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Document NO.: 78. K156-2E
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N300-16.7/538/538 TYPE 300MW CONDENSING REHEAT
STEAM TURBINE
GENERAL DESCRIPTION AND OPERATION MANUAL
SHANGHAI ELECTRIC EQUIPMENT CO., LTD
SHANGHAI TURBINE WORKS
Document NO.: 78. K156-2E
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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 .
Document NO.: 78. K156-2E
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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
Document NO.: 78. K156-2E
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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
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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
Document NO.: 78. K156-2E Page 2 of 3
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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
Document NO.: 78. K156-2E Page 3 of 3
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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
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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.
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.
Compiled:Yu Yan 2008.09Turbine Control Settings Checked:Zhang Xiaoxia 2008.09
Countersign:Sheng Chaojun,
Tang Jun, Zhang D.M 2008.09
OP.2.03.01E-00 Approved:Peng Zeying 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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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Page 1 of 1
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Compiled:Zhang D.M 2008.09Turbine Cooling Steam System Inspection Checked:Huang Q.H 2008.09
Countersign:Yu Yan 2008.09
Countersign:
OP.1.04.01E-00 Approved:Peng Zeying 2008.09
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
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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
OP.1.05.01E-00 Approved:Peng Zeying 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
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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
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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
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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
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Compiled:Zhang D.M 2008.09Turbine Steam and Metal Thermocouples Checked:Huang Q.H 2008.09
Countersign:Tang Jun 2008.09
Countersign:
OP.1.06.01E-00 Approved:Peng Zeying 2008.09
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
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Item TC No. Thermocouple Location MeasuresTemp. of:
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
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Item TC No. Thermocouple Location MeasuresTemp. of:
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
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Compiled:Yu Yan 2008.09Allowable Variations in Steam Conditions Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.08.01E-00 Approved:Peng Zeying 2008.09
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
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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
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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
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Compiled:Yu Yan 2008.09
Turbine Steam Purity Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.02.01E-00 Approved:Peng Zeying 2008.09
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
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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
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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
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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
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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
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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
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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.
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.
Compiled:Yu Yan 2008.09 Operating Limits and Precautions Checked:Zhang Xiaoxia 2008.09
Countersign:Yan Weichun,
Tang Jun, Zhang D.M 2008.09
OP.2.09.01E-00 Approved:Peng Zeying 2008.09
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
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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
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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.
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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
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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
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“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
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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.
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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
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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
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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
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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
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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℃.
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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
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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.
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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
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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.
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.
Compiled:Zhang D.M 2008.09
Water in The Turbine Checked:Huang Q.H 2008.09
Countersign:Yan W.CH 2008.09
Countersign:Yu Yan 2008.09
OP.1.10.01E-00 Approved:Peng Zeying 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
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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
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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
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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
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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
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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
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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
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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
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a. Accomplish the basic isolation procedure for feedwater heaters.
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:
a. Accomplish the basic isolation procedure for feedwater heaters.
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
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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
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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
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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.
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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
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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
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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.
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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
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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
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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
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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.
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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
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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
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Compiled:Jiang Jianfei 2008.09Governor Valve Management (Single
Valve-Sequential Valve)
Checked:Yu Yan 2008.09
Countersign:Tang Jun 2008.09
Countersign:He Xiaozhong 2008.09
OP.2.12.02E-00 Approved:Peng Zeying 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.
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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.
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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
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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.
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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.
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Compiled:Yu Yan 2008.09Preliminary Checks and Operations Checked:Zhang Xiaoxia 2008.09
Countersign:Yan Weichun,
Tang Jun, Zhang D.M 2008.09
OP.2.13.01E-00 Approved:Peng Zeying 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.
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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)
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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)
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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
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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
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Compiled:Tang Jun 2008.09Starting Procedure before Admitting Steam Checked:Wang Zurong 2008.09
Countersign:
Countersign:
OP.6.14.01E-00 Approved:Peng Zeying 2008.09
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
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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”.
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.
Compiled:Yu Yan 2008.09 Start Up With Bypass Off Checked:Zhang Xiaoxia 2008.09
Countersign:Yan Weichun,
Tang Jun, Zhang D.M
2008.09
OP.2.15.01E-00 Approved:Peng Zeying 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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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.”
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.
Compiled:Yu Yan 2008.09 Start Up and Operation With Bypass in Service Checked:Zhang Xiaoxia 2008.09
Countersign:Yan Weichun,
Tang Jun, Zhang D.M
2008.09
OP.2.16.01E-00 Approved:Peng Zeying 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
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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
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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
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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
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.
4. Hold the turbine at 600 r/min long enough to check all supervisory instruments to
Page 4 of 13
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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 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.
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
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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.
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 6 of 13
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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
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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 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 ClosedLP 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.
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
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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.
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.
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
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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.
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.
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
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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
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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
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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
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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
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Compiled:Yu Yan 2008.09
Load Changing Checked:Zhang Xiaoxia 2008.09
Countersign:Tang Jun 2008.09
Countersign:
OP.2.17.01E-00 Approved:Peng Zeying 2008.09
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
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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
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Compiled:Yu Yan 2008.09Shut Down Procedure Checked:Zhang Xiaoxia 2008.09
Countersign:Yan Weichun,
Tang Jun, Zhang D.M 2008.09
OP.2.18.01E-00 Approved:Peng Zeying 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
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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
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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
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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
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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
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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
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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
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Compiled:Zhang D.M 2008.09Turning Gear Operation During Shutdown Checked:Huang Q.H 2008.09
Countersign:Yan W.CH 2008.09
Countersign:Yu Yan 2008.09
OP.1.19.01E-00 Approved:Peng Zeying 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
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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
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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
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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
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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.
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.
Compiled:Yu Yan 2008.09 Feedwater Heater Operation Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.20.01E-00 Approved:Peng Zeying 2008.09
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
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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
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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.
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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
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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”.)
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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
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(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
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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.
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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
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Figure 1(Continued). EXAMPLES
Example 9: Not Manifolded
Example 8: Manifolded
Example 10: Not Manifolded
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(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
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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
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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
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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
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effect on the turbine-generator. Therefore, formulate rules to protect other auxiliary
equipment.
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Compiled:Yu Yan 2008.09 Periodic Functional Test Checked:Zhang Xiaoxia 2008.09
Countersign:Yan Weichun,
Tang Jun, Zhang D.M 2008.09
OP.2.21.01E-00 Approved:Peng Zeying 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
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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
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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.
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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.
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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.
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(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
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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
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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
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Compiled:Tang Jun 2008.09Caution for ATC Operation Checked:Wang Zurong 2008.09
Countersign:
Countersign:
OP.6.22.01E-00 Approved:Peng Zeying 2008.09
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
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Compiled:Tang Jun 2008.09Remote Automatic Modes of Operation Checked:Wang Zurong 2008.09
Countersign:
Countersign:
OP.6.23.01E-00 Approved:Peng Zeying 2008.09
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
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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.
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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
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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.”
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.
Compiled:Yu Yan 2008.09Limits, Precautions and Tests Checked:Zhang Xiaoxia 2008.09
Countersign:Yan Weichun,
Tang Jun, Zhang D.M 2008.09
OP.2.25.01E-00 Approved:Peng Zeying 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
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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
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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℃
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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:
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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
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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)
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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.
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(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
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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
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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.
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(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.
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(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
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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
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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
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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.
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(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.
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(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
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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
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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 ℃
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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
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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.
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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
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Compiled:Yu Yan 2008.09Turbine Speed Hold Recommendations Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.51.01E-00 Approved:Peng Zeying 2008.09
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
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Compiled:Yu Yan 2008.09Cold Start Rotor-Warming Procedure Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.52.01E-00 Approved:Peng Zeying 2008.09
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
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Compiled:Yu Yan 2008.09Start Recommendations For Rolling & Minimum
Load Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.53.01E-00 Approved:Peng Zeying 2008.09
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
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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
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Star
t rec
omm
enda
tion
for
rolli
ng a
nd m
inim
um lo
ad
Page 1 of 2
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Compiled:Yu Yan 2008.09Startup Steam Conditions Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.54.01E-00 Approved:Peng Zeying 2008.09
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
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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
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Compiled:Yu Yan 2008.09No-Load and Light Load Operation Guide for
Reheat Turbines Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.55.01E-00 Approved:Peng Zeying 2008.09
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
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Compiled:Yu Yan 2008.09Load Changing Recommendations Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.56.01E-00 Approved:Peng Zeying 2008.09
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
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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
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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
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LOA
D C
HA
NG
ING
REC
OM
MEN
DAT
ION
S
Page 1 of 1
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Compiled:Yu Yan 2008.09Cyclic Index for Loading and Unloading at Different
Rates Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.57.01E-00 Approved:Peng Zeying 2008.09
CYCLIC INDEX FOR LOADING AND UNLOADING AT DIFFERENT
RATES
Page 1 of 2
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Compiled:Yu Yan 2008.09Gland Sealing Steam Temperature
Recommendations Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.58.01E-00 Approved:Peng Zeying 2008.09
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
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Page 1 of 1
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Compiled:Yu Yan 2008.09Cooldown Time for A Typical Fossil Hp Turbine Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.59.01E-00 Approved:Peng Zeying 2008.09
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
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Compiled:Yu Yan 2008.09Off-Frequency Turbine Operation Checked:Zhang Xiaoxia 2008.09
Countersign:
Countersign:
OP.2.60.01E-00 Approved:Peng Zeying 2008.09
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
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Page 1 of 6
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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
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Page 3 of 6
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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
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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
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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
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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
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Page 1 of 8
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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.
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Page 3 of 8
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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
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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)
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Page 6 of 8
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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
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Page 8 of 8
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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.
Prepared:Pan Donghua 2008.07.08
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
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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
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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
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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
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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).
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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
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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
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Page 5 of 74
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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.
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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.
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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
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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
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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
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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
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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
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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
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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.
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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
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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
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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
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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
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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
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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
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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.
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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
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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
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11 Three-way valve interconnecting piping
Connected to the two oil coolers, a three-way valve is supplied. Use the three-way
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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
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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.
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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
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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
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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
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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
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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
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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
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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.
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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.
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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.
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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.
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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
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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
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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.
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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.
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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.
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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.
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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
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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.
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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
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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
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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.
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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
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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
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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.
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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
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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.
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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.
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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.
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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
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supporting the spindle with the spindle jacks, and rolling the bearing out completely.
Page 74 of 74
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Prepared:Pan Donghua 2008.07.08
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.
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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
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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
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( 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.
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Page 4 of 21
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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
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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).
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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.
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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
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=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%
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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.
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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.
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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.
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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.
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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.
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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
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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
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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
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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.