed protection, the purchaser must accept responsibility for any damage that

results.

(12). When an auxiliary boiler is provided in a power plant to supply miscellaneous

quantities of steam for such purposes as gland sealing or deaerator pegging, the type of

boiler and the pressure and temperature rating should be considered carefully. When

selecting the boiler, verify that the pressures and temperatures required can be obtained

over the load range. For example, an auxiliary boiler rated at 4536kg/h at 316 could ℃

Page 19 of 21


only provide steam at 204 when steam generation was limited to 9072kg/hr for sealing ℃

turbine glands. This prevented matching steam and rotor metal in the gland areas within

required temperature difference limits for hot starts. The temperature and pressure ratings

of an auxiliary boiler should be carefully selected with due consideration of the

requirements of “Gland Sealing Steam Temperature Recommendatios” and the reduction

in temperature when throttling auxiliary steam to the turbine gland system.

(13). If reheat attemperating spray water is used, the following conditions must be

observed: Using the maximum calculated heat balance as a base, the quantity of reheat

attemperating spray water must be measured. The load must then be reduced from the

load shown on the base heat balance by 0.6% for each 1% of reheat attemperating spray

water measured as a percentage of throttle flow shown on the base heat balance.

(14). Manufacturer furnishes a dump valve on each reheat stop valve of many units. When

the unit trips, these dump valve vent steam from the chamber at the internal end of the

reheat stop valve dapper shaft. The clapper shaft of each reheat stop valve has one end

exposed to atmosphere and one end to full reheat pressure. In operation, the net force

caused by this pressure difference pushes the shaft towards the atmospheric end so that a

shoulder on the shaft seats firmly against a spherical washer. This contact forms

metal-to-metal seals which help prevent steam leakage along the clapper shaft to

atmosphere. When the unit trips, the pres-shaft must be eliminated quickly to reduce

friction between metal surfaces of the seal. This helps prevent unacceptable, frictional

resistance to closure of the reheat stop valves. Each line from these valves to the

condenser must be sized for a maximum pressure drop of 0.207MPa (including exit losses

at the condenser) when passing 1815kg/hr of steam at the reheat enthalpy given on the

maximum calculated heat balance. The maximum allowable pressure at the discharge

(purchaser’s connections) of the dump valves is 0.234MPa. The purchaser's vent lines

should be larger than the connections on the dump valves, and may be several sizes larger.

No other valves, or restrictions such as orifices, are permitted in vent lines. These vent

lines must be routed to separate connections at the condenser.

(15). To avoid overheating HP turbine blading immediately following a high load turbine

trip or load loss, manufacturer furnishes (if require) the ventilating valves for HP turbine

elements requiring ventilation because following a trip from high load, windage heating

may increase the temperature of steam bottled-up in the HP blade path enough to damage

Page 20 of 21


the blades and other turbine components. The temperature increase occurs rapidly and to

avoid unacceptable temperatures, ventilation is required. Some HP turbine elements have

sufficient internal ventilation so that separate vent valves are unnecessary. However, some

HP turbine elements require supplementary ventilation. When vent valves are provided

the discharge of these valves must be routed by the purchaser to individual connections on

the condenser wall or to individual connections on a short manifold mounted on the

condenser wall. Only the disconnected to this manifold.

The flow area between the condenser wall and internal impingement baffles over the

vent valve discharge openings in the condenser must be large enough to minimize

restriction to vent flow into the condenser, but not less than 2.5 times each vent line or

manifold cross-sectional area.

There must be no other valves or restrictions, such as orifices, in the vent lines. Since

the increase in the temperature of bottled-up steam in the HP blading occurs rapidly, vent

valves must open quickly. To avoid restricting the discharge of air from the vent valve

actuators on a trip or load loss, and thus slowing valve opening, do not use air piping sizes

smaller than the 20mm recommended by manufacturer. Also, locate the 20mm solenoid

dump valve connection close to the vent valve actuators in the common airline before it

separates to the two valves. Design the air piping to permit the solenoid to be close to

each actuator. There should be a vent connected from one main steam inlet loop from

each steam chest.

(16). Nonreturn valve (NRV) actuators should close in 0.5 to 1 second maximum on load

loss or turbine trip involving separation of the generator from the electrical system to

effectively back-up the other (two) clapper closing forces.

To accomplish this rapid closure, the purchaser must furnish a three-way solenoid valve

immediately adjacent to each NRV actuator to dump the air in the required time.

Experience has shown repeatedly, that without adequate capacity to dump air from NRV

actuators, these actuators close in 3 to 4.5 seconds. Closing times of these magnitudes are

unacceptable for both the prevention of excessive overspeed and water damage to the

turbine.

When solenoid dump valves are used as recommended, they can also be controlled to

close NRV actuators on high level in associated feedwater heaters as required by both

manufacturer and the ASME recommendations to minimize water damage to turbines.

Page 21 of 21


When separate solenoids are used as recommended, the oil operated air pilot valve

furnished by manufacturer is used to supply air to NRV actuators and serve as a back-up

dump valve to the occasional solenoid valve that malfunctions.

(17). For many years, manufacturer producted steam turbines have been equipped with a

steam cooling system to reduce the temperature of the reheat steam which bathes the

blade roots and rotor at the inlet to the intermediate pressure turbine(IP). This cooling

steam is required to improve the creep strength of the blade roots and rotor in the affected

area and to reduce the likelihood of rotor bowing. Considering the serious consequences

of having insufficient cooling steam, it is essential that an adequate supply be provided

whenever the unit is in operation and reheat temperature is above 482℃.

The cooling steam flow paths of combined high pressure-intermediate pressure turbine

elements are internal and cannot inadvertently be blocked (unless altered during a

shutdown for repairs). Separate IP turbine elements have a combination of internal and

external folw passages for cooling steam which can be blocked by closed valves. By

flanges containing blanks for blowdown, or foreign material in the pssages. For this

reason manufacturer recommends that:

a. There be no valves in cooling steam pipes;

b.There be no flow restrictions in cooling steam pipes except the flow measuring device

provided by manufacturer;

c. There be a complete check of the cooling steam system before initial startup of the

unit, before any restart following disassembly of the IP element, and before restart after

maintenance which otherwise disturbs the cooling steam flow passages. This check is to

ensure that the cooling system does not contain closed valves, solid spacers in flanges or

other foreing materal that blocks or restricts flow. The portion of the system inside the IP

cylinders must be inspected after the IP is assembled and before the cooling steam pipes

are connected to the cylinder.

If a preheating system is used on unit which requires a valve in the cooling steampipe,

it is imperative that the purchaser consult manufacturer about essential protective

provisions.

Page 1 of 1


Compiled：Yu Yan 2008.09Turbine Speed Hold Recommendations Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


Turbine Speed Hold Recommendations

Do not hold speed in a resonant speed range for an extended period. If a hold is

necessary, reduce speed below the resonant range before holding. The LP turbine blade

resonant speed range should be avoided which are shown cross hatched below. The

turbine-generator shaft critical speed refers to drawing “Shaft System Alignment”.

For a cold start, hold the speed out of blade resonant speed range and shaft critical speed,

for the warming period determined from the curve “cold-start rotor warming procedure”.

0 50000 1000 1500 25002000

1620

1950

3000 (r/min)

2515

2820

2120

2295

1775

1475

This curve is applicable for the turbine with L-0 blade height is 905mm and L-1 blade

height is 518mm.

Page 1 of 1


Compiled：Yu Yan 2008.09Cold Start Rotor-Warming Procedure Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


COLD START ROTOR-WARMING PROCEDURE This procedure consists of accelerating the turbine to a speed specified on the chart

“Turbine Speed Hold Recommendations” and holding at that speed for a warming period

determined from the curve below. Prior to the first attempt to roll the turbine, observe the

First Stage Metal and the IP Blade Ring temperatures and use the lower temperature

reading to determine the rotor warming period from the curve. This rotor warming period

begins after the IP inlet steam temperature reaches a minimum of 260℃ . And

rotor-warming is not necessary for no-bore rotor from thermal stress side.

First Stage Metal or the IP Blade Ring temperatures

Page 1 of 3


Compiled：Yu Yan 2008.09Start Recommendations For Rolling & Minimum

Load Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


START RECOMMENDATIONS FOR ROLLING & MINIMUM

LOAD

EXAMPLE

Determine the time to roll to rated speed (3000r/min), synchronize and hold at minimum

load with first stage metal temperature at 260℃ prior to rolling off turning gear, and

throttle steam conditions existing at no load synchronous speed at 6.86MPa-425℃. During

the minimum load hold, the steam inlet conditions increase to 10.3MPa-510℃. Single

valve control is used during the synchronization and minimum load operations.

PROCEDURE

Enter Figure 1 at throttle conditions 6.86MPa 425℃ and project to the single-valve 5%

minimum load line in Figure 2. The first stage steam temperature for these conditions is

indicated as 360℃. Project the 360℃ steam temperature to the 260℃ “Initial First Stage

Metal temperature” line in Figure 3 to determine a mismatch of steam-metal = 100℃.

Enter Figure 4 with the 100℃ mismatch to the “Roll Time” line. Roll time to synchronous

speed is determined as 22 minutes.

Project the 100℃ mismatch line to Figure 5. It crosses the line marked “0℃ First Stage

Steam Temperature Rise During Hold”. This intersection indicates that 5% minimum load

should be held for 6 minutes if there is no first stage steam temperature change during the

hold. However, in the example the steam inlet conditions are expected to increase during

the minimum load hold; this requires the hold to be extended.

To determine the total length of time to remain at 5% minimum load, enter Figure 1 at

the 10.3MPa -510℃ steam conditions that are expected to be reached at the end of the 5%

Page 2 of 3


load hold. Project to the single-valve line in Figure 2. The first stage steam temperature is

432℃. The rise in first steam temperature is 432-360=72℃ during the hold. In Figure 5

extend the initial 100℃ mismatch to a 72℃ “First Stage Steam Temperature Rise” point.

A hold time of 45 minutes is indicated at minimum load.

NOTES

1. If the throttle steam conditions produce a first stage steam temperature cooler than the

metal temperature as indicated by the hatched region below the exact match line in figure 3.

The unit should be rolled to rated speed in 10 minutes, synchronized and minimum loaded

as indicated in Figure 4. There is no minimum load hold period required. Extending the

rolling and loading time will force cool the turbine metal.

2. Figure 3 can be used as a guide to select throttle conditions in Figure 1 which will better

match the residual first stage metal temperature in order to minimize thermal stresses and

starting time.

Page 3 of 3


Page 4 of 3


Star

t rec

omm

enda

tion

for

rolli

ng a

nd m

inim

um lo

ad

Page 1 of 2


Compiled：Yu Yan 2008.09Startup Steam Conditions Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


STARTUP STEAM CONDITIONS

In order to avoid thermal shocking the steam chest, Curve 1 shows the desirable

relationship between throttle valve inlet pressure, throttle valve inlet steam temperature and

Steam Chest Deep metal temperature that should exist before transferring speed control

from the throttle valves to the governor valves. And Curve 2 shows desirable relationship

between interceptor valve inlet pressure and interceptor valves inlet steam temperature.

When Steam Chest Metal temperature is below saturation temperature corresponding to

existing throttle valve inlet pressure, continue operating with throttle valve pilot control

with steam temperature at or above the “Minimum Throttle Valve Inlet Steam

Temperature” shown until the Steam Chest Metal reaches saturation temperature before

transferring to governor valve control.

When starting a cold turbine, the throttle valve inlet steam conditions should be in the

“cold start” region before transferring from throttle valve to governor valve control.

When starting a hot turbine, the throttle valve inlet steam temperature should be above

the curve labeled “Minimum Throttle Valve Inlet Steam Temperature at Transfer” before

transferring from throttle valve to governor valve control.

Page 2 of 2


Curve1 Startup Steam Condition at Throttle Valve

200

250

300

350

400

450

500

550

1 3 5 7 9 11 13 15 17 19 21 23Throttle Valve Inlet Steam Pressure MPa

Thro

ttle

Val

ve In

let S

team

Tem

pera

ture

℃

Cold StartupMinimum Steam Chest MetalTemp. at Transfer (Sat.Temp.)Minimum Throttle Valve Inlet Steam

Temp. at Startup (56℃ SPHT)

Minimum Throttle Valve InletSteam Temp. at Tranfer

Curve 2 Startup Steam Condition at Interceptor Valve

0

50

100

150

200

250

300

350

400

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0

Interceptor Valve Inlet Steam Pressure MPa

Reh

eat T

empe

ratu

re ℃

Max. Reheat Temp.

Minimum ReheatTemp.(56℃ SPHT)

Note: Max.Reheat Temp. also refer to"No Load and Light Load OperationGuide for Reheat Turbine", and selectthe lower temp.

Page 1 of 1


Compiled：Yu Yan 2008.09No-Load and Light Load Operation Guide for

Reheat Turbines Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


NO-LOAD AND LIGHT LOAD OPERATION GUIDE FOR REHEAT

TURBINES FOR OVERSPEED TEST USE THE FULL SPEED-NO LOAD CURVE AND

MAINTAIN STABLE BACK PRESSURE

250

300

350

400

450

500

550

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14

LP Exhaust Pressure kPa

Reh

eat T

emp.

at T

urbi

ne In

let ℃

5% Max. Guaranteed Load

Full SpeedNo Load

Recommendation OperatingLimits For Reheat Turbines

Page 1 of 4


Compiled：Yu Yan 2008.09Load Changing Recommendations Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


LOAD CHANGING RECOMMENDATIONS

1．CONSTANT PRESSURE

50Hz, 16.7MPa(a)-538℃/538℃

STEAM TURBINE DESIGN FOR 50%MINIMUM ARC ADMISSION CONTROL

EXAMPLE1-INCREASING LOAD

Determine the time required and load changing rate to increase load using single valve

mode of operation from 50% at steady state conditions at throttle steam conditions of

11MPa/425℃ to 100% load at rated conditions. Assume a 10,000 cycle fatigue index.

PROCEDURE

Enter Figure 1 at throttle steam pressure at 11MPa. Project vertically to the throttle

steam temperature of 425℃, continue line horizontally to (Figure2)single valve line at 50%

load. The first stage steam temperature for these conditions is 377℃. To determine the

temperature for 100% load. Start at Figure 1 throttle steam pressure at 16.7MPa, project

vertically to throttle steam temperature at 538℃, continue line horizontally to (Figure 2)

100% load. The first stage steam temperature for these conditions is 498℃. The difference

in first stage temperature due to the load change from 50% to 100% is 121℃ (498-377 =

121℃). Enter Figure 4 at the 121℃ (△t) first stage temperature difference. Extend line

horizontally to the 10,000 cycle fatigue index and read 63 minutes (time to change

load/throttle conditions).

RESULTS

By following the procedure above it is determined in example that load can be increased

from 50% to 100% at a uniform rate over 63 minutes for a 10,000 cycles rotor fatigue

index. The load changing rate is 50%/63min. = 0.794%/min.

Page 2 of 4


EXAMPLE 2. DECREASING LOAD

Determine the time and rate to reduce load using sequential valve mode of operation

from 100% at rated throttle conditions to 5% load at rated conditions prior to shutting down

the unit. Assume a 10,000 cycle fatigue index.

PROCEDURE

Enter figure 1 at existing throttle steam pressure of 16.7MPa. Project vertically to the

throttle steam temperature of 538℃, continue line horizontally to (Figure 2) sequential

valve line at 5% load. The first stage steam temperature for these conditions is 382℃. The

existing first stage steam temperature for 100% load is 498℃ (Refer to Example 1). The

change in first stage temperature due to the load change from 100% to 5% is 116℃

(498-382= 116℃ ). Enter Figure 4 at the 116℃ (△t) first stage temperature difference

extend line horizontally to 10,000cycle fatigue index and read 57 minutes (time to change

load/throttle conditions).

RESULTS

The load reduction from 100% to 5% can be made over 57 minutes for a 10,000 cycles

rotor fatigue index. The load changing rate is 95%/57min = 1.67%/min.

2. SLIDING PRESSURE

50Hz, 16.7MPa(a), 538 ℃ /538 ℃

STEAM TURBINE DESIGN FOR 50% MINIMUM ARC ADMISSION CONTROL

SLIDING PRESSURE-SEQUENTIAL VALVE MODES

EXAMPLE

Determine the time required and load changing rate to increase load using both

sequential valve and sliding pressure modes of operation from 5% load at throttle steam

conditions of 11.0 MPa/470 to 1℃ 00% load at rated conditions. Assume a 10,000 cycle

fatigue index.

PROCEDURE

Enter Figure 3 at 5% load. Project vertical to the dotted Line Labeled 11.0MPa which

represents the condition with 2 governor valves partially open. To increase load follow the

11.0MPa dotted line to 53% load at 2 valves wide open. Increase load to 83% by increasing

throttle pressure to 16.7MPa at 2 valves (50%admission) wide open. Increase load to 100%

Page 3 of 4


by sequentially opening 3&4 valves at 16.67MPa. Calculate the change in first stage steam

temperature due to change in load by determining the difference between highest and

lowest first stage steam temperature from Figure 3 (488-436 =52 ), add to this change the ℃

change in inlet steam temperature that occurs during this transient (538-470 = 68 )℃ ， (52

+ 68 = 120 ). On Figure 4 plot this change in first stage steam temperature (℃ 120 ) ℃

against the 10,000 cycle fatigue index to determine that this change should occur in 62

minutes.

RESULTS

By following the procedure above, it is determined that load can be increased from 5%

to 100% at a uniform rate over 62 minutes for a 10,000 cycles rotor fatigue index. The load

changing rate is 95%/62 minutes = 1.53%/min

Page 4 of 4


LOA

D C

HA

NG

ING

REC

OM

MEN

DAT

ION

S

Page 1 of 1


Compiled：Yu Yan 2008.09Cyclic Index for Loading and Unloading at Different

Rates Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


CYCLIC INDEX FOR LOADING AND UNLOADING AT DIFFERENT

RATES

Page 1 of 2


Compiled：Yu Yan 2008.09Gland Sealing Steam Temperature

Recommendations Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


GLAND SEALING STEAM TEMPERATURE

RECOMMENDATIONS To protect against rotor damage in the gland zones resulting from thermal stresses, the

difference between gland sealing steam temperature and rotor surface temperature should

be kept to a minimum when starting and shutting down. The estimated number of cycles to

start rotor cracking due to thermal stresses at various temperature differences between

gland sealing steam and rotor surface metal can be determined from the curve below as

follows:

Page 2 of 2


Page 1 of 1


Compiled：Yu Yan 2008.09Cooldown Time for A Typical Fossil Hp Turbine Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


COOLDOWN TIME FOR A TYPICAL FOSSIL HP TURBINE

Note: If the unit is tripped with the temperature at a different value than that given for time

zero, shift the time scale so that time zero starts at the temperature when tripping occurred.

TIME AFTER UNIT TRIP (HOURS)

Page 1 of 1


Compiled：Yu Yan 2008.09Off-Frequency Turbine Operation Checked：Zhang Xiaoxia 2008.09

Countersign：

Countersign：


OFF-FREQUENCY TURBINE OPERATION

Operating Time (Total Life)

Frequency Accumulation Every Time

Hz (Min) (Sec)

48.5~51.5 Continuous Operating

48.0~48.5 ≤300 ≤300

47.5~48.0 ≤60 ≤60

47.0~47.5 ≤10 ≤20

Prepared：Pan Donghua

LP exhaust spray SYS Checked：Yan Weichun

Countersign：

Countersign：

AS.4.MAC01.P001 E-00 Approved：Chen Lehua

Contents

1 General and function..........................................................................1

2 Control switch....................................................................................3

3 Solenoid .............................................................................................3

4 Pressure switch ..................................................................................3

5 Pneumatic regulator valve .................................................................3

6 Bypass valve ......................................................................................5


Page 1 of 6


LP EXHAUST HOOD SPRAY SYSTEM

1 General and function

The exhaust hood spray system for this unit is designed to be put in operation

automatically when the rotor speed has reached 2600 rpm and continue in operation

until the unit is carrying approximately 15 percent rated load.

Page 2 of 6


Page 3 of 6


2 Control switch

The switch is usually located on the control panel and has provisions for

OFF-MANUAL-AUTOMATIC operation. It should be in the automatic position

during startup. Manual operation provisions are included in case it is desirable to

operate the exhaust hood sprays during other than the automatic mode period.

3 Solenoid

The solenoid is actuated either by a signal from the turbine control system after the

unit has reached 2600 rpm when the control switch is in the automatic position or by

manual operation of the switch. When the solenoid is energized it allows the

pneumatically operated valve to open which in turn provides water from the

condensate pump to the exhaust hood sprays.

4 Pressure switch

This is a pressure switch, which senses across-over pressure corresponding to

10-15% load and deactivates the solenoid, thereby closing the exhaust hood spray

valve.

5 Pneumatic regulator valve

This is an operated valve, which controls the flow of condensate to the exhaust

hood spray nozzles. It is normally closed and is opened by air from a regulator or air

set when the solenoid valve is actuated either by automatic or manual operation of the

control switch. The operating air to the valve is regulated by a pressure controller,

which is a mechanical device, utilizes air at a constant pressure and produces a

variable output in response to a pressure change applied to a sensing element, which

Page 4 of 6


is located on the outlet side of the control valve. This provides a uniform flow of

condensate to the spray nozzles.

Air at a constant pressure of 0.226 MPa (g) trained to the controller by an air set

which consist of strainer and reducing valve.

A high pressure reducing valve dis installed between the sensing device and the

controller to limit the signal to a maximum 0.7 MPa (g). This protects the bourdbn

tube in the controller from damage.

All of the above items except the control switch are shown diagrammatically on the

EXHAUST HOOD SPRAY CONTROL SYSTEM. The air set reducing valve and

controller are all mounted on the control valve.

Component supplier leaflets containing recommended spare parts and operating

and maintenance instructions follow this leaflet.

Overheating of the exhaust is not expected with no load steam and full vacuum.

Poor vacuum will cause overheating as will materially less than no load steam flow,

which would result if the unit were allowed to motor. If a temperature in excess of

80℃ is obtained, care must be taken to lower the temperature of the exhaust casing

gradually by increasing load or improving the vacuum. The limiting exhaust casing

temperature is l2l℃. If this temperature is reached, the unit should be shutdown and

the trouble corrected.

This pneumatic regulator valve is made up of body, pneumatic actor, limit switch,

Page 5 of 6

filter, solenoid valve, positioner, gauge, etc.(the detail see the manufactory’s manual)

In order to protect turbine, the pneumatic regulator should be closed when electric

or signal, or control air failure.

The pneumatic regulator is whole unit, should not disconnect on site except valve

manufacture.

LP exhaust spray pneumatic regulator valve outline (typical)

6 Bypass valve


The exhaust hood spray-regulating valve has a bypass valve, which should only be

used in the event of regulating valve failure of servicing. The bypass valve should

only be opened enough to maintain the calculated control pressure. See Control

Settings instructions.

Page 6 of 6


NOTE

To prevent possible damage to the turbine it is important that the BYPASS

VALVE is not left open when operating the turbine in the range that exhaust

hood sprays are not required.

Prepared：Pan Donghua 2008.07.08

Turbine Drain System Checked：Yan Weichun 2008.07.15.

Countersign：

Countersign：

AS.4.MAL10.P001E-00 Approved：Chen Lehua 2008.08.08

Contents

1 Forced cooling connection ......................................................................1

2 Drain valves.............................................................................................1

3 Main steam inlet ventilating valves.........................................................3

4 HP ventilating valve ................................................................................6

4.1 Function................................................................................................6

4.2 Structure ...............................................................................................7

5 Drain piping connection ..........................................................................7


Page 1 of 8


TURBINE DRAIN SYSTEM

1 Forced cooling connection

The term Forced Cooling refers to the forced cooling of turbine components. This

process is used to cool down the steam turbine as quickly as possible so that the

turning gear system can be switched off at the earliest possible point. A higher

availability can be achieved in this manner.

Cooling of the turbine is achieved by the use of the vacuum pumps (customer

supply) which draw in outside air via the normal steam path through the blading,

using the opening of the flange connection in the drain piping.

NOTE

1. Forced cooling connection must be closed when steam turbine in operated.

2. Forced cooling device can cool down the steam turbine as quickly as

possible but can bring steam turbine life consumption, careful used.

3. The forced cooling device will be supplied by customer.

2 Drain valves

The drain valves are alike in physical and functional operation. They consist of

diaphragm actuator and valve, three-way solenoid valve, pressure regulator valve, and

limit switches. The limit switches indicate drain valve to the operator. Air is supplied

through a regulating valve to a solenoid air control valve at a constant pressure. When

the solenoid valve is energized, air pressure is applied to the drain valve diaphragm

actuator and drain valves close. Likewise, when the solenoid valve is de-energized, air

pressure on the diaphragm actuator is vented to the atmosphere and the drain valve

opens.

The drain valves are arranged to open, to protect the turbine, on loss of supply air

Page 2 of 8

resulting from shutdown, trip, or loss of electrical signal to the solenoid valve in the

supply line.

A limit switch is mounted on each drain valve. Movement of the valve stem

actuates the limit switches. These switches are used to indicate valve position for

interlocks.

Refer to the operation leaflet section "Water in the Turbine" for more information

on the operation of this system.

The complete turbine drain system is shown on the "Steam, Drain & Gland Piping

Diagram."

Typical drain valve control diagram (air closed)

NOTE

1: In normally, the drain valve is auto-operate. If operators want to achieve

handle-operate function, pay attention to the following:

A: The drain valve must in on-condition when turbine shutoff until totally

cooling down.


Page 3 of 8


B: The drain valve must in on-condition when turbine start up until the gland

seal steam totally fill in the gland zoom.

C: In order to drain the condensate form reheat stop valve upsteam, when

increase turbine load, the drain valve must in on-condition until 10% rated load.

D: In order to drain the condensate form reheat stop valve downstream, when

increase turbine load, the drain valve must in on-condition until 20% rated load.

2: When drain valves in on-condition, vacuum break is forbidden, this

prescribe is inapplicable to vacuum break emergency condition and inapplicable

to main steam pipe drain.

3: When turbine startup drain valves in on-condition, turning gear device go

into work and turbine increase load always until 10%-20% rated load, check the

pressure in every drain piping, if the pressure exceed the pressure which come

from the lowest pressure fountainhead, turbine must be turnoff and eliminate

malfunction.

4: If customers adopt the motor drived valves, the measure to drain the

turbine and piping condensate in emergency condition must be ensure.

CAUTION

1: Before air-operated drain valves, install hand-operated or motor drived

stop valve is not advised. If customers install hand-operated or motor drived stop

valves, make sure the stop valve is normally-open, and check the stop valve open

condition at any moment.

2: Hand wheel in air-operated drain valve is not advised also, additional force

moment can influence drain valve normally work.

3 Main steam inlet ventilating valves

The ventilating valves are supplied to prevent a rapid vise in HP turbine blade

Page 4 of 8


temperature when the main and reheat steam valves are closed, trapping high density

steam in HP turbine and causing windage heating. The ventilating valves consist of

diaphragm actuator and valve, two-way solenoid valve, strainer, pressure reducing

valve, release valve, limit switches, and check valve.

The inlet sides of the ventilating valves are connected by piping to a main steam

inlet pipe from each steam chest. The outlet sides of the ventilating valves are

connected by piping to the main condenser. Tubing from the ventilating valve

actuators is connected through a pressure-reducing valve and EH fluid operated air

pilot valve to the station instrument air supply. Tubing is also connected from the

ventilating valve actuators through a solenoid valve to atmosphere. A check valve is

connected in parallel to the pressure-reducing valve.

The ventilating valves open when a turbine trip results in loss of EH fluid pressure

in the OPC header. When EH fluid pressure is reduced, the air pilot valve opens and

blocks instrument air supply. Air from the pressure-reducing valve is vented to

atmosphere through the air pilot valve. Air supplied to the ventilating valve actuators

is passed through the check valve and vented through the pilot valve. The ventilating

valves then open and pass HP steam to the main condenser. The ventilating valve

solenoid valve also open and loss of OPC header pressure. The pressure switch

monitoring the OPC header de-energizes the solenoid valve. Air from the ventilating

valve actuators is vented to atmosphere through the solenoid valve causing the

ventilating valves to open.

Page 5 of 8

main steam inlet ventilating valves control diagram (typical)


Page 6 of 8


Typical main steam inlet ventilating valves outline

4 HP ventilating valve

4.1 Function

HP ventilating valve will protect the HP cylinder when steam turbine startup or

shutdown.

When the steam turbine startup(HP-IP combine to startup), the HP ventilating valve

shall be opened till rated speed, after 1 minute , the HP ventilating valve will be

closed.

When the steam turbine shutdown, the HP ventilating valve shall be opened to

Page 7 of 8

extract the steam of HP cylinder.

4.2 Structure

The HP ventilation valve is one pneumatic valve, stop valve or butterfly valve all

can be used.

Typical HP ventilation valve outline

5 Drain piping connection

5.1 Check turbine outer cylinder and the drawing “Drain and LP Cylinder Spray

Piping”, confirm governing stage and turbine inner cylinder drain connection position.

5.2 Locate scaffold in correspond turbine outer cylinder place.

5.3 Remove insulation layer, drain connection extend out 200～300mm form HP

cylinder.

5.4 Machining drain connection to form weld groove, perforate drain connection.

5.5 Distance below form drain connection 150mm saw off drain piping.

5.6 After inner cylinder installation, base on space between machining piping


Page 8 of 8


connection.

5.7 Warm-up piping、piping connection &drain connection to 204～232℃.

5.8 Weld piping to piping connection or drain connection.

5.9 Coated weld zone with fabric insulation until cooling down to environment

temperature.

5.10 Remove fabric insulation.

5.11 Execute magnetic powder detection or penetrant examination in weld zone.

5.12 Recovery insulation layer.

5.13 Remove scaffold.


Lubrication Oil System Checked：Yan Weichun 2008.07.15.

Countersign：

Countersign：

AS.4.MAV10.P001E -00 Approved：Chen Lehua 2008.08.08

Contents

1 Main equipment and function .................................................................1

1.1 Oil reservoir..........................................................................................1

1.2 Main oil pump ......................................................................................1

1.3 HP startup oil pump (AC) ....................................................................1

1.4 Auxiliary pump(AC) ............................................................................2

1.5 Emergency oil pump (DC) ...................................................................3

1.6 Oil ejector .............................................................................................3

1.7 Vapor extraction system .......................................................................4

1.8 Strainer .................................................................................................5

1.9 Oil coolers ............................................................................................5

1.10 Oil heaters...........................................................................................5

1. 11 Fluid level controls ............................................................................6

1.12. Terminal box "R"...............................................................................6

1.13. Terminal box "L"...............................................................................7

1.14 Pressure-switches ...............................................................................9



2 Rated revolution ....................................................................................10

3 Auxiliary pumps ....................................................................................10

4 Oil temperature and oil coolers .............................................................12

5 Turning gear ..........................................................................................13

6 Emergency trip functions ......................................................................14

7 Lubrication oil .......................................................................................15

7.1 New oil ...............................................................................................15

7.2Oil sampling during operation ............................................................17

8 Oil reservoir...........................................................................................18

9 Oil coolers .............................................................................................19

10 Three-way valve (only used for shell & tube oil cooler) ....................20

12 Strainer ................................................................................................27

13 Pressure switch ....................................................................................27

14 Temperature switch and heaters ..........................................................28

15 Level controls ......................................................................................28

16 Oil pressure value................................................................................29

17 Bearing and lubrication oil system......................................................30

18 Backup power......................................................................................31

19 Oil system flushing and installation procedure...................................32

19.1 Preface ..............................................................................................32

19.2 Introduction ......................................................................................33


20 Shipping and on-site storage ...............................................................34

21 Installation and general housekeeping procedures..............................36

22 Pre-flush planning and familiarization................................................37

22 Pre-flush operations and procedures ...................................................39

23 General design considerations.............................................................43

24 General notes.......................................................................................45

25 Flushing procedures ............................................................................50

1. Reservoir/oil cleanliness ......................................................................50

2. Main oil pump suction and discharge lines (ref. figure 1). ..................51

4. Hydrogen seal oil lines.........................................................................57

26 Procedures for determining system cleanliness ..................................57

27 Restoration of the system ....................................................................59

28 Temporary flushing materials..............................................................60

Page 1 of 77


LUBRICATION OIL SYSTEM

1 Main equipment and function

1.1 Oil reservoir

The lubrication oil reservoir is a large carbon steel tank in which the lubrication oil

is stored. The reservoir is usually located below the centerline of the turbine-generator

unit. The bottom of the reservoir contains a hanged drain hole which is plugged

during shipment but which may be connected to the purchaser’s piping system at his

discretion.

1.2 Main oil pump

The main oil pump is a volute, centrifugal pump type, which mounted on the

turbine rotor in the governor pedestal. It has a large capacity and a stable discharge

head. At or near rated turbine speed, the main oil pump supplies all the oil

requirements of the steam turbine and generator lubrication system and, in addition,

provides two sources of backup for the hydrogen seal oil system of the generator. The

main oil pump is not self-priming and must constantly be supplied with oil under

pressure. During turbine startup and shutdown periods, the auxiliary oil pumps do this.

At or near rated speed, the oil ejector supplies priming oil. The main oil pump

discharge is piped back into the reservoir where it is connected to the oil ejector inlet

and to the HP Seal Oil Backup Header from which the Mechanical Overspeed and

Manual Trip Header by orifice.

1.3 HP startup oil pump (AC)

The HP startup oil pump(sometime named seal oil backup pump) is an AC motor

driven, horizontal pump mounted on top of the reservoir. It provides high pressure oil

to seal oil backup header and mechanical overspeed devices during the period of

turbine startup or shutdown. If anytime the main oil pump cannot satisfy the HP seal

oil requirements, including the requirements of the Mechanical Overspeed and

Page 2 of 74


Manual Trip Header, the HP startup oil pump will work. During normal operation at

rated speed, the HP startup oil pump does not work, and the main oil pump supplies

all of the oil requirements. The HP startup oil pump is controlled by the same pressure

switch that controls the auxiliary oil pump by monitoring the bearing oil pressure. If

the bearing oil pressure decreases to 0.07-0.08 Mpa(g) such as occurs during a

shutdown or contingency condition, the HP startup oil pump automatically starts and

brings the HP Seal Oil Backup Header up to the required pressure. The pump will not

stop on rising pressure, however, and must be turned off manually from the control

room. During startup procedures the HP startup oil pump is put into service before the

unit is started and should not be taken out of service until the main oil pump is

capable of satisfying all of the oil requirements (approximately 90% of rated speed).

A relief valve in the discharge piping prevents overpressures.

1.4 Auxiliary pump(AC)

The auxiliary pump is an AC motor driven, centrifugal pump mounted on top of the

reservoir. It is used during startup and shutdown procedures and also serves as a

backup to the main oil pump during contingency conditions. It is capable of supplying

all of the LP seal oil backup and bearing oil requirements. During normal operation at

rated speed, the bearing oil pump does not work and the main oil pump supplies all of

the oil requirements. A pressure switch that senses the bearing oil pressure controls

the bearing oil pump. If the bearing oil pressure decreases to 0.07-0.08 Mpa(g) such

as occurs during a shutdown or contingency condition the bearing oil pump will turn

on and bring the pressure back up to requirements. However the pump will not

automatically shut off on rising pressure and must be turned off manually from the

control room. During startup procedures the bearing oil pump is put into service

before the unit goes on turning gear and is not taken out of service until the main oil

pump is capable of satisfying all of the oil requirements of turbine and generator

bearings (approximately 90 % of rated speed).

Page 3 of 74


1.5 Emergency oil pump (DC)

The emergency oil pump is identical in construction and operation to the auxiliary

pump except that it is operated by a DC motor powered by station batteries, and the

controlling pressure switch is set point is below the set point of the pressure switch

which controls the auxiliary pump. During startup procedures the emergency oil pump

is put into service after the bearing oil pump establishes sufficient bearing oil pressure.

The emergency oil pump's control switch is then set on "Automatic”, and the pump

will turn on if the bearing oil pressure decreases to 0.06-0.07 Mpa(g). Thus, the

emergency oil pump services as a backup to the auxiliary pump and is the final

backup for the turbine-generator bearings oil system. The station batteries are sized to

provide sufficient power to drive the pump during a normal coast down, and it is

imperative that the batteries are kept sufficiently charged to maintain this capability.

1.6 Oil ejector

One oil ejector mounted in the piping below the oil level. The oil ejector consists,

essentially, of a nozzle, pickup chamber, throat, and a diffuser. The nozzle inlet is

connected to the main oil pump discharge, which provides motive oil. The oil passes

through the nozzle, is directed through the pickup chamber into the ejector throat, and

finally passes into the diffuser. As the oil passes through the nozzle, its velocity

increases. When this high velocity oil passes through the pickup chamber, it creates a

low-pressure zone in the pickup chamber and causes the oil from the reservoir to be

drawn into the pickup chamber and be carried with the high velocity oil into the

ejector throat area. The quantity of oil picked up from the reservoir is approximately

equal to the quantity provided to the nozzle inlet by the main oil pump. After passing

through the ejector throat area the oil enters the diffuser where the oil velocity is

converted to pressure. The oil is then piped through the oil coolers to the Bearing Oil

Header, to the main oil pump suction, and to the LP Seal Oil Backup Header. A swing

check valve, mounted after the diffuser, prevents backflow from the system. A check

Page 4 of 74

plate mounted above the pickup chamber inlets from the reservoir prevents a

backflow into the reservoir when the bearing oil pump is running. A removable

perforated, steel plate (mesh) strainer mounted on the ejector’s suction side prevents

foreign matter from entering the ejector.

1.7 Vapor extraction system

, oil

ction system is provided to prevent the vapor pressure from becoming

excessive.

ister, an adjustable blast butterfly

valve, a motor drive blower and a check valve.

, it

creates a slightly negative pressure in the areas where vapors accumulate and thus

When the lubrication oil supply system is in operation, some of the oil becomes

vaporized. These vapors collect in the oil reservoir above the oil level, in the bearing

pedestals, housings, and return oil piping. If the vapor pressure becomes excessive

vapor could be forced through the turbine shaft oil seals into the turbine room. A

vapor extra

The vapor extraction system includes a dem

Essentially, the oil vapor extraction system is AC motor driven gas blowers whose

suction side is connected to the areas above the oil in the reservoir. When operating


Page 5 of 74


draws any vapors through the blower. Any entrained oil is removed from the vapor

and returned to the reservoir, and the cleaned vapor is vented to the atmosphere.

1.8 Strainer

Periodically, remove and clean the oil strainer which is mounted in the trough

inside the reservoir, annunciator provided by the purchaser will indicate this condition,

and the strainer should be replaced immediately. It is recommended that a clean spare

strainer and gasket be readily available to minimize the amount of time that the

strainer is not in place.

1.9 Oil coolers

The oil coolers regulate the temperature of the lubrication oil. Two oil coolers are

normally provided. Under normal operating conditions, one is in use and the other is

on a standby status; although in some special conditions, both coolers may be in

service simultaneously. The coolers are connected to the discharge sides of both the

bearing oil pump and the oil ejector; thus the bearing oil, no matter what the source,

passes through the coolers before flowing to the bearings.

Operators can check which oil cooler is on work through flow inspect hole.

1.10 Oil heaters

The temperature switch and immersion heaters were adjusted either at the factory

or at installation; however, their operation and set points should be verified

periodically.

Cautions

The power to the heaters should be shut off before attempting to inspect them

or perform any maintenance on them.

Page 6 of 74


1. 11 Fluid level controls

Two top mounted displacement type fluid level controls and which activate switch

mechanisms in response to oil level changes.

a. One level control (7l/OL) activates switch mechanisms in response to either high

oil levels or low oil levels. This level control is wired into the purchaser is circuits and

may be connected to either alarm or trip circuits at his discretion. They are normally

connected to alarm circuits.

b. One level control (71/LLL) (optional for indoor units) activates a low-low level

pre-trip alarm and also provides an interlock between the oil level and the heaters by

activating a switch mechanism to turn of f the heaters at anomaly low oil levels.

1.12. Terminal box "R"

One terminal box "R" normally mounted approximately as shown on the side of the

reservoir. The terminal box completely encloses the terminal blocks and pressure

switches and is equipped with a hinged door for easy access. The tubing that connects

the terminal box pressure switches to the components is usually arranged at the time

of erection; thus it is not shown on the illustration. The following equipment is

included in the terminal box.

a. One pressure switch (63/BOR) which indicates when the bearing oil pump is

running by sensing the pressure on the discharge side of the Bearing Oil Pump

between the pump and the check valve. The pressure switch is connected through an

isolation valve to the gauge stem on top of the reservoir and is set to close a contact

when the bearing oil pump is running and producing a discharge pressure of

approximately 0.07-0.08 MPa(g). The pressure switch is wired into the purchaser is

circuits and is usually connected to an annunciator in the control room.

Page 7 of 74


b. One pressure switch (63/EPR) which indicates when the emergency oil pump is

running by sensing the pressure on the discharge side of the Emergency Oil Pump

between the pump and the check valve. The pressure switch is connected through an

isolation valve to the gauge stem on top of the reservoir and is set to close a contact

when the Emergency Oil Pump is running and producing a discharge pressure of

approximately 0.07-0.08 MPa(g). The pressure switch is wired into the purchaser is

circuits and is usually connected to an annunciator in the control room.

c. One pressure switch (63/OVR) which indicates when the oil vapor extractor is

running by sensing the pressure on the suction side of the oil vapor extraction system.

The pressure switch is connected to the top of the oil reservoir and is set to close a

contact when a slight negative pressure exists in the oil reservoir such as is caused by

the oil vapor extractor running. The switch is wired into the purchaser’s circuits where

it is usually connected to an annunciator in the control room. If a second (standby) oil

vapor extractor blower is provided, another pressure switch may be mounted on the

same position. If provided, its function is to control the standby oil vapor extractor

startup automatically when the vacuum in the oil reservoir is lower.

1.13. Terminal box "L"

One terminal box "L" mounted near the turning gear. The terminal box completely

encloses the terminal blocks and pressure switches and is provided, with a hinged

door for easy access. The following equipment is included in the terminal box:

a. One pressure switch (63/BOP) which starts both the Bearing Oil Pump and the

Seal Oil Backup pump if the Bearing Oil Header pressure falls too low.

The switch has two sets of normally closed contacts that are held open by sufficient

bearing oil pressure. If the oil pressure drops to 0.07-0.08 MPa(g) both sets of

Page 8 of 74


contacts close simultaneously. The closing of one set causes the Sea1 Oil Backup

pump (High Pressure startup pump) to start, and the closing of the other set causes the

Bearing Oil Pump to start. Although the pumps will start on failing pressure they will

not stop automatically on rising pressure and must be turned off from the control

room after the bearing oil pressure has risen past the pressure switch's set point. The

control switch should be turned to the OFF position and held until the pumps stop;

when released, it will return to the AUTO position automatically, and the circuitry

will be reset.

b. One pressure switch (63/EOP) which monitors the Bearing Oil Header pressure.

The switch has two sets of normally closed contacts that are held open, under normal

operating conditions, by the bearing oil pressure. If the oil pressure drops to 0.06-0.07

MPa(g), the contacts close simultaneously. The closing of one set causes the

emergency oil pump to start, and the other set is either wired into the ATC circuitry or

is a spare. Although the pumps will start on failing pressure they will not stop

automatically on rising pressure and must be turned off from the control room after

the bearing oil pressure has risen past the pressure switch's set point. The control

switch should be turned to the OFF position and held until the pumps stop; when

released, it will return to the AUTO position automatically, and the circuitry will be

reset.

CAUTION

Shot off pump promptly after test. Pro-longed operation of pump will drain

System battery power below normal voltage required to safely operate the pump

during an emergency coast down.

c. One pressure switch (63/TG) which interlocks the turning gear motor to the

bearing oil pressure. The switch has two sets of normally open contacts. When the

turbine-generator is operating above the supervisory instrument check speed, a

Page 9 of 74


solenoid valve, 20/TGO, isolates the pressure switch from the Bearing Oil Header

thus, the switch contacts are open. When the turbine-generator speed drops below the

supervisory instrument check speed, the 20/TGO solenoid valve automatically opens

and allows the pressure switch to sense the Bearing Oil Header pressure. The pressure

switch is set to close the contacts when the bearing oil pressure is 0.0276-0.0344

MPa(g) or greater. One set of contacts is wired in series with the turning gear motor,

and thus the motor cannot start until the bearing oil pressure reaches or exceeds the

set point. The second set of contacts is either a spare or if a bearing lift pump is

provided, it is wired in series with the bearing lift pump motor, thus preventing that

motor from starting until the proper bearing oil pressure is established. Also, both the

turning gear and the bearing lift pump will be shut off if bearing oil pressure

decreases below the set point and causes the contacts to open.

The operation of the pressure switch can be tested on rising pressure by first

establishing sufficient bearing oil pressure and then checking to assure that the

bearing lift pump motor and the turning gear motor start. Its operation on falling

pressure can be tested by first establishing sufficient bearing oil pressure and then

opening the manual shutoff valve in the line to the pressure switch. Opening the valve

creates a localized pressure drop and causes the contacts to open. Since the pressure is

orificed off from the Bearing Oil Header, the Bearing Oil Header pressure does not

decay during testing. Closing the shutoff valve restores the pressure switch to normal

operation.

1.14 Pressure-switches

Four pressure-switches (63/LBO) which cause a turbine trip if the Bearing Oil

Header pressure is excessively low. The switches are mounted in Terminal BOX "A"

on the governor pedestal, they monitor the Bearing Oil Header pressure, and they are

part of the emergency trip system. Their operation, testing procedures, associated

Page 10 of 74


equipment, etc. are covered in a separate leaflet describing the "Emergency Trip

System" (see "Contents").

2 Rated revolution

When the turbine in rated revolution, main oil pump supplies the whole lubrication

oil of the system, see “lubrication oil system” drawing. The lubrication oil eject out

from main oil pump through an orifice flange to HP startup oil pump and emergency

trip equipment. Also the main oil pump supplies the power oil to the oil ejector. The

oil comes from oil ejector is then piped through the oil coolers to the Bearing Oil

Header, to the main oil pump suction, and to the LP Seal Oil Backup Header.

The lubrication oil system is a hermetical system. All the lubrication oil through an

oil strainer and come to oil reservoir. To make sure the lubrication oil is adequate for

the whole system, the oil reservoir must supplies enough oil and oil controller give an

alarm when oil level is low or high.

Caution

1 To make sure the lubrication oil come into oil reservoir through oil strainer,

when turbine in initialize operation, oil level in the oil reservoir is inspect at any

moment.

2 Condensate may be come into lubrication system from gland steam system,

in order to remove the condensate from lubrication system, oil purification

system is commend to work when turbine is in operate.

3 Auxiliary pumps

The bearing oil pump is an AC motor driven, vertical pump mounted on top of the

reservoir. It is used during startup and shutdown procedures and also serves as a

backup to the main oil pump during contingency conditions. It is capable of supplying

all of the LP seal oil backup and bearing oil requirements. During normal operation at

Page 11 of 74


rated speed, the bearing oil pump is off and the main oil pump supplies all of the oil

requirements. A pressure switch that senses the bearing oil pressure controls the

bearing oil pump. If the bearing oil pressure decreases to 0.076-0.083 MPa(g) such as

occurs during a shutdown or contingency condition the bearing oil pump will turn on

and bring the pressure back up to requirements. However the pump will not

automatically shut off on rising pressure and must be turned off manually from the

control room. During startup procedures the bearing oil pump is put into service

before the unit goes on turning gear and is not taken out of service until the main oil

pump is capable of satisfying all of the oil requirements (approximately 90 % of rated

speed).The emergency oil pump is identical in construction and operation to the

bearing oil pump except that it is operated by a DC motor powered by station batteries,

and the controlling pressure switch is set point is below the set point of the pressure

switch which controls the bearing oil pump. During startup procedures the emergency

oil pump is put into service after the bearing oil pump establishes sufficient bearing

oil pressure. The emergency oil pump's control switch is then set on "Automatic”, and

the pump will turn on if the bearing oil pressure decreases to 0.06-0.07 MPa(g). Thus,

the emergency oil pump serves as a backup to the bearing oil pump and is the final

backup to the bearing oil system. The station batteries are sized to provide sufficient

power to operate the pump during a normal coast down, and it is imperative that the

batteries are kept sufficiently charged to maintain this capability.

CAUTION

An insufficient charge on the batteries may not allow the emergency oil pump

to operate properly thereby resulting in an insufficient supply of lubricating oil

to the bearings. This will result in serious damage to the bearings, journals, and

associated components.

The seal oil backup pump is an AC motor driven, horizontal pump mounted on top

Page 12 of 74


of the reservoir. It provides oil to the HP Seal Oil Backup Header and is used anytime

the main oil pump cannot satisfy the HP seal oil requirements, including the

requirements of the Mechanical Overspeed and Manual Trip Header. During normal

operation at rated speed, the seal oil backup pump is off, and the main oil pump

supplies all of the oil requirements. The seal oil backup pump is controlled by the

same pressure switch that controls the bearing oil pump by monitoring the bearing oil

pressure. If the bearing oil pressure decreases to 0.07-0.08 Mpa(g) such as occurs

during a shutdown or contingency condition, the seal oil backup pump automatically

starts and brings the HP Seal Oil Backup Header up to the required pressure. The

pump will not stop on rising pressure, however, and must be turned off manually from

the control room. During startup procedures the seal oil backup pump is put into

service before the unit is started and should not be taken out of service until the main

oil pump is capable of satisfying all of the oil requirements (approximately 90% of

rated speed). A relief valve in the discharge piping prevents overpressures.

4 Oil temperature and oil coolers

In normal operate, the temperature of lubrication oil come out from oil coolers is

43-49℃.

If the temperature of the oil in reservoir is under 10℃, oil circulation is prohibited.

So the lubrication oil supply system must out of work. Before Auxiliary pump and the

seal oil backup pump startup, if the temperature of the lubrication oil is under 10℃,

oil heaters must put into work.

The oil coolers regulate the temperature of the lubrication oil. Two oil coolers are

normally provided. Under normal operating conditions, one is in use and the other is

on a standby status; although in some special conditions, both coolers may be in

service simultaneously. The coolers are connected to the discharge sides of both the

bearing oil pump and the oil ejector; thus the bearing oil, no matter what the source,

passes through the coolers before flowing to the bearings. The oil coolers are the plate

Page 13 of 74


or tube oil coolers. The oil is circulated within the hot sides while the cooling water is

circulated the cold sides. The oil flow to the coolers is controlled by a manually

operated stop valves or a three-way valve, which directs the flow to either cooler and

permits switching coolers without interrupting the flow of oil to the bearings. The oil

inlets to the coolers are connected through a crossover pipe and four stop valves (used

in plate oil coolers) or a three-way valve(used in tube oil coolers), which permits the

inactive cooler to be filled with oil and ready for immediate operation. The flow of

water to the coolers is adjustable by means of a manually operated valve in the water

supply liner hence the temperature of the oil leaving the coolers is also adjustable.

The valve is normally adjusted to provide an oil temperature of 43-49℃ measured at

the oil cooler discharge.

NOTE

In three-way valve handle, any auxiliary lever and spanner is prohibited.

Caution

Before three-way valve operate, operators make sure the three-way valve is

open up and the connected cooler is full fill with lubrication oil. After change

over, make sure the oil in the oil cooler is not interrupt, lubrication system is

work normally.

5 Turning gear

In order to minimize the distortion of the rotor due to the uneven cooling of the

rotor due to the uneven cooling of the turbine parts, the turning gear rotates the rotor

at a low speed when the turbine is shut down. It normally operates automatically by

starting when the rotor reaches zero speed, controlling the speed of the rotor, and

disengaging when the rotor speed increases slightly. Interlocks prevent the turning

gear from starting when the turbine speed is above the supervisory instrument check

speed or if the bearing oil pressure is not adequate.

Page 14 of 74


A solenoid valve, 20/TGO, interlocks the turning gear operation to the turbine

speed. The solenoid valve is energized closed by a supervisory instrument contact

closure when the turbine speed is above the supervisory instrument check speed.

When the turbine speed is below the supervisory instrument check speed, the contact

opens causing the 20/TGO solenoid valve to open and thereby allowing lubricating oil

from the bearing oil header to reach the turning gear.

A pressure switch, 63/TG, interlocks the turning gear motor to the bearing oil

pressure. The pressure switch connection is located in the line after the 20/TGO

solenoid valve, and thus, when the solenoid valve is open, the pressure switch

monitors the bearing oil pressure. As long as sufficient bearing oil pressure

(above0.0276-0.0344 Mpa(g)) is established, contact closures from the pressure

switch allow the turning gear motor to be started. If the pressure falls below the set

point the contacts open and prevent the turning gear motor from being started, or if

the motor has been started, the contacts opening will turn it off. The turning gear can

also be operated manually.

6 Emergency trip functions

Lubrication oil is used as the control medium for the interface-diaphragm valve.

Mounted on the governor pedestal the interface-diaphragm valve provides an interface

between the mechanical overspeed and manual trip portion of the lubrication oil

system and the autostop emergency trip portion of the control system. Lubrication oil

from the Mechanical Overspeed and Manual Trip Header supplied to the diaphragm

valve acts to overcome a spring force to hold the valve closed and thereby block a

bath to drain of the fluid in the autostop emergency Trip Header. Any decay in the

Mechanical Overspeed and Manual Trip Header Pressure, such as could be caused by

Page 15 of 74


either a manual trip or an overspeed trip, allows the spring to open the

interface-diaphragm valve releasing the emergency trip fluid to drain and tripping the

turbine.

The condition of the lubrication oil system’s bearing oil supply is monitored by the

emergency trip system. Four pressure switches (63/LBO) monitor the condition of the

Bearing Oil Header. If the header pressure decreases to the set point contact closures

from the pressure switches cause the autostop trip (20/AST) solenoid valves to open

and trip the turbine. The operation of the pressure switches and the solenoid valves as

well as part lists are included in the leaflet covering the emergency trip system. See

the content pages.

7 Lubrication oil

7.1 New oil

The oil shall be refined mineral oil of the highest quality and uniformity. It should

not contain any grit, inorganic acid, a1kali, water, soap, asphaltum, pitch, resinous

substances, or any other substance that will interfere with the properties of the oil, or

be detrimental to the metals that are in contact with the oil.

The oil shall be capable of preventing the formation of rust on steel parts. The oil’s

ability to retard rust formation is very important, since it is impossible to exclude

moisture from lubricating oil systems. The tests given in the latest issue of ASTM

Specification D-665 entitled ”Rust Preventing Characteristics of Steam Turbine Oil in

the Presence of Water, Test For” and ASTM D943” Oxidation Characteristics” should

be performed on samples of the turbine lubricating oil to verify its acceptability. For

subsequent care of oil (after initial use) refer to ASTM Standard 118 II Recommended

Practices for the Purification of Steam Turbine Generator Oil”.

The oil purification system must be capable of removing all of the free water (water

not in solution). Also, some oil purification systems using fuller’s earth, or similar

Page 16 of 74


filter materials, may remove the corrosion or oxidation inhibitors that were added by

the supplier. Therefore, consult with him before such systems are applied.

In Table l, the physical and chemical characteristics of the lubrication oil are given

The values shown in this table are based on tests made in accordance With the latest

approved standards of the American Society for Testing Material, except as otherwise

noted.

TABLE 1

Physical and Chemical Characteristics

(New Oil Only)

Flash Point 165.6℃,Min

Viscosity 30-37mm2/s at 37.8℃

Viscosity Index 90,Min.

Carbon Residue 0.10%,Max.

Neutralization No. 0.20, Max.

Sulphur Content ......

Corrosion Shall Pass

Resistance

Test

Oxidation Shall Pass

Resistance Test (l000 Hours with a Maximum Increase in

Neutrality of 0.25)

Sampling …………………………… ASTM D270

Flash point………………………… ASTM D92

Visc0sity…………………………… ASTM D88

Page 17 of 74


Carbon Residue……………………… ASTM Dl89

Neutralization No.………………… ASTM D664

Sulphur Content …………………… ASTM Dl29

Corrosion Resistance ………………ASTM D665

Oxidation Resistance……………… ASTM D943

7.2Oil sampling during operation

It is important that the lubricating oil be properly maintained in order to avoid

harmful wear to the bearings ,journals ,and pumps. Periodic analysis must be made to

determine if there are any property changes in the fluid, if changes do occur the cause

should be established, and immediate steps taken to correct the problem.

Acceptable contamination levels are given in Table 2 below. In this table, the

number of allowable particles for each range of contaminate size includes soft

particles as well as hard particles. Also, these numbers are only valid for lubricating

oil tested during turbine operation; different values apply to lubricating oil that is

tested throughout the turbine flushing procedure. For these values, see section

six ”Determination of System Cleanliness“.

TABLE 2

Acceptable Contamination Levels

Contaminant Size Allowable Particles

In Microns Per 100 ML Sample

5-10 32000

10-25 10700

25-50 1510

50-100 225

Page 18 of 74


100-250 21

Over-250 None

8 Oil reservoir

Oil reservoir zoom must cleanness, no overflow lubrication oil. Operators must

make sure there are no duster cloth、dust or oil pollution in oil reservoir.

The oil reservoir and the oil conditioning unit (if available) should be drained and

thoroughly cleaned. Any damaged painted surfaces that come in contact with the

lubricating oil must be cleaned and repainted.

Turn off oil heaters before drain lubrication oil form oil reservoir.

After drain the lubrication oil form oil reservoir, clean the inside shell and repaint

the damage part. Inspect the flange connection and tighten the connection blot. The

filter of the motor drive pump and oil ejector must be demounted and cleaned after oil

drain. Remount the filter and make sure the washer placement is correct.

Clean the translate pump and piping before return the oil to oil reservoir. It is

recommended that return the oil to oil reservoir through the oil purification so that the

oil is purificatory.

After turbine long time shutdown, if oil purification is out of work, drain little

lubrication oil form oil reservoir bottom, so that it can drain the deposition and water

in oil reservoir bottom.

Caution

1 Motor drive pumps must be inspected every week, and operate in a short time

to make sure the safe standby condition.

2 DC emergency oil pump is the turbine last safety precautions, make sure there is enough

voltage. 3 After large capacity flushing, oil reservoir inside piping and connection may be

Page 19 of 74


loosed. Inspect the connection and reconvert it.

4 During operation time, fire and high temperature piping are prohibited near

lubrication oil system zone.

5 If the oil level is below the operate oil level or drain the oil form oil reservoir,

oil heaters must be turn off.

6 Low voltages can make DC emergency oil pump out of work, it make bring

bearing and journal neck damage.

7 The oil level is strictly controlled, too high can bring oil overflow and too low

can bring un-normal operate of oil pumps.

9 Oil coolers

Oil coolers continuous services for two years, in the planned outage, dismount the

tubes of oil coolers and clean the tubes and shell.

When clean the tubes, water chambers must be dismounted. Check the tube plates

and find the damaged tube plates. Before pull out the tubes, dismount the water

reverse chamber、tube side O-rings and gland spacer. To avoid scrape gland spacer,

acuminate tool for dismount is forbidden. O-rings breakaway when pull out the tubes.

Use lifting nut to pull out the tubes, tube shall be moved in support or guide rail and

displaced in support board. Displaced tube in tube is forbidden. Pull tubes in rough

plate may damage the tube plates. Tube plates outer diameter is actually the same to

the inner shell inner diameter, They must meet very close to the equipment in good

working condition.

NOTE: Before water chambers dismount, drain all the oil and water from oil

coolers.

Pulled out tubes, inspection of all O-ring, if damaged or falling, that is to be

replaced. In reverse chamber side, any O-ring diameter greater than for the outer

Page 20 of 74


diameter of the reverse tube plate, that is to be replaced.

When the oil coolers outage, dry coating method is proposed to protect the oil

coolers. Drain the water form oil coolers and keep dry.

If the dry coating method is not practical, with the water and tubes still contact, can

not remain dry, it is necessary to let water flow continued and regularly replaced. So

that the accumulation of harmful pollutants caused by corrosion to minimize. Water

storage must not be allowed to stay fixed.

If the oil coolers are received at the site had not been installed within six months,

before operation of the turbine, replace at both ends of the O-ring. For the O-ring

forms and materials must be the same as the original supply.

10 Three-way valve (only used for shell & tube oil cooler)

The valve should be checked at least once a year, to ensure operational flexibility.

(1) Cleaning, inspection, repair and re-assembly

Should use the appropriate solvent to wash all the parts, to remove oil or

attachment of fouling, until the exposed metal color.

Inspection, repair and / or replacement of damaged in the dismounting of all the

parts (the gap, Burr, etc.). O-ring shall be replaced if damaged.

Before the re-assembly, all parts should be no damage.

Re-assembly is the disintegration of the inverse process. However, before blind

flange plate (item No. 068) is not installed, check handle direction, and make sure the

three-way valve is in work position. At the same time check valve disc opening

direction. Two disc valve openings direction must in the same side and valve

processing plate must face of valve seat. (May be the disc valve overturned after the

assembly).

When in the replacement of O-ring, smear the O-ring a thin of grease.

Page 21 of 74


After the assembly, check whether the smooth operation of the valve. The valve

should be able to facilitate smooth work in two directions.

Note:

Unless the release of the hand wheel and raised his disc valve, or not rotating handle.

(2) Break

In order to the stem disintegration, we must follow the following steps:

1. Removed pin (item No. 2) from the top, unloaded the control handle (item No.

1).

2. Anti-clockwise rotation removed the hand wheel (item No. 3).

3. Removed screw (item No. 5) and remove (item No. 15) Journal bearing.

4. Remove O-ring (item No. 7).

5. Remove bolt (item No. 10) and washer (item No. 11) and unloaded set ring (item

No. 9).

6. Remove sleeve (item No. 8).

7. Remove O-ring flange (item No. 24), with an O-ring (item No. 12).

8. In the valve, removed the valve disc (item No. 16), removed the key (item No. 17) on the stem.

9. Blind flange from the valve end, removed (item No. 21, 22), which can be removed blind

flange (item No. 28). The valve stem and valve disc pull together. From the stem nut on the

opposite side removed the valve disc (item No. 16), not touch dynamic positioning nut.

10. Now the stem disintegration of all the components for inspection. (3) Troubleshooting

Fault

The possible reasons

Treatment

Sleeve and sleeve ring O-ring wear or damage Replacement of O-ring

Page 22 of 74


leakage

(item No. 7) (with a small

amount of lubricating

grease)

Stem and the O-ring

flange leakage

O-ring wear or damage

Replacement of O-ring

(item No. 12) (with a small

amount of lubricating

grease)

O-ring flange and shell

flange leakage

O-ring flange or bolt

(item No. 21) loose.

special liner wear or

damage

Tightening bolt,

replacement (item No. 19)

Blind flange and shell

flange leakage

Fixed blind flange bolt

(item No. 21) .blind flange

gaskets wear or damage

Tighten screw,

replacement special

liner(item No. 19)

Valve operation

difficulties (in the

conversion operation

mode)

The pressure difference

between the valve disc

is too high.

Do not operate the

valve. reference for oil

coolers leaf note

Page 23 of 74


Page 24 of 74


11 Three-way valve interconnecting piping

Connected to the two oil coolers, a three-way valve is supplied. Use the three-way

Page 25 of 74


valve, an oil cooler from standby to go into operation.

Three-way valve

For the oil side of the two oil coolers, connected by a pipe and a switch valve. As

shown.

Note

Before standby oil cooler is put into operation, the oil cooler must full fill with oil.

At the same time completely discharge the gas, otherwise due to pressure fluctuations

in the moment, bearing low pressure will cause turbine shutdown.

Open the switch valve to fill the standby oil cooler with oil, when seen the oil flow

indicator with the flow of oil, that is, oil has been filled with standby oil cooler. When

in the operation time, switch valve remains open to ensure that the standby oil cooler

is always filled with oil and ready to put into operation.

Stop valve

Apart from the cold cooler switch, stop valves (if the valve supplied) in all the

operation time must be open.

Oil coolers switch

For the process of Oil coolers switch shown as follows:

1: In standby oil cooler full fill with cooling water.

Note

If oil cooler put into operation before the cooling water enter the oil cooler, it

will cause bearings high temperature, bearings damage and shaft scratches.

2: To check switch valve is fully open, standby oil cooler filled with oil.

3: If a stop valve installed in standby oil cooler exhaust pipe, temporarily close the

valve. In order to step up oil pressure of standby oil cooler close to the oil pressure of

Page 26 of 74


operation oil cooler.

Note: pressure difference between the oil coolers is smaller; three-way valve will

be easier to operate.

4: Appropriate rotate hand wheel, slightly rise up the sleeve. Operate three-way

valve to the standby oil cooler running position. Turn hand wheel to reduce the sleeve.

Tightening sufficient to ensure that the sleeve in place.

5: Open the oil piping valve (if provided), oil cooler is put into operation.

6: When the three-way valve operation, do not use valve wrenches or any other

supporting leverage to operate hand wheel.

Standby oil cooler for drain and maintenance

When oil coolers stop operation, in order to clean or inspect oil coolers, turn off the

switch valve and drain the oil form oil coolers. After cleaning、inspection and / or

maintenance, close standby oil coolers drain connection and fill oil.

Note: Standby oil cooler to be filled with oil and ready for transport.

Page 27 of 74


12 Strainer

Periodically, remove and clean the oil strainer which is mounted in the trough

inside the reservoir, annunciator provided by the purchaser will indicate this condition,

and the strainer should be replaced immediately. It is recommended that a clean spare

strainer and gasket be readily available to minimize the amount of time that the

strainer is not in place.

13 Pressure switch

Electrical pumps start oil temperature above 10 ℃

Turning gear oil temperature above 21 ℃

Bearing back to the oil temperature below the 71 ℃ is normal

Bearing back to the oil temperature 77 ℃ alarm

Page 28 of 74


Bearing back to the oil temperature 83 ℃ shutdown

Radial bearing metal temperature below 90.5 ℃ is normal

Radial bearing metal temperature 107 ℃ alarm

Radial bearing metal temperature 113 ℃ shutdown

Thrust bearing metal temperature below 90 ℃ is normal

Thrust bearing metal temperature 99 ℃ alarm

Thrust bearing metal temperature 107 ℃ shutdown

Bearing lubricating oil pressure 0.08 ~ 0.15MPa (g) is normal

Bearing lubricating oil pressure 0.07 ~ 0.08 MPa (g) auxiliary pump (AC) and the

HP startup oil pump put into work

Bearing lubricating oil pressure 0.06 ~ 0.07 MPa (g) the emergency oil pump put

into work

Bearing lubricating oil pressure 0.045 ~ 0.055 MPa (g) Alarm

Bearing lubricating oil pressure 0.035 ~ 0.048 MPa (g) shutdown

Lifting oil system oil pressure 8 ~ 12MPa (g) is normal

Lifting oil system oil pressure > 4.2MPa (g) turning gear can put into work

All the pressure switch in lubricating oil supply system must test at least once a

year.

14 Temperature switch and heaters

The temperature switch and immersion heaters were adjusted either at the factory

or at installation; however, their operation and set points should be verified

periodically. The power to the heaters should be shut off before attempting to inspect

them or perform any maintenance on them.

15 Level controls

The level controls were calibrated either at the factory or at installation; however

their set points and operation should be verified periodically. The low-level alarm and

Page 29 of 74


heater trip can be checked while the reservoir is being drained. With the power to the

heaters disconnected an ohmmeter should be connected across the heater lockout

contacts on the level control. As the oil level falls, the heater trip set point can be

verified by noting the oil level at which the ohmmeter indicates a loss of continuity.

The alarm point can be verified by noting the oil level at which the alarm activates.

The high level alarm and trip set points can be checked while the reservoir is being

refilled; the reservoir should be filled to a level that is sufficient to activate the alarm

or trip before starting the motor driven oil pumps to fill the oil supply piping. See the

section of this leaflet describing the level controls for additional information.

16 Oil pressure value

name Description symbol Design value MPa(g)

Outlet——In rated speed

A 1.442～1.8

Inlet——and emergency oil pump

put into work

A 0.069～0.1373 Main oil pump

Inlet——In rated speed A 0.069～0.31

HP startup oil pump A 0.838～0.896

Auxiliary pump(AC) A 0.083～0.124

emergency oil pump(DC) A 0.083～0.124 Auxiliary pumps

Lifting oil pumps A 8～12

Lubrication oil 0.096～0.124 Pressure set

value(in rated

speed)

Auto-shutdown lubrication oil 0.03

Emergency Trip set value ≤3330r/min

Page 30 of 74


17 Bearing and lubrication oil system

Description:

Exciter the generator’s bearing temperature limit may be found in "generator

statement."

(1) Bearing metal limit temperature (3000 r / min).

a: According to oil temperature, oil flow, bearing size and bearing load different, the

turbine bearings metal general temperature is between 66 ℃ to 121 ℃. 107℃

alarm. In more than 107 ℃, operator must be aware and to identify the causes of

abnormal temperature . Bearing metal temperature exceeds 113 ℃, turbine should be

tripping.

Note:

When the bearing temperature changes frequently. Operator should

immediately identify the cause and trip of turbine if necessary. Inspect bearing

and necessary repairs.

b: thrust bearing metal temperature range, primarily on the basis of axial loading,

from slightly over oil inlet temperature up to 99 ℃. Alarm setting value is 99 ℃,

tripping setting value is 107 ℃. If the temperature is between alarm temperature and

tripping temperature, operator should pay attention to monitor and identify the causes

of abnormal temperature.

(2) Lubrication oil pressure limit

The turbine of the bearing oil pressure alarm value and tripping value see "restrictions

on the value of preventive measures and testing" in a “turbine lubrication oil

pressure," the relevant provisions.

(3) Lubrication oil temperature limit

a: If oil temperature of the oil reservoir below 10 ℃, shall not be initiated bearing pumps. b: Oil temperature of the oil reservoir at least at 21 ℃, the startup of turning gearing

Page 31 of 74


is permit ion. 21 ℃ is also the minimum turbine operation oil temperature.

c: The oil temperature of turbine bearings back to oil reservoir should be below 83 ℃,

the alarm value is 77 ℃, the tripping value is 83 ℃.

c: When the turbine at normal operation, the lubrication oil temperature inlet bearing

is between 38℃ and 49 ℃., cut off oil cooler’s cooling water, make oil temperature

rose to above range.

d: When turbine in operate, make three-ways valve in open condition, to ensure that

the standby oil cooler is full of cold oil inside and can be put into work at any time.

(4) Vapor extraction device

a: When the turbine in operate, the vapor extraction device in oil reservoir must be put

into work.

b: The vapor extraction device put the mist-gas (hydrogen and air) from the

lubrication oil system and seal oil system out so that the whole turbine lubrication

system and sealing oil system to maintain a low of negative pressure, and prevent the

fuel-air along the rotor, leakage to the atmosphere.

c: These task of exciter and generator oil system is done by the seal oil system vapor

extraction device, and the turbine bearing box﹑oil reservoir and other parts of piping

to the above-mentioned tasks, is completed by the vapor extraction device in oil

reservoir.

d: When the turbine in operate, if one of the two vapor extraction device failure or cut

off. Have the possibility that some hydrogen 、oil gas and (or) lubrication oil may

leaked to the turbine room. Under such circumstances, the turbine generator should

immediately shutdown until the vapor extraction system to regain work.

18 Backup power

When the turbine in any higher speed than turning gear, with a reliable standby

power is very important. Lubrication oil system designs two bearing oil pumps; one is

AC pump and the other pump is DC oil pump. In some emergency situations, such as

Page 32 of 74


the AC power cut off, in order to guarantee the safety of turbine coast down, backup

power supply time for the turbine should not be less than coast down time. Provide a

reliable, adequate capacity of the DC power supply is the consumer’s responsibility.

By the power failure caused the loss should be responsible for the consumer.

As a storage battery to DC power, Its capacity in the coast down time, the pump

must supply the necessary rating power. Maintenance of its time is about 60 minutes.

In the absence of a reliable and adequate backup power supply, turbine does not

allow startup. Operator must continue to monitor the DC power capacity, at any time

should guarantee the safety of turbine coast down time required capacity.

Note:

After the DC motor-driven pumps and its subsidiary pressure switch test, the

pump must be cut off, and then switch back to the "automatic" position.

19 Oil system flushing and installation procedure

19.1 Preface

It is the responsibility of the purchaser or his installation contractor to obtain a

clean oil system in accordance with the acceptance criteria of this specification.

There are a number of operations, which must be carefully followed beg1nning

with certain factory operations and terwinating with the flushing and restoration of the

oil system for operation. Each recommendation made herein must be carefully

considered and implemented accordingly. Although the basic concepts are applicable

to all units, including pace and integrated BFP turbines, each unit must be reviewed

and modified for specific differences.

Remember that the oil system is a large complex system with large piping and oil

flows. Yet a small harmful particle can damage a large journal bearing resulting in a

Page 33 of 74


costly shutdown to correct the damage.

19.2 Introduction

Oil flushing is a necessary operation, which must be performed after all of the oil

piping is installed and connected. This operation, however necessary, really does not

add to the physical assembly of the unit. It generally is performed when the unit is

nearing completion and falls directly in the critical path for startup. Therefore,

considerable attention is focused on the time spent to flush and restore the unit for

operation.

The primary function of the oil flushing operation is to remove any harmful particle

contaminants, which can damage or cause any related turbine generator component to

malfunction.

Past experience has shown that most of the harmful contaminants removed during

the flushing operation are those which were introduced into the system during the

storing and installation of the unit.

These contaminants primarily enter the system through the open pedestals, open

bearing housings, and/or contaminants, which collect in the guard piping during the

field installation.

It is of utmost importance that all contaminants be physically or mechanically

removed, wherever possible, before the flushing operation. All current units are now

provided with access openings to mechanically clean and inspect all components

including the guard pipes, prior to the flushing operation. Any contamination, so

removed l will not score or damage a bearing or a journal.

The time and effort spent during this pre-flush cleaning program will

unquestionably decrease the overall flushing time required to achieve a clean system.

The burden imposed on the flushing operation must be limited to the contaminants,

which cannot be mechanically or physically removed prior to flushing.

Page 34 of 74


To assure compliance with the specifications and procedures, all checks as

identified in the check-off list must be completed and verified by the installation

contractor. All pre-flush checks required by this list must be completed before

flushing begins.

20 Shipping and on-site storage

Experience has shown that during shipment some of the devices provided to protect

components, such as pipe caps, may be lost or damaged. Unless these protective

devices are promptly restored, the unprotected areas will gather dirt and be

susceptible to corrosion.

Therefore, we recommend that the following on-site precautions and procedures be

exercised to include the following components:

A. Oil piping, both guarded and unguarded

B. Seal oil systems

C. Loop seal tanks

D. Pedestals

E. Oil reservoirs

F. Bearing housings including generator brackets

G. Bearings

H. Oil purification systems (Generally not furnished by STC)

1. Inspect the components, upon arrival in the job site. Ascertain that all blanks and

protective devices are intact. If any blanks or protective devices are found missing or

damaged, the interior surfaces they were intended to protect shall be throughly

inspected and restored and reprotected to drawing requirements.

2. Report any damage or abnormal condition of the components to STC.

Page 35 of 74


3. Off-ground, under roof storage is recommended for these components.

4.If under roof storage cannot be provided, the minimum storage requirements shall

be off ground and completely covered with a suitable covering to preclude direct

contact with sand, dirt, rain, or snow.

5. Judgement should be exercised as to the type of shelter provided dependirig on

the contemplated storage time and environment.

6. If long term storage is contemplated, the integrity of the storage procedures must

be periodically confirmed by inspection of the internal surfaces of the components.

Inspections may be performed by sampling 1O% of the components at the end of the

first 3 months and 5% of the total number of components inspected every 6 months

thereafter in accordance with the following guidelines:

a. Remove the component covers that will permit access to internal surfaces

exposed to oil during normal operation. Any surface showing signs of corrosion must

be restored and re-protected to drawing.

b. If 50% or more of the surfaces inspected have some corrosion, all components

must be inspected. Any surface showing signs of corrosion must be restored and

re-protected to drawing.

c. If less than 50% of the sample shows corrosion, identify the components in the

sample so that they are not included in subsequent inspections. Any surface showing

signs of corrosion must be restored and re-protected to drawing.

NOTE

Moisture and sand are generally introduced during the equipment

storage-make certain that the storing facility will exclude both.

Page 36 of 74


21 Installation and general housekeeping procedures

During the installation of the turbine generator unit, the environmental conditions

in the powerhouse are extremely dirty, dusty, and untidy. Under these conditions l all

of the exposed oil bearing surfaces can become contaminated. At this time, a large

amount of debris can be introduced into the guard piping and pedestal cavities, which

may not be removed prior to the final flushing operation.

This debris constitutes the bulk of the contaminants removed from the system

during the flushing operation.

To avoid the introduction of contaminants into the system during the erection cycle,

it is recommended that:

A. Caps or blanks remain on the pipe joints until removed for the fit up and

welding of the joints.

B. Covers be provided on all pedestals and bearing housings. Temporary pedestal

covers can be made of plywood or similar materials. Covers must be equipped with

openings for access to sampling strainers, temporary flushing piping valves, etc.

without removing the cover.

C. Until the permanent coupling guards are installed, each guardpipe joint must be

covered at all times except when actual pipefitting and welding is being performed on

the joint to the installation of the couplings.

D. Upon the completion of each butt or socket weld within the guard pipe, remove

all slag. Wire brush the weld and adjacent areas to the bare metal and restore and

re-protect the areas to drawing. Care must be exercised not to admit contaminants into

the guard pipe.

E. Prior to the assembly of the guardpipe couplings. Inspect the internals of the

guardpipe and vacuum to remove all contaminants.

Page 37 of 74


F. If any drilling, burning or chipping inside of bearing housings or oil reservoirs is

required, special precautions (protective barriers) must be made to protect the adjacent

surfaces. All contaminants must be removed immediately.

G. If modifications must be made on the oil piping, all modified piping must be

mechanically cleaned except in the case of new piping used in modifications, which

must be mechanically or chemically cleaned before installation.

H. Avoid all burning or grinding operations adjacent to the turbine generator.

I. The oil reservoir is generally the first component placed on its foundation. Aside

from periodic internal inspection, all reservoir openings must be sealed until access is

required for field installation.

J. Polyethylene used to cover pedestals, reservoirs, or pipe openings should not be

made from fiber-polyethylene plastic material as the fibers come loose and

contaminate the oil system.

22 Pre-flush planning and familiarization

Although the actual flushing procedure is conducted during the final stages of the

turbine installation, it is essential that the installation contractor and the responsible

parties plan ahead to achieve a clean system.

A. Flushing drawings, where applicable, are standardized for various frame

combinations and are available for early transmittal. These drawings should be

carefully reviewed along with the various component assemblies to obtain a thorough

knowledge of the flushing requirements, procedures and required complement of

material.

B. Prepare a schedule for performing the various flushing operations.

C. The purchaser is responsible for furnishing and maintaining the lubricating oil.

We recommend the use of lubricating oil for flushing. The use of flushing oils other

Page 38 of 74


than lubricating oil is not recommended as these oils contain additives to enhance

their cleaning capability which may be harmful to oil system components. In addition,

flushing oils normally cannot be used as lubricating oil as they do not contain some of

the beneficial additives as lubricating oil. However, if the customer uses flushing oils,

he assumes full responsibility to ensure its compatibility with the entire lubricating oil

system and all turbine equipment exposed to this oil including, but not limited to the

following:

1. All components of the lubrication system.

2. Final charge of lubricating oil.

3. Permanent or temporary flushing hose linings at temperatures up to 88℃.

Including BFPT systems.

4. Rust preventive paints used in pedestal and guard piping.

5. Preservatives used in the pipes for shipping and erection that normally are not

removed.

If turbine oil is used for flushing, it must be reconditioned to new oil specifications

if used for operating oil.

D. Power requirements

1. Both AC and DC bearing oil pumps must be operated simultaneously throughout

the entire flushing operation. Therefore, sufficient AC and DC power must be

available for this and other auxiliary equipment.

2. If DC power is not available for continuous operation, a temporary AC motor

must be provided by the purchaser or his installation contractor to operate the DC

pump

3. The seal oil backup pump must be operable as required.

CAUTION

Page 39 of 74


Before starting pump: Fill the pump with clean oil to seal the clearances and

lubricate the internal parts. Starting or running a dry pump will came galling,

seizing or destructive war between gears, side plates and pump body.

4. The bearing lift pump l where used, must also be operable as required.

E. Contamination analysis equipment

The following contamination analysis equipment must be supplied by the purchaser

or his installation contractor.

A). The following equipments:

1. Pyrex filter holder with stainless screen.

2. Filtering flask, 1-liter capacity.

3. Vacuum hose ,gum rubber.

B). One vacuum pump.

C). 150-mesh wire cut at site to fit item A-l. Wire should be purchased locally.

D). 10X(Min.) Scaled magnifier.

Refer to section X for sampling procedures and techniques for determining system

cleanliness.

NOTE

150, l60, or l70-mesh can be used depending on local supplier availability. This

is also applicable to 15O-mesh required in all strainers throughout the procedure.

The same mesh should be wed throughout the system.

22 Pre-flush operations and procedures

It is extremely important that all oil wetted surfaces be cleaned and inspected prior

to charging the system with oil.

A. Ascertain that the temporary flushing connections are correctly installed.

Page 40 of 74


Generators shipped assembled will have the bearing oil bypassed at the brackets to

drain. Generators assembled in the field will be treated in a manner similar to the

turbine bearings.

B. It is necessary to modify the oil reservoir piping to obtain the desired flow

configuration, as illustrated in Fig. 1. To flush the main oil pump suction (MOPS) and

discharge (MOPD) piping the oil ejector is disconnected in the reservoir. It is no

necessary to remove the ejector from the reservoir. Lay the ejector on the bottom of

the reservoir and place all nuts, bolts f and associated hardware in a clean sealed metal

container. This container can be stored in the reservoir for the duration of the flush.

The temporary modifications shown in fig. 1 will permit the flushing of the MOPS

and MOPD lines, seal oil backup and the bearing lines without any further internal

reservoir modifications.

C. Inspection and charging the reservoir initially with oil.

l. Inspect inside of reservoir carefully to ascertain that all flanges and temporary

connections are tight and properly supported.

2. Reservoir internal surfaces must be clean and free of all contaminants.

3. The initial charge of oil must be passed through a 15O-mesh strainer.

4. Add sufficient oil so that during operation the oil level in the reservoir is a

minimum of 0.508m above the pump discharge with BOTH coolers and BOTH

pumps in operation.

5. Contaminant traps and inspection covers are furnished on the guardpipe

couplings on new units. Remove all contaminants through these openings manually or

with vacuum cleaners.

6. Clean and cover all pedestals, bearing housings and reservoir openings. These

covers must not be removed during the entire flush unless absolutely necessary.

Page 41 of 74

D. The oil level in the (reservoir) drain trough to the strainer will run near full with

both pumps in operation. Provide a temporary 150-mesh strainer over all overflow

openings including those at the inlet areas. These temporary overflow strainers must

be removed after completion of the flush prior to turbine generator start-up.

E. Guardpipe vent line cleaning

A DN100 vent line is provided in the vertical run of the guardpipe. This vent

connects the reservoir with the horizontal run of guardpipe. Its function is to vent the

reservoir to the horizontal guardpipe since the section of guardpipe adjacent to the

reservoir runs full. This arrangement permits a negative pressure to be maintained

throughout the oil system. This vent pipe normally does not pass oil and generally is a

straight run of pipe.

To clean the vent pipe perform the following steps:

1. When cleaning the reservoir prior to adding any oil, inspect the vent pipe

internally.

2. Remove any debris by washing with solvent and blow clean with high-pressure

air.

3. After pipe is clean. Add a 150-mesh temporary strainer over the opening in the

reservoir using a hose clamp. The pipe generally protrudes 25.4mm to 38.1mm

through the top plate.

4. Remove the screen after flush and reclean if necessary.


Page 42 of 74


F. Hot oil vapors will ignite if exposed to open flame. Avoid any burning, welding,

or any open flame in the turbine areas when flushing.

G. Make certain that fire extinguishers are readily available at the turbine and

reservoir areas.

H. Establish communications with the control room for emergency shutdown of the

pumps. It is recommended that the customer provide temporary emergency switches

at the reservoir to operate the AC and DC bearing oil pumps.

I. Oil purification system (ref: ASME standard no.118).

The oil purification system is normally supplied by the purchaser who is

responsible for the cleanliness of the unit and the interconnecting piping prior to the

flushing operation.

1. It is recommended that all internal surfaces contiguous with the oil be clean and

painted with a permanent type of oil resistant paint. (this includes all surfaces wetted

by oil or exposed to oil vapor).

2. Provide a l50-mesh temporary strainer in both the suction and discharge lines to

the purification unit- The strainer in the discharge line must be located adjacent to the

reservoir as shown in Fig. 2.

3. Oil from the purification system returns directly to the oil reservoir. Therefore,

all interconnecting piping to and especially from the purification system must be

pickled and immediately preserved. Piping must be clean before installation.

4. Provisions must be made to connect a temporary suction line to the purification

system from the bottom of the reservoir. See Fig. 2.

5. The permanent purification system is generally sized to bypass l0%-20% of the

reservoir capacity per hour. It is recommended that additional supplementary filtering

be added to accelerate the removal of fine particles below 0.l27mm.

Page 43 of 74


NOTE

The purification system must be in service throughout the entire flushing

operation. If the pumping operation is conducted on less than a 24-hour per day

basis, the purification system should remain in service continuously.

The strainer in the return line between the purchaser's oil conditioning unit and the

oil reservoir is to be removed and cleaned each time the flushing operation is

shutdown. At the successful conclusion of the entire flushing operation ,this strainer

can be removed permanently providing the debris on the strainer meets the particle

count requirements of this specification. If the debris exceeds the specification

requirements, the strainer must be replaced and remain in operation until the debris is

within the specification requirements. Removal of this temporary strainer, for

sampling and cleaning, can be performed at any time after the successful completion

of the flushing process.

23 General design considerations

A. The primary areas contiguous with the lubrication oil surfaces are:

1. Oil reservoir

2. Oil coolers

3. Oil piping ,guarded and unguarded

4. Bearing housings and pedestals

5. Oil purification system

B. Oil reservoirs:

On large central station units we have standardized on the following nominal

reservoir sizes: 30m3. The reservoirs are cylindrical in shape and in addition to the oil

contain internal piping, check valves, oil ejector, pumps f orifices and relief valves

necessary to control the lubricating oil system. Provisions are also made in the

Page 44 of 74


reservoir to supply high and low oil pressure seal oil backup to the generator seals.

The oil reservoir shell is fabricated and sandblasted internally then cleaned and

painted with oil resistant aluminum paint. This paint affords an excellent oxidation

resistant surface. Similarly, all of the exteri or surfaces of the components inside of

the reservoir are painted to aluminum paint. The inside of the oil piping is pickled and

coated with a rust preservative oil.

C. Oil coolers:

Oil coolers are fabricated in a package including the stop valves and

interconnecting piping. This cooler package is hydro-tested using water. The fluid is

then drained; however, all internal surfaces of the cooler are adequately coated with

the rust preservative fluid. The openings are immediately blanked for shipment.

D. Oil piping-guarded and unguarded

The guarded oil piping interconnects the oil reservoir with the turbine pedestals. It

acts as an envelope for the internal pressure piping and also as a drain line to return

the oil to the reservoir.

The internal surfaces of the guard pipe and the external surfaces of the internal

pressure piping are painted with aluminum paint. All of the internal surfaces of the

pressure supply piping are pickled or sand blasted and coated with a rust preservative

oil and capped. The end of the large guard pipes are also capped, thereby double

protection is provided for the internal pipe system.

E. Bearing housings and pedestals

The bearing housings and pedestals are designed to eliminate any crevices, which

may act as a dirt retainer. All oil supply & BRG lift lines are fabricated to avoid areas,

which cannot be cleaned and inspected through suitable clean-out plugs. All pedestal

internal surfaces ,base and cover,are cleaned and painted with aluminum paint. All

machined surfaces are coated with a preservative.

Page 45 of 74


All assembled components are properly capped or plugged to preclude the

introduction of contaminants during the shipping and subsequent on-site storage

period.

24 General notes

A. Pumps and motors

To obtain maximum flushing velocities the AC and DC bearing oil pumps must be

run simultaneously throughout the entire flushing operation. The pumps are capable

of producing flows well above the normal rated flow requirements. The maximum

load imposed on the motor must be periodically checked by monitoring the input

current. Record the results of each check.

1. Open drip proof motors may be operated continuously at 15% above the

nameplate rating.

2. Do not exceed the nameplate rating on totally enclosed fan cooled or explosion

proof motors.

B. The oil flushing must be conducted on a minimum of one shift per day (8 hours

normal) basis.

C. Vibrators: fieldwelds in exposed and accessible oil supply piping should be

rapped or vibrated in the weld areas with the following considerations and

precautions:

1. Use brass or lead hammers to rap the weld areas, do not use lead on nuclear

units.

2. Use blunt contoured chisels with ends surfaced with soft brass.

3. Vibrating the guard piping is not recommended since it may distort the internal pipe bracing

and weld joints. CAUTION

Page 46 of 74


Do not impair the integrity of the welds or the adjacent piping in any way the

rapping or vibrating operations.

D. Alternate heating and cooling of the oil is required throughout the entire flushing

operation. The heating and cooling produces thermal expansion and contraction of the

piping, thereby, loosening the foreign particles adhering to the walls of the pipe.

Heating and cooling of the oil also produces large changes in the oil viscosity thereby,

providing a better scrubbing action and capability of transporting heavier particles to

the strainer. To achieve the beneficial effects of contraction and expansion and

changes in viscosity, we suggest a minimum oil temperature change of 38℃. The

maximum oil temperature should not exceed 88℃.

E. The oil coolers normally supplied with the unit may be used to heat and cool the

oil. Hot water (not exceed 93℃)may be circulated through one cooler to heat the oil.

If hot water is not available it then will be necessary for the flushing contractor to

furnish a heat exchanger for this purpose. A typical heat exchanger is shown in Fig. 3.

The other cooler should be connected to a cold water source for cooling the oil'

Refer to note on last page of this content

F. To preclude excessive pressure drop resulting from large oil flows through a

single oil cooler, the cooler bundle must be removed for the flushing operation.

Therefore:

1. Supplemental heating of the oil must be furnished by the flushing contractor.

2. The source for heating the oil may be steam coils or electric immersion heaters in

the oil coolers or in the oil reservoir. The heating device should be sized to heat the oil

to 66-82℃, in approximately four (4 ) hours. A considerable amount of heat is lost by

radiation when circulating at low station ambient temperatures; therefore, include this

factor when sizing the oil heaters.

3. If electric immersion heaters are used they must not exceed 0.028 watts per

Page 47 of 74


square mm density.

CAUTION

Always maintain an oil level in the reservoir to completely cover the electric

heaters' Shot off heaters when oil is not being circulated. Un-submerged,

energized heaters in the reservoir will ignite the oil.

4. If steam heaters are used, inlet steam temperatures do not exceed 177℃. Shut off

steam to heaters when oil is not being circulated.

G. Supplemental pump

Although the capability of the system will produce adequate flows to obtain the desired flushing

velocities, the system can be readily modified to accept a supplemental pump. Refer to Figure 4, which diagrammatically illustrates a typical system utilizing a

supple mental pump.

By removing the DC pump, access for the supplemental pump suction is readily

available. The pump discharge is connected to the ejector discharge in the reservoir.

Priming of the pump may be accomplished by using the AC bearing oil pump in the

reservoir.

H. Oil coolers

The oil coolers are designed for 0.33 Mpa(a)shell pressures and hydro tested to

0.50 Mpa(a)

CAUTION

Do not under any circumstances pressurize the coolers above 0.50 Mpa(a).

I. Flow philosophy

It is important that the flushing contractor understands the basic flow philosophy so

that he will take the necessary steps to attain the desired flushing velocities.

Page 48 of 74


Primarily the fluid velocity in a pipe is a function of the flow and area' Figure 5

illustrates a typical bearing header supply configuration where four bearings are

supplied from a single header. Each bearing requires0.76m3/min at synchronous

speed with a bearing oil pressure of approximately 0.11 MPa(g) at the turbine

pedestals.

The header-supply pipe system is sized for a normal operating velocity of

approximately 1.52m per second.

In order to double the flow-velocity the discharge area must be doubled. To triple

the flow-velocity through the header the discharge area must be tripled. Note that in

each case the flow-velocity through the system is a function of the discharge area and

obtained with moderate oil header pressures. Openings are generally provided

adjacent to the bearings for cleaning and visual inspection of the supply headers in the

pedestals and bearing housings. These openings are also designed to provide

supplementa1 discharge areas in the bearing header. Each supplemental port must be

partially open during the flushing operation to obtain cleaning and additional flow. A

2mm half gasket applied to the top half of all blind flanges or application of

temporary hoses and valves; to pipe plug connections as shown on Fig. 5 will provide

adequate flow.

Remember that the velocity is a direct function of the flow' Doubling the flow will

double the velocity. Also, the header flow is contingent on the discharge openings.

Therefore, always attempt to circulate oil with all discharge areas open as wide as

possible without overloading the pump motors, flooding the bearing pedestals, or

overflowing the reservoir manhole cover.

CAUT1ON

Under emergency conditions involving loss of one pump immediately check

the load on the operating pump motor, as it may become overloaded. If this

Page 49 of 74


condition occurs, reduce the flow from the header he closing selected discharge

valves at the bearings until the motor current is reduced to a permissible level-

Discontinue the flushing operation until both pumps are restored to service.

A general rule for the application of short (approximately 4.6m long) DN50

temporary hoses is that one hose is adequate to obtain twice the normal flow-velocity

for all bearing sizes including:

406 mm× 406mm- 3000RPM

533.4 mm× 533.4mm- 1500RPM

For larger bearing sizes a single DN 80 line or two DN50 temporary hoses must be

used.

For the following generator bearing use a single DN100 line or a DN80 line in

parallel with a DN5O hose:

533. 4mm ×533. 4mm- 3000RPM

7l1. 2mm × 889mm- 1500RPM

All valves used in the above temporary lines must be full flow gate valves. When

instal1ing temporary hoses, select hose length to allow some slack in the line. Apply

two clamps on each hose connection. Check all clamps periodically during the

flushing operation and anchor all hoses to eliminate whip or walk.

To preclude excessive pressure drop through the cooler with two-pump, full flow

flushing, place both coolers in service simultaneously by placing the three-way vavle

handle or hand wheel in the mid position. This does not interfere with the heating and

cooling as described under section E.

NOTE

Alternate controlled admission of cold and hot cater to the respective cooler with

oil flowing simultaneously through both coolers will attain the desired oil temperate

Page 50 of 74


cycling with minimum oil flow restriction and pressure drop through the coolers.

25 Flushing procedures

A. The flushing procedure is subdivided into four(4) basic parts:

1. Preliminary flushing procedure to determine reservoir/oil cleanliness.

2. Main oil pump suction and discharge lines including the associated control lines

in the pedestals.

3. Bearing oil supply lines and miscellaneous lubricating oil lines including bearing

lift pump lines where applicable.

Bearing lift lines, where provided for the central BRG lift system, oil reservoir, are

to be flushed continuously with the bearing oil lines. Figure 6 outlines the necessary

modifications to a typical bearing lift line. All of the internal tubing is removable and

can be visually inspected and mechanically cleaned if required.

For individual bearing lift system the lines are flushed with the bearing oil line in

the respective bearing housing. Fig. 6A outlines the necessary modification to a

typical individual bearing lift line. The bearing lift pump is supercharged from the

bearing supply header. The filter at the discharge of the lift pump shall be inspected

and clean before starting the lift pump' Remove the filter element and clean after

completion of the bearing oil flush.

4. Sampling is not required for bearing lift lines, hydrogen seal oil lines and HP and

LP back up lines.

B. The following describes details of the four flushing steps:

1. Reservoir/oil cleanliness

a. Start oil flow. Clean the reservoir return strainers as required to prevent oil from

overflowing the oil reservoir manhole cover during the initial period of high debris

accumulation.

Page 51 of 74


b. When approximately 8 cumulative hours of full flow flushing have been

completed. Shutdown flushing operation for the overnight period immediately

following the 8-hour total run. Continue operation of the oil purification system.

c. After approximately 16 hours of flushing, shutdown and perform the following

operations:

1). Secure purification system and inspect, clean, and reassemble the temporary

strainers in the lines to and from the purification system.

2). Open guard pipe access covers and inspect and clean the inside of the guardpipe

in the vicinity of the access opening as required.

3). Drain, clean and reassemble all guard pipe contaminant traps.

d. Commence full flow flushing with oil purification system in service.

e. Repeat step b and c. 1.

f. Determine c1.anliness of reservoir by examining the temporary strainer in the

suction line to the oil purification system. Recommended guidelines for action are:

1). Less than 50 hard particles greater than 0.127mm continue to flush.

2). More than 50 hard particles greater than 0.127mm drain and clean reservoir.

3). Recharge with same procedure as initial fill if step (2) is required.

2. Main oil pump suction and discharge lines (ref. figure 1).

The reservoir modifications have been made per the "pre-flush operation and

procedure" to accommodate the flushing of the MOPS and MOPD lines. Provisions

11ave also been included (ref. fig. 1) whereby the temporary bypass line can be

capped at "A" after flushing the MOPS and MOPD lines without draining the

reservoir so that full oil flow to the bearing oil header can be accomplished. The oil,

which is circulated through the main oil pump lines does not pass through the oil

coolers. Therefore, it is necessary to continuously bypass oil through the bearing

Page 52 of 74


header to heat and cool the oil.

The shut off valve in any bearing supply line can be opened during this flushing

operation to facilitate the heating and cooling of the oil. (Bypass approximately 0.75

m3 /min).

Install a sampling strainer on the temporary main oil pump discharge line (see fig. 1)

at the reservoir to determine when these lines meet the acceptance criteria

NOTE

All miscellaneous control tubing inside, of the pedestals and bearing housings must

be disconnected at this time and pumped throughout the entire flushing procedure.

Connections may vary depending on unit configuration. Generally the principle

connections include the following components.

a. Auto-stop and protective devices.

b. Zero speed indicator.

c. Thrust bearing trip.

d. Oil supply to the turning gear and gear sprays.

Remove and catalog any orifices in these lines to insure full flushing flows. Flush

the MOPS and MOPD lines by closing the valves in the temporary flushing hose lines

at the bearings so that the pumps are not overloaded. However, sufficient bearing

lines must remain open to provide adequate flow through the oil coolers for heating

and cooling the oil.

Thrust bearing supply lines are to be open throughout the entire flush. No sampling

is required since the common supply line is sampled adjacent to the thrust bearing.

NOTE

During the M0PS and M0PD flush, open additional bearing oil lines to Pump as

many bearing simultaneously as possible without overloading the pumps.

Page 53 of 74


In the event the MOPS and MOPD lines do not meet the cleanliness requirements

of this specification, or show a positive and continuous reduction in the number of

hard particles deposited on the sampling strainer within the first 100 hours of flushing.

Shutdown and locate and remove the source of contamination before continuing the

flushing operation.

To ascertain that there is a positive and continuous reduction in the number of

particles ,a minimum of 10 samples must be taken during the 100-hour period. The

trend may be determined by counting particles on the 150-mesh filters. By weighing

or by examination with a magnifying glass. All samples must be identified, protected

and retained until successful completion of the flushing process for the entire oil

system. These samples will be used for comparative analysis and reference in the

event problems develop during the flushing operation.

If a positive and continuous reduction in the number of hard particles is not

demonstrated in this initial 100-hour period, analyze the debris to determine whether

or not it is typical of the foreign material usually encountered in these components as

a result of normal erection procedures. If it is normal, restart and flush until the

system is clean. If the debris is abnormal ,locate and remove the source before

continuing the flushing procedure. In either case, if the system does not clean up in

the next 100 hours, shutdown and repeat the above process. Thereafter, continue the

flushing operation in 100-hour increments shutting down and executing the above

procedure at the end of each 100-hour increment until the oil system meets the

cleanliness requirements of this specification. After the flush has been completed,

reassemble the orifices as originally found. When the MOPS and MOPD lines meet

the cleanliness criteria, the temporary bypass hose line is capped or blanked off.

Remember that this hose remains pressurized during the remainder of the flush.

Page 54 of 74


3. Bearing 0il supply lines

All bearing lines are f1ushed to a point adjacent to the bearing, there is no oil flow

through the bearing during flushing. All thrust bearing shoes must be removed prior to

commencing oil flush. Determine the type of bearings provided at each location and

install the temporary bypass configuration as shown on Figures 7A, 7B.

If the top half of the bearing is removed, protect the exposed journal surface. When

flushing, always open as many bearing oil discharge lines as possible at the turbine

pedestals and bearing housings without overloading the motor or flooding the bearing

pedestals or housings. Remember, maximum flow will produce maximum velocity'

Typical L P bearing housings, including the temporary hoses and sampling strainers

are shown on Figures 7A. Note that the section of the supply line adjacent to the

bearing is removable and a temporary pipe must be connected directly to the header.

Also note that the temporary hose should be directed into the bearing drain guard to

avoid flooding the pedestal.

Removable flanges or plugs are available for added flow area. They must be

partially open as shown in Figures 5, 7A. On other pedestal configurations, check for

the location of the clean out plugs and apply temporary hoses or valves connections.

These must also be partially open during the flushing operation.

NOTE

Record the location of the partial gaskets and the removed plugs. These flanged

joints and plugs must be restored after the Pump is completed.

Always install and record a bearing header gauge to monitor the pressure in the line.

Opening the bearing bypass lines and the supplemental bypass lines in the bearing

housings will reduce the header pressure. This is normal, and indicates that additional

flow is passing through the header piping. Do not attempt to maintain a high header

pressure by closing the bearing bypass valves. Remember that the velocity is a

Page 55 of 74


function of the flow through the pipe and not the pressure in the pipe. Full flow flush

for 24 hours and begin sampling the cleanliness of the bearing lines. Sampling strainer

screens are not to be installed during the flush unless the oil is being sampled.

Remove the plug and screen to permit full flow through the strainer housing.

Begin sampling after this 24-hour period, all bearings may be sampled

simultaneously or individually in any sequence at the discretion of the flushing

contractor. Thereafter, sampling of any bearing or bearings may be repeated in

two-hour intervals. In the event, the bearing supply lines do not meet the cleanliness

requirements of this specification, or show a positive and continuous reduction in the

number of hard particles deposited on the sampling strainer within the first 100 hours

of flushing, shutdown and locate and remove the source of contamination before

continuing the flushing operation.

To ascertain that there is a positive and continuous reduction in the number of

particles, a minimum of 5 samples on each bearing must be taken during the 100-hour

period. The trend may be determined by counting particles on the l50-mesh filters, by

weighing or by examination with a magnifying glass. All samples must be identified,

protected and retained until successful completion of the flushing process for the

entire oil system. These samples will be used for comparative analysis and reference

in the event problems develop during the flushing operation.

If a positive and continuous reduction in the number of hard particles is not

demonstrated in this initial l00-hour period, analyze the debris to determine whether

or not it is typical of the foreign material usually encountered in these components as

a result of normal erection procedures. If it is normal, restart and flush until the

system is clean. If the debris is abnormal, locate and remove the source before

continuing the flushing procedure. In either case, if the system does not Clean up in

the next 100-hours, shutdown and repeat the above process. Thereafter, continue the

flushing operation in l00-hour increments shutting down and executing the above

Page 56 of 74


procedure at the end of each l00-hour increment until the oil system meets the

cleanliness requirements of this specification. Each bearing supply line must meet the

acceptance criteria before it is finally judged clean. When flushing has progressed to

the point where two(2) bearing line samples approach the acceptance criteria ,i.e.:

a. l0-15Hard particles in the 0.127 to 0.254mm range.

b. Up to 4 hard particles above 0.254mm. Shutdown the flushing operation and

remove the oil cooler bundle(s).

NOTE

Coolers must be drained and pulled individually with the 3-mp valve in an

appropriate position to isolate the bindle being removed. The isolated cooler

must be drained before pulling any tube bundle.

Clean the oil cooler shell(s) with clean, lint-free rags. Steam clean the oil cooler

tube bundle(s). The cooler bundle(s) must be protected during the entire time they are

removed from the cooler shell(s). Re-install the cooler bundle (s) and continue the

flushing operation.

Once the cleanliness criteria is satisfied for any bearing, that bearing line is judged

clean and no further sampling of that line is required.

When any generator or LP turbine bearing line is judged clean, immediately connect

those temporary hoses to the seal oil manifold to back-flush the seal oil lines. Provide

a minimum of 3 to 5 supply lines from the generator and LP bearings to each

manifold.

Roll each bearing after the flushing operation and carefully inspect the babbitted

surfaces. Remove any embedded hard particles by lightly scrapping the bearing

surface without removing any babbit. Clean and coat journals with S. T- P. oil or SAE

Page 57 of 74


90 oil and reassemble bearing caps.

4. Hydrogen seal oil lines

The hydrogen seal oil lines interconnect the seal oil unit to the generator brackets.

These lines are normally flanged at each end. By disconnecting the flanges at each

end and installing side outlet flanges, each pipe section can be flushed. All

interconnecting hydrogen seal oil piping is backflushed from the generator to the oil

reservoir. Valves manifolds are used at the generator brackets to supply and regulate

the oil through each line. A similar manifold is used at the seal oil unit to return the

oil to the reservoir. Oil for back flushing is supplied to the manifolds from the

generator and low-pressure turbine temporary bearing bypass lines. At least three (3)

or more supply lines must be connected to each manifold in produce sufficient back

flush oil.

There are several configurations of seal oil piping, however, the basic back flush

philosophy will apply to all units. Two DN50 temporary drain lines ate adequate to

return the oil to the reservoir on fossil units under 500MW.

On larger fossil and all nuclear units provide a DNl00 pipe header from the seal oil

unit to the reservoir. Hose or pipe (steel f aluminum, or plastic) connections are to be

used from the seal oil manifolds to the header and from the header to the reservoir.

Most of the seal oil pipe connections are under DN25 and are sensing lines with

little or no flow. These lines are to be backflushed for a minimum of 8 hours and

checked for free flow. No sampling is required on these lines. The air side and

hydrogen seal oil feed lines are to be flushed and must meet the bearing acceptance

criteria. See Fig. 8 for sampling strainer locations

26 Procedures for determining system cleanliness

A. Insert a clean sampling strainer into the Y housing and open valve for 30

Page 58 of 74


minutes of full flow.

1. Close valve and carefully remove the sampling strainer and place into a clean

container.

2. In a clean environment l wash the sampling strainer with a clean fluid collecting

all residue on a l50-mesh filter into a vacuum flask.

3. Remove the filter and, using a scaled magnifier, scan the filter to determine the

size and number of particles in the 0.l27-0.254mm range.

No attempt is to be made to move or rotate particles. They are to be observed as

they lay on the filter with two dimensions visible.

B. Based on these two dimensions, cleanliness of the specific system being checked

is acceptable if particle sizes and count meet the following requirements:

1. No hard particles above 0.254mm.

2. The total number of hard particles in the 0.127-0.254mm range must be less than

five (5).

C. All contaminants removed from the system should be retained and carefully

inspected. Experience has shown that a system where all pre-flush cleanliness

operations have been followed will yield legs than 0.5kg of contaminants. If during

the normal flushing procedures, a large influx of contaminants is noted, shutdown the

pumps and investigate the source of these contaminants.

D. Harmful particles generally removed during the flushing operation consist of:

1. Large particles of scale or rust, weld beads, and weld slag.

2. Sand, stones ,concrete, or glass.

3. Metal chips of any sort including weld rods.

4. Large particles of cloth, plastics, or other materials, which may not score the

Page 59 of 74


journals but can impede the flow of oil through the piping or restricted openings.

Particles which may exceed the 0.254mm size but are soft and not considered harmful

are: lint, paper, saw dust, tobacco, asbestos, and any soft materials which can be

readily powdered between the fingers.

NOTE

The fore-mentioned procedure is a statistical approach for determining the system

cleanliness. It does not require all of the flushing oil at individual bearings to pass

through the sampling strainers then samples are taken. Supplemental openings or

branch lines added to increase the flushing velocities are to remain open during the

sampling run.

27 Restoration of the system

It is important, after the system has been judged clean, to carefully supervise the

restoration of the unit for operation. Any contaminants entering the system after this

time must be mechanically removed. There is no reflush prior to the operation of the

unit. Several recommendations are in order:

1. Drain reservoir, restore all internal piping ,clean and carefully inspect the reservoir after

restoration. It must be thoroughly clean before the final charge of operating oil is supplied. 2. Remove main oil pump casing cover. Inspect pump casing and impeller and

ascertain that pump housing, seals, and vanes are clean.

3. Clean and install all bearing pedestal covers immediately after the flushing is

completed.

4. If any piping modifications are made to the oil system after the flushing

operation has been completed, it may be necessary to reflush.

5. Clean all contaminant traps in the guard pipe. Carefully inspect internal piping

and guard-pipe through the handhole openings and reassemble promptly.

Page 60 of 74


6. Any blanks or plugs removed or lost in the bearing housings or pedestal for

flushing must be properly reassembled and tightened. Tack weld plugs or two flange

nuts diametrically opposite.

7. After the system has been restored, oil must be circulated for a period of 1 hour

per week to maintain an oil film on all areas contiguous with oil that are not painted.

(check for leaks and proper oil operating levels). For extended lay-up of the unit after

the system has been flushed consult STC.

8. Any miscellaneous fittings or valves not shown on the "TEMP CLEANING

B/M" required for the flushing operation will be furnished by the flushing contractor.

9. Temporary strainers over drain through overflow slots and other locations where

applied, must be removed before the startup of the turbine prevent oil spill if the

return strainer should become plugged.

28 Temporary flushing materials

It is the responsibility of the purchaser or his designated flushing contractor to

supply all of the necessary temporary equipment to satisfy the "oil flushing

specifications and procedures."

The following section will outline the basic major temporary components required

for the flushing operations. It is not intended to outline in detail the miscellaneous

hardware such as nuts, bolts, pipe plugs, pipe reducers, etc., which is normally carried

by most piping contractors.

There are a number of drawings transmitted to the customer shortly after the unit is

purchased. These are the basic drawings which must be reviewed in order to produce

a materials list for flushing.

A. General information; drawings. Drawings transmitted to the customer.

1. Piping clear & equip LOC oil

Page 61 of 74


2. Oil sys flsh instl proc

3. Piping oil flow diagram 4. Piping oil drain guard assy

5. Piping oil generator assy

6. Piping oil seal assy

7. Lub oil reservoir outline

B. General information-flushing hardware:

1. Sufficient temporary material must be procured to flush the entire system.

2. All temporary flushing equipments must be free of all harmful particle and

chemical contaminants.

3. The pressure rating of the flushing materials must be suitable for the maximum

working pressures encountered during the flushing operation.

4. Any hose materials used for bypass or sampling connections, must be compatible

with hot oil at 88℃ temperatures. Neoprene or buna-N has been generally used.

5. When the lube oil pumps are used to provide the flushing oil pressures, 0.84 MPa

fittings are acceptable. If a supplemental pump is used, the pressure rating of the

hardware at the pump, must be furnished accordingly.

6. Use gate valves where full flow is required, otherwise, globe valves are

acceptable.

7. The flushing contractor should investigate the use of aluminum irrigation piping

with suitable couplings for sizes above 100 mm with suitable pressure ratings.

8. If any temporary pipe is fabricated or pre assembled and stored for any period of

time, all internal surfaces contiguous with oil must be protected with a rust

preventative oil compatible with turbine oil.

Page 62 of 74


C. Reservoir Preparation:

1. Supply the necessary connections to the customer' s purification system from the

bottom of the reservoir. If a supplemental oil filter is used, include the necessary

connections to and from the filter. The 100-mesh strainer from the reservoir is a

sampling strainer to monitor the cleanliness of the flushing oil. Suitable valve is

necessary to periodically remove this strainer for inspection fig. 2.

2. Provide a blank off flange at the ejector discharge fig. 1.

3. Connect temporary bypass line from MOP

discharge line to the strainer trough. For all sizes use a .168 bypass line. Provide

bypass sampling strainer line as shown. Provisions for a blank off flange or a DN150

valve must be made at location "A".

4. Supplemental pump: If a supplemental pump is used, the pump discharge is connected into the

ejector discharge. Remove blind flange (C.l-3) fig. 4. 5. Provide a suitable heat exchanger for heating the oil fig. 3.

6. Provide a temporary AC motor if DC power is not available.

D. Bearing oil fIush

1. Determine the number, size and flows for the bearings.

2. Provide one sampling hose assembly for each bearing.

3. Provide sufficient hose or pipe bypass assemblies for each bearing for required

size and arrangement in pedestals refer VIII.

APPENEX

APPROXIMATE FLOW VELOCITY

FOR VARIOUS PIPE SIZES

STANDARD m3/h FLOW m3/h FLOW m3/h FLOW

Page 63 of 74


PIPE SIZE mm FOR 3.05m/s

VELOCITY

FOR 4.57m/s

VELOCITY

FOR SHORT

NOZZLE WITH

△P=0.113MPa

φ64 22.7 34 91

φ89 51 77 198

φ102 69 104 272

φ114 91 136 363

φ140 136 204 454

φ168 204 306 795

φ219 363 545 1452

φ273 568 850 1816

Page 64 of 74


Page 65 of 74


Page 66 of 74


Page 67 of 74


Page 68 of 74


Page 69 of 74


FIGUER 6

1. Remove tubing sections "A" and "B" cap openings as shown.

2. Add temporary DN20 gate or globe valve at bearing lift inlet inside of pedestal.

3. Flush all bearing lift lines simultaneously for 4 hours.

4. Beginning at the generator end of unit, flush each line for two hours. Close all

other lines.

5. After all lines have been flushed individually, re-open all lines and continue to

flush until the bearing flush has bee1completed.

6. Ascertain that the bearing lift passages in the bearing are clean when the bearing

is rolled out after the bearing flush.

7. Set flow control valve to maximum opening and blow through with clean dry air.

Page 70 of 74

Add clean oil to valve internals.

8. Blow out tubing sections "A" and "B" and inspect thoroughly.

9. Reassemble to drawing.

1. Remove tubing section "B" cap opening at the bearing & leave the opening at lift

pump discharge open.

2. Flush the lift system for 4 hours.

3.Ascertain that the bearing lift passages in the bearing are clean when the bearing

is rolled out after the bearing flush.

4. Blow out tubing sections "A" & "B" and inspect thoroughly.

5. Reassemble to drawing.


Page 71 of 74


Page 72 of 74


NOTES:

1. Protect journal and oil groove from oil.

2. Adapter to be supplied by field service.

3. Bottom half of bearing to be rolled as shown.

4. Disconnect hose connections to each pad drain into pedestal during flushing

operation. Remove orifices from supply manifold to insure an equate flow.

CAUTION

Orifice size for upper pads is smaller than for lower pads; be sure they are correctly

reinstalled upon completion of Pumping.

5. Those designs of tilting pad bearings have a horizontal inlet oil supply and

having the seal ring bolted direct to the bearing support, must be flushed by

Page 73 of 74


supporting the spindle with the spindle jacks, and rolling the bearing out completely.

Page 74 of 74



Gland Seal Steam SYS Checked：Yan Weichun 2008.07.15.

Countersign：

Countersign：

AS.4.MAW10.P001E-00 Approved：Chen Lehua 2008.08.08

Contents

1 Gland Seal Steam ....................................................................................1

2 Gland Seal Steam Regulator Valves set points .......................................4

3 Gland seal desuperheater.........................................................................5

3.1 Operation ..............................................................................................5

3.2 Maintenance .........................................................................................6

4 Cleaning of gland steam piping...............................................................6

5 Gland seal steam temperature suggestion ...............................................8

6 Gland steam system operation ..............................................................11

6.1 Startup.................................................................................................11

6.2 Controlled load reduction...................................................................14

6.3 Turbine trip .........................................................................................15

6.4 Shutdown summary............................................................................15

6.5 Shutdown sequence ............................................................................15

7 Gland steam condenser..........................................................................17

7.1 General ...............................................................................................17

7.2 Operation ............................................................................................18 The reproduction, transmission or use of this document or its content is not permitted without express written authority. Offenders will be liable for damages. All rights, including rights created by patent, grant or registration of a utility, model or design are reserved. Copyrights STW all rights reserved.


7.3 Maintenance .......................................................................................18

7.3.1 Access to tubes ................................................................................18

7.3.2 Tube plugging..................................................................................18

7.4 Tube replacement ...............................................................................19

Page 1 of 21


GLAND SEAL STEAM SYSTEM

1 Gland Seal Steam

(1) Gland seal steam should be keep 14℃ superheat before inter rotor gland.

(2) To avoid rotor distortion, before turning gear operation, Gland seal steam

system should be prohibited to work.

(3) The temperature of steam in the LP glands is maintained in the range of 121℃

to 177℃ to prevent possible distortion of the gland cases and damage to the turbine

rotor. Gland seal steam desuperheater temperature controller set point is 149℃. Signal

from LP cylinder GEN END rotor gland thermocouple.

(4) To protect rotor gland from heat stress damage, when turbine in operated or shut

down, minimize the temperature difference between gland seal steam and rotor.

Difference temperature heat stress damage can make rotor flaw in period which can

examine in “Gland seal steam temperature suggestion” flag. For operator, 10000

weeks be suggested used for allowable period endurance fatigue limit.

(5) If customers adopt the motor dr0ve regulate valve, translate pressure signal to

control room from pressure switch. Basis on regulate set value, feedback 4-20mA

signal to the motor drove regulate valve.

(6) When turbine in hot startup, if customer used Auxiliary Supply steam as gland

seal steam, pay attention to the following notes:

A: Gland seal steam must be superheat steam, 14℃ superheat at least.

B: The temperature difference between gland seal steam in rotor gland and rotor

must less than 110℃.

C: Be sure the gland steam piping from Auxiliary Supply station to turbine is hot,

so it can prove that there is no condensate in gland steam piping.

D: Be sure the gland steam piping before gland steam regulator valve station is dry.

Page 2 of 21


( Drain valve is on work).

(7) If the gland seal steam temperature is low or gland seal desuperheater have

condensate,

It can bring turbine vibration increase.

Each valve is equipped with a pressure control pilot（mounted on the valve） and an

air pressure reducing valve containing an integral filter．

The reducing valve supplies air to the control pilot at a constant pressure off

0.1379-0.1517 MPa（g）．The control pilot，In turn utilizes this air to produce variable

output in response to pressure changes transmitted to the pilot through a sensing line

connected to the gland steam header． The controlling regulator valve is then able to

maintain sealing steam to the glands at a pressure established by the set point of its

control pilot under all turbine operating conditions．

The control pilot of each valve senses gland steam header pressure．As required by

turbine steam and load Conditions， steam is supplied through the regulating valve

with the highest control pilot pressure setting providing steam is available at the

source．Normally， the HP steam supply is used on startup，following trips and load

rejections，or at low loads when the cold reheat supply is not available. Therefore, the

HP supply control pilot is set at the lowest pressure setting and the cold reheat supply

control pilot is set 0.00345 MPa（g）higher．

If the leakage past the inner glands into chamber“X”exceeds the mount of steam

required to seal the LP turbine glands， the header pressure will increase， the supply

valve will completely close， and the spillover valve will open dumping the excess

steam to the condenser thereby controlling steam pressure In the gland steam

header .Therefore， the control pilot of the spillover valve is set above the set point of

the cold reheat supply control pilot．

NOTE

Page 3 of 21

1:Gland steam supply to the three Supply valve have different parameter,

table as follow show the refer parameter (reference):

Item Pressure MPa(g) Temperature ℃ Flow Kg/h

HP Supply valve 17.48 538 3325.8

Cold reheat Supply valve 4.024 326.1 2290.2

Auxiliary Supply valve 0.655 200 3325.8

Notes:

1. the detail requirements see the P&ID, the drawing NO XXXX.98.01(Gland

seal, drain & customer connects)

2. Before air pressure reducing valve , The Supply air which control pneumatic

regulator valves pressure is 0.3～0.8MPa(g), temperature is 40～60℃.

3. If customer adopt the motor drove boiler feed pump turbine(BFPT), the

gland seal system of main turbine will be absolute.

4. The temperature is the most important parameter, mixture two supply

gland seal steam to control the temperature will be allowed.

5. Difference temperature between steam and shaft not exceed 111℃,at any

time, the gland seal steam should be superheated (14℃ above saturated

temperature).

6. The supply pneumatic regulator should be opened when electric or signal, or

control air failure. The spillover pneumatic regulator should be closed.


Page 4 of 21


2 Gland Seal Steam Regulator Valves set points

Normally, the HP steam supply is used on startup，following trips and load

rejections，or at low loads when the cold reheat supply is not available. Therefore, the

HP supply control pilot is set at the lowest pressure setting and the cold reheat supply

control pilot is set 0.00345 MPa（g）higher．.

If the leakage past the inner glands into chamber “X” exceeds the mount of steam

required to seal the LP turbine glands, the header pressure will increase, the supply

valve will completely close, and the spillover valve will open dumping the excess

steam to the condenser thereby controlling steam pressure In the gland steam

header .Therefore, the control pilot of the spillover valve is set above the set point of

the cold reheat supply control pilot．

The set points（approximate） are as follows：

Control Pilot Set Point

HP Supply 0.0207 MPa（g）

Auxiliary 0.0241 MPa（g）

Cold Reheat Supply 0.0276 MPa（g）

Spillover 0.0310 MPa（g）

The status of the valves at various gland header pressures is shown on Table l．

TABLE 1—Regulating valve status(reference):

Gland Header

Pressure

HP Supply Valve Auxiliary Supply

valve

Cold Reheat Supply

Valve

Spillover Valve

0.0207MPa(g) open and controlling open open closed

0.0241MPa(g) closed open and controlling open closed

Page 5 of 21

0.0276MPa(g) closed closed open and controlling closed

0.0310MPa(g) closed closed closed open and controlling

3 Gland seal desuperheater

3.1 Operation

The LP gland seal desuperheater lowers the temperature of the LP gland sealing

steam in the supply pipe before this pipe enters the condenser space. The temperature

of steam in the LP glands is maintained in the range of 121℃ to 177℃ to prevent

possible distortion of the gland cases and damage to the turbine rotor. Desuperheating

of the steam is obtained by utilizing the natural desuperheating that occurs in the bare

supply pipe in the condenser space supplemented and controlled by a temperature

sensitive spray system. The temperature, which actuates the spray system is sensed in

one LP gland. Using this system, with the temperature of steam to the desuperheater

at about 260℃ or higher, gland temperatures in the range of 12l℃ to 177℃ can be

obtained. However, if the temperature of steam to the desuperheater is much below

260℃,and particularly if it is close to the control range of 121℃ to 177℃,the sprays

will not be needed and the natural desuperheating effect in the bare supply pipe may

lower the gland temperatures below the 121℃ limit.

The desuperheater and associated piping is shown diagrammatically on the drawing

"Piping-Steam, Drain and Gland Diagram." The superheated steam enters the

desuperheater where steam velocity increases in the reduced section of pipe' The

steam then passes the spray nozzle where cooling water is injected into the high

velocity stream thus insuring positive atomization and reducing the temperature of the

steam as the cooling water is evaporated. Cooling water from the condensate pump

enters the desuperheater through a pipe to the spray nozzle located in the throat of the

desuperheater. The flow of cooling water to the spray nozzle is controlled by a

diaphragm-operated valve responsive to an air signal from a pilot sensing temperature The reproduction, transmission or use of this document or its content is not permitted without express written authority. Offenders will be liable for damages. All rights, including rights created by patent, grant or registration of a utility, model or design are reserved. Copyrights STW all rights reserved.

Page 6 of 21


at one of the low pressure glands. A drain is provided in the supply pipe at least 1500

mm downstream of the spray nozzle.

Notes：

⑴ The set temperature come from LP cylinder gland(GNN).

⑵ Drain point should be set at least 1500mm downstream of the spray

nozzle.

3.2 Maintenance

(1) Check regulator valve agility one time at least one week.

(2) Check spray nozzle blockage condition per minor overhaul, change the nozzle

if the nozzle is block.

(3) Set a filter before condensate water inter nozzle to protect nozzle block.

4 Cleaning of gland steam piping

Blowdown with Steam

Blowdown with steam is the preferred and most effective method of cleaning

gland steam piping in that temperature cycling helps to dislodge foreign particles (mill

scale ,weld beads ,etc.) from the inside pipe wall surfaces.

1. “ Y" type steam strainer assemblies are provided by manufactory in the steam

inlet pipe to all steam sealed rotor glands. These strainer assemblies are furnished

with an extra (unperformed ) element which is installed in place of the strainer (Item 1

Figure 2) for the blowdown procedure.

2. To prepare the gland steam system for blowdown, the following steps must be

taken:

a. Replace all strainers (Item l) with the unperforated elements.

b. Replace all plugs (Item2) with a section of pipe containing a blow-off valve

(Item 3).

Page 7 of 21

Fig 2. "y" Strainer.

c. Isolate all the gland regulators with valves normally used for regulator isolation.

(Refer to "Piping-Steam Drain & Gland Diagram” ).

d. Gag the outer gland system relief valve.

e. For units having a desuperheating section in the LP gland supply line, remove

spray nozzle and blank off opening.

f. Isolate pressure gauges, regulator sensing lines and switches in the gland

system.

g. Provide connection for the introduction of steam in the cold reheat supply line

to regulator as close to its source as practical.

3. Gland System Blowdown Procedure:

a. Prior to the operation of unit, introduce steam from the boiler into the gland

piping system through the high pressure supply by-pass valve and cold reheat supply

line.

b. If boiler steam is not available, steam from an external source may be

introduced into the gland piping through a connection as close to the supply source as

practical.

c. The maximum recommended steam pressure and temperature in the gland

system for blowdown is 11.6bar(g) and 232℃.

d. Blowdown the large gland pipe lines by opening all blow-off valves (Item 3) The reproduction, transmission or use of this document or its content is not permitted without express written authority. Offenders will be liable for damages. All rights, including rights created by patent, grant or registration of a utility, model or design are reserved. Copyrights STW all rights reserved.

Page 8 of 21


for a period of 2 to 3 minutes or as required to remove foreign matter.

e. Repeat this process several times with sufficient time (1O to 15 minutes )

allowed between blows to insure some cooling of the pipes. Cycling the temperature

in this manner will aid the steam in removing loose scale from the pipes. Hammering

on the pipes in the area of welds during blowdown is also effective in removing loose

scale.

f. Close all blow-off valves (Item 3).

g. Open each blow-off valve repeating procedure as shown in paragraph "e”.

h. Continue the blowdown procedure until all pipes are clean then replace all

strainers (Item 1 ) and all plugs (Item 2). The plugs need not be replaced if the

blow-off pipes and valves are left in place with the valves closed tightly.

i. Pipes between the steam strainers and the gland cases should be cleaned before

erection and the inlet holes in the gland cases for these pipes sh0uld be covered during

erection.

j. the arrangement will be see the drawing GLAND SEAL DRAIN AND

CUSTOMER CONNECT, drawing number is xxx.98.01.

5 Gland seal steam temperature suggestion

To protect rotor form heat stress damage in gland zoom, minimize the difference

temperature between rotor and gland seal steam when turbine in startup or shutoff. In

difference temperature between rotor and gland seal steam, the time produce flaw

because of heat stress damage can examine by the following diagram.

(1) The different temperature between rotor and gland seal steam can be change

in different operating condition, we can count the rotor life consumption in

differential temperature △T by the expressions as follow:

Differential temperature △T operating time

Rotor life consumption percent =Σ ——————————————————×100

Differential temperature△T produce flaw time

Page 9 of 21


=Σ(N/E)×100

(2) For example, give the times in different operation:

N1= In differential temperature△T=166.7℃ startup 60 times。

N2= In differential temperature△T=138.9℃ shutoff 55 times。

N3= In differential temperature△T=125℃，master switch trip 20 times。

Examine the diagram to check the time produce flaw:

E1=2600 times（△T=166.7℃)。

E2=4600 times（△T=138.9℃)。

E3=6600 times（△T=125℃)。

Take the value to the expressions, count the rotor life consumption in gland seal

steam zoom:

Σ(N/E)×100=(60/2600+55/4600+20/6600)×100=3.8%

Page 10 of 21


Page 11 of 21


6 Gland steam system operation

6.1 Startup

6.1.1 Place unit on turning gear, with all turbine and inlet pipe drains open.

6.1.2 Establish water circulation through main condenser.

6.1.3 Start condensate pumps, and establish cooling water flow through gland

condenser.

6.1.4 Open vents on gland condenser water chambers until all residual air is purged

to atmosphere.

6.1.5 Make sure that condenser shell drain system is open to main condenser.

6.1.6 Make sure that gland condenser level alarm is in service and that instrument

shutoff valves are open.

6.1.7 Turn on air supply to LP turbine gland steam desuperheater control valve.

Open manual shutoff valves on either side of control valve. Control valve should stay

in the closed position, since no steam is being supplied to LP turbine glands. Make

sure bypass valve around control valve is closed.

6.1.8 Make sure manual shutoff valves and bypass valve at each gland system

pressure regulating valve station are closed.

6.1.9 Turn on air supply to each gland pressure-regulating valve.

6.1.10 Make sure that steam drains on inlet side of HP and cold reheat supply

pressure regulating valves are open and that supply pipes are free of water.

6.1.11 The operator should verify that the HP supply steam temperature is

compatible with the measured rotor metal surface temperature for the HP-IP turbine.

See the turbine "Operation" leaflet for information on gland sealing steam

temperature limits.

Page 12 of 21


6.1.12 After making sure that the supply piping upstream of regulating valve is free

of water and that steam supply temperature is within the specified range, open manual

shutoff valves on both sides of regulating valve in this order: spillover, cold reheat

supply and, finally, HP supply. The bypass valve around each regulating valve should

stay closed.

6.1.13 Steam pressure will be established in gland supply header when the HP

steam supply shutoff valves are opened. Make sure gland header pressure stabilizes at

the set point pressure for the controlling regulator valve.

6.1.l4 Start gland condenser exhauster immediately after gland header supply

pressure is established.

6.1.15 Make sure there is a slight vacuum at each turbine gland.

6.1.16 Make sure there is no steam leakage to atmosphere from any turbine steam

gland. If steam leakage is found, increase vacuum in gland condenser, or adjust set

point on regulating valves to lower steam pressure in gland header until external

leakage stops.

6.1.l7 Check that steam temperature at LP turbine glands is between the limits of

l21℃ and 177℃. Also check that gland header continuous drain, located between

steam desuperheating section and LP glands is working right.

6.1.18 Close main condenser vacuum breakers. Start air removal equipment, and

establish as high a vacuum as possible in main condenser.

The amount of gland sealing steam required will increase as the vacuum in the

condenser is improved until a maximum flow rate is established at each turbine gland.

6.1.19 If startup is under Automatic Turbine

Control (ATC), a roll off turning gear will be prevented if:

a. HP gland steam temperature is too low.

Page 13 of 21


b. Differential between gland steam supply temperature and end wall metal

temperature is too high.

c. LP gland steam temperature is not being properly regulated between maximum

and minimum limits by gland desuperheater.

ATC will turn on Gland System Error Alarm indicator if any of the above three

conditions are detected and will prevent a roll off turning gear until the fault is

corrected or the operator overrides the alarm.

6.1.20 As load is increased over the initial value, the quantity of external sealing

steam required will begin to decrease. At about 25 percent of rated load, the cold

reheat supply connection will provide all makeup steam required sealing turbine gland

seal system. At higher loads, gland leakage from HP and IP turbine glands may be

equal to total requirements of LP turbine glands. As high load is approached, gland

header steam pressure will increase to set point of cold reheat supply valve pilot, and

this regulating valve will close. If gland header pressure continues to increase, gland

header spillover valve will open and allow excess gland leakoff steam to flow to main

condenser.

NOTE

1: Check the gland clearance when turbine in installation, be sure the

clearance error is in the allowable value. Otherwise it can influence the gland

seal steam regulator valves set point, and it can increase gland seal steam supply.

2: If the gland seal steam leak to atmosphere, inspect the gland clearance and

gland seal steam mother pipe pressure, be sure the clearance and pressure are

not exceed the allowable value.

3: In normally, one gland steam condenser exhauster is on work can satisfy the

turbine operation, but in abnormal condition the two exhausters can work at one

time.

Page 14 of 21


4: If the gland seal steam temperature is low or gland seal desuperheater have

condensate,

It can bring turbine vibration increase. In this condition, the following process

can help the operator to find out the cause:

A: Check the set point of LP gland desuperheater is correct.

B: Check the temperature which actuates the spray system is sensed in one LP

gland.

C: Increase the temperature of gland seal steam.

D: Be sure the superheat of the gland seal steam is above 14℃.

E: Gland seal steam piping inside condenser must heat insulation.

F: Regulate the hand-operated valve before LP gland desuperheater valve,

control the pressure of condensate inter desuperheater regulator valve is between

0.5MPa (g).

G: Check the LP gland desuperheater spray nozzle is installed correctly,

include nozzle size and spray direction.

6.2 Controlled load reduction

On a controlled load reduction, the gland seal system make-up requirements are

taken from the main cold reheat piping as long as the cold reheat pressure is high

enough to maintain the gland supply header steam pressure above 0.0207 Mpa(g). If

the header pressure drops below0.0207 Mpa(g), the HP supply regulating valve opens

as required to keep the header pressure at the 0.0207 Mpa(g) level.

The temperature of the HP supply of sealing steam should be adjusted to match the

HP-IP rotor metal surface temperature as the load is reduced. Matching of the steam

and metal temperatures minimizes the rotor thermal stress (in the gland areas) when

the gland sealing steam makeup is taken from an external source.

Page 15 of 21


There is a check valve in the cold reheat seal supply piping upstream of the

regulating valve. This check valve prevents backflow from the gland steam header to

the main cold reheat piping when cold reheat pressure becomes less than gland header

pressure.

6.3 Turbine trip

In case of a turbine trip, the sealing steam makeup flow is taken from the main cold

reheat piping until the cold reheat pressure drops to a level that causes the gland

header pressure to fall below 0.0207 Mpa(g). When header pressure drops, the steam

sealing supply is taken from the HP steam supply source as described in the previous

paragraphs.

Temperature matching between HP supply steam and cylinder end wall metal is

limited at this time because of the rapid transfer in the source of seal supply. However,

if proper temperature matching was in effect before the trip, excessive rotor metal

surface temperature cycling is minimized when the shift to an external steam supply

takes place.

6.4 Shutdown summary

Gland steam must be supplied to the turbine glands as long as there is a vacuum to

draw air through the seals into the cylinders. The flow of cool air chills the rotor

surface metal and can distort the hot stationary gland cases. Do not shut off the

sealing steam supply until the air removal equipment for the main condenser has been

shut down and the main condenser vacuum has been completely dissipated.

6.5 Shutdown sequence

6.5.1 With the unit on turning gear and sealing steam supply from an external

source, make sure main condenser vacuum has been completely dissipated.

6.5.2 Turn off gland condenser exhauster.

Page 16 of 21


6.5.3 Close manual shutoff valves on both sides of gland steam pressure regulating

valves in this order:

a. HP Supply Valve

b. Auxiliary Supply Valve

c. Cold Reheat Supply Valve

d. Spillover Valve.

The above valves should be closed immediately after the gland condenser exhauster

is shutdown. Operation of sealing steam supply without vacuum in gland cases with

result in a steam blow to atmosphere. This same steam can enter the lubricating oil

leakoff area and condense. The condensed steam in the lubricating oil builds up in the

oil reservoir as a contaminant.

6.5.4 Turn off air supply to each gland steam pressure-regulating valve.

6.5.5 Close manual shutoff valves on both sides of gland steam desuperheating

control valve.

6.5.6 Turn off air supply to gland steam desuperheating control valve.

6.5.7 Shut off cooling water flow through gland condenser.

Page 17 of 21

7 Gland steam condenser

7.1 General


Page 18 of 21


The purpose of the gland steam condenser is to maintain in the gland leak off

system a pressure slightly below atmospheric pressure, to prevent the escape of steam

from the ends of the glands, and to remove and condense the vapor.

7.2 Operation

The circulating water enters the inlet chamber, and flows through the tubes in the

gland condenser, and exits via the discharge chamber.

The gland seal steam is admitted into the condensing section via the steam inlet and

then passes among the tubes. The air and other on condensable vapors are discharged

to atmosphere by an air exhauster, which is described in another leaflet. The drain of

the exhauster should be left open to waste for removal of condensate. The condensate

formed in the gland steam condenser shell is removed via the drain.

7.3 Maintenance

7.3.1 Access to tubes

To clean or inspect the tube ends, both water chambers must be removed.

When the gland condenser is not in use dry lay up procedures are recommended.

Drain and thoroughly dry the tube side of the gland condenser.

If dry lay up is not practical and water must remain in contact with the tubing – it

must be continuously circulated and periodically replaced to minimize corrosion

caused by the concentration of deleterious contaminants. At no time should water

become stagnant.

7.3.2 Tube plugging

Tubes, which develop leaks, should be plugged at each until an opportune time

arises for their replacement. Using light hammer blows, firmly tap the tube plugs into

the tube ends. Tubes, which are leaking at the tube joints, but are otherwise in good

condition, should not be plugged. The proper repair in such cases involves re-rolling

Page 19 of 21


the tube-to-tube plate joint. If leakage persists replace the tubes at the first

opportunity.

7.4 Tube replacement

Removal of a tube requires the use of a tube reamer with a pilot and a pushing pin.

The pilot serves as an aligning device to avoid tilting the reamer and inadvertently

reaming through the diameter of the tube.

Reaming is required to relieve the pressure between the tube and the tube plate, and

to establish a shoulder for the use of the pushing pin. Ream to a distance of 0.80 past

the rolling ridge on the I.D. of the tube at each end of the condenser. Reaming beyond

this point will cause the tube to split when using the pushing pin.

Insert the pushing pin at either end of the tube strike the pin with sufficient force to

jar the tube and break it loose from the tube plates. Withdraw the tube.

Insert a new tube, expand, and machine flush with the tube plates.

LIST OF PARTS

Item Name

0l Shell 02 Water Chamber

03 Gasket 04 Bolt

05 Nut 06 Washer

07 Coupling 08 Stop Valve

09 Coupling 10 Bolt

11 Nut 12 Washer

13 Blower With AC Motor 14 Plug

15 Cover 16 Cover

17 Bolt 18 Nut

Page 20 of 21


19 Washer 20 Butterfly Valve

21 Gasket 22 Tube

23 Bolt 24 Check Valve

25 Gasket 26 Tube

27 Bolt 28 Level Controller

29 Stud 30 Nut

31 Level Indicator 32 Gasket

33 Bolt 34 Name Plate

35 Name Plate 36 Screw

37 Glass Tube 38 Brass Tube

Page 21 of 21

gland steam condenser(typical) The reproduction, transmission or use of this document or its content is not permitted without express written authority. Offenders will be liable for damages. All rights, including rights created by patent, grant or registration of a utility, model or design are reserved. Copyrights STW all rights reserved.

Documents

系统概述en