.
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OPERATION & MAINTENANCE MANUAL FOR 2 X 282.5 TPH
TRIPPLE PRESSURE NATURAL CIRCULATION, SINGLE DRUM,UNFIRED HEAT RECOVERY STEAM GENERATOR WITH REHEAT
SUPPLIED TO
LANCO KONDAPALLI — STAGE III
THERMAX PROJECT NO.: PH 0401/02
THERMAX BABCOCK & WILCOX A DIVISION OF THERMAX LIMITED PUNE, INDIA
0 REV
VSD
30.12.2011
PREPARED BY
AA
30.12.2011
CHECKED BY
NS
30.12.2011 APPROVED BY
0 REVISION DESC. / REMARK
Operation & Maintenance Manual
Contents Volume 1 — Boiler Description....................................................................................................1 Section A................................................................................................................................2 1 Design Specifications of Steam Generator....................................................................3 2 Design Code...............................................................................................................4 3 Levels With Respect To Center Line .............................................................................4 4 Material Specifications — Pressure Parts .....................................................................4 5 Evaporating Heating Surface Area ...............................................................................6 6 Exhaust Gas Analysis .................................................................................................6 6.1 Continuous Blowdown........................................................................................6 7 Recommended Boiler Water Quality .............................................................................7 8 Recommended Feed Water Quality..............................................................................7 9 Utilities .......................................................................................................................8 10 Chemicals for Dosing ................................................................................................9 11 Site Condition............................................................................................................9 12 Recirculation Pump ................................................................................................. 10 13 HP/IP/LP Dosing System .........................................................................................10 14 Gauge Glass .......................................................................................................... 12 15 Stack Damper .........................................................................................................13 16 Safety Valves ..........................................................................................................13 17 Relief Valves ...........................................................................................................15 Section B..............................................................................................................................16 1 Brief Description of the HRSG.................................................................................... 16 2 Description of HRSG Operation .................................................................................16 3 Steam & Water System .............................................................................................17 3.1 HP Boiler Components Description ...................................................................17 3.2 IP Section Components Description ..................................................................26 3.3 LP Section Components Description .................................................................33 3.4 Operational Control..........................................................................................39 3.5 Water And Steam Quality Control And Monitoring .............................................. 40 3.6 Maintaining Quality Of Steam .......................................................................... 42 4 Flue Gas System ......................................................................................................43 4.1 AIM.................................................................................................................43 4.2 Detailed Description.........................................................................................43 5 Drain & Dosing System..............................................................................................45 6 HRSG System Protection ..........................................................................................51 7 Automatic Controls....................................................................................................53 7.1 Drum Level Control..........................................................................................53 7.2 CBD Drain Temperature Control ....................................................................... 59 7.3 Stack Temperature (CPH Bypass 3- Way) Control .............................................59 7.4 LP Drum Pressure Control ............................................................................... 60 7.5 LP Drum Pressure Control ............................................................................... 60 7.6 HP Attemperator Control ..................................................................................60 7.7 RH1 Attemperator Control................................................................................60 7.8 CPH Recirculation Temperature Control ............................................................61 7.9 IP Line Back Pressure Control..........................................................................61 7.10 Start up Vent (HP, IP & LP) Control ................................................................. 61 Section C .............................................................................................................................63 1 Section Overview ......................................................................................................63 2 HRSG Start Up and Shut Down .................................................................................63 3 Startup of a Cold HRSG ............................................................................................63 3.1 Walk Down Check ...........................................................................................63 3.2 Valve Lineup....................................................................................................64 3.3 System Lineup ................................................................................................ 65
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Operation & Maintenance Manual
3.4 Valve Positions Chart For HP, IP & LP Section (Before Light Up) ........................ 66 3.5 Filling Water in Boiler .......................................................................................75 3.6 HRSG Start Up & Pressurisation.......................................................................75 3.7 HRSG Cold Start Up Curve ..............................................................................78 3.8 Taking Reheater On Line .................................................................................79 3.9 Charging & Operation of CPH........................................................................... 80 3.10 Parallel HRSG to the Plant Steam Mains.........................................................80 4 Hot and Warm Start up of HRSG ...............................................................................81 5 HRSG Shutdown.......................................................................................................86 5.1 Planned Shutdown........................................................................................... 86 5.2 HRSG Emergency Trips................................................................................... 86 6 Cooling of a Shutdown Boiler .....................................................................................87 6.1 Natural Cooling................................................................................................87 6.2 Forced Cooling ................................................................................................ 87 7 HRSG Operation Walk Down Checks ........................................................................ 87 8 Do’s and Don’ts For HRSG Operation........................................................................ 87 9 Boiler Log Sheet .......................................................................................................89 9.1 Log Sheet for HRSG ........................................................................................89 10 Boiler Emergency Safety Procedures .......................................................................93 10.1 Emergency Procedures..................................................................................93 10.2 Alarms and Trips............................................................................................95 10.3 Operational Precautions for Safety .................................................................95 10.4 Tube Failures ................................................................................................ 95 10.5 Safety in Boiler House....................................................................................95 11 Trouble Shooting Chart ............................................................................................ 96 Section D ........................................................................................................................... 100 1 Section Overview .................................................................................................... 100 1.1 Recommended Maintenance Practices ........................................................... 100 2 Welding Procedure Specifications (WPS) ................................................................. 107 3 Boiler Preservation Procedure.................................................................................. 107 3.1 Definitions of Water Quality ............................................................................ 107 3.2 Dry Storage Preservation ............................................................................... 108 3.3 Wet Storage .................................................................................................. 109 3.4 Nitrogen Blanket............................................................................................ 110 3.5 Boiler Lay Up Procedures............................................................................... 111 3.6 Preservation of Rotating Equipments .............................................................. 111 3.7 Preservation of Instruments ........................................................................... 111 4 Tube Failures.......................................................................................................... 112 4.1 Tube Failure Investigation / Analysis Method ................................................... 112 4.2 Window Patch Welding .................................................................................. 114 5 General Principal of Weld Repairs............................................................................ 116 6 Failure Reporting Format .........................................................................................127 7 Water Chemistry ..................................................................................................... 128 7.1 Undissolved and Suspended Solid Materials ................................................... 128 7.2 Dissolved Salts and Minerals.......................................................................... 128 7.3 Dissolved Gases............................................................................................ 129 7.4 Other Materials.............................................................................................. 129 7.5 pH Value of the Water and its Importance........................................................ 129 7.6 Effects of Impurities ....................................................................................... 129 8 Feed & Boiler Water Conditioning............................................................................. 131 Section E............................................................................................................................ 134 Volume 2 — Drawings.............................................................................................................. 135 List of Drawings ..................................................................................................................135 Volume 3 — E & I Specifications.............................................................................................. 136
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Operation & Maintenance Manual
Section 1 ............................................................................................................................ 137 Section 2 ............................................................................................................................ 137 Section 3 ............................................................................................................................ 137 Section 4 ............................................................................................................................ 137 Section 5 ............................................................................................................................ 137 Section 6 ............................................................................................................................ 137 Section 7 ............................................................................................................................ 137 Section 8 ............................................................................................................................ 137 Section 9 ............................................................................................................................ 137 Section 10 .......................................................................................................................... 137 Section 11 .......................................................................................................................... 137 Section 12 .......................................................................................................................... 138 Section 13 .......................................................................................................................... 138 Volume 4 — Vendor Manuals ................................................................................................... 139 Section 01 .......................................................................................................................... 140 Recirculation Pump - Sulzer.......................................................................................... 140 Section 02 .......................................................................................................................... 140 Dosing System - Metapow ............................................................................................ 140 Section 03 .......................................................................................................................... 140 HP Drum Level Gauge Glass – Hi tech. ......................................................................... 140 Section 04 .......................................................................................................................... 140 IP & LP Drum Transparent Level Gauge Glass - Chemtrols............. ................................ 140 Section 05 .......................................................................................................................... 141 Blow Down Tank Reflex Level Gauge Glass - Chemtrols....... ......................................... 141 Section 06 .......................................................................................................................... 141 Stack Damper — Indira Damper.................................................................................... 141 Section 07 .......................................................................................................................... 141 Spring Hanger – Pipe Support.......................................................................................141 Section 08 .......................................................................................................................... 141 Flow Nozzle — Micro Precision ..................................................................................... 141 Section 09 .......................................................................................................................... 141 Safety Valve — Tyco Sanmar........................................................................................ 141 Section 10 .......................................................................................................................... 142 Relief Valve — Tyco Sanmar......................................................................................... 142 Volume 5 — Vendor Manuals ................................................................................................... 143 Section 01 .......................................................................................................................... 144 1.1 Differential Pressure Transmitter (EJA) – Yokogawa.................................................. 144 1.2 Absolute & Gauge Pressure Transmitter (EJA) – Yokogawa ............. ......................... 144 1.3 HART Protocol (EJA Series) - Yokogawa.............. .................................................... 144 Section 02 .......................................................................................................................... 144 2.1 Temperature Transmitter (YTA Series) - Yokogawa ................................................... 144 2.2 HART Protocol (EJA) – Yokogawa ........................................................................... 144 Section 03 .......................................................................................................................... 144 3.1 O2 Analyser (ZR 402G) — Yokogawa ...................................................................... 144 3.2 HART Protocol — Yokogawa................................................................................... 144 Section 04 .......................................................................................................................... 145 Motor for Recirculation Pump - Siemens ........................................................................ 145 Section 05 .......................................................................................................................... 145 Thermocouple - Pyroelectric .........................................................................................145 Section 06 .......................................................................................................................... 145 Electronic Level Switch – Levelstate .............................................................................. 145 Section 07 .......................................................................................................................... 145 DO2 Analyser - Emerson .............................................................................................. 145 Volume 6— Vendor Manuals .................................................................................................... 146
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Operation & Maintenance Manual
Section 01 .......................................................................................................................... 147 In-Situ Stack Gas Analysers - CODEL .......................................................................... 147 Section 02 .......................................................................................................................... 147 Process Valve – Xomox Sanmar ................................................................................... 147 Section 03 .......................................................................................................................... 147 Motorised Valve – Xomox Sanmar................................................................................. 147 Section 04 .......................................................................................................................... 147 Motorised Actuator - Auma ...........................................................................................147 Section 05 .......................................................................................................................... 147 Blow Down Valve - BHEL.............................................................................................. 147 Section 06 .......................................................................................................................... 148 Pressure Gauge - Bourdon ........................................................................................... 148 Section 07 .......................................................................................................................... 148 Temperature Gauge – General Instrument .................................................................... 148 Section 08 .......................................................................................................................... 148 Control Valve – Fisher .................................................................................................. 148 Index.................................................................................................................................. 149
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Operation & Maintenance Manual
Volum e 1 — Boiler Descr ipt ion Chapters Covered in this Part ♦ ♦ ♦ ♦ ♦
Section A Section B Section C Section D Section E
Volume 1 — Boiler Description
1
Operation & Maintenance Manual
Section A Topics Covered in this Chapter ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦
Design Specifications of Steam Generator Design Code Levels With Respect To Center Line Material Specifications — Pressure Parts Evaporating Heating Surface Area Exhaust Gas Analysis Recommended Boiler Water Quality Recommended Feed Water Quality Utilities Chemicals for Dosing Site Condition Recirculation Pump HP/IP/LP Dosing System Gauge Glass Stack Damper Safety Valves Relief Valves
Section A
2
Operation & Maintenance Manual
Number and Type of Boiler 2X 282.5 TPH (HP) 98.7 Bar (a), 40.2 TPH (IP) 26.1 Bar (a) and 32.3 TPH (LP) 4.37 Bar (a) Triple Pressure, Natural Circulation, Single Drum, Unfired Heat Recovery Steam Generator With Reheat
1
D esi g n Sp eci fi cat ions of Steam Generator
PARAMETERS
UNIT
VALUE
HP Boiler Rating [MCR]
TPH
282.5
IP Boiler Rating [MCR]
TPH
40.2
LP Boiler Rating [MCR]
TPH
32.3
HP Steam Pressure at Main Steam Stop Valve Outlet from minimum Load upto MCR
Bar (a)
98.7
IP Steam Pressure at Main Steam Stop Valve Outlet from minimum Load upto MCR
Bar (a)
26.1
LP Steam Pressure at Main Steam Stop Valve Outlet from minimum Load upto MCR
Bar (a)
4.37
HP Steam Temperature at the Main Steam Stop valve at MCR
°C
567.3± 3
IP Steam Temperature at the Main Steam Stop valve at MCR
°C
313.7
LP Steam Temperature at the Main Steam Stop valve at MCR
°C
286.5
Water temp at FW control valve inlet/Economiser inlet
°C
151
Design HP Pressure
Bar (a)
112
Design IP Pressure
Bar (a)
31
Design LP Pressure
Bar (a)
9
Boiler Performance Testing Procedure
Section A
ASME PTC 4.4
3
Operation & Maintenance Manual
2
Desi gn Co de
Boiler & Economiser / Pressure Parts:
As per IBR 1950 with latest amendments
Piping:
IBR, ANSI B 31.3
3
Levels With Respect To Center Line
For the High Pressure Steam Drum PARAMETER
ALARM
VALUE
Normal Water Level
NWL
+ 25 mm
Level Alarm High
LAH
+ 225 mm
Level Alarm Low
LAL
– 225 mm
Level Trip Low Low
LLLT
– 330 mm
Level Trip High High
HHLT
+ 300 mm
ALARM
VALUE
Normal Water Level
NWL
0 (Center line of Drum)
Level Alarm High
LAH
+ 125 mm
Level Alarm Low
LAL
– 125 mm
Level Trip Low Low
LLLT
– 215 mm
Level Trip High High
HHLT
+ 215 mm
ALARM
VALUE
Normal Water Level
NWL
+ 300 (Center line of Drum)
Level Alarm High
LAH
+ 375 mm
Level Alarm Low
LAL
- 300 mm
Level Trip Low Low
LLLT
- 1050 mm
BFW Pump Trip
FWPT
- 1350 mm
Level Trip High High
HHLT
+ 450 mm
For the Intermediate Pressure Steam Drum PARAMETER
For the Low Pressure Steam Drum PARAMETER
4
M at e r i al Sp eci fi cation s — Pressur e Part s Description
Details
HP Drum Risers
Shell Dished end for S.D. (Hemispherical) Shell Dished end for S.D. (Hemispherical) Shell Dished end for S.D. (Hemispherical) 24 Nos. of Tube
IP Drum Risers LP Drum Risers
HP Steam Drum IP Steam Drum LP Steam Drum
Section A
Size In Mm 2000 I.D. x 100 Thk 2000 I.D. x 100 Thk 1375 I.D. x 25 Thk x 12500 L 1375 x 25 Thk 3000 I.D. x 20 Thk 3000 I.D. x 20 Thk
Material SA 516 Gr.70 SA 516 Gr. 70 SA 516 Gr. 70
200 NB x SCH 120
SA 106 Gr. B
14 Nos. of Tube
150 NB x SCH 40
SA 106 Gr. B
30 Nos. of Tube
150 NB x SCH 40
SA 106 Gr. B
4
Operation & Maintenance Manual
Description
Details
Size In Mm
Material
HP Drum Downcomers
4 nos. of Tube
350 NB x SCH 120
SA 106 Gr. B
IP Drum Downcomers
4 nos. of Tube
200 NB x SCH 40
SA 106 Gr. B
LP Drum Downcomers
4 nos. of Tube
300 NB x SCH 40
SA 106 Gr. B
38.1 OD x 4.3 THK.
SA 213 T91
Top & Bottom Header
200 NB x 45 THK.
SA 335 P91
Serrated
44.5 OD x 3 ThK.
SA 213 T91
Top & Bottom Header
250 NB x 30 THK.
SA 335 P91
38.1 OD x 3.2 THK.
SA 213 T91
Top & Bottom Header
200 NB x 30 THK.
SA 335 P91
Serrated
44.5 OD x 3 THK.
SA 213 T22
Top & Bottom Header
200 NB x SCH 160
SA 335 P22
Serrated
38.1 OD x 3 THK.
SA 213 T11
Top Header
200 NB x 25 THK.
SA 335 P22
Bottom Header
200 NB x 25 THK.
SA 335 P11
Top Header
250 NB x 30 THK.
SA 106 Gr. B
Bottom Header
250 NB x 30 THK.
SA 106 Gr. B
Serrated
38.1 OD x 2.6 THK.
SA 201 A1
Top & Bottom Header
200 NB x SCH 100
SA 106 Gr. B
Serrated
38.1 OD x 2.6 THK.
SA 201 A1
250 NB x SCH 80
SA 106 Gr. B
38.1 OD x 2.6 THK.
SA 201 A1
HP Superheater 3 Reater 2 HP Superheater 2 Reater 1
HP Superheater 1
HP Evaporator IP Superheater LP Superheater
Spiral Solid Tube
Serrated
Top & Bottom Header Serrated
HP Economiser 3
IP Evaporator
HP Economiser 2 HP Economiser 1A HP Economiser 1B IP Economiser LP Evaporator
CPH
Top & Bottom Header Serrated Top & Bottom Header -1 Top & Bottom Header
200 NB x 25 THK.
SA 106 Gr. B
38.1 OD x 2.6 THK.
SA 201 A1
250 NB x SCH 80
SA 106 Gr. B
200 NB x SCH 100
SA 106 Gr. B
38.1 OD x 2.6 THK.
SA 201 A1
250 NB x 30 THK.
SA 106 Gr. B
38.1 OD x 2.6 THK.
SA 201 A1
250 NB x 30 THK.
SA 106 Gr. B
38.1 OD x 2.6 THK.
SA 201 A1
Top & Bottom Header
200 NB x 25 THK.
SA 106 Gr. B
Top & Bottom Header
200 NB x 120 SCH
SA 106 Gr. B
Serrated
38.1 OD x 2.6 THK.
SA 201 A1
Serrated
38.1 OD x 2.6 THK.
SA 201 A1
Top & Bottom Header
200 NB x SCH 100
SA 106 Gr. B
Serrated Top & Bottom Header (CPH Top & A) Bottom Header
38.1 OD x 2.6 THK.
SA 201 A1
250 NB x SCH 100
SA 106 Gr. B
250 NB x SCH 80
SA 106 Gr. B
-2 Serrated Top & Bottom Header Serrated Top & Bottom Header Serrated
(CPH B)
Section A
250 NB x 30 THK.
5
Operation & Maintenance Manual
5
Evaporating Heating Surface Area Zone
Unit
Value
HP Superheater 3
M 2
2727.57
Reheater 2
M 2
5150.00
HP Superheater 2
M 2
4472.50
Reheater 1
M 2
11274.00
HP Superheater 1
M 2
7589.00
HP Evaporator
M 2
48730.00
IP Superheater
M 2
3742.00
LP Superheater
M 2
834.00
HP Economiser 3
M 2
48670.00
IP Evaporator
M 2
24725.00
HP Economiser 2
M 2
14846.50
IP Economiser
M 2
7453.00
HP Economiser 1
M 2
22270.00
LP Evaporator
M 2
33524.00
CPH
M 2
58805.00
Total Heating Surface Area
M 2
294812.60
PARAMETERS
UNIT
FIRED 100% GT
N2 + AR
% VOL
74.641
O2
% VOL
13.6367
CO2
% VOL
4.2678
H2O
% VOL
7.4448
CO
% VOL
0.0006
SO2
% VOL
0.0018
6
Exhaust Gas Analysis
Exhaust Gas
6.1
Continuous Blow dow n
Design
: 3 % / Hr
Operating
: 0 %/ Hr
Section A
6
Operation & Maintenance Manual
7
Recomm ended Boiler Water Quality
Parameter
Units
HP Section
IP Section
LP Section
Sodium Phosphate as PO4
ppm
16 –13
40 – 34
-
Alkalinity as CaCO3
ppm
< 10
< 60
Nil
9.7 — 10.2
10.8 – 11.4
–
pH Oil & Organic
ppm
Nil
Nil
Nil
Total dissolved solids
ppm
< 50
< 300
< 300
Silica as SiO2
ppm
< 0.9
< 21
< 60
HP Section
IP Section
LP Section
Clear & Colourless
Clear & Colourless
Clear & Colourless
8
Recomm ended Feed Water Quality
Parameter
Units
General Appearance Total Hardness as CaCO3
ppm
Commercial zero
Commercial zero
Commercial zero
Total Fe
ppm
< 0.01
< 0.01
< 0.01
Total Cu
ppm
< 0.005
< 0.005
< 0.005
Oxygen
ppm
< 0.007
< 0.007
< 0.007
Oil & organics
ppm
Nil
Nil
Nil
9.3-9.5
8.5-9.5
8.5-9.5
ppm
< 0.1
< 0.1
< 0.1
Electrical Conductivity
µs/cm
< 0.2
< 0.2
< 0.2
Silica SiO2
ppm
< 0.02
< 0.02
<0.02
pH Total Dissolved solids
Section A
7
Operation & Maintenance Manual
9
Ut i li t ies
Electrical Power Parameters
Units
Value
Voltage
V
6600
Frequency
Hz
50
Combined Variation
%
10
For HT Motors (above 160 KW)
Type
AC, 3 Phase
For LT Motors (upto 160 KW) Voltage
V
415
Frequency
Hz
50
Combined Variation
%
10
Type
AC, 3 Phase
For Instrumentation (Field Switches, Level Gauge illumination, solenoid valves etc) Voltage
V
220
Frequency
Hz
50
Type
AC, 1 Phase
For Field Transmitters Voltage
V
Type
24 DC
Instrument Air Parameters
Unit
Value
Pressure
Barg
7.0
Temperature
Deg C
26
Dew Point
Deg C
– 20
Quality Duty
Dry & Oil free Instruments
Nitrogen
Section A
8
Operation & Maintenance Manual
Parameters
Unit
Value
Pressure (min/normal/design)
Barg
6/7/10
Deg C
0/30/35/40
%
99.9 % Pure
Temperature (min/normal/max/design) Quality Duty
HRSG Preservation
Service Water for Quenching Parameters Pressure
Unit
Value
Barg
2.0
Duty
Quenching
10 Chemicals for Dosing HP Dosing:
Tri sodium phosphate
IP Dosing:
Tri sodium phosphate
LP Dosing:
Hydrazine
11 Site Condition Parameter
Units
Site Location
Details Kondapalli, Andhra Pradesh
Temperatures Ambient Temperature (min/max/design)
Deg. C
15/45/30
For Performance Testing
Deg. C
30
Relative Humidity (min/max/design)
%
45/81/60
For Performance Testing
%
60
Relative Humidity
Seismic Design Basic Horizontal Seismic co-efficient
0.05
Importance Factor
1.75
Soil Condition Factor
1.0
Altitude Area Classification Environment HRSG Location Number of HRSGs
Section A
m
35 m above MSL Safe & Non Hazardous Non-Corrosive Outside 2
9
Operation & Maintenance Manual
12 Recirculation Pump Description
Units
Recirculation Pump
Pump Make
Sulzer Pumps
Pump Type
ZE 100–3315
Pump Speed
RPM
2980
Flow
m3/hr
191
Differential Head
m
100
Temperature
°C
148
kg/cm2
11.7
m
115
KW
64.32
%
74.4
Suction Pressure Shut off Head at 50 HZ Rated power Efficiency Motor Make
Siemens
Motor type
Sqirrel Cage Induction Motor
Rating
KW
90
Speed
rpm
2975
Frame Size
280M/2 Pole Unique Metaflex, Size: 80 SPL-162
Coupling
13 HP/ I P/ LP Dosing System HP Dosing for HP Drum
HP Dosing for IP Drum
LP Dosing for LP Drum
Metapow Industries
Metapow Industries
Metapow Industries
A-1109 Rev 02
A-1110 Rev 03
A-1111 Rev 02
Tank Details
ID 950 X 1125 X 3 THK (Capacity 600 lit)
ID 700 X 1000 X 3 THK (Capacity 300 lit)
ID 950 X 1125 X 3 THK (Capacity 600 lit)
Chemical Dosed
Tri-Sodium Phosphate
Tri-Sodium Phosphate
Hydrazine
Make
VK Pump
VK Pump
VK Pump
Model
PR 20
PR 10
PR 10
0–15 LPH by Stroke Adjustment
0–10 LPH by Stroke Adjustment
0–15 LPH by Stroke Adjustment
110.5 kg/cm2 g (Normal), 118 kg/cm2 g (Design)
31.7 kg/cm2 g (Normal), 36 kg/cm2 g (Design)
8.5 kg/cm2 g (Normal), 14 kg/cm2 g (Design)
138 kg/cm2 g
46 kg/cm2 g
11 kg/cm2 g
Description Make Reference Drawing No.
Dosing Pump
Flow Discharge pressure Relief valve set pressure
Motor for Dosing Pump
Section A
10
Operation & Maintenance Manual
HP Dosing for HP Drum
HP Dosing for IP Drum
LP Dosing for LP Drum
Make
CGL
CGL
CGL
Motor
M- 120A & M-120B, TEFC IP 55
M- 123A & M-123B, TEFC IP 55
M- 126A & M-126B, TEFC IP 55
Rating
1 HP, 1500 RPM, 415± 10% V
0.5HP, 1500 RPM, 415± 10% V
0.5 HP, 1500 RPM, 415 ± 10% V
Make
CGL
CGL
CGL
Motor
M-120, Frame Size — ND90L
M-123, Frame Size — ND90S
M-126
Rating
1.5 HP, 1000 RPM, 415±15% V
1 HP, 1000 RPM, 415±10% V
1.5 HP, 1000 RPM, 415 ± 10% V
Description
Motor for Agitator
Section A
11
Operation & Maintenance Manual
14 Gauge Glass HP Drum Level Gauge Glass Description
Details
Make
Hi Tech System and Services
Type
Bicolour Duco Gauge Glass
Tag No.
LI 016A & LI 016B
Location
HP Steam drum
Operating pressure
103.5 Bar (g)
Design pressure
111 Bar (g)
C/c distance
1000 mm
Visibility range
606 mm
Operating temperature
Saturated
Design Temperature
320 °C
IP & LP Drum Level Gauge Glass IP Drum Level Gauge Glass Details
LP Drum Level Gauge Glass Details
Make
Chemtrols samil
Chemtrols samil
Type
Transparent Level Gauge Glass
Transparent Level Gauge Glass
Tag No.
LI 059A & LI 059B
LI 082A & LI 082B
Location
IP Steam drum
LP Steam drum
26.7 kg/cm2
5.7 kg/cm2
30 kg/cm2
8 kg/cm2
C/c distance
550 mm
1900 mm
Visibility range
320 mm
1650 mm
Operating temperature
Saturated
Saturated
236 °C
176 °C
Description
Operating pressure Design pressure
Design Temperature Blow Down Tank Level Gauge GLass Description Make
Details Chemtrols samil
Tag No.
LI 096
Location
Blow Down Tank
Operating pressure
1.5 kg/cm2
Design pressure
3 kg/cm2
C/c distance
1900 mm
Visibility range
1468 mm
Operating temperature
Section A
144 °C
12
Operation & Maintenance Manual
15 Stack Damper Description
Units
Stack Damper Details
Design Data Make
Indira Damper Industries
Medium
Exhaust Gas
Gas Flow
kg/sec
624.83
Gas Temperature
Deg C
100
Design Temperature
Deg C
200
Structural Design Pressure
mmWc
500
%
99
Sealing Efficiency Flow Direction
Vertical — Upward
Operation
Electrical
Duty
On — Off
Pressure Drop Quantity Operating Time
mmWc
5
no.
1 per boiler
Seconds
60
Gear Box Details Make
Auma (I) Pvt Limited
Type
GSD 200+GZ16
Reduction Ratio
424:1
Torque Actuator Details Make
Auma (I) Pvt Limited
Type
SA12E180
Rating
KW
1.1 415±10% V, 50±5% Hz, 3Phase, AC
Supply
16 Safety Valves HP Boiler DESCRIPTION Type
UNIT
DRUM LHS
DRUM RHS
MAIN STEAM LINE
-
Spring Loaded
Spring Loaded
Spring Loaded
Tyco Sanmar
Tyco Sanmar
Tyco Sanmar
Make Tag No
-
PSV 006A
PSV 006B
PSV 027
Size Orifice
-
3.0 M2 6.0
3.0 M2 6.0
3.0 L2 6.0
Set pressure
Bar (g)
117
118
109.7
Relieving Temperature
Deg.C
Saturated
Saturated
573
kg/hr
117200
117200
73300
Required Valve Capacity
Section A
13
Operation & Maintenance Manual
UNIT
DRUM LHS
DRUM RHS
MAIN STEAM LINE
Quantity
-
1 no. / Boiler
1 no. / Boiler
1 no. / Boiler
Fluid
-
Saturated Steam
Saturated Steam
Superheated Steam
UNIT
DRUM LHS
DRUM RHS
MAIN STEAM LINE
-
Spring Loaded
Spring Loaded
Spring Loaded
Tyco Sanmar
Tyco Sanmar
Tyco Sanmar
DESCRIPTION
IP Boiler DESCRIPTION Type Make Tag No
-
PSV 060A
PSV 060B
PSV 062
Size Orifice
-
3.0 L 4.0
3.0 L 4.0
3.0 K 4.0
Kg/Cm2
29.57
30.59
28.96
Relieving Temperature
Deg.C
Saturated
Saturated
350
Required Valve Capacity
kg/hr
20300
20300
12700
Quantity
-
1 no. / Boiler
1 no. / Boiler
1 no. / Boiler
Fluid
-
Saturated Steam
Saturated Steam
Superheated Steam
UNIT
DRUM LHS
DRUM RHS
MAIN STEAM LINE
-
Spring Loaded
Spring Loaded
Spring Loaded
Tyco Sanmar
Tyco Sanmar
Tyco Sanmar
Set Pressure
LP Boiler DESCRIPTION Type Make Tag No
-
PSV 084A
PSV 084B
PSV 085
Size Orifice
-
4.0 P 6.0
4.0 P 6.0
6.0 Q 8.0
Kg/Cm2
7.13
8.16
5.30
Relieving Temperature
Deg.C
Saturated
Saturated
350
Required Valve Capacity
kg/hr
15000
16500
10500
Quantity
-
1 no. / Boiler
Fluid
-
Saturated Steam
1 no. / Boiler Saturated Steam
1 no. / Boiler Superheated Steam
Set Pressure
Reheater DESCRIPTION Type
UNIT -
Make
Spring Loaded
Spring Loaded
REHEATER OUTLET Spring Loaded
Tyco Sanmar
Tyco Sanmar
Tyco Sanmar
REHEATER INLET
Tag No
-
PSV 302
PSV 302A
PSV 072
Size Orifice
-
6.0 RR 10.0
6.0 RR 10.0
6.0 RR 10.0
Kg/Cm2
27.53
28.35
24.58
Relieving Temperature
Deg.C
410
410
572
Required Valve Capacity
kg/hr
125000
125000
90,000
Set Pressure
Section A
14
Operation & Maintenance Manual
DESCRIPTION
UNIT
Quantity
-
Fluid
-
REHEATER INLET 1 no. / Boiler Superheated Steam
1 no. / Boiler Superheated Steam
REHEATER OUTLET 1 no. / Boiler Superheated Steam
17 Relief Valves DESCRIPTION Type
IP ECONOMISER
Spring Loaded
After Recirculation Pump Spring Loaded
Tyco Sanmar
Tyco Sanmar
Tyco Sanmar
UNIT
CPH
-
Make
Spring Loaded
Tag No
-
PSV 109
PSV 111
PSV 078
Size Orifice
-
4.0 N 6.0
3.0 J 4.0
2.0 H 3.0
Kg/Cm2
24.50
27.00
71.30
Required Valve Capacity
kg/hr
162681
500940
78000
Relieving Temperature
Deg.C
250
250
290
Quantity
-
1 no. / Boiler
1 no. / Boiler
1 no. / Boiler
Fluid
-
Water
Water
Water
Set pressure
Section A
15
Operation & Maintenance Manual
Section B
transmitter and proximity switches form a part of control system and act as final control element to control the process variables. Position transmitters allow the monitoring of the controlling element position. Closed control loops are configured in DCS.
Topics Covered in this Chapter ♦ ♦ ♦ ♦ ♦ ♦ ♦
1
Brief Description of the HRSG Description of HRSG Operation Steam & Water System Flue Gas System Drain & Dosing System HRSG System Protection Automatic Controls
Process switches and transmitters monitor the process variables and generate alarms and safe shutdown of HRSG.
Brief Description of the HRSG
The HRSG is designed to extract maximum recoverable heat from the exhaust gas of the gas turbine. For this purpose the exhaust gas flow from the gas turbine is arranged in a direction counter to the water / steam circuit of HRSG. The exhaust gas from the gas turbine enters HP, IP & LP section of the Boiler. All the three section include the secondary and primary superheaters, evaporators, economisers & finally through CPH module before exhausted to the atmosphere by the stack. The steam drum placed above the evaporators serves as a balancing vessel for water and steam. It receives feed water from the economiser and maintains positive water supply to the evaporator modules. Drum receives the mixture of steam and water from the evaporator modules by the heat transfer. After separating water from the steam / water mixture at drum, the saturated steam is supplied to the main steam line through superheaters.
Analyzers are used for the measurement of Conductivity and pH of feed water, boiler water and steam to maintain the required quality.
Control Loops: • HP Steam Drum level control • IP Steam Drum level control • LP Steam Drum level control • CBD Drain Temperature Control • Stack Temperature (CPH Bypass 3- Way) Control • LP Drum Pressure Control • HP Attemperator Control • RH1 Attemperator Control • CPH Recirculation Temperature Control • IP Line Back Pressure Control Control philosophy of these loops is described in section of Automatic control
2
Descript ion of HRSG Operation
Generation Capacity
HRSG Operation
Generation capacity of the HRSG
HRSG is filled with cold DM water through the back filling line provided at the drain headers. Valves line up and procedure for boiler fill up will be described later in operation instruction manual.
• HP steam of 282.5 TPH / 98.7 Bar (a) at a temperature of 567.3 ±3°C • IP steam of 40.2 TPH /26.1 Bar (a) at a temperature of 313.7°C • LP steam of 32.3 TPH / 4.37Bar (a) at a temperature of 286.5°C
Gener al Descript ion Instrumentation
of
HRSG
The latest generation of the field instruments is used to facilitate monitoring and control of the process variables, generating alarms and trips. Differential pressure Transmitters for the measurement of process variables like pressure, drum level and flow are used. Thermocouples with transmitters are used for the measurement of temperature. Control valves with position
Section B
On satisfying the necessary safety interlocks, gradually admit turbine exhaust gas into HRSG. Cold start up curve has to be followed to pressurize the boiler. HRSG is pressurized by modulating the GT load and by establishing the steam flow through the start up vent and also modulating it. On attaining the rated pressure and temperature of superheated steam, main steam stop valve can be opened and steam shall be admitted to header. Start up vent will be closed, once the flow through MSSV is established. Control loops will be selected into auto operation mode with their corresponding set points.
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Operation & Maintenance Manual
This is a brief overview of the HRSG. Details of equipments, their operational and maintenance features will be elaborated in the subsequent chapters of the manual.
The exhaust gas from the Gas Turbine flows in a direction counter to the water / steam flow path with the hottest gas entering the sequence below
3
• Reheater 2
St e a m & W a t er Sy st e m
AI M The water and steam system covered in this chapter describes the components of the HRSG which transfer heat from the exhaust gas of the gas turbine to the feed water flowing from the feed water main to convert it to HP steam of 282.5 TPH / 98.7 Bar (a) at a temperature of 567.3 ± 3°C, IP steam of 40.2 TPH /26.1 Bar (a) at a temperature of 313.7°C and LP steam of 32.3 TPH /4.37 Bar (a) at a temperature of 286.5°C. The components in the serial order of water flow of path for HP section are, • HP Boiler Feed water Control Station • HP Economizer I • HP Economiser II
• HP Superheater 3 • HP superheater 2 • Reheater 1 • HP Superheater 1 • HP Evaporator • IP Superheater • LP Superheater • HP Economiser 3 • IP Evaporator • HP Economiser 2 • IP Economiser • HP Economiser 1 • LP Evaporator • CPH
• HP Economiser III
3.1
• HP Drum
3.1.1HP Boiler Feed w ater Contr ol Stat ion
•
HP Evaporator
• HP Superheater I • HP Superheater II •
Attemperator
• HP Superheater III The components in the serial order of water flow of path for IP section are, • IP Economizer
HP Boiler Component s Descripti on
During normal operating HRSG, it must be kept continuously supplied with feed water to maintain near normal level in the drum. The HRSG trips if water level in the drum is either too low or too high. Feed water is obtained from the HP BFW from the client. There are three feed control valves, out of which at least one must be in service when the HRSG is operational. HP Boiler Feedwater Regulating Station
• Boiler IP Feed water Control Station
The feed water flow control station consists
• IP Drum
• 30% capacity control valve [FCV 003A]
• IP Evaporator
• 100 % capacity control valve [FCV 003B]
• IP Superheater
• 100 % capacity control valve [FCV 003C]
•
Reheater 1
•
Attemperator
•
Reheater 2
Both 30% & 100% control valves are provided with motorised isolation valves [M 003A ,M 003B & M 003C] and manual isolation valve at downstream of control valve [GT 028, GT 027 & GT 026]. The feed water flow control valve is a globe type valve, pneumatically actuated by a spring opposed diaphragm actuator and positioned by the feed water flow indicating controller [HIC 003A,HIC 003B & HIC 003C] in order to maintain the normal water level at boiler steam drum.
The components in the serial order of water flow of path for LP section are, • CPH • Boiler LP Feed water Control Station • LP Drum/Dearator •
LP Evaporator
• LP Superheater
Section B
Out of the above, 30% level control [FCV 003A] is used during start up and is capable of feeding the boiler only when the steam flow from HRSG is less
17
Operation & Maintenance Manual
than 30%. A special feature of 30% level control valve [FCV 003A] is that it enables the regulation of feed water to the HRSG to be on auto mode from the very start of HRSG. The 100% flow control valve [FCV 003B] is capable of feeding the HRSG when the steam flow from HRSG is from 20% to MCR. [FCV 003C] is an identical stand by to [FCV 003B]. The following are installed in the common inlet line from the HP BFW line to the feed regulation Stations. •
Tap off for Attemperator spray water with electrically operator Isolating valve M 026A.
• An isolation valve GT 038. • Temperature elements TE-001A & TE 001B for indicating temperature of inlet feed water. A signal is fed to the FX 003. • Pressure elements PT-002A & PT 002B for indicating pressure of inlet feed water. A signal is fed to the FX 003. •
Flow nozzle FE 003A with impulse connections to flow transmitter FT-003A, FT-003B & FT-003C.
• Pressure indicator PI 004 for indicating pressure of inlet HP feed water. The flow transmitters provide feed flow signal to the feed Indicating controller FIC-003 (which will be described later). After the above, the common inlet line branches into three parallel paths, on which are installed the three feed regulating stations mentioned earlier to be connected to a common line for feeding water to the HP Economizer 1. The feed regulating stations are now described. 30% or Start up Feed Regulation Station The 30% feed regulating valve [FCV 003A] is used during HRSG start up and up to 30% steam flow of HRSG. The valve can be operated either on auto or manual mode. The positioning of [FCV 003A] on auto is controlled only by the level signal from the Drum and the pressure transmitters, which is acceptable at low loads. Valve [FCV 003A] is a globe type control valve Pneumatically actuated by a spring opposed diaphragm actuator. The characteristic of the valve is linear, with equal increase in flow for equal valve opening. On loss of control air, the valve opens full. There is no manual override for controlling the valve. The valve [FCV 003A] is arranged between an electrically operated inlet Isolating valve M 003A
Section B
and a manually operated outlet Isolating valve GT 028. The valve GT 028 is normally kept open. After the control valve [FCV 003A] , two drain valves (GT 025 & GT 024) are installed. The drain valves normally remain closed and opened only to drain the line when valve [FCV 003A] has to be opened for inspection/maintenance. The electrically operated 30% feed Isolating valve M 003A can be interlocked for opening or closing under the following conditions. • The valve [M 003A] can be opened for using the valve [FCV 003A] if the HRSG steam flow is less than 25% MCR and if the drum level is not high. • The valve [M 003A] closes automatically when there is a HRSG trip and closure of main steam stop valve M 029A. • The valve [M 003A] gets a permission for closing when any of the Isolating valves [M 003B] or [M 003C] of the 100% feed regulating stations are open. • The valve closes when the drum level is very high. The valve [FCV 003A] can be positioned on manual mode from the DCS to provide the required quantity of water to maintain normal water level. In the auto mode, the level indicating controller HIC-003A positions the valve [FCV 003A]. Level transmitters LT-003A , B & C continuously monitors the steam drum water level. A signal from two out of two of these transmitters feed a level signal to LIC-003A through a special drum level control macro. These level signals are compensated for drum steam pressure at the macro. The set point of the controller LIC-003A is 0 (i.e. normal level). When LIC-003A is switched on the auto mode, the controller compares the level signal with the set point and generates an error signal if there is a deviation and positions the valve FCV 003A through the positioner to correct the deviation. FCV 003A and its automatic control are adequate during HRSG startups & low steam flows, when rapid changes of drum level (except during swelling) is not envisaged. The operation of FCV 003A can be sluggish and cannot respond to rapid water level changes due to large load changes. 100% Feed Controller FCV 003B The inlet, outlet and drain arrangements of FCV 003B are similar to the low load control valve FCV 003A described earlier. Electrically operated valve M 003B is the inlet-isolating valve. GT 027 is the outlet-isolating
18
Operation & Maintenance Manual
valve, which normally remains open. Drain valves GT022 & GT 023 normally remain closed and are opened for draining only when the line is isolated for inspection/maintenance of valve FCV 003B The inlet isolating valve M 003B is interlocked in the following manner. • The isolating valve M 003B (or M 003C as per operator choice) opens automatically when the HRSG steam flow exceeds 25% • Valve M 003B (or M003C) closes when,
100% Feed Controller FCV 003C It is exactly similar to FCV 003B described above except for its valve tag numbers. The feed water control station is connected to the HP economizer 1 through a feed water control station. Pressure gauge [PI 008] installed in the line provide the economiser inlet feedwater pressure and a NRV 031 is provided in the inlet of the HP Economiser 1. 3.1.2HP Economiser
– There is an HRSG trip or – MSV (M 029A) closes or – When the drum level is very high. Three-element feed water control system is provided to regulate the quantity of feedwater flowing into the boiler to maintain the required water level in the steam drum. In three-element control, the drum level is controlled by the measurement of three process parameters (elements) - drum level, feedwater flow & steam flow. The drum level is measured by using differential pressure type level-transmitter LT 003A/B/C installed on the steam drum. The measured signal is taken as the process variable (PV) to the drum level controller [LIC 003B]. This process variable (PV) is compared with the fixed set point (SP) in the drum level indicating controller block and a control signal (CV) is generated. The level controller control output (CV) is added with steam flow signal from the main steam line in a feed forward block. This is done to achieve a better level control by taking corrective action in anticipation. The output of the feed forward block is used as a variable set point to the water flow-indicating controller [FIC-003]. This variable set point is compared to the actual feed water flow signal from [FE 003A], which acts as the measured variable for the controller [FIC-003]. The control output signal (CV) from the controller [FIC-003] will position the feed water control valve through a current-pneumatic converter. Action of the control valve is air/ signal FAIL to OPEN. The valve position is transmitted to the DCS. On the DCS, current drum level, steam flow, feed flow & the feed control valve position can be monitored. The three element control adopted for the 100% flow control valves FCV 003B & C takes into account the drum level, steam flow and feed water flow for positioning the control valve whereas the 30% level controller FCV 003A takes only the drum level for its operation.
Section B
HP Economiser 1 There are 2 modules of Economizer (HP Economizer- 1) located on the last stages of the exhaust gas path of the HRSG, before LP Evaporator. The Economiser modules consist of a top and bottom header of size 200 NB x 25.4 Thk and Serrated tubes of size 38.1 O.D. x 2.6 Thk. The water leaving HP economiser 1 passes through the HP economiser 2. All the drains of Economizer-1 have been grouped together and connected to the HP drain header through three isolating valves. Air vent valves are located on the cross over pipes of the top headers (which are the high points of the modules). Air vents of Economizers modules are individually grouped together. Inlet piping to HP Economiser 1 is provided with following: • A pressure transmitter (PI 008) for local indication. • A NRV 031 is provided. Outlet piping of the HP Economiser 1 is provided with following: • A temperature transmitter (TE 009A & B ) for high temperature remote indication. • A pressure and temperature indicator PI 010A & B and TI 047B for local indications HP Economiser 2 There is 1 module of Economizer (HP Economizer- 2) located on the last stages of the exhaust gas path of the HRSG, before IP Economiser. The Economiser module consists of a top and bottom header of size 250 NB x 30 Thk and Serrated tubes of size 38.1 O.D. x 2.6 Thk. The water leaving HP economiser 2 passes through the HP econmiser 3.
19
Operation & Maintenance Manual
All the drains of Economizer-2 have been grouped together and connected to the HP drain header through three isolating valves. Air vent valves are located on the cross over pipes of the top headers (which are the high points of the modules). Air vents of Economizers modules are individually grouped together. Outlet piping of the HP Economiser 2 is provided with following: • A temperature transmitter (TE 011A & B) for high temperature remote indication. • A pressure and temperature indicator PI 012A & B and TI 046B for local indications HP Economiser 3 There are 3 modules of Economizer (HP Economizer- 3 ) located on the last stages of the exhaust gas path of the HRSG, before IP Evaporator. The Economiser modules consist of a top and bottom header of size 250 NB x 30 Thk and Serrated tubes of size 38.1 O.D. x 2.6 Thk. The water leaving HP economiser 3 is fed to the HP Drum in two feed lines. All the drains of Economizer-3 have been grouped together and connected to the HP drain header through three isolating valves. Air vent valves are located on the cross over pipes of the top headers (which are the high points of the modules). Air vents of Economizers modules are individually grouped together. Outlet piping of the HP Economiser 3 is provided with following: • A temperature transmitter (TE 013A/B) for high temperature remote indication. • A pressure and temperature indicator PI 014A/B and TI 042A/B for local indications 3.1.3HP Drum The Steam Drum is 14500mm long welded cylindrical vessel made of SA-516 Grade 70 material. The cylindrical portion and the two hemispherical dished ends are made of thick plates respectively. The steam drum is supported by a saddle and sliding arrangement on top of the HRSG structure over beams. The sliding arrangement permits a limited shift due to thermal expansion through the oblong holes for mounting the saddle. The drum is insulated by lightly resin bonded mineral wool mats. Two manholes at either end of the drum provide access to the drum. The drum is closed tight at either end by thick
Section B
cover plates bolted against the manhole rim by two holding bars. A gasket is fitted between the cover plate and the mating machined surfaces in the dished ends. The cover plates swing inside, for convenience during opening. Steam Drum is fitted with several components to perform important functions, which are listed below: • Steam Drum receives feed water from the HP Economizer 3 outlet through two feed pipes & 4 nos. of (2 on each side) cyclone separators called hydroclones (to take care of economiser steaming) to maintain a near constant level (Normal water level) and for continuous supply to the evaporator through down comer pipes. While flowing through the evaporator modules, by absorbing heat from the gas turbine exhaust gas, the hot water gets converted to water / steam mixture and flows back to the Drum behind the baffles through riser tubes. • Steam drum receives the water – steam mixture from the evaporator modules through the riser tubes behind the baffles. From the baffles, the water – steam mixture flows tangentially through the 50 nos. cyclone separators installed in the steam drum. In this tangential flow, water, which is heavier, is separated from steam and trickle down to mix with the water in the steam drum. Steam rises upward to flow through the primary scrubber and secondary scrubber provided at the top portion of the steam drum. The scrubber provides a tortuous path to the steam and during its passage, strips any traces of moisture from steam. Saturated dry steam is collected at the top of the drum and distributed to the HP Superheater 1. • Conditioning of Boiler Water: Due to continuous evaporation of boiler water in the drum, minor impurities present in the feed water, concentrate to high impermissible levels in the boiler water. Rise in hardness of water (conductivity), content of chlorides, silica etc., have to be kept to a minimum to prevent scale formation or deposits in the evaporator tubes and drum. While Quality Control of water is described in the manual, a brief outline of the control strategy is stated and the provisions made in the Drum to execute the control is indicated. Sample of Boiler water is collected from the continuous blow down line to the SWAS. An analyzer continuously analyses the sample for pH & conductivity. If the analysis indicate high conductivity (chlorides, silica) etc., small pre-determined amount of water is continuously drained from the steam drum
20
Operation & Maintenance Manual
through the continuous Blow down valve M 040 with isolating valves for controlling the flow to reduce their concentration to permissible levels in the steam drum. Tri-Sodium phosphate is dosed into steam in the boiler drum to maintain a phosphate concentration and a pH of 8 to 10. The Phosphate has the capacity to convert hardness producing insoluble calcium/ magnesium salts to soluble sodium salts, which are drained through the blow down. A typical reaction can be as follows. 3 CaSO4 + 2 Na3 PO4→ Ca3 (PO4)2 ↓ + 3Na2 SO4 The dozed phosphate also provides desired alkalinity to the boiler water. An alkaline pH minimizes the possibilities of corrosion. The following facilities have been provided in the steam Drum for the above operations:
Continuous Blow Down (CBD) Line To enable the water drained from the drum to reflect the true composition of Boiler water, a perforated is laid along the water space of the drum below the normal water level (axis of the drum) and connected through the CBD line to the Blow down tank. There is a isolating valves on the upstream of a blow down valve M 040 and a non-return valve NRV676 on the line. The valve for Boiler water continuous Blow down (CBD) is positioned to drain continuously a pre-calculated quantity. HP Steam drum is fitted with several components to perform important functions, which are listed below: Sampling Line The CBD line provided to the SWAS through two isolating valves GT726 & GT727. Water & Steam quality control is described elsewhere in this manual. HP (Phosphate) Dosing Line Dosing of phosphate to the Boiler water is to be done in a manner that it quickly mixes with the whole of Boiler water. To enable this, a perforated pipe has been laid along the length of the drum and connected to the HP dosing line through a non-return valve NRV 053 and an isolating valve GT 052. HP dosing system is described in subsequent pages of this manual. Emergency Blow Down (EBD)
Section B
During HRSG startup situations arise resulting in high drum water levels. As high drum water levels are not permissible and may lead to a boiler trip, provision has been made for quickly draining some water from the boiler drum under this condition. The EBD line, drawn from the entire length of the drum consists of a manually operated inlet isolating valve GT 765, an inching type motor operated blow down valve M 039A & B followed by a non return valve NRV 677. The EBD line drains to the blow down tank. Manual isolating valves are normally kept closed and are opened only when emergency blow down has to be done by opening M 039A & B. GAUGES & TRANSMITTERS Level Gauges, Transmitters
Level
Indicators,
Level
As maintaining normal water level in the steam drum is one of the important parameters to be monitored and controlled, elaborate provisions for level instrumentation has been made on the Steam Drum. Brief mention of this instrumentation will be made in this section LEVEL GAUGES (LI 016A & LI 016B) The Level Gauges is of multiport type. The top of the gauge glass is connected to the steam side of the drum through two isolating valves. The bottom portion of the gauge glass is connected to the waterside of the drum through two isolating valves. Care is taken to ensure that the center line of the center port coincides with the center line of the drum, which is the required normal water level. Twin drain valves are fitted to each gauge. The drains normally remain shut when the gauge is in service with steam side and waterside isolating valves open. The level gauges are simple direct reading instruments and serve for quick and accurate reading of the drum level. During the start up of HRSG, level gauges may be the only instruments, which can be relied upon, as other instruments may not be accurate. The level gauges are also used to verify the readings of other instruments. The level gauges being located at the drum level are not convenient for regular operation of the Boiler. The level gauges however must be maintained in service, as IBR requires that at least one of the level gauges must be in service to operate the HRSG. Control of water Level in the steam drum relies on the following Instruments. • Level Transmitters LT 003A, B & C and indicators LI 016 A & B and LI 017 (Hydrastep).
21
Operation & Maintenance Manual
Level transmitters LT 003A,B & C provide inputs for Drum level indication at DCS and Low Drum level, High drum level alarms, A median of the three level transmitters is taken. • The level transmitter LT 003A,B & C provide drum level signal to the single element and three element controllers. The above level instruments are connected to the steam drum, steam and water space through twin isolating valves. The reading of the steam drum water level by the above instruments is sensitive to the drum pressure. Transmitters PT- 003A ,B & C (through twin isolating valves) mounted on the steam drum, provide a pressure compensation signal to the level transmitters, so that their signals represent true level neutralizing variations due to pressure changes. They also provide steam drum pressure signal to DCS. for low and high steam drum pressure. • PI- 015A & B are two local instruments indicating Drum pressure at the drum level, A 4 nos. of Skin metal temperature transmitter TE 037A- TE 037D are provided on the drum to measure the Drum metal temperature and generate the high alarm in remote. Drum Safety Valves (PSV- 006A AND PSV006B)
To protect the boiler and personnel against consequences of abnormal pressure increases caused by sudden load decrease, malfunction of firing system, closure of steam valves etc., two spring loaded safety valves have been fitted on the drum. On increase of steam pressure beyond a pre-determined set value (117 & 118 kg/cm2), the safety valves opens automatically to relieve steam from the drum to the atmosphere. The safety valve closes when the steam pressure falls by around 4% of the set value. IBR prescribes norms for installation, care and testing of the safety valves, which are mandatory. Safety valve, PSV- 006A and PSV- 006B along with the safety valve PSV- 027 (on the super heated steam line) have the capacity, as per IBR, to relieve steam from the HRSG in such a manner that pressure rise above 103% of the working pressure is prevented on any condition. As the spring-loaded safety valves result in high noise levels when they open, the exhaust of the safety valves are connected through a silencer to substantially reduce the noise level. Installation, adjustment and maintenance instructions for safety valves are enclosed which may be referred for a full understanding of the safety valves. Silencers
Figure 2 Figure 1
Section B
Exhaust of various safety valves, steam dump & startup valves are exhausted through Silencers.
22
Operation & Maintenance Manual
The Silencers are acoustically & mechanically designed to attenuate the large noise made during operation of these valves. The silencers are made out of suitable casing in which the sound absorbing materials are packed in a certain pattern & wrapped by scrim cloth and wire mesh to avoid ‘fly off’ of sound absorbing materials during operation of silencer at high flow rates. The process fluid enters the annular space between the sound absorbing materials packing where the sound energy is absorbed throughout the length of the silencer. The Silencers are mounted on separate structures on top of the HRSG and the exhaust pipes form the valves are connected to the silencers. As the silencer contain no moving parts, no operational care is needed except opening the drain plug provided in the drain line, once in three months to drain the line. Air Vent An air vent (with twin valves M 005A & M 005B ) has been fitted on the drum to vent out air during initial boiler filling, before start up and during start up. During start up, the air vents are closed at a drum pressure of 2 Kg/cm² (g) and when copious steam is passing. The air vents are opened after shut down of the boiler when the boiler pressure falls to 2 kg/cm2.
a top and bottom header and one module consist of three rows of tubes. The modules are hung from the top headers in the flue gas path, on guide supports with provision for thermal expansion downward & in the sides. Finned Evaporator tubes are welded between the top & bottom headers of each module to form the heat absorption surface. Hot water flow to the evaporators from the drum and steam/water mixture flows to the drum from the Evaporators through risers. A down comer header of the Evaporator spans all the Evaporator modules. The four down carrier pipes from the Drum connect to the down comer header. From the down comer header, interconnecting pipes connect to all the lower headers of the Evaporator modules. The top headers of the module are connected to the drum by riser tubes. The circulation through Evaporator modules takes place as follows: • Heated Boiler water from the drum flows through the four down comer pipes to down comer header.
The N2 filling line to the HP steam drum is provided with the Isolation valve GT 095 which is normally closed.
• From the down comer header, the hot water flows to the lower headers, and then through Evaporation module tubes, to the Evaporation module top headers. During its passage through the Evaporation module tubes, the hot water absorbs heat from the exhaust gases of the gas turbine and gets converted to a water/steam mixture. This circulation is assisted by the higher density of water in the down comer compared to the lower density of water / steam mixture in evaporator and riser tubes
A NRV 096 is provided after Isolation valve.
•
N2 Filling
The Saturated steam from the steam header is connected to the HP Superheater 1 with the following • A temperature point TP 007 is provided for the indication of the temperature of the saturated steam entering to the HP superheater 1. 3.1.4HP Evaporat or The Evaporators convert hot boiler water received from the HP Drum through four down comer pipes into a steam water mixture, by absorption of heat from the Gas Turbine exhaust gas. The steam water mixture is led back to the drum from the evaporators through riser pipes. Evaporator consists of 3 modules. Two modules consists of four rows of tubes arranged between
Section B
The water / steam mixture from the top headers of the Evaporation module, flows behind the baffle chamber in the steam drum.
• In the steam drum, the steam/water mixture flows through the cyclones where water & steam are separated and saturated steam flows to the HP Superheater 1. Separated water mixes with boiler water to flow through the Evaporator modules again. Evaporator are of fully drainable type & drains (one for each downcomer) have been provided on the down comer header of the HRSG. These drains are connected to the HP drain header through three isolating valves. These drains essentially are for draining the Evaporation modules after shut down of HRSG. It is not to be operated when the HRSG is in service as their opening may interfere with the natural circulation in the modules.
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Operation & Maintenance Manual
3.1.5HP Superheater Superheating of saturated steam from drum is done in three stages in HP Superheater 1 , HP Superheater 2 & HP Superheater 3. Between HP Superheater 2 & HP Superheater 3 an attemperator is located to control the temperature of final steam outlet at 567.3 ± 5 °C. Superheaters are made of modules, each consisting of a top header and a bottom header, with tubes between the headers. Superheater modules are hung from their top headers with provision for thermal expansion down wards & in the sides. HP Superheater 1 HP Superheater 1 Consists of 1 modules. Saturated steam from the drum flows to the first module of superheater 1 lower header through saturated steam supply pipes from the steam header. Steam travels up from both the ends of lower header of the first module, through the module tubes to the top header of the same module, absorbing heat.
There are Serrated tubes per row; 3 rows per module; 3 module in HP superheater 2. The tubes are of size 38.1 O.D. x 3.2 Thk. and made of SA213 T91 material. . The HP Superheater 2 header (Lowest point), are provided with drain line with two isolation valves each. These drains are operated to drain the HP Superheater 2 drain header. The drains are opened before light up of the boiler to drain HP Superheater 2 . They are closed at a drum pressure of 2 To 5 Kg/cm². The outlet line of the HP superheater 2 is provided with • A temperature transmitter TE 020. It transmits the HP superheater 2 outlet temperature signal for the high alarm. • A pressure Indicator PI 019. • A temperature indicator TI 044 before the Atttemperation. • A temperature point TP001. Attemporator
There are Serrated tubes per row; 2 rows per module. The tubes are of size 38.1 O.D. x 3 Thk. and made of SA 213 T11 material.
The function of the attemporator is to control the temperature of main steam at HP Superheater 3outlet to 567.3 ± 3°C.
The HP Superheater 1 lower headers (Lowest point), are provided with manual drain valve GL 739 which is normally closed. HP Superheater drain line with two isolation valves GT680 & GT761 which are normally kept open connected to condensate drain pot. The condensate drain pot is operated through the electrically operated drain valve (M 038D & M 038 H) on the principle of conductivity and drain the condensate to the BD Tank. A temperature element TE 038DH is provided in the drain line for the drain control.
Water sprayed into steam evaporates, drawing heat from the steam and completely mixes with steam. Attemporator is a header connecting from the bottom header of the module of HP Super-heater 2 to the lower header of the module of HP Super-heater 3 with an inner sleeve. Spray nozzle is held across the header on to the header nozzle . The spray nozzle at the blind end rests on a guide to with stand the force of steam. Holes are drilled on the spray nozzle in the direction of steam flow.
The outlet line of the HP superheater1 is provided with
The spray water for the Attemperator is obtained from the HP Boiler Feed water main, before the flow transmitter FT 034. The spray water line consists of the following.
• A temperature transmitter TE018A/B . • A temperature indicator TI 045 before the HP Superheater 2.
• A Solenoid operated Shut off valve TV 034.
• A temperature point TP 008.
•
A flow Element FE-034 to measure spray water flow and indicate on flow transmitter FT034.
•
A Control station consists of the two Pneumatically operated flow control valve TV-026A & TV-026B (100 %). The flow control valve is provided with inlet/outlet isolating valves. Motorised inlet isolation valve M 026A & M 026B are provided before the control valves and manual outlet isolation valve GT 049 & GT 050 are provided and remain
HP Superheater 2 HP Superheater 2 Consists of one modules. Steam from the HP superheater 1 flows to the first module of HP superheater 2 lower header through steam supply pipes from the steam header. . Steam travels up from both the ends of lower header of the first module, absorbing heat and travels to the top header of the HP Superheater 2..
Section B
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Operation & Maintenance Manual
normally open. The are two drain valves GT 045 & GT 046 are provided after the control valve TCV 026A and two drain valves GT 047 & GT 048 are provided after the control valve TCV 026B, which remain normally closed. These drain valves are opened after closing inlet/outlet Isolating valves, when valve TCV 026A & B are to be taken for maintenance. • A pressure indicator PI 033 with two isolation valve. The spray water line connects to the spray nozzle of the attemperator through a non-return valve NRV 051. Temperature transmitter TE 020 & TE- 042 provide steam temperature indication before and after the attemperator to judge the effectiveness of attemperation. . The temperature transmitter TE026A &B (1out of 2) indicate the high temperature alarm through TIC 026. A feed back signal from TIC 026 is provided to the controller HIC 026A & B which controls the pneumatically operated attempearation flow control valve TV-026A & B to maintain the temperature as required. An attemperator is provided with manual twin drain valve GL 739 & GT 683, which are normally closed. Attemperator drain line is connected to HP SH drain header through two isolation valves GT 764 & GT 694 which are normally kept open. A temperature element TE 038BF is provided in the drain line for the drain control. HP Superheater 3 HP Super-heater 3 does superheating of steam.
third
stage
of
HP Super-heater 3 consists of one modules. The module are constructed out of Spiral Solid Tube These rows screen the radiation of flame coming from the combustion chamber and avoid fin overheating in subsequent HRSG surface area. The HP Superheater 3 module tubes are made of SA213 T91 material. Steam after attemperation enters the lower header of the HP Super-heater 3 first module and rises to the top header of the same module with absorbing heat and then to HP Main steam line. The HP Super-heater 3 lower headers (Lowest point), are provided with three drains with two isolation valves . These drains valves GT 682, 2 nos. are kept closed are connected to the HP Superheater drain header. Temperature element TE 035A to TE 035H (8nos.) are installed on the HP Superheater 3.
Section B
An air vent is provided on main steam piping just after HP Superheater 3 piping. Pressure & temperature indication is provided for main steam piping. 3.1.6HP Main Steam line The HP steam line connects the top header of HP Super-heater 3 module to the plant steam main This line incorporates the following • Electrically Operated HP Steam Stop Valve M 029AThis valve Isolates the HRSG from the plant HP steam main. This valve is provided with an electrically operated, integral by pass valve M 029B. • Safety Valve PSV-027To take care of the pressure upset caused by sudden load cut, malfunctioning of firing system, closure of steam valves etc., a safety valve is provided on the main steam line at the Superheater outlet. This is a spring-loaded, valve set at 110.6 bar (a) pressure to protect the boiler against over pressures. The safety valve is similar to Drum safety valves PSV-006A & PSV-006B described earlier. The exhaust of the safety valve is piped to a silencer to reduce the noise levels when the safety valve is operating. The silencer is mounted on a separate structure on top of the HRSG. • Start Up Vent ValveValve PCV 028 is a pneumatically operated start up vent valve. M 028 is a motor operated Isolating valve for start up vent. The outlet of the start up vent valve is exhausted to atmosphere through a silencer. The start up vent valve is to be kept open while start up. It provides initial steam flow for the cooling of superheaters. • HP Steam Line Drain The steam line drain consists of the following valves. Electrically operated motorised valve M 038A & M 038E, are normally closed are connected in the drain line with an isolation valve GT 698 which is normally open. • Flow Nozzle FE 003BFlow nozzle FE- 003B is installed on the HP steam line after the main stop valve to provide steam flow indication. The flow transmitter reading after steam pressure & temperature compensation is used for the following, 1. Steam flow reading. 2. Steam flow compensation for feed water flow
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Operation & Maintenance Manual
• HP Steam Temperature InputTemperature transmitter TT- 026A & 026B (1out of 2) provide the HP steam temperature input for the following 1. Temperature Indicating controller TIC-026 which controls positioning of the attemperator spray control valve as described earlier. 2. Temperature compensation signal to steam flow. A temperature gauge TI 024 is provided for the local indication. • HP Steam Pressure InputPressure transmitter PT- 025A & B (1out of 2) provide the HP steam temperature input for the following 1. Pressure compensation signal to steam flow. A pressure Indicator PI 022 for local indication.
Serrated tubes of size 38.1 O.D. x 2.6 Thk & material SA201 A1. The water leaving IP economiser through the Feed regulating Station to the IP Steam Drum. All the drains of Economizer have been grouped together and connected to the IP drain header through two isolating valves. Air vent valves are located on the cross over pipes of the top headers (which are the high points of the modules). Air vents of Economizers modules are individually grouped together. Inlet piping to IP Economiser is provided with following: • A connection is provided for the attemperation after the reheater 1. • A pressure transmitter ( PT 052) for remote indication.
• Air VentGT 107 > 108 are air vent valves on the HP steam line, which may be used during hydro test.
• A temperature transmitter (TE 051 ) for high temperature remote indication.
• Drum Metal Temperature MonitoringWhen a HRSG is started after filling water to normal level, initially drum metal temperatures on the steam side and water side may show considerable difference due to slow conductive heat transfer across the drum metal and difference of heat inputs across the water washed & steam washed parts of the drum. The temperature difference, if it exceeds 50°C, may set up abnormal thermal stresses. To warn the operator of such a situation, four drum skin metal thermocouples have been installed, two on the water side & two on the steam side of the drum. These thermocouples connect to a monitor in the DCS. When the differential temperature exceeds 50°C, an alarm is generated in the DCS. This alarm is an indication to the operator to slow down the startup rate. However, when the drum pressure reaches 5 to 10 Kg/cm², temperature differentials disappear. A similar caution is desired during cooling down of HRSG.
• A non return valve NRV 209.
• A tapping from the HP Steam line is provided for the Steam turbine gland sealing system.
3.2
I P Section Components Description
• A pressure Indicator PI 053 for local indication.
Outlet piping to IP Economiser is provided with following: • A pressure safety valve PSV 078 is provided. • An Export Water Connection is provided through a valve (GT 211) & NRV (NRV 261) and pressure indicator PI 076 & temperature indicator TI 076 for local indication. • A pressure relief valve PRV 050 is provided. The outlet of PRV 050 is connected to the LP steam drum for safe relief of hot water. • A pressure transmitter ( PT 077A & B) for remote indication and also for the pressure compensation to maintain the IP drum level. • A pressure transmitter ( PT 077A & B) is provided to measure the pressure at IP Eco Outlet. A Feed back control loop with the pressure indicating controller FIC 050 is provided for automatic pressure control to the flow control valve FCV 050A & B in the feed regulating station of the IP section.. • A temperature transmitter ( TE 075A & B) for remote indication and also for the temperature compensation to maintain the IP drum level..
3.2.1I P Economiser
3.2.2I P Boiler Feed wat er Cont rol Stati on
There are 1 modules of Economizer (IP Economizer) located Before HP Economiser 1 in the HRSG flue gas path . The Economiser modules consist of a top and bottom header and
During normal operating HRSG, it must be kept continuously supplied with feed water to maintain near normal level in the drum. The HRSG trips if water level in the drum is either too low or too high.
Section B
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Operation & Maintenance Manual
Feed water is obtained from the IP feed water from the client. There are two feed control valve , out of which at least one must be in service when the HRSG is operational. IP Boiler Feedwater Regulating Station The feed water flow control station consists • 100 % capacity control valve [FCV 050A] • 100 % capacity control valve [FCV 050B] Both 100% control valve are provided with motorised isolation valves [M050A & B] and manual isolation valve at downstream of control valve [GT216 & GT 217]. The feed water flow control valve is a globe type valve, pneumatically actuated by a spring opposed diaphragm actuator and positioned by the feed water flow indicating controller [HIC 050A & 050B] order to maintain the normal water level at boiler steam drum. The 100% flow control valve [FCV050A] capable of feeding the HRSG. [FCV 050B] is an identical stand by to [FCV050A].
positioning of [FCV 050A] on auto is controlled as discussed below. Valve [FCV 050A] is a globe type control valve Pneumatically actuated by a spring opposed diaphragm actuator. The characteristic of the valve is linear, with equal increase in flow for equal valve opening. On loss of control air, the valve opens full. There is no manual override for controlling the valve. The valve [FCV 050A] is arranged between an electrically operated inlet Isolating valve M 050A and a manually operated outlet Isolating valve GT 216. The valve GT 216 is normally kept open. After the control valve [FCV 050A] , one drain valve (GT 214 ) is installed. The drains normally remain closed and opened only to drain the line, when valve [FCV 050A] has to be opened for inspection/maintenance. The electrically operated 100% feed Isolating valve M 050A can be interlocked for opening or closing under the following conditions.
The following are installed in the common inlet line from the IP feed water line from IP Economiser to the IP feed regulation Stations.
• The valve [M 050A] can be opened for using the valve [FCV 050A] if the HRSG steam flow is less than 25% MCR and if the drum level is not high.
• Temperature elements TE-075A &B for indicating temperature of inlet feed water. A signal is fed to the FI 050A.
• The valve [M 050A] closes automatically when there is a HRSG trip and closure of main steam stop valve.
• Pressure elements PE-077A & B for indicating pressure of inlet feed water. A signal is fed to the FI 050A.
• The valve [M 050A] gets a permission for closing when any of the Isolating valves [M 050B] of the 100% feed regulating stations are open.
• A temperature indicator TI 075 for indicating temperature. • Flow nozzle FE 050A with impulse connections to flow transmitter FT-050A, FT-050B & FT-050C. • Pressure indicator PI 056 for indicating pressure of inlet IP feed water. The flow transmitters provide feed flow signal to the feed Indicating controller FIC-050 (which will be described later). After the above, the common inlet line branches into two parallel paths, on which are installed the two feed regulating stations mentioned earlier to be connected to a common line for feeding water to the IP Drum. The feed regulating stations are now described. 100% Feed Controller FCV 050A The feed regulating valve [FCV 050A] is used for level controlling in the IP Drum. The valve can be operated either on auto or manual mode. The
Section B
• The valve closes when the drum level is very high. Three-element feed water control system is provided to regulate the quantity of feedwater flowing into the boiler to maintain the required water level in the steam drum. In three-element control, the drum level is controlled by the measurement of three process parameters (elements) - drum level, feedwater flow & steam flow. The drum level is measured by using differential pressure type level-transmitter LT 050A/B/C installed on the steam drum. The measured signal is taken as the process variable (PV) to the drum level controller [LIC 050]. This process variable (PV) is compared with the fixed set point (SP) in the drum level indicating controller block and a control signal (CV) is generated. The level controller control output (CV) is added with steam flow signal from the main steam line in a feed forward block. This is done to achieve
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Operation & Maintenance Manual
a better level control by taking corrective action in anticipation. The output of the feed forward block is used as a variable set point to the water flow-indicating controller [FIC-050]. This variable set point is compared to the actual feed water flow signal from [FE 050A] with pressure and temperature compensation from the PT 077A & B and TE 075A & B, which acts as the measured variable for the controller [FIC-050]. The control output signal (CV) from the controller [FIC-050] will position the feed water control valve through a current-pneumatic converter. Action of the control valve is air/ signal FAIL to OPEN. The valve position is transmitted to the DCS. On the DCS, current drum level, steam flow, feed flow & the feed control valve position can be monitored. The three element control adopted for the 100% flow control valves FCV 050A & B takes into account the drum level, steam flow and feed water flow for positioning the control valve. 100% Feed Controller FCV 050B It is exactly similar to FCV 050A described above except for its valve tag numbers. The feed water control station is connected to the IP Drum Pressure gauge [PI056] installed in the line provide the IP Drum inlet feedwater pressure and a temperature element TE 055 for remote indication of the inlet IP drum water temperature . 3.2.3I P Drum The Steam Drum is 12500mm long welded cylindrical vessel made of SA-516 Grade 70 material. The cylindrical portion and the two hemispherical dished ends are made of thick plates respectively. The steam drum is supported by a saddle and sliding arrangement on top of the HRSG structure over beams. The sliding arrangement permits a limited shift due to thermal expansion through the oblong holes for mounting the saddle. The drum is insulated by lightly resin bonded mineral wool mats. Two manholes at either end of the drum provide access to the drum. The drum is closed tight at either end by thick cover plates bolted against the manhole rim by two holding bars. A gasket is fitted between the cover plate and the mating machined surfaces in the dished ends. The cover plates swing inside, for convenience during opening. Steam Drum is fitted with several components to perform important functions, which are listed below:
Section B
• Steam Drum receives feed water from the IP Economizer outlet through single feed pipes & 2nos. of (1 on each side) cyclone separators (to take care of economiser steaming) to maintain a near constant level (Normal water level) and for continuous supply to the evaporator through down comer pipes. While flowing through the evaporator modules, by absorbing heat from the gas turbine exhaust gas, the hot water gets converted to water / steam mixture and flows back to the Drum behind the baffles through riser tubes. • Steam drum receives the water – steam mixture from the evaporator modules through the riser tubes behind the baffles. From the baffles, the water – steam mixture flows tangentially through the 20 nos. cyclone separators installed in the steam drum. In this tangential flow, water, which is heavier, is separated from steam and trickle down to mix with the water in the steam drum. Steam rises upward to flow through the secondary scrubber provided at the top portion of the steam drum. The scrubber provides a tortuous path to the steam and during its passage, strips any traces of moisture from steam. Saturated dry steam is collected at the top of the drum and distributed to the IP Superheater . • Conditioning of Boiler Water Due to continuous evaporation of boiler water in the drum, minor impurities present in the feed water, concentrate to high impermissible levels in the boiler water. Rise in hardness of water (conductivity), content of chlorides, silica etc., have to be kept to a minimum to prevent scale formation or deposits, in the evaporator tubes and drum. While Quality Control of water is described in the manual, a brief outline of the control strategy is stated and the provisions made in the Drum to execute the control is indicated. Sample of Boiler water is collected from the continuous blow down line to the SWAS. An analyzer continuously analyses the sample for pH & conductivity. If the analysis indicate high conductivity, (chlorides, silica) etc., small pre-determined amount of water is continuously drained from the steam drum through the continuous Blow down valve M 079 with isolating valves for controlling the flow to reduce their concentration to permissible levels in the steam drum. Tri-Sodium phosphate is dosed into steam in the boiler drum to maintain a phosphate concentration and a pH of 11. The Phosphate has the capacity to convert hardness producing insoluble calcium/ magnesium salts to soluble
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Operation & Maintenance Manual
sodium salts, which are drained through the blow down. A typical reaction can be as follows. 3 CaSO4 + 2 Na3 PO4→ Ca3 (PO4)2 ↓ + 3Na2 SO4 The dozed phosphate also provides desired alkalinity to the boiler water. An alkaline pH minimizes the possibilities of corrosion. The following facilities have been provided in the steam Drum for the above operations:
Continuous Blow Down (CBD) Line To enable the water drained from the drum to reflect the true composition of Boiler water, a perforated is laid along the water space of the drum below the normal water level (axis of the drum) and connected through the CBD line to the Blow down tank. There is a isolating valves on the upstream of a blow down valve M 079 and a non-return valve NRV633 on the line. The valve for Boiler water continuous Blow down (CBD) is positioned to drain continuously a pre-calculated quantity. IP Steam drum is fitted with several components to perform important functions, which are listed below: Sampling Line The CBD line provided to the SWAS through two isolating valves GT723 & GT724. Water & Steam quality control is described elsewhere in this manual. IP (Phosphate) Dosing Line
EBD line drains to the blow down tank. Manual isolating valves are normally kept closed and are opened only when emergency blow down has to be done by opening M 078. GAUGES & TRANSMITTERS Level Gauges, Transmitters
Level
Indicators,
Level
As maintaining normal water level in the steam drum is one of the important parameters to be monitored and controlled, elaborate provisions for level instrumentation has been made on the Steam Drum. Brief mention of this instrumentation will be made in this section LEVEL GAUGES (LI 059A & LI 059B) The Level Gauges is of multiport type. The top of the gauge glass is connected to the steam side of the drum through two isolating valves. The bottom portion of the gauge glass is connected to the waterside of the drum through two isolating valves. Care is taken to ensure that the center line of the center port coincides with the center line of the drum, which is the required normal water level. Twin drain valves are fitted to each gauge. The drains normally remain shut when the gauge is in service with steam side and waterside isolating valves open. The level gauges are simple direct reading instruments and serve for quick and accurate reading of the drum level. During the start up of HRSG, level gauges may be the only instruments, which can be relied upon, as other instruments may not be accurate. The level gauges are also used to verify the readings of other instruments.
Dosing of phosphate to the Boiler water is to be done in a manner that it quickly mixes with the whole of Boiler water. To enable this, a perforated pipe has been laid along the length of the drum and connected to the IP dosing line through a non-return valve NRV 256 and an isolating valve GT 257. IP dosing system is described in subsequent pages of this manual.
The level gauges being located at the drum level are not convenient for regular operation of the Boiler. The level gauges however must be maintained in service, as IBR requires that at least one of the level gauges must be in service to operate the HRSG.
Emergency Blow Down (EBD)
• Level Transmitters LT 050A, B & C and indicators LI 059 A & B .
During HRSG startup situations arise resulting in high drum water levels. As high drum water levels are not permissible and may lead to a boiler trip, provision has been made for quickly draining some water from the boiler drum under this condition. The EBD line, drawn from the entire length of the drum consists of a manually operated inlet isolating valve GT 628, an inching type motor operated blow down valve M 078 followed by a non return valve NRV 634. The
Section B
Control of water Level in the steam drum relies on the following Instruments.
Level transmitters LT 050 A, B & C provide inputs for Drum level indication at DCS and very Low Drum level, very High drum level alarms. • The level transmitter LT 050A, B & C provide drum level signal to the three element controllers. The above level instruments are connected to the steam drum, steam and water space through twin isolating valves. The
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Operation & Maintenance Manual
reading of the steam drum water level by the above instruments is sensitive to the drum pressure. Transmitters PT— 057A, B & C (through twin isolating valves) mounted on the steam drum, provide steam drum pressure signal to DCS. for low and high steam drum pressure. • PI- 058A & B are two local instruments indicating Drum pressure at the drum level
As the spring-loaded safety valves result in high noise levels when they open, the exhaust of the safety valves are connected through a silencer to substantially reduce the noise level. Installation, adjustment and maintenance instructions for safety valves are enclosed which may be referred for a full understanding of the safety valves. Silencers
Drum Safety Valves (PSV- 060A AND PSV060B)
Figure 4
Figure 3
To protect the boiler and personnel against consequences of abnormal pressure increases caused by sudden load decrease, malfunction of firing system, closure of steam valves etc., two spring loaded safety valves have been fitted on the drum. On increase of steam pressure beyond a pre-determined set value (30 & 31 Bar g), the safety valves opens automatically to relieve steam from the drum to the atmosphere. The safety valve closes when the steam pressure falls by around 4% of the set value. IBR prescribes norms for installation, care and testing of the safety valves, which are mandatory. Safety valve, PSV060A and PSV- 060B along with the safety valve PSV- 062 (on the super heated steam line) have the capacity, as per IBR, to relieve steam from the HRSG in such a manner that pressure rise above 103% of the working pressure is prevented on any condition.
Section B
Exhaust of various safety valves, steam dump & startup valves are exhausted through Silencers. The Silencers are acoustically & mechanically designed to attenuate the large noise made during operation of these valves. The silencers are made out of suitable casing in which the sound absorbing materials are packed in a certain pattern & wrapped by scrim cloth and wire mesh to avoid ‘fly off’ of sound absorbing materials during operation of silencer at high flow rates. The process fluid enters the annular space between the sound absorbing materials packing where the sound energy is absorbed throughout the length of the silencer. The Silencers are mounted on separate structures on top of the HRSG and the exhaust pipes form the valves are connected to the silencers. As the silencer contain no moving parts, no operational care is needed except opening the drain plug
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Operation & Maintenance Manual
provided in the drain line, once in three months to drain the line.
through the Evaporation module tubes, the hot water absorbs heat from the exhaust gases of the gas turbine and gets converted to a water/steam mixture. This circulation is assisted by the higher density of water in the down comer compared to the lower density of water / steam mixture in evaporator and riser tubes
Air Vent An air vent (with valves M 061 ) has been fitted on the drum to vent out air during initial boiler filling, before start up and during start up. During start up, the air vents are closed at a drum pressure of 2 Kg/cm² (g) and when copious steam is passing. The air vents are opened after shut down of the boiler when the boiler pressure falls to 2 kg/cm2. N2 Filling The N2 filling line to the HP steam drum is provided with the Isolation valve GT 228 which is normally closed. A NRV 227 is provided after the Isolation valve. 3.2.4I P Evaporator The Evaporators convert hot boiler water received from the IP Drum through down comer pipes into a steam water mixture, by absorption of heat from the Gas Turbine exhaust gas. The steam water mixture is led back to the drum from the evaporators through riser pipes. Evaporator consists of 2 modules. Two modules consists of three rows of tubes arranged between a top and bottom header. The modules are hung from the top headers in the flue gas path, on guide supports with provision for thermal expansion downward & in the sides. Serrated Evaporator tubes are welded between the top & bottom headers of each module to form the heat absorption surface. Hot water flow to the evaporators from the drum; and steam/water mixture flows to the drum from the Evaporators through risers. A down comer header of the Evaporator spans all the Evaporator modules. The down carrier pipes from the Drum connect to the down comer header. From the down comer header, interconnecting pipes connect to all the lower headers of the Evaporator modules. The top headers of the module are connected to the drum by riser tubes. The circulation through Evaporator modules takes place as follows: • Heated Boiler water from the drum flows through the down comer pipes to down comer header. • From the down comer header, the hot water flows to the lower headers, and then through Evaporation module tubes, to the Evaporation module top headers. During its passage
Section B
•
The water / steam mixture from the top headers of the Evaporation module, flows behind the baffle chamber in the steam drum.
• In the steam drum, the steam/water mixture flows through the cyclones where water & steam are separated and saturated steam flows to the IP Superheater. Separated water mixes with boiler water to flow through the Evaporator modules again. Evaporator are of fully drainable type & drains (one for each downcomer) have been provided on the down comer header of the HRSG. These drains are connected to the IP drain header through two isolating valves. These drains essentially are for draining the Evaporation modules after shut down of HRSG. It is not to be operated when the HRSG is in service as their opening may interfere with the natural circulation in the modules. 3.2.5I P Superheat er Superheating of saturated steam from drum is done in IP Superheater , to control the temperature of final steam outlet at 313.7 °C. Superheaters are made of single module, it consists of a top header and a bottom header, with tubes between the headers. Superheater modules are hung from their top headers with provision for thermal expansion down wards & in the sides. IP Superheater IP Superheater Consists of 1 modules. Saturated steam from the drum flows to the module of superheater lower header through saturated steam supply pipes from the steam header. Steam travels up from both the ends of lower header of the module, through the module tubes to the top header of the same module, absorbing heat. There are Serrated tubes per row; 1 rows per module. The tubes are of size 38.1 O.D. x 2.6 Thk. and made of SA210 A1 material. The IP Superheater lower headers (Lowest point), are provided with manual drain valve GT 637
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Operation & Maintenance Manual
.The drains are operated through the electrically operated drain valve (M 076) and drain to the IP RSH drain header. 3.2.6I P Main Steam line The IP steam line connects the top header of IP Super-heater module to the plant steam main This line incorporates the following • Electrically Operated HP Steam Stop Valve M 064This valve Isolates the HRSG from the plant IP steam main. This valve is with an electrically operated valve which connects the IP main Steam to the Reheater 1. • Safety Valve PSV-062To take care of the pressure upset caused by sudden load cut, malfunctioning of firing system, closure of steam valves etc., a safety valve is provided on the main steam line at the Superheater outlet. This is a spring-loaded, valve set at 29.4 bar (a) pressure to protect the boiler against over pressures. The safety valve is similar to Drum safety valves PSV-060A & PSV-060B described earlier. The exhaust of the safety valve is piped to a silencer to reduce the noise levels when the safety valve is operating. The silencer is mounted on a separate structure on top of the HRSG. • Start Up Vent ValveValve PCV 063 is a pneumatically operated start up vent valve M 063 is a motor operated Isolating valve for start up vent. The outlet of the start up vent valve is exhausted to atmosphere through a silencer. The start up vent valve is to be kept open while start up. It provides initial steam flow for the cooling of superheater. • IP Steam Line DrainThe steam line drain consists of the following valves: Electrically operated motorised valve M 077 is normally closed connected in the drain line with an isolation valve GT 264 which is normally open. • IP Pressure Control valveA PCV 129 is provided for controlling the IP main steam pressure. The pressure controller PIC 129 receives a feed back signal from the Pressure transmitter PT 129A & B . • Air VentGL255 is manual air vent valves on the IP steam line, which may be used during hydro test. • Flow Nozzle FE 050BFlow nozzle FE- 050B is installed on the IP steam line before the main
Section B
stop valve to provide steam flow indication. The flow transmitter reading after steam pressure & temperature compensation is used for the following, 1. Steam flow reading. 2. Steam flow compensation for feed water flow • HP Steam Temperature InputTemperature transmitter TT- 130A & 130B (1out of 2) provide the IP steam temperature input for the following 1. Temperature compensation signal to steam flow. • HP Steam Pressure InputPressure transmitter PT- 129A & B (1out of 2) provide the HP steam temperature input for the following 1. Pressure compensation signal to steam flow. 2. Pressure High and Low Alarms for the remote indications. • A Cold reheat line is connected to the IP Main Steam line .The steam pass through the Reheater 1 for further heating the steam. 3.2.7Reheaters Superheated steam from the IP Superheater and the Cold reheat steam from the HP turbine exhaust is again Superheated in the Reheaters to control the temperature of final steam outlet at 567 ± 3°C (Hot reheat line to IP Superheater). Reheater are made of single module, it consists of a top header and a bottom header, with tubes between the headers. Reheater modules are hung from their top headers with provision for thermal expansion down wards & in the sides. Reheater 1 Reheater 1 Consists of 1 modules. Superheated steam from the IP Superheater and the Cold reheat steam from the HP turbine passes through the module of reheater upper header through steam supply pipes. Steam travels down from both the ends of upper header of the module through the module tubes to the top header of the same module, absorbing heat. There are Serrated tubes per row; 3 rows per module. The tubes are of size 44.5 O.D. x 3 Thk. and made of SA213 T22 material. The inlet line of the Reheater1 is provided with a temperature indicator TI 303. Attemporator
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Operation & Maintenance Manual
The function of the attemperator is to control the temperature of main steam at reheater 2 outlet to 567 ± 3°C. Water sprayed into steam from the reheater 1, drawing heat from the steam and completely mixes with steam. Attemperator is a header connecting from the bottom header of the module of Reheater 1 to the lower header of the module of reheater 2 . Spray nozzle is held across the header . The spray nozzle at the blind end rests on a guide to with stand the force of steam. Holes are drilled on the spray nozzle in the direction of steam flow. The spray water for the Attemperator is obtained from the IP Boiler Feed water main, before the flow transmitter FE 050A. The spray water line consists of the following: • A Solenoid operated Shut off valve TV 074. • A flow transmitter FE-073 to measure spray water flow and indicate on flow indicator FI-073. •
A Control station consists of the two Pneumatically operated flow control valve TCV-068A & TCV-068B (100 %). The flow control valve is provided with inlet/outlet isolating valves. Motorised inlet isolation valve M 068A & M 068B are provided before the control valves and manual outlet isolation valve GT 248 & GT 249 are provided and remain normally open. The drain valve GT246 are provided after the control valve TCV 068A and drain valves GT 247 are provided after the control valve TCV 068B, which remain normally closed. These drain valves are opened after closing inlet/outlet Isolating valves, when valve TCV 068A & B are to be taken for maintenance.
The spray water line connects to the spray nozzle of the attemporator through a non-return valve NRV 250. Temperature transmitter TE 068A & B provide steam temperature indication after the Reheater 2 to judge the effectiveness of attemperation. . The temperature transmitter TE- 068A &B (1 out of 2) indicate the high & low temperature alarm through TIC 068. A feed back signal from TIC 068 is provided to the controller HIC 068A & B which controls the pneumatically operated attemperation flow control valve TCV-068A & B to maintain the temperature as required. The Outlet line of the Reheater 1 before the attemperation consists of • The Temperature indicator TI 065. • The Pressure indicator PI 065.
Section B
• The temperature point TP 004. • A temperature Element TE 065 for high alarm . The Inlet line to the Reheater 2 after the attemperation consists of • A temperature Element TE 066 for high alarm . • The temperature point TP005. • The Pressure indicator PI 066. • The Temperature indicator TI 066. The Attemperator header is provided with manual drain valve GL 738 which is normally closed. The attemperator drain line is connected to reheater drain header through GT646 isolation valve which is normally open. Reheater 2 Reheater 2 does second stage of reheating of steam. Reheater 2 consists of one modules. The module following the burner/combustion chamber are constructed out of Serrated tubes .Each module consists of 3 rows of tubes. The Reheater 2 module tubes 44.5 O.D. x 3 Thk are made of SA213 T91 material. Steam after attemperation enters the lower header of the Reheater 2 module and rises to the top header of the same module with absorbing heat. and then to Hot reheat line. The Reheater 2 lower headers (Lowest point), are provided with three drains with two isolation valves . These drains valves GT 642, 2 no. are kept closed connected to the Reheater 2 drain header through NRV 643 to Blowdown tank.. The outlet line to Hot Reheat Line consists of • The temperature indicator TI 067. • The temperature transmitters TE 068A & B. • The pressure Indicator PI 069. • The Pressure transmitter PT 070 for low pressure alarm. • The flow transmitter FE 071 for flow measurement of the Hot reheat Steam.
3.3 LP Section Components Description 3.3.1Condensate Pre heater (CPH) A Condensate preheater (CPH) assembly is last module assembly in flue gas path to the stack from the boiler to recover economically feasible
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Operation & Maintenance Manual
heat from the flue gas before discharging to the atmosphere. The recovered heat increases the temperature of DM water entering the LP Drum/deaerator. Thus overall efficiency of the boiler is increased. The CPH modules consist of a top and bottom header of size 200 NB x SCH.100 and also 250 NB x SCH.80 and segmented finned tubes of size 38.1 O.D. x 2.6 Thk. The CPH assembly is fully drainable by the drain valve provided on the bottom header. The drain line is connected to the LP drain header. To expel air from the CPH during charging and while draining air Individual vent valves are provided on the each module and the common vent GT 609 is provided on the top header. DM Water from Client enters to CPH through a three-way temperature control valve TCV 102. This three-way control valve is to be throttled suitably to maintain LP drum/deaerator water outlet temperature. DM water I/L piping is provided with following: • Pressure control valve PCV 100 at CPH inlet is provided to delivered 15 bar pressure (at outlet of PCV 100) at inlet of three way control valve TCV 102. • Pressure transmitter PT 100 for indication /control of water pressure at the outlet of PCV 100.
The 3 way control valve (TCV- 102) Bypass line is provided with the NRV (NRV 313) and isolation valve GT 314. A recirculation line is provided parallel to the 3 way control valve (TCV- 102) Bypass line, the recirculation line is provided to controls the inlet temperature of the DM water entering the CPH module. The recirculation line consists of the following • Isolation valve GT 306. • Pressure transmitter PT 103 for remote indication of the pressure. • Pressure indicator PI 105 for local indication of the pressure. • Recirculation pump FW3-PP- 302 with a motor M 106. • A safety valve PSV 111 is provided in the discharge line of the recirculation pump. • Pressure indicator PI 110 for local indication of the pressure. • Flow element FT 107 is used to measure the flow of the recirculating water. • A control valve TCV 108 is provided in the discharge of the recirculation pump. • A NRV valve NRV 311. • An Isolation valve GT 312.
• Temperature Element TE 100 for remote temperature indication .
DM water O/L piping from CPH is provided with following:
• Pressure gauge PI 101 for local pressure indication.
• A Temperature indicator TI 049 after the tapping of the recirculation line.
• 3-way control valve TV 102 (Stack Temperature is fed to (TIC-102) where the process variable is compared with the local set point for generating the manipulated variable. Depending upon the set point three way control valve (TCV- 102) regulates the flow of DM water through bypass & CPH to control the outlet temperature.)
• A NRV 315 is provided in the discharge of the CPH.
• NRV valve NRV304 is provided in the inlet of the CPH inlet header.
• Temperature transmitter TE 132 A & B are provided for remote temperature low indication. A signal is fed to the feed regulating Controller HIC 080A.
• Temperature transmitter TT 108A & TT 108B are provided in the inlet of CPH. The signal is fed to the Recirculation pump discharge line control valve TCV 108 which regulates the control valve position accordingly to maintain the inlet temperature of DM water to CPH around 57°C. • Temperature Indicator TI 048 is provided before an isolation valve GT 305 and a NRV 328.
Section B
• An isolation valve GT327. • Pressure transmitter PT 131 A & B are provided for remote pressure low indication. A signal is fed to the feed regulating Controller HIC 080A.
• Flow element FE 104 is used to measure the flow of the CPH discharge line to the Dearetor /LP Drum.. • Level control regulating station is provided with the two control valves FCV 080A & B in parallel with a motorized isolation valve M-080A & B and manual isolation valve GT 322 & GT325
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Operation & Maintenance Manual
for LP Drum /deaerator level control . Both the control valves controller HIC 080A & HIC 080B are fed with the signal from the FIC 080. • A NRV 329 is provided after the control valve . 3.3.2LP Feed Regulatin g St ation When HRSG is in service, must be kept continuously supplied with DM water to maintain near normal level in the LP drum / Deareter . The HRSG trips if water level in the drum is either too low or too high. DM water is obtained from the client There are two feed control stations, out of which at least one must be in service when the HRSG is operational. LP Boiler Feedwater Regulating Station The feed water flow control station consists • 100 % capacity control valve [FCV 080A] • 100 % capacity control valve [FCV 080B] Both 100% control valve are provided with manual isolation valve at downstream of control valve [ GT322 & GT325]. The DM water flow control valve is a globe type valve, pneumatically actuated by a spring opposed diaphragm actuator and positioned by the DM water flow indicating controller [FIC-080] in order to maintain the normal water level at LP steam drum. The 100% flow control valve FCV 080A is capable of feeding the HRSG . FCV 080B is an identical stand by to FCV 080A is provided.
(elements) - drum level, feedwater flow & steam flow. The drum level is measured by using differential pressure type level-transmitter LT 080A, B & C installed on the LP steam drum. The measured signal is taken as the process variable (PV) to the drum level controller [FIC 080]. This process variable (PV) is compared with the fixed set point (SP) in the drum level indicating controller block and a control signal (CV) is generated. The level controller control output (CV) is added with steam flow signal from the main steam line in a feed forward block. This is done to achieve a better level control by taking corrective action in anticipation. The output of the feed forward block is used as a variable set point to the water flow-indicating controller [FIC 080]. This variable set point is compared to the actual feed water flow signal from [FE 104], which acts as the measured variable for the controller [FIC-080]. The control output signal (CV) from the controller [FIC-080] will position the feed water control valve through a current-pneumatic converter. Action of the control valve is air/ signal FAIL to OPEN. The valve position is transmitted. In remote, current drum level, steam flow, feed flow & the feed control valve position can be monitored. The three element control adopted for the 100% flow control valves FCV-080A takes into account the drum level, steam flow and feed water flow for positioning the control valve for its operation. 100% Feed Controller FCV-080B
The flow transmitters (FE104) provide feed flow signal to the feed Indicating controller FIC-080.
It is exactly similar to FCV-080A described above except for its valve tag numbers.
After the above, the common inlet line branches into two parallel paths, on which are installed the two feed regulating stations mentioned earlier to be connected to a common line for feeding water to the LP Drum /Deaerator. The feed regulating stations are now described.
The feed water control station is connected to the LP Steam Drum/ Deaerator through a feed water control station. 3.3.3LP Drum / Deaerator
100% Feed Controller FCV-080A Motorized operated valve M080A is the inlet-isolating valve. GT322 is the outlet-isolating valve, which are normally open. Drain valves GT321 normally remain closed and are opened for draining only when the line is isolated for inspection/maintenance of valve FCV-080A. Three-element feed water control system is provided to regulate the quantity of feedwater flowing into the LP drum to maintain the required water level in the LP steam drum. In three-element control, the drum level is controlled by the measurement of three process parameters
Section B
Figure 5
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Operation & Maintenance Manual
LP Drum/deaerator is Integral type of Dearator. The LP Drum is connected to the LP Evaporator. Condensate from CPH flows into LP Drum /deaerator. The level control valve FCV 080A & B control the deaerater level. LP Drum /deaerator in this boiler is L.P. integral type. Deaeration removes the corrosive gases such as dissolved oxygen and free carbon dioxide from the boiler feed water. This ensures protection of the feed water lines, steam lines, boiler tubes and other pressure parts of the boiler against corrosion and pitting, saves costly boiler re-tubing and expensive plant shutdowns. Further as the temperature of feed water/condensate is raised from 57 ° C temp. to LP Drum /deaerator operating temperature of 147°C and then fed to the LP Drum , the overall boiler thermal efficiency also increases. Deaeration is done by heating the feed water/condensate with steam. Vigorously scrubbing the water with this steam removes the last traces of dissolved O2 and brings down well below the recommended level in feed water. LP Drum /deaerator in which DM water/ condensate is heated to its boiling temperature at the operating pressure by steam. At boiling point all the dissolved gases such as Oxygen, Carbon Dioxide, etc. are liberated as solubility of gases decreases with increase in temperature. The mechanical scrubbing between water and heating steam ensures release of the dissolved gases. LP Drum /deaerator is of spray type, consists of a storage tank and a vapour tank. Water is sprayed from the top of the vapour tank by spray nozzles . Partial scrubbing of the steam and water takes place in the storage tank water and the rest is taking place in the vapour tank with the incoming water spray. Vapour tank is mounted upon the Deaeretor . Both the tanks are connected with steam connection Nozzle at the middle. This interconnection nozzle is flushed with inner wall of the vapour tank’s dished end and embedded inside the water level of storage tank to facilitate the feed water flow from vapour tank to the storage tank. Interconnection accommodates concentrically the steam balancing connection assembly. This steam connection is projected inside the vapour tank and masked from the water flow direction by a hood fitted at the top, thus facilitates the steam flow from Deaertor tank to vapour tank. DM water from CPH enters into the vapour tank through the topside nozzle to the distribution
Section B
header. Spray nozzles are fixed on the header to spray the water into fine particles covering the entire cross section of the tank so that easy and complete scrubbing with steam is possible. Perforated stainless steel trays at levels are placed inside the vapour tank to provide enough delay time to scrub the feed water with the upcoming steam. Feed water from vapour tank flows into the storage tank through the interconnection pipe. LP Drum /deaerator storage tank is a LP steam drum having downcomers & riser bank tubes . Feed water/condensate after spray at vapour tank enters to LP Drum /deaerator bank assembly. LP Drum /deaerator bank assembly consist of downcomer supply pipes, bottom & top headers interconnected with two modules of tube sheet & risers which supply steam to LP steam drum or storage tank. Feed water flows to bottom headers through down comer pipes and steam & water mixture rises up through LP boiler bank tubes & finally through rises to the L.P. drum. L.P. Drum is provided with perforated sheet as steam separator all risers ends inside this perforated plate box which separate moisture from steam this steam rises further & enters into vapour tank where it scrubs the incoming water & finally to atmosphere through vent condenser vent. Steam rises from the bottom of Storage Tank, heating the water and rises through the interconnection pipe into the Vapor Tank. Perforated Trays inside the Vapor tank increase the residence time of water and Heating Steam. Oxygen, Carbon dioxide and other dissolved gases are vented out along with vent steam through the vent nozzle. Vent pipe has a valve GL362 to throttle or restrict the flow of venting steam as required in addition to this a pressure control valve PCV 083 is also provided at vapour tank vent. The dissolved Oxygen level in the feed water by mechanical deaeration can be brought to 0.02 to 0.03 ppm. The residual dissolved Oxygen can be further scavenged by the reaction with chemicals such as Hydrazine . By chemical scavenging the dissolved Oxygen level can be brought down to as low as 0.007 ppm. Chemical is dosed in the storage section of the LP Drum /deaerator through a header, which is connected to the dosing system through a pipe with an isolation valve GT 361. The dosing of the particular chemical is done in predetermined quantity and concentration. A sample cooler provided in the feed water outlet piping is used to collect the sample for analysis of water.
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Operation & Maintenance Manual
Platforms and ladders are provided for tanks and condenser for O & M feasibility. The continuous blowdown line is connected to the storage tank through a valve GT630 and M 095 and Emergency Blowdown line is connected to the storage tank through a valve GT612 and M 094. The blowdown lines are connected to the BD Tank through NRV 613 & NRV 610 respectively. LP Drum /deaerator Accessories And The Mountings LP Drum /deaerator Level Control The desired normal water level (NWL) of the storage tank is maintained through a level control valve describe in the LP feed regulating Station. Level in the storage take is measured by the level transmitter LT 080A, B & C. A Feed back control loop with the level indicating controller LIC 080 is provided for automatic level control to the level control valve FCV 080A & B. Process variable signal for the level indicating controller is provided by the LT 080A, B & C. Set point of the level controller is to be kept at ’0’ mmWC, which corresponds to NWL. Level in the storage take is measured by the level transmitter LT 080A, B & C. A Feed back control loop with the level indicating controller LIC 080 is provided for automatic level control Process variable signal for the level indicating controller is provided by the LT 080A, B & C. It provides the high high & Low Low alarm signal for remote indication. Apart from the remote level indication direct level gauge ( LI 082A & LI 082B) is provided for the local indication. Pressure Control Flue gases leaving HP economiser I are led to the LP Evaporator where deaerated water is heated to 147°C depending upon the steam demand. The steam generated by the LP evaporator is used for deaerating the incoming plant condensate to rated temperature. A Pressure control valve PCV 083 mounted on the top of the vapour tank is used to control the LP Drum /deaerator pressure through pressure transmitter PT 083A & B. It also provide the high & Low Alarm for remote indication. Local pressure gauges PI-081A & B are also provided for LP Drum /deaerator pressure indication. Pressure Relief Valve
Section B
Two pressure relief valves (PSV 084A & PSV 084B) are mounted on the storage tank . Relief valve would relieve the steam when there is excessive pressure build-up inside the vessels (system) or deaerater incase of sudden reduction of water out flow/ intake to LP Drum /deaerator or malfunctioning of pressure control loop. Set pressures of the safety valves are 8 bar (a) & 9 bar (a). Silencers Exhaust of various safety valves, steam dump & startup valves are exhausted through Silencers. The Silencers are acoustically & mechanically designed to attenuate the large noise made during operation of these valves. The silencers are made out of suitable casing in which the sound absorbing materials are packed in a certain pattern & wrapped by scrim cloth and wire mesh to avoid ‘fly off’ of sound absorbing materials during operation of silencer at high flow rates. The process fluid enters the annular space between the sound absorbing materials packing where the sound energy is absorbed throughout the length of the silencer. The Silencers are mounted on separate structures on top of the HRSG and the exhaust pipes form the valves are connected to the silencers. As the silencer contain no moving parts, no operational care is needed except opening the drain plug provided in the drain line, once in three months to drain the line. Air vent Air vent GT 359 is provided on the vapor tank. Air vent is provided with a globe Valves and the Pressure relief valve PCV 083 . Through the air vent, Steam and dissolved gases are vent out to the atmosphere. Other Connections • A connection from CBD tank is provided to storage tank through a valve M 095 & an NRV 613. • A connection from EBD tank is provided to storage tank through a valve M 094 & an NRV 610. • Feed water outlet connection . Water inlet & outlet piping going to the boiler feed water pumps recirculation. • A Nozzle connected to a perforated pipe in the storage tank for chemical dosing connection.
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Operation & Maintenance Manual
• A Manhole is provided each for storage and vapour tank. • A N2 line is provided with a GT354 & NRV 355. • A perforated pipe has been laid along the length of the drum and connected to the LP dosing line through a non-return valve NRV360 and an isolating valve GT 361. LP dosing system is described in subsequent pages of this manual. 3.3.4LP Evaporat or The Evaporators convert hot boiler water received from the Drum through down comer pipes into a steam water mixture by absorption of heat from the Gas Turbine exhaust gas. The steam water mixture is led back to the drum from the evaporators through riser pipes. Evaporator consists of three modules. Each module consists of three rows of tubes arranged between a top and bottom header. The modules are hung from the top headers in the flue gas path, on two guide supports with provision for thermal expansion downward & in the sides. Serrated Evaporator tubes 38.1 O.D. x 2.6 Thk and material SA201 A1 are welded between the top & bottom headers 200 NB x SCH.120 and material SA 106 Gr .B of each module to form the heat absorption surface. Hot water flow to the evaporators from the drum and steam/water mixture flows to the drum from the Evaporators through risers. A down comer header of the Evaporator spans all the Evaporator modules. The down carrier pipes from the Drum connect to the down comer header. From the down comer header, interconnecting pipes connect to all the lower headers of the Evaporator modules. The top headers of the module are connected to the drum by riser tubes. The circulation through Evaporator modules takes place as follows: • Heated Boiler water from the drum flows through the down comer pipes to down comer header. • From the down comer header, the hot water flows to the lower headers and then through Evaporation module tubes to the Evaporation module top headers. During its passage through the Evaporation module tubes, the hot water absorbs heat from the exhaust gases of the gas turbine and gets converted to a water/steam mixture. This circulation is assisted by the higher density of water in the down comer compared to the lower density of
Section B
water / steam mixture in evaporator and riser tubes •
The water / steam mixture from the top headers of the Evaporation module, flows behind the baffle chamber in the LP steam drum.
•
In the LP steam drum, the steam/water mixture flows through the cyclones where water & steam are separated and saturated steam flows to the Superheaters. Separated water mixes with boiler water to flow through the Evaporator modules again.
Evaporator are of fullly drainable type & drains (one for each downcomer) have been provided on the down comer header of the HRSG. These drains are connected to the LP drain header through isolating valve. These drains essentially are for draining the Evaporation modules after shut down of HRSG. It is not to be operated when the HRSG is in service as their opening may interfere with the natural circulation in the modules. 3.3.5LP Superheater Superheating of saturated steam from LP drum is done in LP Superheater. The temperature of final steam outlet at 286.5 °C. Superheaters are made of single module, it consist of a top header and a bottom header, with tubes between the headers. Superheater modules are hung from their top headers with provision for thermal expansion down wards & in the sides. LP Superheater LP Superheater Consists of single module. Saturated steam from the drum flows to the module of LP superheater upper header through saturated steam supply pipes from the steam header. Steam travels up from both the ends of lower header of the first module, absorbing heat and travels down through the module tubes to lower header . There are Serrated tubes per row; 1rows per module;1 module in LP Superheater. The tubes are of size 38.1 O.D. x 2.6 Thk and made of SA201 A1 material. The LP Superheater lower headers (Lowest point), are provided with drain with isolation valves GT617 which is normally kept open. This drain is operated through the electrically operated drain valve (M 098) and drain to the IP Superheater drain header. The air vents & drains
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Operation & Maintenance Manual
are opened before light up of the boiler to drain LP Superheater. They are closed at a drum pressure of 2 To 5 Kg/cm².
• HP Steam Temperature InputTemperature transmitter TT- 090A & B provide the LP steam temperature input for the following
3.3.6LP Main Steam Line
1. Temperature compensation signal to steam flow
The LP steam line connects the bottom header of LP Super-heater module to the plant steam main
A temperature gauge TI 088 is provided for the local indication.
This line incorporates the following • Electrically Operated LP Steam Stop Valve M092AThis valve Isolates the HRSG from the plant LP steam main. This valve is provided with an electrically operated, integral by pass valve M092B. • Safety Valve PSV-085To take care of the pressure upset caused by sudden load cut, malfunctioning of firing system, closure of steam valves etc., a safety valve is provided on the main steam line at the Superheater outlet. This is a spring-loaded, valve set at 6.2 bar (a) pressure to protect the boiler against over pressures. The safety valve is similar to Drum safety valves PSV-084A & PSV-084B described earlier. The exhaust of the safety valve is piped to a silencer to reduce the noise levels when the safety valve is operating. The silencer is mounted on a separate structure on top of the HRSG. • Start Up Vent ValveValve PCV 091 is a pneumatically operated start up vent valve with a controller HIC-091. M 091 is a motor operated Isolating valve for start up vent. The outlet of the start up vent valve is exhausted to atmosphere through a silencer. The start up vent valve is to be kept open while start up. It provides initial steam flow for the cooling of superheaters. • HP Steam Line Drain The steam line drain consists of the following valves. Manually operated valve GT 371. The manually operated valve are kept open till the condensate is removed and once the condensate is removed it is close during normal operation of boiler. • Flow Nozzle FE 093Flow nozzle FE- 093 is installed on the LP steam line after the MSSV valve to provide steam flow indication. The flow transmitter reading, after steam pressure & temperature compensation is used for the following,
• HP Steam Pressure InputPressure transmitter PT- 089A & B (1out of 2) provide the LP steam temperature input for the following 1. Pressure Indicating controller PI-089A & B which provides LP steam Pressure High & low alarms . 2. Pressure compensation signal to steam flow A pressure Indicator PI 086 for local indication. • Air VentGT 374 are air vent valves on the LP steam line, which may be used during hydro test. • A connection to the SWAS is provided with a valve GT 376.
3.4 Operational Control This section explains the major operational control points described in this chapter. Steam Drum • Maintain Feed water, Boiler water quality, phosphate concentration •
Maintain water level in the drum within permissible low and high levels. The protection system envisages boiler trip at very high and very low levels, which should not be bypassed
•
Maintain drum level gauge glasses in good working condition. Operators may verify the readings of Level Transmitter with the readings of the drum level gauge glasses once a day
• For a cold HRSG start up, DM makeup water from boiler initial filling line at room temperature may be used to feed the HRSG by opening valves and the drain valves in Economizers and Evaporator. When water is filled up to low level in the drum, the drain valves and filling line valve are closed. After Boiler start, this line shall not be used and feeding is from the feed station.
1. Steam flow reading.
• Drain superheaters thoroughly during startup
2. Steam flow compensation for feed water flow
• Thermal StressesThermal Stresses In Drum During Start Up And Shut Down
Section B
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Operation & Maintenance Manual
Steam Drum is a large cylindrical shell. Before light up of a boiler, the inner and outer surfaces of the drum are at the same temperature. When boiler is lighted up, the inner surface gets heated up first by the water (and then by steam) and transmits heat to the outer surface of drum. The heat transfer is by conduction and is a bit slow. For short time after light up, there can be differences of temperature between steam and water surfaces of the drum. Such a difference can set up thermal stresses, which are not desirable and an alarm sounds at DCS. To minimize the thermal stresses, the operator must restrict the firing rate when starting the HRSG by modulating the divertor damper. Boiler water temperature rise rate must not be above 100°C per hour till operating pressure is reached. To monitor the skin metal temperature of the drum, instruments have been provided which may be checked during light ups. • Swelling During HRSG startup, as the Boiler water temperature reaches 90°C, there is a increase of water level caused by increase in the volume of hot water. Such swelling, if not controlled, can cause a High Level trip. To avoid this, initial filling is normally restricted to low level (say – 100 to 150 mm) and the smart Operator anticipates a swell and uses the EBD to drain and control the level. • Do not operate the HRSG with safety valves gagged. Passing safety valves must be attended during the next planned shut down. • EvaporatorsEvaporator module drains must not normally be opened after starting the HRSG. They must be verified for tight closure before pressurizing. • Super Heaters & Attemporator Super heaters must be drained after shut down and cooling of the boiler. They must also be kept open before a cold start up till 2 - 3 kg/cm2 of pressure is built up. During hot light ups they are opened for a few minutes Super heated steam temperatures at exit of HP primary Super Heater , HP secondary Super
Section B
Heater & main steam temperatures must be monitored to see there is no excessive heat pick up. Compare these figures with predicted performance values. High steam temperatures may mean high metal temperatures. • GeneralBoiler water can be drained after a shut down only after depressurizing to 2 kg/sq. cm and after cooling to 80 °C Draining of Boiler water must preferably be done through the blow down tank. If a tube failure is detected, it is advisable to plan for an early shut down. It may be possible to quickly repair the failed tube and return to service. If the shut down is in-ordinately delayed, there are possibilities of larger secondary damages, which may prolong the shut down, required for repairs. Manually operated valves must be closed hand tight only. Use of levers on hand wheels is not desired.
3.5 Water And Steam Quality Control And Monitoring Aim This chapter describes the standards for the boiler feed water and boiler water for corrosion and scale free operation of the HRSG and for obtaining pure steam. Methods of control of boiler water are also explained. Important Note This chapter must be read in conjunction with the following vendor manuals • HP/ IP /LP dosing system • Steam and Water analysis system Suggested quality of HP, IP & LP boiler feed water (and attemperator water) fed to the HRSG is given in following Table:
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Operation & Maintenance Manual
Parameter
Units
General Appearance
HP Section
IP Section
LP Section
Clear & Colourless
Clear & Colourless
Clear & Colourless
Total Hardness as CaCO3
ppm
Commercial zero
Commercial zero
Commercial zero
Total Fe
ppm
< 0.01
< 0.01
< 0.01
Total Cu
ppm
< 0.005
< 0.005
< 0.005
Oxygen
ppm
< 0.007
< 0.007
< 0.007
Oil & organics
ppm
Nil
Nil
Nil
9.3-9.5
8.5-9.5
8.5-9.5
ppm
< 0.1
< 0.1
< 0.1
Electrical Conductivity
µs/cm
< 0.2
< 0.2
< 0.2
Silica SiO2
ppm
< 0.02
< 0.02
<0.02
pH Total Dissolved solids
Note
• Alkaline levels of feed water minimizes corrosion of steel • Chlorides, Silica, Iron, Copper, Organic matter etc., present in the feed water concentrate further in Boiler water. Their higher concentration calls for increased blow down (CBD) of boiler water causing loss of useful heat • Silica in boiler water vaporizes to SiO2 and escapes through steam • Copper present in water, deposits on the inner surfaces of evaporator tubes and is harmful • Chlorides in boiler water depress the pH level and renders boiler water acidic and may cause accelerated corrosion • Oxygen in boiler water promotes corrosion of boiler tubes • Oil present in feed water deposit on tubes and interferes with heat transfer. Considering all these factors, maximum permissible values for contaminants in feed water have been suggested in Table
Section B
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Operation & Maintenance Manual
Following Table gives the Boiler Water Quality to be maintained in the Drum. Recommended Boiler Water Quality Parameter
Units
HP Section
IP Section
LP Section
Sodium Phosphate as PO4
ppm
16 –13
40 – 34
-
Alkalinity as CaCO3
ppm
< 10
< 60
Nil
9.7 — 10.2
10.8 – 11.4
–
pH Oil & Organic
ppm
Nil
Nil
Nil
Total dissolved solids
ppm
< 50
< 300
< 300
Silica as SiO2
ppm
< 0.9
< 21
< 60
Minor permissible contaminants present in the HRSG feed water concentrate to high levels in boiler water due to continuous evaporation in the steam drum - evaporator circuits. Two controls are exercised on Boiler water to avoid corrosion of HRSG tubes and the drum water - washed surfaces. The controls are: • Continuous blow control to restrict the contaminants to prescribed levels suggested for Boiler water Tri-sodium phosphate dozing to convert the hardness producing insoluble calcium, magnesium salts to soluble sodium salts which can be drained by CBD and to maintain the alkalinity levels of boiler water. The controls are described below.
3.6 Maintaining Quality Of Steam Good Quality steam is obtained if the following requirements are met: • Proper assembly of baffles, cyclone separators in the steam drum as per erection instructions (checked before commissioning of the Boiler) • Boiler feed water as per norms as suggested above. (Monitor the feed water conductivity & PH analysers) • Control of Boiler water quality as suggested above. • Monitor the saturation steam & main steam conductivity • Increase of saturation steam conductivity may be a warning for check of drum internals or maintaining high water levels in steam drum.
Section B
It should be understood that if the quality of Boiler feed water deteriorates, the steam quality is directly affected as the attemporator spray water is by boiler feed water. After several years of service, during a boiler over haul, the cyclones, baffles and demisters are checked for damage or erosion holes, which may bypass steam from the separation devices. Steam which bypasses the separation device, carry with it moisture & salt contaminants. Higher than permissible levels of Silica in boiler water will result in Silica carry over in steam. Operational Control • The water chemistry for determining low levels of impurities in water calls for special instruments, special analytical procedures and an experienced chemist. These should be available from the time of commissioning the boiler. • In a chemical process plant, inspite of the best available demineralization facilities the boiler feed water may occasionally get contaminated by return condensate from the system. A procedure to systematically check the return condensates (particularly for contamination by Fe, Chlorides and Oil) must be established and contaminated condensate must be discarded. • pH & Conductivity meters must be calibrated once a month. Phosphate dosing must continuous operation.
be
adjusted
for
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Operation & Maintenance Manual
4 4.1
Flue Gas System AI M
• A pressure transmitters PT 201 provides furnace pressure low alarm for remote indications.
This chapter describes the Gas Turbine exhaust flow through the HRSG, insulation and casing of HRSG and the Stack.
• A temperature indicator TI 202 is provided for the temperature and pressure indicator PI 203 for pressure measurement before HP Superheater.
4.2 Detailed Description
• Four Pressure points (PP001A -PP001D) & Temperature points (TP 001A- 001D ) are provided.
The steam drum & HRSG pressure part modules are supported on column structures. The entire HRSG is enclosed in a gas tight casing and ducting enclosing the modules to provide a gas tight passage for the exhaust gas from the gas turbine. The casing is properly stiffened to enhance the rigidity of the ducting and casing. The HRSG design incorporates cold casing concept. The modules are covered fully with SS & CS sheet casing on all four sides, with appropriate openings for penetration of feed water lines, interconnecting pipes, steam lines etc. All these penetrations are suitably protected by expansion bellows to maintain a gas tight passage. Specially designed studs hold the Ceramic/Min wool insulation material tightly to the ducting. The overlapping design of the insulation liners covering the insulation minimises penetration of flue gases into the insulation material. The liners prevent erosion & loss of Ceramic/Min wool fibre material. This system permits the outer casing to be at a very low temperature thus minimising the thermal expansion of the casing & thermal loads on GTG flange. Exhaust gas from the gas turbine enters the HRSG through an expansion bellow. HRSG, which receives highly turbulent gases from gas turbines, gets affected drastically by gas mal-distribution. A careful design of included angle of transition ducting has been done for producing predictable HRSG performance & avoiding overheating of tubes. TBW carries out computer simulation of the gas flow distribution to decide the design of included angle of transition ducting . Operation of the HRSG on the turbine exhaust gas (TEG) only is termed as ‘unfired mode’ of operation. Following instrumentation is provided in flue gas path of the HRSG on gas tight casing for various indication & controls:
• The drain to the casing is provided with an isolation valve GT 161. Temperature and Pressure Indication Before HP Superheater 1 • For Local indication Pressure indicator PI-205 and temperature indicator TI-204. • Temperature indication TE –206A & B is provided before HP Superheater 1 to measure heat pickup in HP Superheater 2 & 3 and Reheater , to check for fouling in HP superheater modules. • Four pressure points (PP002A-PP002D) & Four temperature points (TP002A-TP002D) are provided . After HP Evaporator • For Local indication Pressure indicator PI-207 and temperature indicator TI-208A. • Two Temperature transmitters (TE-209A & B) provides temperature high & low indication for remote indications. • Four pressure points (PP003A-PP003D) & Four temperature points (TP003A-TP003D) are provided . After HP Economiser 3 • Local pressure gauge PI- 210 & temperature indicator TI211A. • Temperature Indicator TE – 212A & B provides temperature high & low indication for remote indications • Four pressure points (PP004A-PP004D) & Four temperature points (TP004A-TP004D) are provided . After IP Economiser
Before HP Superheater
• Local pressure gauge PI- 213 & temperature indicator TI214.
• Eight temperature transmitters (TE-200 A, B, C, D, E, F, G & H) provides furnace temperature low & high for remote indications.
• Temperature Indicator TE – 215A & B provides temperature high & low indication for remote indications
Section B
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Operation & Maintenance Manual
• Four pressure points (PP005A-PP005D) & Four temperature points (TP005A-TP005D) are provided . After LP Evaporator • Temperature Indicator TE – 216A & B provides temperature high & low indication for remote indications • Local pressure gauge PI- 217 & temperature indicator TI218A. After Condensate preheater • Six Temperature Element TE – 222 A, B, C, D, E & F for the low and high remote indications. • Local pressure gauge PI- 219 and Temperature indicator TI 220A. • Four pressure points (PP007A-PP007D) & Four temperature points (TP007A-TP007D) are provided . • A pressure transmitter PT 221 for remote indication of the flue gas Stack inlet pressure. • A provision for installation of sampling probes for measurement of O2 (AT 226) is provided. • A drain is provided with an isolation valve GT162. Stack (Chimney) The Turbine exhaust gas after CPH is exhausted through the Stack. Stack is a hollow structur e.
The inlet Flue gas connection from the HRSG to the Stack is through expansion bellows to contain the thermal expansion of the HRSG ducts form the Stack. A temperature element TE 227A & B provides the low and high remote temperature indication. A Motorized Damper M 228 is provided on the stack . A drain is provided at the bottom of the Stack with an isolation valve GT160. Operational Control • The anticipated figures both steam / water and gas side has been given in following section. The operator shall familiarise himself with these figures. Elaborate instrumentation has been provided to measure each of these factors. Alarms also have been provided to alert the operator in case of deviations for several of these readings • Operator attention is needed particularly for the following – Turbine Exhaust Gas (TEG) inlet pressure and temperature – Gas side pressure and temperature drop, Steam/Water side heat pick up across pressure parts like ♦ HP Superheater 3, 2 & 1
Stack is supported on concrete foundations on a circular frame fabricated. Stack has a manhole access at the lower end for inspection.
♦ Reheater 1 & 2
Aviation warning lights are fitted at top elevations on the stack. Provision for installation of sampling probes for measurement of SOx ,CO & NOx (AT 225,AT 224 & AT 223), is provided at suitable elevation on the Stack. There are platforms providing access to the aviation lights, sample probes and ease of repainting the Stack. Platforms are accessible from the ground by ladders. On the top side of the Stack, helical wind-breakers are built around the outer shell, to provide stability to the Stack against wind forces.
♦ HP & IP Economisers
Section B
♦ HP , IP & LP Evaporator Modules
♦ Condensate Preheater
Evaluating these figures the operator should decide to check during shut down., • Levels of CO, NOx, & SOx emissions must be monitored and any abnormalities must be reported to the shift in-charge. • Healthiness of aviation warning lamps is to be check periodically.
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Operation & Maintenance Manual
5
D r ai n & Do si n g Sy st e m
Boiler Blowdown System Aim This chapter describes the HRSG blow down system for safe draining of high pressure / High temperature steam and water from the boiler using the blow down tanks System Description The P & I Diagram of drains & vents shows the various drains & vents from the HRSG, HP , IP & LP steam line, HP , IP & LP steam drum, HP , IP & LP saturated & superheated drain header.
Section B
Large quantities of steam or high pressure/temperature water are not to be drained through open canals for the following reasons: • Such draining will cause splashing of higher volumes of steam which can be a nuisance by the noise it creates and also it affects the visibility around the draining area • High temperature of these drains can cause scalding injures to workmen if they come into contact with it • The force and temperature of these drains will erode the linings of the drain canals Table below is a summary of such drains.
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Operation & Maintenance Manual
High Pressure / High Temperature Steam And Water Drains SL. No
1
2
Source
Continuous blow down
Emergency blow down
Sections
Valve Nos
Temp of drain °C
HP Drum
GT 674 , M 040
Up to 310°C
IP Drum
GT 631 , M 079
Up to 217°C
LP Drum
GT 630 , M 095
Up to 145°C
HP Drum
GT 675 , M 039 A &B
Up to 310°C
IP Drum
GT 628 , M 078
Up to 217°C
LP Drum
GT 612 , M 094
Up to 145°C
3
HP SH Drain header
GT 688 , NRV 689
Varying from 100°C to 567°C
4
Reheater Drain header
GT 650 , NRV 649
Varying from 100°C to 567°C
RHS 5
HP Drain Header
GT 669 , NRV 670 LHS RHS
6
IP Drain header
LP Drain header
LHS
LHS
Varying from 100°C to 310°C
GT 622 , NRV 623 GT 624 , NRV 625
RHS 7
GT 695 , NRV 697
Continuous, quantity depending on quality of boiler water Occasional during high levels in drum, during start up. Draining HPsuper-heaters during initial startup & after a shut down. Draining Reheater during initial startup & after a shut down. Draining of HP Evaporator & HP Economiser modules after shutdown
Varying from 60°C to 217°C
Draining of IP Evaporator & IP Economiser modules after shutdown
Varying from 60°C to 145°C
Draining of CPH & LP Evaporator modules after a shut down
GT 605 , NRV 606 GT 607 , NRV 608
Frequency of usage
The drains indicated in above table are connected to the continuous & intermediate blow down tank. The blow down tank is capable of separating steam from the drain water. The drains are connected tangentially in the upper half of the drum to direct the drain fluid circumferential around the inner wall of the tank, to aid separation of steam and water by their differences in densities.
CBD control involves the following operations
Other Drains
•
Positioning the CBD valve is to be decided depending on the sample analysis.
•
Repeating the sampling, analysis and repositioning the CBD valve after certain interval is necessary to maintain the required Boiler water quality. This system of manual control requires the services of a sampler, a chemist and a laboratory round the clock. The arrangement provided for CBD control is: A perforated pipe, laid along the water space in
It can be seen that drains have been provided in the feed water line and the attemperator spray water lines connected to the drain canal. As these drains are either for operation to drain these lines after an isolation or for short time during charging, Their connections to the open canal is not expected to pose a problem. Continuous Blow Down Control (CBD)
Section B
• Obtaining a sample of boiler water from the steam drum. • Analyzing the sample for conductivity, hardness, NaCl, Silica, Fe, etc. and working out a rate of draining of boiler water to maintain the concentrations as suggested in Table Boiler water.
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Operation & Maintenance Manual
the steam drum connects through a stub to the continuous blow down line. •
CBD line from drum connects to the blow down tank.
•
A tap off from the CBD line is taken to the sample cooler for continuous analysis of boiler water conductivity and also for a grab sample.
Sampling of CBD / Boiler water is done in SWAS at customer end. This package provides analysis of the following samples to provide a comprehensive information of quality of steam and water of HRSG.
Blowdown tank (BD Tank) BD Tank is provided with the following • A Level gauge LI 096 • A vent is provided. • An Over flow connection is provided which is connected at the Drain line through a valve GT708. • After the drain valve GT 708 the Quenching water arrangement is provided . • A temperature Element TE 096A & B are in the Drain line after the Quenching arrangement.
• Samples of main steam from HP , IP & LP header of HRSG.
The Quenching water line consists of the following
• Samples of boiler water (CBD) from the HP , IP & LP steam drum of HRSG.
• A Flow transmitter FE 097 for the measurement of the quenching water in the Blow down tank.
• Samples of HP , IP & LP feed water.
• A control valve TCV 096 with a inlet and outlet isolation valve GT 704 (2 nos.) and a bypass line with a valve GT 706.
While all the samples above are analysed for conductivity by separate analysers, the CBD sample and the feed water samples are analysed in addition for pH also. CBD valve is normally kept open to maintain small continuous flow of boiler water to the blow down tank. This is required to ensure the sample at any time to the SWAS is truly representative of the sample being analysed. This continuous flow also ensures that these lines do not get choked for want of adequate flow.
The feed back from the TE 096 A & B to the the controller TIC 096 controls the TCV 096 Operation . HP Dosing
CE & pHE are the conductivity and pH analysers installed on the sample line. The specific requirements of the analyzers are that the pressure and temperature of the sample must be rigidly controlled within permissive values (see vendor manual). The Analysers are to be maintained as per vendor instruction. Emergency Blow Down Control (EBD) EBD control involves the following operations During Startup of the boiler the Drum level which is maintained at NWL suddenly rises due the swelling of the drum water. In such case when there is an emergency condition an EBD connection from the Drum is provided. EBD connection is provided with an isolating valve and an motorised valve . The isolating valve is kept open and the motorised valve controls the Drum level . The EBD connection is connected to the Blowdown tank.
Section B
Figure 6
Tri-sodium phosphate dosing to Boiler water to maintain its phosphate content at 8 to 10 PPM. The tri-sodium phosphate at the suggested levels, maintains the alkalinity of the boiler water (pH 10 to 11) and also converts the harmful, insoluble calcium and magnesium salts which forms the residual hardness of boiler water, to being soluble, sodium salts, in the form of a soft sludge, to be drained by the CBD. Phosphate dosing prevents corrosion of the water washed parts of the steam drum and the evaporator tubes. Adjusting the speed or the stroke of the pump provided as described below can control quantity of dosing. Excess as well as reduced phosphate levels in
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Operation & Maintenance Manual
Boiler water should be avoided. (The phosphate dosing is also some times called as "HP dosing" as the pump used develops high pressure to dose against the boiler drum pressure).
type. The stroke of the plunger can be altered. The vendor manual of the pump and gearbox is to be referred for full information on construction and parts detail.
The equipment provided for phosphate dosing ("HP dosing") as shown in P & I diagram consists of:
Each pump is connected to a common discharge line with the following valve arrangement:
• A 600 liter mixing tank for preparation of 5% tri-sodium solution. • Two dosing pumps. •
DM Water source for preparation of the phosphate solution as well as for flushing.
Mixing Tank The Mixing tank is a carbon steel with rubber lining covered cylindrical vessel of 600 litres capacity with a level indicating gauge glass LI-122, DM water inlet line (with a manual isolating valve) BL 561, a tank drain line with a manual isolating valve BL 565, a basket for placing required quantity of tri-sodium phosphate powder for preparation of the solution. A solution inlet connection to the pumps with a manual isolating valves BL 567, BL 568. A motor operated stirrer M 120 is also fitted for preparation of chemical solutions. The level of the mixing tank is monitored by level gauge (LI-122). Availability of a minimum level is a pre-requisite for starting or continued service of a dosing pump. Preparation of 5% Phosphate Solution in The Tank • Tank drain valve BL 565 is closed. • Gauge glass inlet cocks are opened and its drain is closed. • The lid of the tank is opened, and a calculated quantity of phosphate to prepare 600 liters of solution is placed in the basket and lid closed.
• An inlet valve with a "Y" type strainer at the pump inlet. Y strainer traps dirt or other solid particles in its basket. The Y strainer is to be cleaned once a month, after stopping the pump and closing its inlet and outlet isolating valves. • On the discharge side of the pump, a pressure gauge PI-120A & B and an outlet-isolating valve BL 577 & BL 578 is fitted before the common discharge line. A safety relief valve PSV 120A & B has also been fitted on the discharge line to relieve any over pressures in case of closure of valves on the discharge line. The outlet of the relief valve is returned to the mixing tank. The relief valve must be tested for its operation at the set pressure at least once a year. The pump must not be operated with the relief valve continuously operating (cause of relief valve operation must be found and rectified). The common discharge line is connected to the HP dosing line of the steam drum through an NRV 053 and an isolating valve GT 052. The isolating valve is verified open before boiler light up and normally remains open all the time. Phosphate dosing is through a perforated pipe along the full length of the water space in the drum. Availability of a minimum level in the mixing tank is a pre condition for starting or running of the dosing pumps. Out of the two pumps, one pump is selected for service and the other is in reserve (DCS macro, Local module). The pumps are interlocked such that when a working pump trips, the reserve pump starts automatically
• The water inlet valve (BL 561) is opened to admit water (from the DM water line). The level gauge is watched and when the level in the tank is nearly full, the water inlet valve is closed.
A phosphate pump is placed immediately in service after the HRSG start up in the following manner:
• The stirrer is placed in service for 30 minutes by operating its switch in the local module. Availability of a minimum level is a precondition for starting and running of the stirrer.
• The pump is prepared by opening the outlet valve from the mixing tank, opening the inlet and the two outlet valves of the pump. Two minutes are allowed after opening the inlet valve for the pump to get filled with phosphate solution. The pump is started by switching on the motor. The pressure gauge is observed. It should show a reading, higher than the steam drum pressure. An accumulator on the pump discharge line dampens the pulsations which
Phosphate Dosing Pumps Two phosphate dosing pumps have been provided, out of which one is for service at a time and the other is a standby. The pumps are plunger operated reciprocating, positive displacement
Section B
• Boiler water sample is analyzed and phosphate content is determined.
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Operation & Maintenance Manual
otherwise would be there as this is a positive displacement reciprocating pump. Any abnormal noise from the pump, motor or gearbox is noted. The safety relief valve should not also be operating. If there are no abnormalities the pump is allowed to run. Every four hours, the phosphate content in the boiler water is checked by laboratory sample analysis and also by the pH meter. The pump speed stroke is increased or decreased to maintain the phosphate content within 8 to 10 PPM by continuous pump operation. The phosphate solution level is observed in the mixing tank by the gauge glass. If the level falls to 25% of the gauge glass level, additional solution is prepared as stated above. Flushing the phosphate pump and the lines with water during long stoppage of the HRSG: If the HRSG is to be stopped for more than a few days for servicing or maintenance, the phosphate pumps and the line are flushed with water to keep them clean. IP Dosing Tri-sodium phosphate dosing to Boiler water to maintain its phosphate content at 30 to 35 PPM. The tri-sodium phosphate at the suggested levels, maintains the alkalinity of the boiler water (pH 10 to 11) and also converts the harmful, insoluble calcium and magnesium salts which forms the residual hardness of boiler water, to being soluble, sodium salts, in the form of a soft sludge, to be drained by the CBD. Phosphate dosing prevents corrosion of the water washed parts of the steam drum and the evaporator tubes. Adjusting the speed or the stroke of the pump provided as described below can control quantity of dosing. Excess as well as reduced phosphate levels in Boiler water should be avoided. (The phosphate dosing is also some times called as "IP dosing" as the pump used develops high pressure to dose against the boiler drum pressure). The equipment provided for phosphate dosing ("IP dosing") as shown in P & I diagram consists of: • A 300 liter mixing tank for preparation of 5% tri-sodium solution. • Two dosing pumps. •
DM Water source for preparation of the phosphate solution as well as for flushing.
Mixing Tank
Section B
The Mixing tank is a carbon steel with rubber lining covered cylindrical vessel of 300 liters capacity with a level indicating gauge glass LI-125, DM water inlet line (with a manual isolating valve) BL 531, a tank drain line with a manual isolating valve BL 535, a basket for placing required quantity of tri-sodium phosphate powder for preparation of the solution. A solution inlet connection to the pumps with a manual isolating valves BL 537, BL 538. A motor operated stirrer M 123 is also fitted for preparation of chemical solutions. The level of the mixing tank is monitored by level gauge (LI-125). Availability of a minimum level is a pre-requisite for starting or continued service of a dosing pump. Preparation of 5% Phosphate Solution In The Tank • Tank drain valve BL 535 is closed. • Gauge glass inlet cocks are opened and its drain is closed. • The lid of the tank is opened, and a calculated quantity of phosphate to prepare 300 liters of solution is placed in the basket and lid closed. • The water inlet valve (BL 531) is opened to admit water (from the DM water line). The level gauge is watched and when the level in the tank is nearly full, the water inlet valve is closed. • The stirrer is placed in service for 30 minutes by operating its switch in the local module. Availability of a minimum level is a precondition for starting and running of the stirrer. Phosphate Dosing Pumps Two phosphate dosing pumps have been provided, out of which one is for service at a time, and the other is a standby. The pumps are plunger operated reciprocating, positive displacement type. The stroke of the plunger can be altered. The vendor manual of the pump and gearbox is to be referred for full information on construction and parts detail. Each pump is connected to a common discharge line with the following valve arrangement: • An inlet valve with a "Y" type strainer at the pump inlet. Y strainer traps dirt or other solid particles in its basket. The Y strainer is to be cleaned once a month, after stopping the pump and closing its inlet and outlet isolating valves. • On the discharge side of the pump, a pressure gauge PI-123A & B and an outlet-isolating
49
Operation & Maintenance Manual
valve BL 547 & BL 548 is fitted before the common discharge line. A safety relief valve PSV 123A & B has also been fitted on the discharge line to relieve any over pressures in case of closure of valves on the discharge line. The outlet of the relief valve is returned to the mixing tank. The relief valve must be tested for its operation at the set pressure at least once a year. The pump must not be operated with the relief valve continuously operating (cause of relief valve operation must be found and rectified). The common discharge line is connected to the HP dosing line of the steam drum through an NRV 256 and an isolating valve GT 257. The isolating valve is verified open before boiler light up and normally remains open all the time. Phosphate dosing is through a perforated pipe along the full length of the water space in the drum. Availability of a minimum level in the mixing tank is a pre condition for starting or running of the dosing pumps. Out of the two pumps, one pump is selected for service and the other is in reserve (DCS macro, Local module). The pumps are interlocked such that when a working pump trips, the reserve pump starts automatically A phosphate pump is placed immediately in service after the HRSG start up in the following manner: • Boiler water sample is analyzed and phosphate content is determined. • The pump is prepared by opening the outlet valve from the mixing tank, opening the inlet and the two outlet valves of the pump. Two minutes are allowed after opening the inlet valve for the pump to get filled with phosphate solution. The pump is started by switching on the motor. The pressure gauge is observed. It should show a reading, higher than the steam drum pressure. An accumulator on the pump discharge line dampens the pulsations which otherwise would be there as this is a positive displacement reciprocating pump. Any abnormal noise from the pump, motor or gearbox is noted. The safety relief valve should not also be operating. If there are no abnormalities the pump is allowed to run. Every four hours, the phosphate content in the boiler water is checked by laboratory sample analysis and also by the pH meter. The pump speed stroke is increased or decreased to maintain the phosphate content within 30 to 35 PPM by continuous pump operation.
Section B
The phosphate solution level is observed in the mixing tank by the gauge glass. If the level falls to 25% of the gauge glass level, additional solution is prepared as stated above. Flushing the phosphate pump and the lines with water during long stoppage of the HRSG: If the HRSG is to be stopped for more than a few days for servicing or maintenance, the phosphate pumps and the line are flushed with water to keep them clean. LP dosing Hydrazine is dosed to Boiler water to maintain the Dissolved O2 to 0.007 ppm. The Hydrazine at the suggested levels, maintains the alkalinity of the boiler water in Dearator and thus chemical deaeration is done in the deaerator. Adjusting the speed or the stroke of the pump provided as described below can control quantity of dosing. Excess as well as reduced Hydrazine in Boiler water should be avoided. (The dosing is also some times called as "LP dosing" as the pump used develops high pressure to dose against the boiler drum pressure). The equipment provided for Hydrazine dosing ("LP dosing") as shown in P & I diagram consists of: • A 600 liter mixing tank for preparation of 2.5% Hydrazine solution. • •
Two dosing pumps. DM Water for preparation of the Hydrazine solution as well as for flushing.
LP Mixing Tank The Mixing tank is a carbon steel with rubber lining covered cylindrical vessel of 600 liters capacity; with a level indicating gauge glass LI 128. A DM water inlet line (with a manual isolating valve) BL 501, a tank drain line with a manual isolating valve BL 505, a basket for placing required quantity of Hydrazine for preparation of the solution. A solution inlet connection to the pumps with a manual isolating valves BL 507 & BL 508 .A motor operated stirrer M 126 is also fitted for preparation of chemical solutions. The level of the mixing tank is monitored by level gauge (LI 128). Availability of a minimum level is a pre-requisite for starting or continued service of a dosing pump. Preparation of 2.5 % Hydrazine Solution in the LP Tank • Tank drain valve BL 505 is closed.
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Operation & Maintenance Manual
• Gauge glass inlet cocks are opened and its drain is closed.
through a perforated pipe along the full length of the water space in the drum.
• The lid of the tank is opened, and a calculated quantity of Hydrazine to prepare 600 liters of solution is placed in the basket and lid closed.
Availability of a minimum level in the mixing tank is a pre condition for starting or running of the dosing pumps. Out of the two pumps, one pump is selected for service and the other is in reserve (DCS macro, Local panel). The pumps are interlocked such that when a working pump trips, the reserve pump starts automatically.
• The water inlet valve (BL 501) is opened to admit water (from the DM water line). The level gauge is watched and when the level in the tank is nearly full, the water inlet valve is closed. • The stirrer is placed in service for 30 minutes by operating its switch in the local panel. Availability of a minimum level is a precondition for starting and running of the stirrer. Hydrazine LP Dosing Pumps Two Hydrazine dosing pumps, M- 126A & B have been provided, out of which one is for service at a time, and the other is a standby. The pumps are plunger operated reciprocating, positive displacement type. The stroke of the plunger can be altered. The motor is provided with a variable frequency drive through a gearbox for continuous speed control. The vendor manual of the pump and gearbox is to be referred for full information on construction and parts detail. Each pump is connected to a common discharge line with the following valve arrangement
A Hydrazine pump is placed immediately in service after the HRSG start up in the following manner: • The pump is prepared by opening the outlet valve from the mixing tank, opening the inlet and the two outlet valves of the pump. Two minutes are allowed after opening the inlet valve for the pump to get filled with Hydrazine solution. The pump is started by switching on the motor. The pressure gauge is observed. It should show a reading, higher than the steam drum pressure. An accumulator on the pump discharge line dampens the pulsations which otherwise would be there as this is a positive displacement reciprocating pump. Any abnormal noise from the pump, motor or gearbox is noted. The safety relief valve should not also be operating. If there are no abnormalities the pump is allowed to run.
• An inlet valve BL 507 & BL 508 with a "Y" strainer at the pump inlet. Y strainer traps dirt or other solid particles in its basket. The Y strainer is to be cleaned once a month, after stopping the pump and closing its inlet and outlet isolating valves.
The Hydrazinesolution level is observed in the mixing tank by the gauge glass. If the level falls to 25% of the gauge glass level, additional solution is prepared as stated above.
• On the discharge side of the pump, a pressure gauge PI-126A & B and an outlet-isolating valve BL517 & BL 518 is fitted before the common discharge line. A safety relief valve PSV 126A & B has also been fitted on the discharge line to relieve any over pressures in case of closure of valves on the discharge line. The outlet of the relief valve is returned to the mixing tank. The relief valve must be tested for its operation at the set pressure at least once a year. The pump must not be operated with the relief valve continuously operating (cause of relief valve operation must be found and rectified).
If the HRSG is to be stopped for more than a few days for servicing or maintenance, the Hydrazine pumps and the line are flushed with water to keep them clean.
The common discharge line is connected to the LP dosing line of the steam drum through an NRV 360 and an isolating valve GT 361. The isolating valve is verified open before boiler light up and normally remains open all the time. Hydrazine dosing is
Section B
Flushing the hydrazine pump and the lines with water during long stoppage of the HRSG:
6
HRSG System Protection
Aim This chapter lists out various protections and interlocks provided in the HRSG. As the system protections and interlocks have been described in the preceding chapters along with the description of equipment, a listing of these protections will only be made with brief notes on their significance. Testing of these interlocks & protections is to be done before the first start up of HRSG and at suitable intervals subsequently.
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Operation & Maintenance Manual
Protections Among various protections provided, ESD guides the operator in preparing the HRSG in an orderly manner to ensure availability of all essential inputs before starting the HRSG and monitoring their availability all the time when the HRSG is in service. The boiler protections are implemented through the emergency shut down (ESD) logics.
Any of the following conditions cause tripping of the HRSG • HP Drum level very Low • HP Steam outlet pressure very High • IP Drum level very Low • LP Drum level very Low • GT Exhaust gas Pressure high
Heat input to HRSG is from:
Operational Control
• Gas turbine exhaust gas which can be controlled by GT operation at Different operating mode (viz FSNL , Spinning Reserve , Full Load).
The interlocks are to be tested before commissioning. Repeat tests are advised once a year. Any malfunction noted during operation has to be attended early.
Section B
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Operation & Maintenance Manual
7
Au t o m at i c Co nt r o l s
Aim To describe the automatic controls provided for operation of the HRSG.
7.1 Drum Level Control HP Drum Level Control The aim of this control loop is to maintain the drum Level at the normal operating level in drum. Two modes of operation are provided for drum level control. Single element & Three element drum level control system is envisaged to regulate the quantity of feed water flowing into the drum to maintain required water level in the drum, Single-element drum level control for low loads and Three-elements drum level control for normal & high load. 31HFW FS-003A is mode selector switch which changes single element control to three elements control and three elements control to single element control. If steam flow increases beyond 85 TPH(30%) then control will change to three elements control.
controller 31HFWFIC003A. The feed water flow signal is compared with the remote set point in the feed water flow indicating controller & output of feed water flow controller 31HFWFIC003A is given to feed water flow control valve 31HFWFCV003BJYPA & 31HFWFCV003CJYPA through manual loader 31HFWHIC003B & 31HFWHIC003C respectively, output signal is inverted due to control valve air fail action is open. Control action of the feed water flow controller 31HFWFIC003A & Drum level controller 31HPD LIC003B is Reverse. The drum level measured by DP (Differential Pressure) type level transmitters 31HPDLT003A, 31HPDLT003B, 31HPDLT003C & measured drum level is compensated (density) in function block 31HPDLY003A, 31HPDLY003B & 31HPDLY003C with median drum pressure. The drum pressure is measured by pressure transmitter 31HPDPT003A, 31HPDPT003B, 31HPDPT003C & measured drum pressure are PV for function block 31HPDPY003 (Median block). The compensated drum level values are the PV for function block 31HPDLY003 (Median block).The median drum level is PV to drum level controllers 31HPDLIC003A and 31HPDLIC003B.
If steam flow decreases below 70 TPH(25%) then control will change to single element control.
The Drum level transmitter is calibrated for - 1000 to 0 mmWC and correspondence indication shall 0 to 100 %.
Single Element Drum Level ControlIn single element only Drum level is the reference level to control the feed water flow.
The Drum pressure transmitter is calibrated for 0 to 140 Kg/Cm2 (g) and correspondence indication shall 0 – 140 Kg/Cm2 (g).
The drum level signal is compared with the fixed set point in the drum level-indicating controller & output of drum level controller 31HPD LIC003A is given to feed water flow control valve 31HFWFCV003AJYPA. Output signal is inverted due to control valve air fail action is open. Control action of the Drum level controller 31HPD LIC003A is Reverse.
Drum level density compensation
Three Element Drum Level Control In Three elements Drum level, Water flow and Steam flow are the references to control the water flow. Drum level as primary element, Feed water flow as secondary element and steam flow as third element (feed forward). In three - element control the drum level signal is compared with the fixed set point (+25mmWC) in the drum level indicating controller 31HPDLIC003B. To achieve, better drum level control, a feed forward action is added to in the form of steam flow in function block 31HPSFX003A. The feed forward output use as a remote set point to feed water flow indicating
Section B
Computing block 31HPD LY003A, 31HPD LY003B & 31HPD LY003C shall be configured to Pressure compensated /corrected drum level indication can be obtained from equation below Where ‘Hm’ is the corrected level indication. Hm = {Delta p + H (Da - Ds)} / (Dw - Ds ) Where: DP = differential pressure measured by level transmitter (DPT). [The range of DP in above equation is also to be taken as (– 100 to 0 cmWC)] Hm – Compensated drum level signal. Dw – Density of water (To be taken from the enclosed table) Ds – Density of Steam (To be taken from the enclosed table) H — Water head on LP side, wet head leg which is to be feed as constant = 100
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Operation & Maintenance Manual
Da – Wet leg density; water Density at 30 Deg.C. (Constant =0.996). Head on HP = Hm *Dw + (H-Hm)*Ds Head on LP = H *Da
Computing block 31HPSFY003A, 31HPSFY003B & 31HPSFY003C shall be configured to Pressure & temperature compensated steam flow indication can be obtained from equation below Compensated Steam Flow in TPH = Indicated Steam Flow in TPH * √ (P1 + 1.029) * (T2+273.15) / √ (P2+1.029) * (T1+273.15)
Delta p = HP- LP =Hm (Dw-Ds) – H (Da-Ds) Hm = {delta p + H (Da-Ds)}/ (Dw- Ds) Here,
Where: P1 = Measured Pressure Signal in Bar (g) T1 = Measured Temperature Signal in °C
H = 100 cm.
P2 = Flow nozzle Rated Pressure Signal in Kg/Cm2g
Da = 0.996 gm/cm3 at 30 deg. c Hm calculated from above formula is density corrected drum level, which shall be in scale range 0 to 100 cm (Hm output should be blocked in this range), this value shall be scaled for (-)475 to (+)525 mmwc display range on DCS .
T2 = Flow nozzle Rated Temperature Signal in Deg. C
The steam flow measured by DP (Differential Pressure) type steam flow transmitter 31HPSFT003D, 31HPSFT003E & 31HPSFT003F these are connected across flow element 31HPS FE003B. Square root for steam flow shall be done in smart transmitter. The measured Steam flow is compensated (Average pressure & average temperature) in function block 31HPSFY003A, 31HPSFY003B & 31HPSFY003C with average pressure & average temperature.
Normal Flow = 279.2 TPH
The steam pressure measured by pressure transmitter 31HPSPT025A, 31HPSPT025B & measured steam pressure are PV for function block 31HPSPY025 (Average block). The steam temperature measured by temperature transmitter 31HPSTT026A, 31HPSTT026B with thermocouple 31HPSTE026A, 31HPSTE026B & measured steam temperature are PV for function block 31HPSTY026 (Average block). The compensated steam flow values are the PV for function block 31HPSFY003 (Median block) The compensated steam flow is subtracted with Attemperator water flow in function block 31HFWFX003. The Attemperator water flow measured by DP (Differential Pressure) type Attemperator water flow transmitter 31HFWFT0034 this is connected across flow element 31HFWFE034. Square root for Attemperator water flow shall be done in smart transmitter. Steam flow (Pressure compensation
Section B
&
temperature)
Flow nozzle Rated Pressure = 104 Kg/Cm2 (g) Flow nozzle Rated Temp = 567.3 Deg. C
Sizing flow = 400 TPH Feed Water Flow Controller Remote Set-point (31HPSFX003A) = Drum Level Controller (31HPD LIC003B) O/P in % + Steam flow (31HFWFX003) O/p in %- 50. The feed water flow is measured by DP (Differential Pressure) type feed water flow transmitter 31HFWFT003A, 31HFWFT003B & 31HFWFT003C these are connected across flow element 31HFWFE003A. Square root for feed water flow shall be done in smart transmitter. The measured feed water flow is compensated in function block 31HFWFY003A, 31HFWSFY003B & 31HFWFY003C with average temperature. The feed water pressure measured by pressure transmitter 31HFWPT002A, 31HFWPT002B & measured feed water pressure are PV for function block 31HFWPY002 (Average block). This is indicated in DCS as 31HFWPI002 The feed water temperature measured by thermocouple 31HFWTE001A, 31HFWTE001B & measured feed water temperature are PV for function block 31HFWTY001 (Average block) The compensated feed water flow values are the PV for function block 31HFWFY003 (Median block). The median feed water flow is PV to feed water flow controller 31HFWFIC003A. Feed water flow (Temperature) compensation Computing 31HFWFY003B
block 31HFWFY003A, & 31HFWFY003C shall be
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Operation & Maintenance Manual
configur configured ed to Temperat emperature ure compens compensate ated d fee feed d wate wa terr flow flow indi indica cati tion on can can be obta obtain ined ed from from equation equation below Compensated FW Flow in TPH = Indicated FW Flow in TPH * √ (T2+273.15) / √ (T1+273.15)
Single Element Control:Control:In single element only Drum level is the reference reference level to control the feed water flow.
Normal Flow = 282.8 TPH
The drum level signal is compared with the fixed set point (0 mmWC) in the drum level-indicating controller & output of drum level controller 31IPD LIC050A is given to feed water flow control valve 31IFWFCV050AJYP 31IFWFCV050AJYPA A & 31IFWFCV050BJYP 31IFWFCV050BJYPA A thro throug ugh h ma manu nua al load loader er 31IF 31IFWH WHIC IC05 050A 0A & 31IFWHI 31I FWHIC05 C050B 0B respecti respectivel vely y. Output Output signal signal is inverted due to control valve air fail action is open. Control action of the Drum level controller 31IPD LIC050A LIC050A is Reverse. Reverse.
Sizing flow = 400 TPH
Three Element Control:
Indications and alarms to be configured as shown in the control schematic.
In Three Three element elements s Drum Drum level, level, Water Water flow and Steam flow are the references to control the water flow. Drum level as primary element, Feed water flow flow as seco seconda ndary ry elemen elementt and steam steam flow flow as third third element (feed forward). forward).
Where: T1 = Measured Temperature Signal in deg. C T2 = Flow nozzle Operating Temperature Signal in deg deg.. C Flow nozzle design Temp = 151 deg. C
Water Water Flow Tota otalis liser er 31H 31HFWF FWFIQ-0 IQ-003 03 & Steam Steam Flow Flow Total otalis iser er 31HP 31HPSF SFIQ IQ-0 -003 03 bloc blocks ks to be configured All process value should be record for reports & trends Drum Level high-high alarm configured in function block block 31HPD 31HPDLAH LAHH0 H003 03A, A, 31H 31HPDL PDLAH AHH0 H003 03B B & 31H 1HPD PDLA LAH HH0 H00 03C 3C.. 31HP 31HPDL DLAH AHH0 H003 03 is derive derived d afte afterr 2oo3 2oo3 votin voting g from from fun funct ctio ion n bloc block k 31HP 31HPDL DLX0 X003 03A. A. Drum Drum Leve Levell lowlow-lo low w alar alarm m configur configured ed in functio function n block block 31H 31HPDL PDLALL0 ALL003A, 03A, 31HPDLALL003B & 31HPDLALL003C. 31HPDLALL003 31HPDLALL003 is derived after 2oo3 voting from function function block 31HPDLX003B. 31HPDLX003B. Whenever drum level high-high or low-low alarm occurs trip the boiler that is Trip the GT. IP Drum Level Control The The aim aim of this this cont contro roll loop loop is to ma main inta tain in the the drum drum Level at the normal operating level in drum. Two modes of operation are provided for drum level control. control. Sing Single le elem elemen entt & Thre Three e elem elemen entt drum drum leve levell cont contro roll syst system em is envi envisa sage ged d to regu regula late te the the quan quanti tity ty of feed feed wa wate terr flowi flowing ng into into the the drum drum to mainta maintain in requi require red d wa wate terr leve levell in the the drum drum,, Single-element drum level control for low loads and Three-elements drum level control for normal & high load. load. 31I 31IFW FW FS-050A FS-050A is mode mode selector selector switch which changes single element control to three elements control and three elements control to single element control.
In three - element control the drum level signal is comp compa ared red with with the fixed xed set set poin pointt in the the drum level indicating controller 31IPDLIC050B. 31IPDLIC050B. To achi achiev eve, e, bet bette terr drum drum leve levell cont control rol,, a feed feed forward action is added to in the form of steam flow in fun functi ction on block block 31I 31IPSFX PSFX050 050A. A. The feed forward output use as a remote set point to feed water flow indicating indicating controller controller 31IFWFIC050A. 31IFWFIC050A. The fee feed d wa water ter flow flow sign signal al is comp compare ared d with with the the remo remote te set set poin pointt in the the feed eed water ater flow flow indi indica cati ting ng cont contro roll ller er & outp output ut of feed feed wa wate terr flow controlle controllerr 31I 31IFWFI FWFIC05 C050A 0A is given given to fee feed d water wat er flow contro controll valve valve 31I 31IFWFC FWFCV050 V050AJYP AJYPA A & 31IFWFCV050BJYP 31IFWFCV050BJYPA A through manual loader 31IFWHIC050A 31IFWHIC050A & 31IFWHIC050B 31IFWHIC050B respectively respectively,, output signal is inverted due to control valve air fail fail action action is open. open. Co Cont ntrol rol action action of the the feed feed water flow controller 31IFWFIC050A & Drum level controller controller 31IPD LIC050B is Reverse. Reverse. The drum drum leve levell me meas asure ured d by DP (Dif (Diffe feren renti tial al Pressure) type level transmitters 31IPDLT050A, 31IPDLT050B, 31IPDLT050C & measured drum level is compensated (density) in function block 31IPDLY050A, 31IPDLY050A, 31IPDLY050B 31IPDLY050B & 31IPDLY050C 31IPDLY050C with median drum pressure. The drum drum pres pressur sure e is measu measured red by pres pressu sure re tran transm smit itte terr 31IP 31IPDP DPT0 T057 57A, A, 31IP 31IPDP DPT0 T057 57B, B, 31IPDPT 31I PDPT057 057C C & measure measured d drum drum pressur pressure e are PV for function block 31IPDPY57 (Median block).
If steam flow increases beyond 13TPH(30%) then control will change to three elements control.
The compensated drum level values are the PV for function block 31IPDLY050 (Median block)
If steam flow decreases below 10TPH(25%) then control will change to single element control. control.
The The me medi dian an drum drum leve levell is PV to drum drum leve levell controllers 31IPDLIC050A and 31IPDLIC050B.
Section B
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Operation & Maintenance Manual
The Drum level transmitter is calibrated for - 550 to 0 mmWC and correspondence indication shall 0 to 100 %. The Drum pressure transmitter is calibrated for 0 to 35 Kg/Cm2(g) and correspondence indication shall 0 – 35 Kg/Cm2(g). Drum level density compensation compensation
is compen compensat sated ed (Avera (Average ge pressur pressure e & Average Average tempera temperatur ture) e) in fun functi ction on block block 31IPSFY0 31IPSFY050A 50A & 31IPSFY050B with average pressure & average temperature. TThe TThe stea steam m pres pressur sure e me measu asured red by pres pressu sure re trans transmi mitte tterr 31IPS 31IPSPT PT129 129A, A, 31IPS 31IPSPT1 PT129 29B B & measure measured d steam steam pressu pressure re are PV for functio function n block 31IPSPY129 (Average block). block).
Computing block 31IPD LY050A, 31IPD LY050B & 31IPD LY050C shall be configured to Pressure compensated /corrected drum level indication can be obtained from equation below Where ‘Hm’ is the corrected level indication.
Th e steam temperature measured by thermoc the rmocoup ouple le 31I 31IPSTE PSTE130 130A, A, 31I 31IPSTE PSTE130 130B B & measured steam temperature are PV for function block 31IPSTY130 (Average block)
Hm = {Delta p + H (Da - Ds)} / (Dw - Ds )
The compensated steam flow values are the PV for function block 31IPSFY050 31IPSFY050 (Average block)
Where: DP = diff differ erent entia iall pres pressu sure re me meas asure ured d by leve levell transmitter transmitter (DPT). [The range of DP in above equation is also to be taken as (– 55 to 0 cmWC)] Hm – Compensated drum level signal Dw – De Dens nsity ity of wa water ter (To (To be taken taken from from the the enclosed table) Ds – Density of Steam (To be taken from the enclosed table) H — Water head on LP side, wet head leg which is to be feed as constant = 55
The steam flow transmitter is calibrated for 0 to 5000 mmWC and correspondenc correspondence e indication indication shall 0-60 TPH. The steam pressure transmitter is calibrated for 0 – 35 Kg/Cm2(g) Kg/Cm2(g) and correspondenc correspondence e indication indication shall 0 – 35 Kg/Cm2(g). Steam flow flow (Pre (Pres ssure ure compensation.
&
tempera peratture)
Computing Computing block 31IPSFY050A 31IPSFY050A & 31IPSFY050B 31IPSFY050B shall shall be configure configured d to Pressur Pressure e & temper temperatu ature re comp compen ensa sate ted d stea steam m flow flow indi indica cati tion on can can be obtained from equation below
Da – Wet leg density; water Density at 30 Deg.C. (Constant =0.996).
Compen Compensat sated ed Steam Steam Flow Flow in TPH =Indica =Indicated ted Steam Steam Flow in in TPH * √ (P1 + 1.029) 1.029) * (T2+273.15) (T2+273.15) / √ (P2+1.029) (P2+1.029) * (T1+273.15) (T1+273.15)
Head on HP = Hm *Dw + (H-Hm)*Ds
Where:
Head on LP = H *Da
P1 = Measured Pressure Signal in Kg/Cm2(g)
Delta p = HP- LP
T1 = Measured Temperature Signal S ignal in °C
=Hm (Dw-Ds) – H (Da-Ds)
P2 = Flow Flow nozz nozzle le Ra Rate ted d Pres Pressu sure re Sign Signal al in Kg/Cm2(g)
Hm = {delta p + H (Da-Ds)}/ (Dw- Ds) Here, H = 55 cm. Da = 0.996 gm/cm3 at 30 deg. c Hm calc calcul ulat ated ed from from abov above e form formul ula a is densi density ty corr correc ected ted drum drum leve level, l, wh whic ich h shall shall be in scal scale e range 0 to 55 cm (Hm output should be blocked in this range), this value shall be scaled for (-)275 to (+)275 mmwc display range on DCS. The The stea steam m flow flow measu measure red d by DP (Dif (Differ feren enti tial al Pressure) type steam flow transmitter 31IP 1IPSFT0 SFT05 50D & 31IPS 1IPSF FT05 T050E both are are connected across flow element 31IPS FE050B. Squa Square re root root for for stea steam m flow flow shal shalll be done done in smar smartt trans transmi mitte tterr. The The me meas asur ured ed Steam Steam flow
Section B
T2 = Flow nozzle Rated Temperature Signal in °C Flow nozzle Rated Pressure = 25.49 Kg/Cm2(g) Flow nozzle Rated Temp = 320 °C Normal Flow = 43.9 TPH Sizing Sizing flow = 60 TPH Feed Water Water Flow Con Contro troller ller Remote Remote Set-poin Set-pointt (31IPSFX050A) = Drum Level Controller (31IPD LIC050B) O/P in % + Steam flow (31IPSFY050) O/p in %- 50. The feed water flow measured measured by DP (Differential (Differential Pres Pressu sure re)) type type feed feed wa wate terr flow flow tran transm smit itte terr 31IFWFT050A, 31IFWFT050B & 31IFWFT050C thes these e are are conn connec ecte ted d acro acros ss flow elem elemen entt 31IF 31IFWF WFE0 E050 50A. A. Squa Square re root root for for feed feed wa wate terr
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Operation & Maintenance Manual
flow flow shal shalll be done done in smart smart trans transmi mitt tter er.. The The measu measure red d feed feed wa wate terr flow flow is comp compens ensate ated d in function function block 31IFWFY050A, 31IFWSFY050B 31IFWSFY050B & 31IFWFY050C with average temperature. The feed water pressure measured by pressure transmi transmitte tterr 31I 31IFWPT FWPT077 077A, A, 31I 31IFWPT FWPT077 077B, B, & measured feed water pressure are PV for function bloc block k 31IFW 31IFWPY0 PY077 77 (Aver (Average age block block). ). This This is indicated in DCS as 31IFWPI077 The The feed feed wa wate terr temp temper erat atur ure e me meas asur ured ed by thermocouple thermocouple 31IFWTE075A, 31IFWTE075B & measu measure red d fee feed d wa wate terr temp tempera eratu ture re are are PV for function block 31IFWTY075 (Average block) The compensated feed water flow values are the PV for for fun functi ction on block block 31I 31IFW FWFY0 FY050 50 (Medi (Median an block block)) The median feed water flow is PV to feed water flow controller 31IFWFIC050A. The feed water flow transmitter is calibrated for 0 to 5000 mmWC and correspondence indication shall 0-60 TPH. The feed water pressure transmitter is calibrated for for 0 – 80 Kg/C Kg/Cm2 m2(g (g)) and and corr corres espo pond nden ence ce indication shall 0 – 80 Kg/Cm2(g). Feed water flow (Temperature) compensation. Computing block 31IFWFY050A, 31IFWFY050B & 31IFWFY WFY050C shall be confi config gured red to temp temper erat atur ure e comp compen ensa sate ted d feed feed wa wate terr flow flow indication indication can be obtained from equation equation below Compens Compensate ated d FW Flow Flow in TPH =Indicated =Indicated FW Flow in TPH * √ (T2+273.15) / √ (T1+273.15). Where: T1 = Measured Temperature Signal in °C °C T2 = Flow nozzle design Temperature Signal in °C Flow nozzle Rated Temp = 218 °C Normal Flow = 42.1 TPH Sizing flow = 60 TPH Indications and alarms to be configured as shown in the control schematic. Water Water Flow Flow Tota otalis liser er 31I 31IPSFIQ PSFIQ-05 -050 0 & Steam Steam Flow Totaliser 31IFWFIQ-050 blocks to be configured All process value should be record for reports & trends Drum Level high-high alarm configured in function bloc block k 31IP 31IPDL DLAH AHH0 H050 50A, A, 31IP 31IPDL DLAH AHH0 H050 50B B & 31I 31IPD PDL LAH AHH H050C 50C. 31IP 1IPDLAH AHH H050 is derive derived d afte afterr 2oo3 2oo3 votin voting g from from fun funct ctio ion n bloc block k 31IP 31IPDL DLX0 X050 50A. A. Drum Drum Leve Levell lowlow-lo low w alar alarm m
Section B
configure configured d in fun functi ction on block block 31IPDLA 31IPDLALL0 LL050A, 50A, 31IPDLALL050B & 31IPDLALL050C. 31IH 31IHPD PDLAL LALL0 L050 50 is deriv derived ed after after 2oo3 2oo3 voting voting from functio function n block block 31IPDLX 31IPDLX050B 050B.. Wheneve Wheneverr drum level high-high or low-low alarm occurs trip the boiler that is trip GT LP Drum Level Control The aim aim of this this contr control ol loop loop is to mainta maintain in the the drum drum Level at the normal operating level in drum. Two modes of operation are provided for drum level control. Sing Single le elem elemen entt & Thre Three e elem elemen entt drum drum leve levell cont contro roll syst system em is envi envisa sage ged d to regu regula late te the the quan quanti tity ty of feed feed wa wate terr flowi flowing ng into into the the drum drum to ma main inta tain in requi required red wa wate terr leve levell in the the drum, drum, SingleSingle-ele element ment drum level level control control for low loads loads and Three-elements drum level control for normal & high load. 31LFW 31LFW FS-093A FS-093A is mode mode selector selector switch which changes single element control to three elements control and three elements control to single element control. Single Element Control:Control:In single element only Drum level is the reference reference level to control the feed water flow. The drum level signal is compared with the fixed set point (0 mmWC) in the drum level-indicating controller controller & output of drum level controller controller 31LPD LIC080A is given to feed water flow control valve 31LFWFCV080AJYP 31LFWFCV080AJYPA A & 31IFWFCV080BJYP 31IFWFCV080BJYPA A thro throug ugh h ma manu nual al load loader er 31LF 31LFWH WHIC IC08 080A 0A & 31LFWHI 31LFWHIC08 C080B 0B respec respective tively ly.. Output Output signal signal is inverted due to control valve air fail action is open. Control Control action of the Drum level controller 31LPD LIC080A LIC080A is Reverse. Reverse. Three Element Control:Control:In Three Three element elements s Drum Drum level, level, Water Water flow and Steam flow are the references to control the water flow. Drum level as primary element, Feed water flow flow as seco seconda ndary ry eleme element nt and steam steam flow flow as third third element (feed forward). forward). In three - element control the drum level signal is comp compa ared red with with the the fixed xed set set poin pointt in the the drum level indicating controller controller 31LPDLIC080B. 31LPDLIC080B. To achi achiev eve, e, bet bette terr drum drum leve levell cont control rol,, a feed feed forward action is added to in the form of steam flow in function block 31LPSFX093A. The feed forward output use as a remote set point to feed water flow indicating controller 31LFWFIC093A. The fee feed d wa water ter flow flow sign signal al is comp compare ared d with with the the remo remote te set set poin pointt in the the feed eed water ater flow flow indi indica cati ting ng cont contro roll ller er & outp output ut of feed feed wa wate terr flow controller 31LFWFIC093A is given to feed
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Operation & Maintenance Manual
water flow control valve 31LFWFCV080AJYPA & 31LFWFCV080BJYPA through manual loader 31LFWHIC080A & 31LFWHIC080B respectively, output signal is inverted due to control valve air fail action is open. Control action of the feed water flow controller 31LFWFIC080A & Drum level controller 31LPDLIC080B is Reverse. The drum level measured by DP (Differential Pressure) type level transmitters 31LPDLT080A, 31IPDLT080B, 31IPDLT080C & measured drum level values are the PV for function block 31LPDLY080 (Median block) The median drum level is PV to drum level controllers 31LPDLIC080A and 31LPDLIC080B. The Drum level transmitter is calibrated for -1900 to 0 cmWC and correspondence indication shall 0 to 100 %. The steam flow measured by DP (Differential Pressure) type steam flow transmitter 31LPSFT093A & 31LPSFT093B both are connected across flow element 31LPS FE093. Square root for steam flow shall be done in smart transmitter. The measured Steam flow is compensated (Average pressure & Average temperature) in function block 31LPSFY093A & 31LPSFY093B with average pressure & average temperature. The steam pressure measured by pressure transmitter 31LPSPT089A, 31LPSPT089B & measured steam pressure are PV for function block 31LPSPY089 (Average block). The steam temperature measured by thermocouple 31LPSTE090A, 31LPSTE090B & measured steam temperature are PV for function block 31LPSTY090 (Average block) The compensated steam flow values are the PV for function block 31LPSFY093 (Average block) The compensated steam flow is added with HP compensated feed water flow, HP Attemperator water flow, IP compensated feed water flow & RH1 Attemperator water in function block 31LFWFX093 The RH1 Attemperator water flow measured by DP (Differential Pressure) type Attemperator water flow transmitter 31IFWFT0073 this is connected across flow element 31IFWFE073. Square root for Attemperator water flow shall be done in smart transmitter. The steam flow transmitter is calibrated for 0 to 5000 mmWC and correspondence indication shall 0-50 TPH.
Section B
The RH1 Attemperator water flow transmitter is calibrated for 0 to 2500 mmWC and correspondence indication shall 0-25 TPH. The steam pressure transmitter is calibrated for 0 – 10 Kg/Cm2(g) and correspondence indication shall 0 – 10 Kg/Cm2(g). Steam flow (Pressure compensation.
&
temperature)
Computing block 31LPSFY093A & 31LPSFY093B shall be configured to Pressure & temperature compensated steam flow indication can be obtained from equation below Compensated Steam Flow in TPH =Indicated Steam Flow in TPH * √ (P1 + 1.029) * (T2+273.15) / √ (P2+1.029) * (T1+273.15) Where: P1 = Measured Pressure Signal in Kg/Cm2(g) T1 =Measured Temperature Signal in °C P2 = Flow nozzle design Pressure Signal in Kg/Cm2(g) T2 = Flow nozzle design Temperature Signal in °C Flow nozzle design Pressure = 3.16 Kg/Cm2(g) Flow nozzle design Temp = 286.6 °C Normal Flow = 34.26 TPH Sizing flow = 50 TPH Feed Water Flow Controller Remote Set-point (31LPSFX093) = Drum Level Controller (31LPD LIC080B) O/P in % + Steam flow (31LFWFX093) O/p in % - 50. The feed water flow measured by DP (Differential Pressure) type feed water flow transmitter 31LFWFT104A & 31LFWFT104B both are connected across flow element 31LFWFE104. Square root for feed water flow shall be done in smart transmitter. The measured feed water flow is compensated in function block 31LFWFY104A & 2IFWFY104B with average temperature. The feed water pressure measured by pressure transmitter 31LFWPT131A, 31LIFWPT131B, & measured feed water pressure are PV for function block 31LFWPY131 (Average block) The feed water temperature measured by thermocouple 31LFWTE132A, 31LFWTE132B & measured feed water temperature are PV for function block 31LFWTY132 (Average block) The compensated feed water flow values are the PV for function block 31LFWFY104 (Average block)
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Operation & Maintenance Manual
The average feed water flow is PV to feed water flow controller 31LFWFIC093A.
CBD drain temperature is the reference temperature to control the drain line temperature.
The feed water flow transmitter is calibrated for 0 to 7500 mmWC and correspondence indication shall 0-500 TPH.
The CBD drain temperature signal is compared with the fixed set point (60°C) in the CBD drain temperature -indicating controller & output of CBD drain temperature controller 31SWSTIC096 is given to quench water flow control valve 31SWSTCV096JYPA. Output signal is inverted due to control valve air fail action is open. Control action of the CBD drain temperature controller 31SWSTIC096 is Direct.
The feed water pressure transmitter is calibrated for 0 – 40 Kg/Cm2(g) and correspondence indication shall 0 – 40 Kg/Cm2(g). Feed water flow (Temperature) compensation. Computing block 31LFWFY104A & 31IFWFY104B shall be configured to Temperature compensated feed water flow indication can be obtained from equation below Compensated FW Flow in TPH = Indicated FW Flow in TPH * √ (T2+273.15) / √ (T1+273.15) Where: T1 = Measured Temperature Signal in °C T2 = Flow nozzle Rated Temperature Signal in °C Flow nozzle design Temp =146 °C Normal Flow =389.2 TPH Sizing flow =500 TPH Indications and alarms to be configured as shown in the control schematic. Water Flow Totaliser 31LFWFIQ104 & Steam Flow Totaliser 31LPSFIQ93 blocks to be configured All process value should be record for reports & trends Drum Level high-high alarm configured in function block 31LPDLAHH080A, 31LPDLAHH080B & 31LPDLAHH080C. 31LPDLAHH080 is derived after 2oo3 voting from function block 31LPDLX080A. Drum Level low-low alarm configured in function block 31LPDLALL080A, 31LPDLALL080B & 31LPDLALL080C. 31LHPDLALL080 is derived after 2oo3 voting from function block 31LPDLX080B. Whenever drum level high-high or low-low alarm occurs trip the boiler that is trip GT
7.2
CBD Drain Temperat ure Cont rol
The aim of this control loop is to maintain the CBD Drain Temperature at the normal operating temperature in drain line. CBD drain temperature control system is envisaged to regulate the quantity of quench water flowing into the drain line to maintain required temperature in drain line CBD drain temperature Control:-
Section B
The CBD drain temperature measured by temperature transmitters 31HVDTT096A, & 31HVDTT096B with thermocouple 31HVDTE096A, & 31HVDTE096B & measured CBD drain temperature are PV for function block 31HVDTY096 (Average block) The average CBD drain temperature is PV to CBD drain temperature controller 31SWSTIC096. The CBD drain temperature transmitter is calibrated for 0 – 150 Deg.C and correspondence indication shall 0 to 150 Deg.C. Following to be taken care while configuring this loop in DCS. In manual mode SP tracking is required to PV.
7.3
St ack Temperat ure (CPH Bypass 3- Way) Control
The aim of this control loop is to maintain the stack temperature at the normal operating temperature in stack. Stack temperature control system is envisaged to regulate the quantity of DM water flowing into the CPH to maintain required temperature in stack. Stack Temperature Control:Stack temperature is the reference temperature to control the stack temperature. The stack temperature signal is compared with the set point in the stack temperature -indicating controller & output of stack temperature controller 31LFWTIC102 is given to CPH bypass flow control valve 31LFWTCV102JYPA. Control action of the Stack temperature controller 31LFWTIC102 is Reverse. The stack temperature measured by thermocouple 31FLUETE226A & 31FLUETE226B & measured stack temperature are PV for function block 31FLUETY226 (Average block) The average stack temperature is PV to stack temperature controller 31LFWTIC102.
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Following to be taken care while configuring this loop in DCS.
7.6
In manual mode SP tracking is required to PV.
The aim of this control loop is to maintain the HP Steam Temperature at the normal operating temperature in HP steam line.
Setpoint for Various fuels is mentioned below:
7.4
LP Drum Pressure Cont rol
The aim of this control loop is to maintain the drum pressure at the normal operating pressure in drum. Drum pressure control system is envisaged to regulate the quantity of steam vent to maintain required pressure in drum. LP Drum Pressure Control:LP Drum Pressure is the reference Pressure to control the drum Pressure. The drum Pressure signal is compared with the fixed set point in the LP drum Pressure -indicating controller & output of LP drum Pressure controller 2LPDPIC083 is given to drum Pressure control valve 2LPDPCV083JYPA. . Output signal is inverted due to control valve air fail action is open, Control action of the LP drum Pressure controller 2LPDPIC083 is Direct. The drum Pressure measured by pressure transmitter 2LPDPT083A & 2LPDPT083B & measured drum Pressure are PV for function block 2LPDPY083 (Average block) The average drum Pressure is PV to drum Pressure controller 2LPDPIC083. The LP drum pressure transmitter is calibrated for 0 – 10 Bar (g) and correspondence indication shall 0 – 10 Bar (g). Following to be taken care while configuring this loop in DCS.
H P Att emperator Control
HP steam temperature control system is envisaged to regulate the quantity of feed water flowing into the steam line (Attemperator) to maintain required temperature in HP steam line. HP1 Attemperator Control HP steam temperature is the reference temperature to control the steam line temperature. The steam temperature signal is compared with the fixed set point (567°C) in the HP Attemperator -indicating controller & output of Attemperator controller 31HFWTIC026 is given to Attemperator control valve 31HFWTCV026AJYPA & . 31HFWTCV026BJYPA through manual loader 31HFWHIC026A & 31HFWHIC026B respectively, Output signal is inverted due to control valve air fail action is open. Control action of the HP Attemperator controller 31HFWTIC026 is Direct. The HP steam temperature measured by temperature transmitters 31HPSTT026A, & 31HPSTT026B with thermocouple 31HPSTE026A, & 31HPSTE026B & measured steam temperature are PV for function block 31HPSTY026 (Average block) The average HP steam temperature is PV to HP Attemperator controller 31HFWTIC026. The HP Steam temperature transmitter is calibrated for 0 – 800 Deg.C and correspondence indication shall 0 to 800 Deg.C. Following to be taken care while configuring this loop in DCS. In manual mode SP tracking is required to PV.
In manual mode SP tracking is required to PV. • Natural Gas - 86°C •
Naptha - 134°C
7.5
LP Drum Pressure Cont rol
The aim of this control loop is to regulate the quantity of steam vent to maintain required pressure in drum. The Vent Valve shall be operated from DCS thro’ Manual Loader 31LPDHIC083. This valve shall be kept crack open all the time to have continuous Vent. LP Drum Pressure Control is envisaged by LP Drum Pegging Steam Pressure Control Valve.
Section B
7.7 RH1 Attemperator Control The aim of this control loop is to maintain the IP Steam Temperature at the normal operating temperature in IP steam line. RH1 steam temperature control system is envisaged to regulate the quantity of feed water flowing into the steam line (Attemperator) to maintain required temperature in IP steam line. RH1 Attemperator Control IP steam temperature is the reference temperature to control the steam line temperature.
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The steam temperature signal is compared with the fixed set point (567°C) in the RH1 Attemperator -indicating controller & output of Attemperator controller 31IFWTIC068 is given to Attemperator control valve 31IFWTCV068AJYPA & . 31IFWTCV068BJYPA through manual loader 31IFWHIC068A & 31IFWHIC068B respectively, Output signal is inverted due to control valve air fail action is open. Control action of the RH1 Attemperator controller 31IFWTIC068 is Direct.
31LFWTE108A, & 31LFWTE108B & measured CPH Water temperature are PV for function block 31LFWTY108 (Average block)
The IP steam temperature measured by temperature transmitters 31HRHTT068A, & 31HRHTT068B with thermocouple 31HRHTE068A, & 31HRHTE068B & measured steam temperature are PV for function block 31HRHTY068 (Average block)
Following to be taken care while configuring this loop in DCS.
The average IP steam temperature is PV to RH1 Attemperator controller 31IFWTIC068.
The aim of this control loop is to maintain the IP steam pressure at the normal operating pressure in IP line.
The IP Steam temperature transmitter is calibrated for 0 – 800 Deg.C and correspondence indication shall 0 to 800 Deg.C. Following to be taken care while configuring this loop in DCS. In manual mode SP tracking is required to PV.
7.8
CPH Recirculat ion Temperat ure Control
The aim of this control loop is to maintain the CPH Water Temperature at the normal operating temperature in CPH tubes to avoid corrosion of the CPH tubes. CPH recirculation temperature control system is envisaged to regulate the quantity of water recirculate into the CPH tubes to maintain required temperature in CPH tubes. CPH Recirculation Temperature Control CPH Water temperature is the reference temperature to control the CPH tubes temperature. The CPH Water temperature signal is compared with the fixed set point (57°C) in the CPH recirculation temperature - indicating controller & output of CPH recirculation temperature controller 31LFWTIC108 is given to CPH recirculation temperature control valve 31LFWTCV108JYPA. Output signal is inverted due to control valve air fail action is open. Control action of the CPH recirculation temperature controller 31LFWTIC108 is Reverse. The CPH Water temperature measured by temperature transmitters 31LFWTT108A, & 31LFWTT108B with thermocouple
Section B
The average CPH Water temperature is PV to CPH recirculation temperature controller 31LFWTIC108. The CPH Water temperature transmitter is calibrated for 0 – 80 Deg.C and correspondence indication shall 0 to 80 Deg.C.
In manual mode SP tracking is required to PV.
7.9
I P Line Back Pressure Cont rol
IP Line Back pressure control system is envisaged to regulate the CV to maintain required pressure in IP line. IP Line Back pressure Control IP line Pressure is the reference Pressure to control the IP line Pressure. The IP steam Pressure signal is compared with the fixed set point (24 Kg/Cm2g) in the IP Line Back pressure control -indicating controller & output of IP Line Back pressure controller 31IPSPIC129 is given to IP Line Back pressure control valve 31IPSPCV129JYPA. . Output signal is inverted due to control valve air fail action is open; Control action of the LP drum Pressure controller 31IPSPIC1293 is direct. The IP steam Pressure measured by pressure transmitter 31IPSPT129A & 31IPSPT129B & measured IP steam Pressure are PV for function block 31IPSPY129 (Average block) The average IP steam Pressure is PV to IP line back Pressure controller 31IPSPIC129. The IP Steam pressure transmitter is calibrated for 0 – 35 Kg/Cm2(g) and correspondence indication shall 0 – 35 Kg/Cm2(g). Following to be taken care while configuring this loop in DCS. In manual mode PV to SP tracking is required.
7.10 Start up Vent (HP, I P & LP) Cont rol Initially during boiler start up it is necessary to keep the start up vent valve open and increase the boiler pressure & steam temperature gradually.
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Start up vent control valve is provided to avoid
Section B
burnout of tubes and to control the start up pressure.
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Section C
3
Topics Covered in this Chapter
A HRSG startup can be termed as cold start up when any of the following conditions are met
♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦
Section Overview HRSG Start Up and Shut Down Startup of a Cold HRSG Hot and Warm Start up of HRSG HRSG Shutdown Cooling of a Shutdown Boiler HRSG Operation Walk Down Checks Do’s and Don’ts For HRSG Operation Boiler Log Sheet Boiler Emergency Safety Procedures Trouble Shooting Chart
Operation
1
Se ct i o n Ov er v i ew
This section describes the start up, shut down procedures of the HRSG. HRSG operation & safety are also described here.
2
HRSG Start Up and Shut Dow n
Operation HRSG Start Up And Shut Down Aim This and subsequent chapters describes the HRSG start up and shut down procedures as applicable for the following conditions: • Start up of a cold HRSG •
HRSG shut down
• Start up of a warm HRSG • Start up of a Hot HRSG Note
• The procedures explained in this chapter apply for start up of the HRSG already commissioned. Commissioning a new HRSG call for several additional requirements. • It is assumed that operators are fully familiar with the design and construction features described in the earlier chapters. • It is assumed that operators are trained in operation of high pressure HRSGs and have been licensed to operate HRSGs or HRSG by the State Boiler Authority
Section C
Start up of a Cold HRSG
• The HRSG has been idle for more than three days • There is no pressure in the steam drum and its metal temperature is less than 70°C In a cold startup, possibilities of some inspection or maintenance works having been done are presumed. A walkdown checks are required and the HRSG and its auxiliaries are to be prepared meticulously for a startup from the control room. Before a walkdown checks ensure that all work permits have been returned, tags removed and maintenance permission for HRSG startup is available. Program of Gas Turbine (GT) availability has also to be checked. Carry out walk down checks before cold start up of HRSG & fill up water in HRSG as per Standard operating procedure.
3.1
Walk D ow n Check
Using powerful torches or low voltage inspection lamps inspect the HRSG and ensure that 1. Furnace and the exhaust gas path are clear, all maintenance personnel have been removed and no scaffolding or inspection devices have been left inside. 2. Boiler bank, Economiser & LP Boiler Bank panels are clean and there is no evidence of any water drips. 3. Verify that all access doors, inspection doors are tightly closed. 4. Verify that the exhaust gas duct to stack is clear and that all maintenance personnel have been withdrawn. HP ,IP & LP Main Steam Line and Reheater 1. Verify that the safety valves are not gagged. 2. Verify that nitrogen purging valves are open. If they are open, they are to be closed just before HRSG light up when air vents are opened.
HP, I P & LP St eam Drum 1. Verify that the safety valves are not gagged. 2. Verify that the illuminators of local level gauges are on. Inlet valves from steam and waterside is open and their drain valves are closed.
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3. Verify that the nitrogen connection line (if used) has been isolated and the drum vent is open.
HP, I P & LP Dosing Systems
(GT 607) & LP RHS side drain header (GT 605) are open. 8. Ensure that drain valves HPSH1 GL739, Reheater2 GL738, HPSH3 GL737 are closed.
1. Check that the solution-mixing tank of HP, IP & LP dosing system has atleast 50% tank level. If the level is low, prepare a full tank level of solution. Check that the pump inlet and solution inlet valves are open.
9. Ensure that following manual drain valves are open:
2. Check oil levels of the gearboxes of the dosing pumps and the stirrer. Top up if necessary.
• HPSH-3 Drain valve (GT682), (GT764, GT694)
3.2
• IPSH Drain valve (GT637) to be normally open.
Valve Lineup
The DCS is linked from field instruments to constantly update process information (Feed flow, steam flow, steam temperature, drum pressure, water/steam temperatures, metal temperatures, gas temperatures, pressure/temperatures for pre trip alarms etc). In the DCS, the information is processed and based on pre-set logic and set points, control commands are sent to I/P converters for control action. Start/Stop command and alarm inputs etc are also from the DCS. 1. Ensure pre-purge of HRSG is done through GT (This is carried out standard GT operation procedure) 2. Ensure that the HRSG is lined up for start up as per cold start up procedure as mentioned above. Ref. cold start up procedure. Line up all valves in HP, IP & LP section as per the valve line up chart for cold start up. 3. During cold start up all the section of HRSG viz HP, IP & LP shall receive hot flue gases from GT & hence undergo cold start up simultaneously. 4. Ensure that HP Section main steam stop valve M029A & Bypass valve M029B are closed & start up vent valve PCV028 is full open. 5. Ensure that IP Section steam isolation valve M064 to reheater is closed & start up vent valve PCV063 is full open. 6. Ensure that drain valves to Blow down Tank of HP SH Drain header (GT688), Reheater Drain Header (GT650) are closed. The HPSH drain header, reheater drain header & HPSH1 drain operate from condensate drain pot arrangement on conductivity principle. 7. Ensure that drain valves to Blow down Tank of IP RHS Drain Header (GT 622) & IP LHS side header (GT 624), LP LHS side drain header
Section C
• HPSH-1 Drain valve (GT680) • RH-2 Drain valve (GT642), (GT 646).
• LPSH Drain valve (GT617) to be normally open. 10. Ensure that following drain valves are open: • IP super heater motorised drain valve M076 to be closed after removal of condensate. •
LP superheater motorised drain valve M098 to be closed after removal of condensate.
• All above mentioned drain valves are start up drain valves & need to be close down when steam pressure of respective section reaches near to 4 bar (g). 11. Ensure following vent valves are open • HP Drum vent valve M005A & M005B, to be closed when drum pressure reaches to 2 bar (g). •
HP Main steam line start up vent valve M028.
•
IP Drum vent valve M061 to be closed when drum pressure reaches to 2 bar (g).
•
LP Drum (Deaerator) vapour tank vent valve PVC 083 & isolation valve GT 359, PVC 083 to be operated as per pressure controller PIC 083.
12. Ensure following valves are closed • HP Drum EBD M039, this need to be open in the event of Drum high level. • IP Drum EBD M078, this need to be open in the event of Drum high level. • LP Drum EBD M094, this need to be open in the event of Drum high level. • HP Drum CBD M040, this need to be open in proportion to keep HP drum water quality as per requirement.
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• IP Drum CBD M079, this need to be open in proportion to keep IP drum water quality as per requirement. • LP Drum CBD M095, this need to be open in proportion to keep LP drum/Deaerator water quality as per requirement.
3.3 System Lineup Preliminary Requirements • Power supply ensure that the power supply is switched ’ON’ and available for all the motors and panels. • Operating station - DCS is ensured for readiness and emergency push buttons are released, if activated. • As instrument air is necessary for the operation of most of the valves and actuators, charge the instrument air header, the branch lines and instruments supply lines elsewhere. Root valves of all Instruments (Pressure gauges, Pressure transmitters, DP transmitters, Level gauges, etc,) must be kept open and their drains if any are to be kept closed. They are not separately listed.
• Verify that drain valves on the spray water line are closed • Verify that the root valves of Pressure gauges, pressure transmitters, pressure switches are open. • Verify that the 30% and the two 100% flow control valves are in the closed (0%) position in the DCS (If they are in open position, close them by manual command from DCS) • Verify that the Manual operated inlet & outlet isolating valve of the feed regulating station is open • Verify that the drain valves before and after the 30% & 100% flow regulating valve are closed Feed Line from HP Economiser I • An export water line valve GT 211 is kept closed. • Root valve of all the instruments are kept open. Attemporator Spray Water Lines • Keep open the manual isolating valves [GT 049, GT050 & GT 248, GT249]. •
Verify that the Attemperator spray water control valve [TCV026A & B and TCV 068A & B] is in closed position (DCS).
• Ensure that all the transmitters are lined up mechanically / electronically
•
Verify that the drains on either side of the control valve are closed.
CPH
• Keep open the inlet and outlet isolating valves of control valves [TCV026A & B and TCV 068A & B]
• Verify that drain valves [GT 603 & GT604] are kept locked open except for maintenance • Verify that air vent valves [GT 609] are locked open. Verify that it is open & is to be closed as soon as air is purged & water comes out during waterside charging. • Verify that water side inlet isolating valves [GT 305] is open • Verify that bypass manual valve [GT 314] is open .
• Keep the Attemporator controller [TIC-026 & TIC 068] in manual mode. Sample System • All the sample lines isolation valves have to be closed. SWAS (Customer System) can be taken into service once the HRSG is pressurized Availability of Nitrogen Gas
For starting a cold HRSG, DM water from the station DM line may preferably be used. However feed lines are lined up such that the Feed Regulating stations can be taken into service from DCS, when requirement arises.
Nitrogen gas is used for purging the gas, oil lines before inspection or maintenance of any of the components. No prediction can be made when the nitrogen gas will actually be required. To meet any eventuality, it is a good practice to charge the nitrogen gas lines up to the consuming points and keep the gas available whenever required.
• Verify that electrically operated isolating valve [TV 034] to spray water lines is closed (DCS)
• Verify valve from plant nitrogen gas main to drums are closed.
Feedwater Control Stations
Section C
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Operation & Maintenance Manual
3.4
Valve Posit ions Chart For HP, I P & LP Sect ion (Before Light Up)
Valve Tag Number
Service
Open Close Remarks
FEED WATER LINE TO HP STEAM DRUM GT-038
Feed Water Main Isolation valve
Y
To be closed while carrying out maintenance during boiler shut down
M -003 A/B/C
Control station inlet motorized isolation valves
Y
To be closed while carrying out maintenance during boiler shut down
GT- 026/027/028
Control station outlet manual isolation valves
Y
To be closed while carrying out maintenance during boiler shut down or problem in control valve operation
GT-020/21/22/23/2 4 & 25
Feed water control station drain valves
Feed water line pressure tapping 2 9/30/32/33/34/3536/37 /54/55 isolation valves GT- 001/002/015/016/
GT – 003,004,005,006,00 7 ,008,009,010,011,012,0 13 & 014
Feed water flow transmitter isolation valves
FCV – 003 A
Feed water control station 30% control valve
Y
To be Opened when control valve is under maintenance
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be closed while carrying out maintenance during boiler shut down Y
To be opened initially when the water is required to maintain the drum level
FCV – 003 B
Feed water control station 100% control valve
Y
To be opened when boiler load reaches above the 30% to maintain the drum level
FCV – 003 C
Feed water control station 100% control valve
Y
To be opened when the 100% line main control valve is under maintenance
FEED WATER LINE TO IP STEAM DRUM GT - 241
Feed Water Main Isolation valve
M – 050 A
Control station inlet motorized isolation valve
GT – 216,217
Control station outlet manual isolation valve
GT – 214,215
Feed water control station drain valve
Section C
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be kept open permanently & it will be closed only during the boiler shutdown or motorized valve is under maintenance Y
To be Opened when motorized valve is under maintenance
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Operation & Maintenance Manual
Valve Tag Number
Service
Open Close Remarks
GT – 201,08, Feed water line pressure tapping isolation valves
Y
To be closed while carrying out maintenance during boiler shut down
GT – 202,03,04,05, 06 & 07
Feed water flow transmitter isolation valves
Y
To be closed while carrying out maintenance during boiler shut down
GT – 211
Export water line valve
Y
To be closed while carrying out maintenance during boiler shut down
FCV – 050A
Feed water control station 100% control valve
Y
To be opened initially when the water is required to maintain the drum level
FCV – 050B
Feed water control station 100% control valve
Y
To be opened when the 100% line main control valve is under maintenance
GT – 59(02 NO’S) GT – 60 & 18 GT – 58
FEED WATER LINE TO LP STEAM DRUM GT - 314
Feed Water Main Isolation valve
GT - 327
Feed Water Second Isolation valve
M – 080 A/B
Control station inlet motorized isolation valves
GT – 322, 325
Control station outlet manual isolation valves
GT – 321, 324
Feed water control station drain valves
GT – 316, 317, 318 & 319
Feed water flow transmitter isolation valves
GT –328, 329,
Feed water line pressure tapping isolation valves
GT – 326
Vent line valve
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be kept open permanently & it will be closed only during the boiler shutdown or motorized valve is under maintenance Y
To be Opened when motorized valve is under maintenance
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be closed while carrying out maintenance during boiler shut down Y
To be open while carrying out maintenance during boiler shut down
ECONOMIZER HP
Section C
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Operation & Maintenance Manual
Valve Tag Number GT – 671 (04 NO’S)
Service
Open Close Remarks
Economizer I/II/III top header Vent Isolation Valves.
Y
To be open only during first filling of Economizer/ boiler.
Y
To be opened for draining & initial water filling the Economizer & hydro
Y
To be opened for draining & initial water filling the Economizer & hydro
Economizer Top & bottom header Drain Isolation Valves.
Y
To be opened for draining & initial water filling the Economizer & hydro
GT-716,714,718,720 , 722 & 712
DM water line at battery limit valves
Y
To be open only to take water for boiler hydro test.
GT – 627 & 636 (02 NO’S EACH)
IP Evaporator drain line valves
Y
To be open only to take water for boiler hydro test.
GT – 615 & 616 (01 NO EACH)
LP Evaporator drain line valves
Y
To be open only to take water for boiler hydro test.
Y
To be open during boiler cold start up to let water/condensate to blow down tank.
GT – 672 (02 NO’S) GT - 673 (14 NO’S ) GT – 651 (06 NO’S) GT – 693 (06 NO’S) GT – 653 (01 NO’S) GT – 654 (01 NO’S) GT – 655 (02 NO’S) GT – 656 (02 NO’S) GT – 657 (02 NO’S) GT – 658 (02 NO’S) GT – 659 (01 NO’S)
Economizer I/II/III Top & bottom header Drain Isolation Valves.
GT – 660 (01 NO’S) GT – 696 (02 NO’S) GT – 663 (12 NO’S) GT – 692 (12 NO’S) GT – 665 (01 NO’S) GT – 666 (01 NO’S) ECONOMIZER IP GT – 626 (02 NO’S) GT – 620 (02 NO’S ) GT – 621 (02NO’S )
Economize top header Vent Isolation Valves.
DM WATER FILLING IN HRSG
GT – 695, 669, 622, 624, 605, & 607
All header drain valves
HP STEAM DRUM M –005 A/B
Motorized Isolation Valves of Drum Vent
GT – 095
N2 Preservation Connection
Section C
To be closed when drum pressure reaches 2 bar (g) during boiler pressurization.
Y
Y
To be opened only when boiler is to be preserved with N2
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Operation & Maintenance Manual
Valve Tag Number
Service
GT – 087,088,089, 090,091 & 092
Steam drum pressure transmitters isolation valves
GT – 084,085 & 086
Steam drum local pressure pressure indicator indicator isolation valves
GT – 087, 088, 089, 090, 091, 092
Open Close Remarks Y
To be closed while carrying out maintenance during boiler shut down
Y
To be closed while carrying out maintenance during boiler shut down
Steam drum local pressure transmitter isolation valves
Y
To be closed while carrying out maintenance during boiler shut down
GT-060,061,062,063, 064,065,066, 067, 068, 069,070,071, 072, 073,074 & 075
Isolation Valves for manifold on Steam Drum for Level Indicating Instruments.
Y
To be closed while carrying out maintenance during boiler shut down
GT – 076,077 076,077,078 ,078,, 079,080,081,0 079,080,081,082 82 & 083
Isolation Valves of Steam Drum Level Gauge Glass
Y
To be closed while carrying out maintenance during boiler shut down
HP EVAPORATOR GT – 678 & 679 (02 NO’S EACH)
HP Evaporator drain line valves
Y
To be open only during first filling of Economizer/ boiler.
GT – 690 (02 NO’S)
Evaporator vent valve
Y
To be open only during first filling of Economizer/ boiler.
HP MAIN STEAM LINE GT – 680 GT – 682 (02 NO’S) GT – 683 (02 NO’S M – 038 B M – 038 F M – 038 D M – 038 H
HP Superheater-1 Drain Isolation Valve before MOVs
Y
HP Superheater-2 & 3 Drain Isolation Valves HP Superheater-2 & 3 Motorized operated Drain valves HP Superheater-1 Motorized Motorized operated Drain valves
To be kept lock open. To be closed at failure of MOV valve. Y
To be open during boiler shut down for complete draining or superheater
Y
To be closed when condensate is drained completely at 4 bar (g) pressure.
Y
To be closed when condensate is drained completely at 4 bar (g) pressure.
GT – 691 (02 NO’S)
Superheater 2 vent valve
GT – 688
HP SH Drain header valve
Y
To be kept lock open
GT – 698
Main Steam line drain before MSSV
Y
To be kept lock open. To be closed at failure of MOV valve.
M- 038A & 038E
Main steam line motorized motorized operated drain valves
Y
To be closed once the condensate removed for line completely
Section C
Y
To be open during boiler shutdown
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Operation & Maintenance Manual
Valve Tag Number
Service
GT – 107 & 108
Main steam line vent valve before safety valve
GT – 129
Steam sampling system main isolation valve
M - 028
Motorized isolation Valve of Startup Vent Valve
Open Close Remarks Y
To be open during boiler shutdown
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be kept open during boiler start up. To be closed when boiler is connected to plant mains along with PV028.
Y
To be Closed once rated pressure is attained and boiler is connected to Plant mains
PV -028
Startup Vent valve
M – 029 B
Motorised Motorised Pressure Pressure Equalization Valve of Main Steam Stop Valve
Y
To be opened for equalization of pressure.
M – 029 A
Motorized Main Steam Stop Valve
Y
To be opened after reaching the rated Pressure. Pressure.
GT – 112 & 113 (02 NO’S EACH) GT –110 & 111
Main steam line pressure transmitter isolation valves
GT – 114,1 114,115,1 15,116, 16, 117,118,119,120, 121,122,123,1 121,122,123,124 24 & 125
Main steam line flow transmitter transmitter tapping line valves
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be closed while carrying out maintenance during boiler shut down
REHEATER GT – 644 (02 NO’S) GT – 642 (02 NO’S)
Reheater drain line valves
Y
To be open during boiler shutdown
Y
This This valv valve e to be clos closed ed once once the condensate condensate removed completely from Re-heater 1 & 2.
GT - 646
Re-heater -1 & 2 drain line manual valve
Y
To be kept lock open. To be closed at failure of MOV valve.
GT – 650
Reheater Drain header valve
Y
To be kept lock open.
GL – 738
Reheater Attemperator Attemperator drain valve
FMV – D201 (Customer (Customer scope)
Reheater -2 O/L to steam header Drain valve
M – 38C
Re-heater -1 & 2 drain line motorized valve
Y
Y
To be open during boiler shutdown To be closed when condensate is drained completely.
HP ATTEMPERATOR SYSTEM
Section C
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Operation & Maintenance Manual
Valve Tag Number
Service
Open Close Remarks
LCV – 034
Attemperator line main isolation valve
Y
To be closed during initial fill up water in boiler / Economizer
M – 026 A/B
Attemperator control station up stream motorized isolation valves
Y
To be closed while carrying out maintenance during boiler shut down
GT – 049 & 050
Attemperator control station down stream manual isolation valves
Y
To be closed while carrying out maintenance during boiler shut down
GT – 045,046 & 047,048
Attemperator Attemperator drain line isolation valves
TCV – 026 A/B
Temperature control valve one is main line valve and another is bypass valves
Y
GT – 103 & 104
Attemperator Attemperator vent line valves
Y
To be opened during boiler shutdown
GT – 105 & 106
Attemperator Attemperator drain line valve
Y
To be opened during boiler shutdown
M – 038B & 038F
HP Attemperator motorized drain valves
GT - 694
HP Attemperator manual drain valve
Y
To be Opened when control valve is under maintenance maintenance To be open as per the steam temperature control requirement. One TCV kept closed and one will be use.
Y
Both valves to be closed once the condensate removed completely
Y
To be kept lock open. To be closed at failure of MOV valve.
HP BLOWDOWN SYSTEM M - 040
HP Drum EBD motorized valve
GT – 674 (02 NO’S)
HP Drum EBD manual isolation valves
Y
This valve need to be open in the event of Drum high level Manual isolation valves keep open continuously
Y
M - 039
HP Drum CBD motorized valve
Y
This need to be open in the event of Drum high level or maintaining the TDS in boiler
GT – 675 (02 NO’S)
HP Drum CBD manual valves
Y
Manual isolation valves keep open continuously
IP STEAM DRUM M –061
Motorized Isolation Valves of Drum Vent
GT - 228
N2 Preservation Connection
Section C
To be closed when drum pressure reaches 2 bar (g) during boiler pressurization.
Y
Y
To be opened only when boiler is to be preserved with N2
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Operation & Maintenance Manual
Valve Tag Number
Service
GT – 224,225 & 226
Steam drum pressure transmitters isolation valves
Open Close Remarks Y
To be closed while carrying out maintenance during boiler shut down
GT – 219,220 & 221
Steam drum local pressure indicator isolation valves
Y
To be closed while carrying out maintenance during boiler shut down
GT-235,236,237, 238,239 & 240
Isolation Valves for manifold on Steam Drum for Level Indicating Instruments.
Y
To be closed while carrying out maintenance during boiler shut down
GT – 231,232 & 234
Isolation Valves of Steam Drum Level Gauge Glass
Y
To be closed while carrying out maintenance during boiler shut down
IP EVAPORATOR GT – 636 & 627 (02 NO’S EACH)
GT – 641 (02 NO’S)
IP Evaporator drain line valves
Evaporator vent valve
Y
To be open only during initial water filling & hydro
Y
To be open during initial water filling & hydro & to be closed after air is expelled completely.
IP MAIN STEAM LINE GT – 637 & GI – 256
Superheater Inlet & Outlet Header Drain Isolation Valves
M – 076
IP Superheater motorized drain valve
GT – 294
Superheater inlet vent valve
Y
GI – 256
Main Steam line drain valve
Y
GI – 255
Main steam line vent valve
Y
GT – 255
Steam sampling system main isolation valve
M - 063
Motorized isolation Valve of Startup Vent Valve
PCV -063
Startup Vent valve
M – 064
IP section to re-heater connecting line isolation valve
Section C
Y
To be closed during boiler shutdown
Y
To be closed once the condensate removed completely To be open during boiler shutdown
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be closed along with PCV 063 when boiler is connected to re-heater
Y
To be Closed once rated pressure is attained and boiler is connected to re-heater Y
To be open once the boiler pressure reaches above 5 Bar
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Operation & Maintenance Manual
Valve Tag Number
Service
Open Close Remarks
GT – 264
IP main steam line drain valve
Y
To be kept lock open.
M -077
IP main steam line motorized operated drain valve
Y
To be closed once the condensate removed from line
GT – 257,258,259 & 260
Main steam line flow transmitter tapping line valves
Y
To be closed while carrying out maintenance during boiler shut down
LCV – 074
Attemperator line main isolation valve
Y
M – 068 A/B
Attemperator control station up stream motorized isolation valves
GT – 248 & 249
Attemperator control station down stream manual isolation valves
GT – 246 & 247
Attemperator drain line isolation valves
TCV – 068 A/B
Temperature control valve one is main line valve and another is bypass valve
Y
GT – 274
Attemperator header vent line valve
Y
GT – 275
Attemperator drain line valve
Y
M - 078
IP Drum EBD motorized valve
Y
GT – 631
IP Drum EBD manual valve
Y
Manual isolation valve keep lock open
GT – 628
IP Drum CBD manual valve
Y
Manual isolation valve keep lock open
M - 079
IP Drum CBD motorized valve
Y
This need to be open to maintain boiler water chemistry
GT – 615 & 616
LP Evaporator drain line valves
Y
To be open for initial water filling & hydro test
GT – 619 (02 NO’S)
Evaporator vent valve
Y
To be open for initial water filling & hydro test
IP ATTEMPERATOR SYSTEM
Y
To be closed while carrying out maintenance during boiler shut down
Y
To be closed while carrying out maintenance during boiler shut down Y
To be Opened when control valve is under maintenance To be open as per the steam temperature control requirement. One TCV kept closed and one will be use.
IP BLOWDOWN SYSTEM This need to be open in the event of Drum high level
IP EVAPORATOR
LP DRUM
Section C
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Operation & Maintenance Manual
Valve Tag Number
Service
GT – 359
Air vent is provided on the vapor tank with twin Valve
PCV - 083 GT - 362
Air vent is provided on the vapor tank
GT - 354
N2 Preservation Connection
GT – 353
LP drum pressure transmitters isolation valve
Open Close Remarks Y
Through the air vent, Steam and dissolved gases are vent out to the atmosphere
Y
Through the air vent, Steam and dissolved gases are vent out to the atmosphere Y
To be opened only when boiler is to be preserved with N2
Y
To be closed while carrying out maintenance during boiler shut down
GT – 356,357 & 358
LP drum local pressure indicator isolation valves
Y
To be closed while carrying out maintenance during boiler shut down
GT-341,342,343, 344 345 & 346
Isolation Valves for manifold on LP Drum for Level Indicating Instruments.
Y
To be closed while carrying out maintenance during boiler shut down
M - 094
LP Drum EBD motorized valve
GT – 612
LP Drum EBD manual valve
M - 095
LP Drum CBD motorized valve
GT – 630
LP Drum CBD manual valve
Y
Manual isolation valve keep lock open
GT – 347,348 & 350,351
Isolation Valves of LP Drum Level Gauge Glass
Y
To be closed while carrying out maintenance during boiler shut down
GT – 617
LP Superheater Inlet & Outlet Header Drain Isolation Valves
Y
To be kept lock open
M – 098
LP Superheater drain valve
Y
To be closed once condensate is removed completely.
GT – 381
Superheater inlet vent valve
Y
GI – 371
Main Steam line drain before MSSV
Y
GI – 374
Main steam line vent valve before MSSV
Y
GT – 376
Steam sampling system main isolation valve
Y
This need to be open in the event of Drum high level Manual isolation valve keep lock open
Y
Y
This need to be open to maintain boiler water chemistry
LP MAIN STEAM LINE
Section C
Y
To be closed while carrying out maintenance during boiler shut down
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Operation & Maintenance Manual
Valve Tag Number
Service
M - 091
Motorized isolation Valve of Startup Vent Valve
To be opened before opening
Y
Start up vent valve. To be Closed once rated pressure is attained and boiler is connected to load
PV -091
Startup Vent valve
M – 092 B
Motorised Motorised Pressure Pressure Equalization Valve of Main Steam Stop Valve
Y
To be opened for equalization of pressure.
M – 092 A
Motorized Main Steam Stop Valve
Y
To be opened after reaching the rated Pressure. Pressure.
GT – 379 & 380
Main steam line flow transmitter transmitter tapping line valves
3.5 Filling Water Water in Boiler For filling water in a cold HRSG, cold water from the plant DM line is preferred preferred through Boiler fill up lines. However However when the water is not deaerated, follow following ing procedure procedure is used for filling filling from the HRSG filling line. • During this this filling, for assurance assurance of correct correct steam drum water level, post an attendant at the drum level to monitor the local level and the hydrastep gauges and to communicate to the control room when a level of –100 mm is reached. reached. (Final level recommendations recommendations shall be set at the time of commissioning). • Filling Filling is done by feeding D.M water water to the HP, HP, IP & LP drain headers from the plant DM main. For this, • Open valves valves GT720, GT720, 722, 716, 716, 718, 718, 714 & 712 from DM water line at battery limit. • Ensure that all all the HP & IP economiser, economiser, HP, HP, IP & LP evaporator panel drain valves are open. • When air is released released and and water comes comes out from economiser vents GT671, GT626, GT672, GT673, these can be closed one by one. These valves need to be operated only during initial initial water filling. •
Open Close Remarks
When wate waterr level level of –150 –150mm mm is reac reached hed in the drum, DM water filling line valves GT 718,716,720,722,712 & 714 and drains of Economisers & evaporators GT616,615,636,621,627,620,660,654,679, 666,653,659,665,678 are to closed and the drain valves of HP ,IP & LP Drain headers to blow down tank GT669,695,622,624 GT669,695,622,624 605,607 is opened.
Section C
Y
Y
To be closed while carrying out maintenance during boiler shut down
• Deaerat Deaerator or storage storage tank can be filled filled up by using Condensate pump & opening battery limit isolation valve GT301. During cold start up three way control valve TCV102 shall remain close to CPH & direct entire water to Deaerator Deaerator through FCV 080A. Keep Deaerator level -50 mmwc below NWL to avoid swelling effect during initial start up. Caution Filling water temperature should not be more than 38 deg C of the boiler metal temperature. During filling filling of a cold cold boiler boiler,, the ambient ambient temperatur temperature e should be used as an indicator of the boiler metal temperature. temperature. Assuming Assuming an ambient temperature temperature of 40 deg C, the maximum temperature of filling water shall be 78 deg C.
3.6
HRS HR SG Star t Up & Press Pressurisation urisation
The The DC DCS S is link linked ed from from field field inst instru rume ment nts s to constantly update process information (Feed flow, steam flow, steam temperature, drum pressure, water/steam water/steam temperatures, temperatures, metal temperatures, temperatures, gas temperatures, temperatures, pressure/temperature pressure/temperatures s for pre trip trip alarm alarms s etc). etc). In the DCS, DCS, the info inform rmat ation ion is proc proces esse sed d and and base based d on prese presett logi logic c and set set point points, s, contr control ol comm command ands s are are sent sent to I/P I/P converters converters for control action. Alarm inputs etc are also from the DCS. 1. Start the HRSG preferably preferably along with GT start up cycle. During cold start up maintained the GT on Reserve spinning mode with 7 % load & ensure that the GT exhaust temperature is maintained below 377 Deg C. 2. Yet time time HR HRSG SG also also can can be star starte ted d afte afterr stabi stabili lisi sing ng GT opera operati tion on by lower lowerin ing g the
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Operation & Maintenance Manual
Load on GT and by lower the GT exhaust temperature below 377 Deg C.
3. Purgin Purging g of of HR HRSG SG 4. Steamin Steaming g & closure closure of various various drai drains ns & vents vents
3. Durin During g cold star startt up of HRSG HRSG,, as the super super heater heaters s are running running dry for few minutes minutes in transition condition. To safe guard the supper heat heater er & rehe reheat at SH tube tubes s it is esse essent ntia iall to cont contro roll the the GT exhau exhaust st tempe temperat rature ure by allowing allowing gas temperature temperature below 377 Deg.
7. Ch Charg argin ing g of CPH
4. Purg Purge e the the HR HRSG SG as per per GT star startt up sequ sequen ence ce (As recommended GT Supplier). Supplier).
Operator Action Action required dur ing HR HRS SG cold cold start -up
5. Start Start GT as as per the the GT star startt up sequen sequence. ce.
• Ensuring Ensuring permissible permissible rate of heat heat input to HRSG during start up.
6. During During cold cold / Warm Warm start start up, maintai maintain n GT in reverse spinning mode with 7% load on GT till the positive steam flow is established through super heater & re-heaters. Ensure that during cold start-up start-up of HRSG flue gas temperature temperature at the inlet of HRSG should not exceed 377 Deg C. Monitor the metal temperature of supper heaters heaters (HPSH3 < 612°C) & re-heater re-heater (RH 2 < 611°C). The heat transfer commences and the water in the HRSG gets slowly converted to steam as a result pressure of steam in the drum starts gradually gradually build up. The saturated steam temperature rise rate (and hence rate of rise in metal temperature) is controlled as per cold start-up pressurisation curve to safe guard against impermissible stress levels by modulating respective start up vent valves. 7. After having stabilised stabilised the positiv positive e steam steam flow through through superheater superheater & reheater, reheater, increase GT load gradually to pressurise the boiler as per Cold start up pressurisati pressurisation on curve. 8. Duri During ng star startt up & cont contin inuo uous us oper operat atio ion, n, monit onitor or the the skin skin me mettal temp tempe eratu rature re of HPSH3 < 612° C , & Reheat RH 2 < 611° C for for ensu ensuri ring ng cooli cooling ng.. If the Skin Skin me meta tall temper temperatur ature e reaches reaches set point, point, please please stop stop gas flow to HRSG. 9. Monito Monitorr Drum metal metal tempera temperature tures s HP Drum TE 037 A – 037 D < 321°C. 11. Monitor the water wat er level in the drum. drum. As the temperature temperature reaches about 90° 90 °C, a huge swelling of water level level in the drum drum takes place. place. The operato operatorr anti antici cipat pates es this this and and cont control rols s the the leve levell by openin opening g the EBD valve. valve. When the swellin swelling g in the drum level is over, EBD valve is fully closed To summarise each start up procedure needs to be followed followed for following sequence: 1. Line Line up of wa wate terr filli filling ng lines lines valve valves, s, HR HRSG SG system drains & vents. 2. Prep Prepar arat atiion/c on/che heck cks s to be done done befo before re admission of hot flue gases in HRSH
Section C
5. Pressur Pressurisat isation ion HP Bypass Bypass & Gland Sealing Sealing line charging charging 6. Cha Chargin rging g of reheate reheaterr
• Monitor Monitor Exhaust Exhaust gas gas temperatu temperature re in various zones. The temperatures temperatures of gas across various various sections sections of HRSG will start increasing after the GT exhaust gas enters in HRSG. • Operator can also also check check the local exhaust gas and temperature indications • Monitor Monitor Drum metal temperatures. temperatures. •
Monito Monitorr the wat water er level level in the the drum. drum. As the the temperature reaches about 90°C, 90°C, a huge swelling of water level in the drum takes place. The operator anticipates this and controls the level by opening opening the EBD valve. valve. When the swelling in the drum level is over, EBD valve is fully closed
• Initially Initially,, checking checking the local local level level gauges gauges and the level indicators takes a careful assessment of water level in the drum. Variations in levels between gauges are possible at low drum pressures are to be relied for true drum level indications which initiate trips at very high and very low levels. Request Request Instrument Instrument Engineer to reconcile the differences in levels between gauges if any. • Observe Observe the air air vent on drum. Air gets expelled expelled and steady steam starts coming out of the air vents • Observe Observe drum pres pressure sure at at DCS as also also local local pressure gauge at drum • When drum pressure pressure shows shows 2 kg/cm², kg/cm², drum air vents can be closed • When the the steam steam pres pressure sure builds builds up up to 3 –5 kg/cm² , the super heater drain valves are to be closed. (If required, manually operated drain valves are also closed) • When the the swelli swelling ng phase phase of drum drum water water level level is over and the level shows a decreasing decreasing trend, the 30% feed control can be taken into service by opening Control valve can be positioned as required required manually to maintain maintain drum level
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Operation & Maintenance Manual
• Ensure CBD, CBD, feed water and and super heated heated steam samples are flowing to the coolers and the pH, conductivity meters are in operation. Verify pH and conductivity is within permissive values.
• Start Start taking taking feed feed water water through through 30% 30% control control valve as per the requirement. Water shall flow to steam drums. drums. CPH can be taken on line line once the flow established and the flue gas exit temperature is above acid dew point.
• Verify Verify the HP dosing dosing mixing tank tank level is more more than 50% and a 5% phosphate solution is available available in the tank. Place one HP dosing pump in service.
•
• Similarl Similarly y Verify Verify the IP & LP dosing dosing mixing mixing tank level is more than 50% and a solution is available in the tank. Place one IP & LP dosing pump in service.
Section C
Allow Allow th the e HRSG HRSG steam steam pressur pressure e and temperature to build up to rated temperature and pressure by suitably modulating the individual Start up vent valve and if required the GT load.
• Monitor Monitor the the steam steam drum drum water water level level.. • Monitor the the parameters, parameters, which which can cause cause a HRSG trip.
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Operation & Maintenance Manual
3.7
HRS HR SG Cold St St art Up Curve Curve
HRSG Cold HRSG Cold Start Start Up Press Pressuri urisi sing ng Curve Curve for for HP Section Please refer section E — Curves
Section C
The The pres pressu suri risa sati tion on curv curve e for cold cold sta start up alon alongw gwit ith h GT oper operat atiion for for HP sect sectiion is illustrated above. The cold start up curve of IP & LP section will follow the pressurisation according to the heat input received based on HP section curve.
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Operation & Maintenance Manual
3.8 Taking Reheater On Line This section describes how to take Reheater on line through HP & IP section. Reheater has to be charged simultaneously through HP & IP section as per the criteria mentioned charging procedure of reheater, only to bring upon clarity procedure is explained here separately (section wise). 3.8.1Chargin g HP Steam to Reheater 1. Keep Open start up vent valve PCV 079 & isolation valve GL 736 provided on hot reheat line for maintaining positive steam flow through re-heater. 2. Once the steam pressure at HP super heater outlet reaches 5 bar, open HP steam stop equalization /bypass valve M029B 100% and charge HP steam line as per steam line charging procedure after heating main steam line by HP steam stop bypass valve M029B and close the bypass valve after opening the HP steam stop valve M029A 100% . 3. When the swelling phase of HP Steam drum water level is over and the level shows a decreasing trend, the 30% feed control can be taken into service by opening isolating valves of FCV 003A, Control valve FCV 003A can be positioned as required manually to maintain drum level 4. Before charging the HP steam line, ensure steam line drain valves (GT 668, GL731) are open to drain out the condensate and close the drain line valve. Before charging HP steam line ensure that the turbine inlet valve is closed. 5. Once HP steam line is charged, throttle HP start up vent valve to follow HP steam pressurisation curve & ensure that sufficient steam is getting passed through Reheater. Pass entire HP steam through reheat and ensure that steam temperature at cold reheat is maintained below 380 Deg. C by operating PCH 0101 (HP to IP bypass valve) in auto / manual mode, as required. 6. Ensure reheat SH is drained properly for water / condensate before charging by operating motorised drain valve M038C for Reheater-2 to be operated. These valve is to be closed as soon as condensate/ water is drained out completely & steam start coming through it (max for 5 min). Ensure that drained water led to blow down tank. 7. Control the steam temperature at outlet of reheat using attemperator control valve
Section C
TCV 068A in auto / Manual mode, as per requirement of steam turbine. 8. Vent the hot reheat steam to atmosphere through Start up vent valve (Valve tag will be added later ) provided on Hot Reheat line till condenser is made ready. Once the Condenser is available to dump the hot reheat steam , line up the IP - LP bypass PRDS PCH0101 and start dumping hot reheat steam to condenser. Once the steam flow through IP - LP bypass PRDS PCH0101 to the condenser is established slowly close the start up vent valve by looking in to the steam pressure at reheater out let and allow entire hot reheat steam to go to Condenser. Place the IP - LP bypass PRDS PCH0101 in auto mode. Steam comes out from Reheat Module 2 is termed as Hot reheat steam. 9. Keep watch on Reheat 2 metal temperature for proper cooling.Caution: To safeguard the Reheater Tubes, it is essential to maintain positive steam flow either by venting steam through start up vent valve provided on hot reheat steam line or by dumping the steam directly to Condenser when it is operational. 10. Now allow HP steam to pressurize as per pressuring curve by controlling start up vent valves opening. Once the HP steam pressure reaches near about 23 bar put the HP by pass PRDS ( PCH 0101) to Reheat in auto mode with 25 bar set point. 11. PSV 302 on cold reheat & PSV 072 on hot reheat line safeguard the reheat SH from high pressure. 12. Continue the operation till HP turbine is put in operation and ensure sufficient steam passed to cold heat line.
3.8.1.1 Charging IP steam to reheat 1. Now the cold reheat line gets HP steam from HP section through PRDS valve PCH 0101 and IP section is getting pressurised as per the start up curve maintaining steam venting to atmosphere through IP start up vent valve PCV063. 2. Open HP to IP bypass valve for leading CRH (Cold Reheat) flow through Reheater. Keep HP start up vent valve throttled to follow HP pressurization curve at the same time ensure positive steam flow through Reheater. once the IP steam pressure reaches to 5 bar or above CRH steam pressure (0.5 bar above RH pressure), synchronize the IP main steam pressure with cold reheat pressure (open PCV
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Operation & Maintenance Manual
129 gradually & introduce steam to CRH. This pressure matching can be done by positioning start up vent valves as per the requirement on HP line PCV028 & on IP line PCV063. NRV 254 in the IP main steam line shall take care of reverse flow of HP steam to IP section. Once IP section working pressure @ 24.3 bar is reached put PCV 129 in auto mode with set pt of 24.3 Bar. 3. Keep watch on flue gas temperature at IP SH inlet. Once the HP steam & HRH steam quality is achieved as per requirement , charge the steam to turbine. After rolling the turbine, once the cold RH steam starts HP turbine HP steam bypass valve closes accordingly in auto mode and closes fully once full-fledged cold reheat steam flow is established from turbine. Further loading of HRSG can be done by increasing load on GT as per load requirement. Loading is done without firing the burners, which is called unfired mode of HRSG operation. Boiler steam generation is limited depending upon the GT load or the exhaust gas flow rate and temperature (heat input to HRSG).
3.9
Charging & Operati on of CPH
CPH charging can be considered as the last most activity in Start up procedure of entire HRSG. During initial water fill up, drain line common isolation valve GT603 & GT 604 will be closed and common vent valve GT 609 shall be kept opened as long as air is purged out completely & then it will be closed. Other Manual valves in the system shall be kept locked open except for maintenance. During cold start up of HRSG, Condensate preheater (CPH) will be kept bypassed completely. This is to avoid steaming in CPH , during transient period of start up due to high gas temperature at CPH inlet there is always chance of steam generation in CPH . Bypassing CPH will also help to keep the deaerator pressure / temperature rise under control. Deaerator temperature will be high during start up and at lower loads which will lead to more venting of steam. Admitting the DM water/Condensate at ambient temperature (condensate return temp.) directly into the deaerator through the CPH bypass, will reduce the venting steam quantity. Deaerator pressure control valve will kept in auto mode during start up with pressure set
Section C
point. However the deaerator pressure will be maintained by controlling LP start up vent valve as per LP pressurising curve. CPH can be charged when once the HRSG start up stabilised and loaded. Once, the boiler is loaded comfortably the flow through CPH can be modulated on observing the deaerator pressure / temperature. Flow through CPH is adjusted in such a way that the difference between Deaerator temperature and CPH outlet water temperature is around 15 Deg C. Condensate is fed to CPH at around 57 Deg C & CPH heats it up to 137 Deg C. Once the CPH is charged start the CPH water circulation pump and put the TCV 108 in auto mode with a set point to maintain the flue gas temperature to stack. During cold start up keep the circulation pump in stop condition. Emergency action HRSG TRIP Close the MSSV and boxup the HP,IP & LP section at prevailing condition. Take out CPH from line by modulating the 3 way valve TCV- 102. Slowly bypass the CPH by closing inlet and outlet valve. The CPH bypass valve GT 314 should be open so that the condensate bypasses the CPH. The CPH can be taken out of line.
3.10 Parallel HRSG to the Plant Steam Mains Parallel HRSG to the Plant Steam Mains Paralleling HRSG to the steam mains of the plant is an important operation to be carefully done without affecting the temperature of steam in the plant. The pre requisites for this operation are: • Building the steam pressure in HRSG to a pressure slightly more than plant steam pressure. This is controlled by modulating the Start up vent valve and if required modulating the GT load. Take into account the permissible rate of drum pressure increase to position the vent valves. • Building the steam temperature (Alternately one can settle for a lower steam temperature initially if it would not cause any problems down stream. To compensate for temperature difference increase temperature of other boiler connected to header).
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Operation & Maintenance Manual
• With the build up of required steam pressure and temperature in HRSG, the main steam stop valve can be opened
permissible heat input rates so as to obtain quickly the required HP steam pressure and temperature .
• When the HP Steam Pressure reaches the pressure of 5 Bar(a).
In event of GT trip first & foremost important duty of operator is to close all steam outlets, close chimney inlet isolation damper & maintain drum water level as recommended. As the HRSG was in service till the trip out, the required valve line up (as was stated for cold start up) will be available except for few vent valves these valves can be quickly verified as per the below mentioned list. Hot restart requires operations to be done fast, using the maximum permissible heat input rates so as to obtain quickly the required HP/IP section steam pressure and temperatures. The HRSG hot restart sequence will comprise of various operations as detailed below:
• Initiate an open command for HP Main steam stop valve and observe – Valve [M-029B] opens; The pressure differential across MSSV [M-029A] starts decreasing and when ∆P at MSSV <5 bar (a) – Valve [M-029A] opens and when open feed back is received, – -Valve [M-029B] (MSSV by-pass) close With the opening of valve [M-029A] , HRSG is ready for supply of HP steam to the plant. • Similarly for LP section • Initiate an open command for LP Main steam stop valve and observe – Valve [092B] opens; The pressure differential across MSSV [M-092A] starts decreasing and when ∆P at MSSV <5 bar (a) – Valve [M-092A] opens and when open feed back is received, – -Valve [M-092B] (MSSV by-pass) close With the opening of valve [M-092A] , HRSG is ready for supply of LP steam to the plant. • Reduce the opening of the start up vent valve to about 15%. • Attemperator can be taken in service if Superheater outlet temperature is exceeding rated value. • Observe steam temperatures after the superheater of individual sections. • Observe the feed control station. When output signal from Level Indicating Controller exceeds 65%, full load control station comes into service .
4
Hot and Warm Start up of HRSG
Hot Start up of HRSG Restarting the HRSG immediately after a trip out, when the HRSG is still hot, with steam pressure not less than 40bar (a) is termed as a hot restart. As the HRSG was in service till the trip out, the required valve line up (as was stated for cold start up) will be available and can be quickly verified by visual inspection. Hot restart requires operations to be done fast, using the maximum
Section C
The HRSG hot restart sequence will comprise of various DCS and manual operations as detailed below 1. Start GT as per GT start up cycle. During Hot start up maintained the GT at 15 % load & ensure that the GT exhaust temperature is maintained at 510 Deg C. 2. During hot start up of HRSG, to avoid superheater & reheater running dry do not open start up vent valves of HP section(PCV028) & IP section(PCV129). Open HP main steam stop valve & pass 100% HP steam generated through cold & hot reheat & dump into condenser by opening IP bypass valve (PCH0101). Similarly dump the LP steam to condenser through LP bypass valve (PCH0101). 3. Bypass CPH from water side to avoid steaming during start up. 4. Ensure that drain valves to Blow down Tank of HP SH Drain header (GT688), Reheater Drain Header (GT650), IP RHS Drain Header (GT 622) & IP LHS side header (GT 624) are open.During Hot start up of boiler super heater & atteperator motorized drain valve need to be opened for say 1 min for removal of condensate then leave the following valves crack open till respective section superheater outlet temperature reaches or 100% condensate is drained out. Following are the valves need to be operated • HP Section – HP superheater 2 & 3 header motorised drain valve M038B & F – HP Superheater 1 motorised drain valve M038D/H
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• Reheater Section – Reheater 1 & 2 motorised drain valve M038C, Reheater 2 drain valves FVM – D201 • IP & LP Section – IP superheater motorised drain valve M076 – LP superheater motorised drain valve M098 • Ensure following vent valves are Closed – HP Drum vent valve M005A & M005B – IP Drum vent valve M061 5. Ensure that GT is maintained at 15% load & exhaust temperature is maintained at 510 Deg C. 6. Ensure that during hot start-up of HRSG flue gas temperature at the inlet of HRSG is maintained at 510 Deg C. Monitor the metal temperature of super heaters (HPSH3 < 612 Deg. C) & re-heater (RH 2 < 611 Deg. C). The heat transfer commences and the water in the HRSG gets slowly converted to steam as a result pressure of steam in the
Section C
drum starts gradually build up. The saturated steam temperature rise rate (and hence rate of rise in metal temperature) is controlled as per hot start-up pressurisation curve to safe guard against impermissible stress. 7. After having stabilised the positive steam flow through superheater & reheater, increase GT load gradually to pressurise the HRSG. 8. During start up & continuous operation Monitor the skin metal temperature of HPSH3 < 612 Deg. C , & Reheat RH 2 < 611 Deg. C for ensuring cooling. If the Skin metal temperature reaches set point please stop gas flow to HRSG. 9. Monitor Drum metal temperatures HP Drum TE 037 A – 037 D < 321 Deg. C. 10. Monitor the water level in the drum. There may be chance of swelling of water level in the drum. The operator anticipates this and controls the level by opening the EBD valve. When the swelling in the drum level is over, EBD valve is fully closed 11. Once the HRSG operation is stabilised & steam parameters suitable for STG operation is reached supply steam to STG.
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HRSG Hot Start-Up Curve for HP section Please refer section E — Curves
of IP & LP section will follow the pressurisation according to the heat input received based on HP section curve.
The pressurisation curve for hot start up for HP section is illustrated above. The hot start up curve
Section C
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Operation & Maintenance Manual
Warm Start up of HRSG Restarting of a hot HRSG within few hours time after a trip or stoppage, with the HRSG steam pressure of not less than 10-kg/cm² (g) is termed as a warm start . In event of GT trip first & foremost important duty of operator is to close all steam outlets, close chimney inlet isolation damper & maintain drum water level as recommended. As the HRSG was in service till the trip out, the required valve line up (as was stated for cold start up) will be available except for few vent valves these valves can be quickly verified as per the below mentioned list. The HRSG warm restart sequence will comprise of various operations as detailed below 1. Start GT as per GT start up cycle. During warm start up maintained the GT on Reserve spinning mode with 7 % load & ensure that the GT exhaust temperature is maintained at 430 Deg C. 2. During warm start up of HRSG, to avoid superheater & reheater running dry do not open start up vent valves of HP section(PCV028) & IP section(PCV129). Open HP main steam stop valve & pass 100% HP steam generated through cold & hot reheat & dump into condenser by opening IP bypass valve (PCH0101). Similarly dump the LP steam to condenser through LP bypass valve (PCH0101). 3. In case if condenser is not ready to dump the steam then follow the procedure as mentioned in cold start up procedure for steam venting & pressurisation. 4.
Bypass CPH from water side to avoid steaming during start up.
5. Ensure that drain valves to Blow down Tank of HP SH Drain header (GT688), Reheater Drain Header (GT650), IP RHS Drain Header (GT 622) & IP LHS side header (GT 624) are open.During warm start up of boiler super heater & attemperator motorized drain valve need to be opened for say 1 min for removal of condensate then leave the following valves crack open till respective section superheater outlet temperature reaches or 100% condensate is drained out. Following are the valves need to be operated • HP Section – HP superheater 2 & 3 header motorised drain valve M038B & F
Section C
– HP Superheater 1 motorised drain valve M038D/H • Reheater Section – Reheater 1 & 2 motorised drain valve M038C, Reheater 2 drain valves FVM – D201 • IP & LP Section – IP superheater motorised drain valve M076 – LP superheater motorised drain valve M098 • Ensure following vent valves are Closed – HP Drum vent valve M005A & M005B – IP Drum vent valve M061 6. Ensure that GT is maintained at 7% reserve spinning & exhaust temperature is maintained at 430 Deg C. 7. Ensure that during warm start-up of HRSG flue gas temperature at the inlet of HRSG ia maintained at 430 Deg C. Monitor the metal temperature of supper heaters (HPSH3 < 612 Deg.C) & re-heater (RH 2 < 611 Deg. C). The heat transfer commences and the water in the HRSG gets slowly converted to steam as a result pressure of steam in the drum starts gradually build up. The saturated steam temperature rise rate (and hence rate of rise in metal temperature) is controlled as per warm start-up pressurisation curve to safe guard against impermissible stress. 8. After having stabilised the positive steam flow through superheater & reheater, increase GT load gradually to pressurise the HRSG. 9. During start up & continuous operation Monitor the skin metal temperature of HPSH3 < 612 Deg. C , & Reheat RH 2 < 611 Deg. C for ensuring cooling. If the Skin metal temperature reaches set point please stop gas flow to HRSG. 10. Monitor Drum metal temperatures HP Drum TE 037 A – 037 D < 321 Deg. C. 11. Monitor the water level in the drum. There may be chance of swelling of water level in the drum. The operator anticipates this and controls the level by opening the EBD valve. When the swelling in the drum level is over, EBD valve is fully closed 12. Once the HRSG operation is stabilised & steam parameters suitable for STG operation is reached supply steam to STG.
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HRSG Warm Start up Curve for HP section Please refer section E — Curves
start up curve of IP & LP section will follow the pressurisation according to the heat input received based on HP section curve.
The pressurisation curve for warm start up for HP section is illustrated above. The warm
Section C
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Operation & Maintenance Manual
5
H RSG Sh u t d ow n
Shutdown of HRSG can be of two types 1. Planned shutdown for maintenance, inspection, where the operator gets advanced notice. 2. Trip on protection or a stop due to emergency. Suggested action by the operator for the above types of shutdowns are indicated below
5.1
Planned Shutdow n
A planned shut down has to be coordinated with other working boilers such that loads reduced from the HRSG are picked up by them without affecting the performance of the plant • Reduce to the load to 50% MCR by reducing the GT load. • Depending on the GT load restrictions, continue to reduce GT load till the HRSG reaches minimum MCR mode of operation. Also reduce the steam demand from the plant or transfer the steam load to other boilers. Close the Main steam stop valve. • Stop the gas turbine. • On the working HP dosing pump, charge over to DM water to the pump inlet and close the phosphate solution inlet to the pump. Run the HP dosing pump for about one hour to keep the line clear of phosphate up to the drum. • Close CBD valve. • Allow the HRSG to cool down naturally. Maintain water level in the drum till the pressure drops to 2-bar (g) • At 2 bar (g) pressure (or slightly lower) open the respective section Drum vent valves. • If water is to be drained from HRSG, normally it can be done only when the drum pressure drops below 1.25 bar (g)
5.2
HRSG Emergency Trips
Emergency trips can occur in HRSG due to any of the following causes: • HP Drum level very Low • IP Drum level very Low • LP Drum level very Low • HP Steam O/L Pressure high-"Hi Hi Pressure Trip In Case of STG Trip and HP Bypass System Valve Not Open
Section C
• GT Exhaust gas Pressure high at inlet of HRSG.
HRSG Trip Due to Gas Turbine Trip In this case the operator action is to shut down the HRSG, if restart of the Gas Turbine will be delayed. Close CBD valve, feed water control station isolation valve after maintaining level in the steam drum. Close Main steam stop valve. HRSG is started when the Gas Turbine comes into service.
HRSG Trip Due to Instrument Air Failure When the HRSG trips due to instrument air failure, exercise extra caution to see that the fail-safe valves do not endanger the boiler. E.g. if feed control valves remain full open, isolating valves before or after the control valves are to be closed; start-up vent valve remain full open, hence close the manual isolation valve. This scenario will likely result into a plant blackout. HRSG to be restarted after restoration & normalising of all services.
HRSG Trip Due to Power Failure In an extreme case of power failure, HRSG may trip due to tripping of Seal air fans. Instruments and controls may still be available as they are usually powered from UPS (please check theplant philosophy). However the status of availability of instrument air, feed water supply and fuel supply will determine the continuation of HRSG in operation.
Operation In The Event Of STG Trip & HRSG Running Condition When ever STG trips, while HRSG is in operation, dump the hot reheat steam to condensor through HP, IP/LP bypass PRDS and pass the steam through reheat to cool the reheat. During STG trip & hot start-up ensure that HP to cold reheat bypass PRDS is opened immediately without any delay during this watch the reheat metal temperature.
Safe Gaurding the HRSG after a Trip • Upon tripping of steam turbine, entire steam will get dumped to condenser via HP,IP,LP Bypass. • In case of failure of bypass valve safety valves provided on respective section steam drum & superheater section will release the steam also start up vent valve shall be open to release the steam in auto mode.
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• Continue to supply feed water to the drum to maintain normal level, after closing the CBD and sample line valves. • Investigate the cause of the trip from the first up signals and DCS data acquisition system. If the cause of the trip is known, rectify the cause and opt for restart of HRSG.
6
Cooling of a Shutdow n Boiler
Aim This chapter describes the methods of cooling a shut down HRSG and the steps to be taken to preserve the HRSG to minimize corrosion. System Description HRSG after shut down has to be cooled carefully. It is recommended to cool the HRSG under normal circumstances at the rate of heating. If the cooling rate is accelerated, thermal stresses develop in the thick components such as the steam drum, Economiser, Evaporator, Super Heater headers, attemperator etc., A HRSG is shut down either for keeping it in reserve as a stand by unit or for maintenance and inspection. The purpose of the shut down determines the method of cooling to be adopted
6.1
to be reduced to a minimum, forced cooling of the HRSG is done. After the shut down of the HRSG, the HP,IP & LP dosing, CBD, EBD and SWAS valves are closed as for natural cooling. Water level in the HP ,IP & LP drum is also maintained between permissible levels till the steam drum pressure falls to 2 bar (a). For 8 hours after the shut down, the HRSG is allowed to cool naturally in the boxed up condition. After 8 hours, access doors on HRSG are opened to allow airflow through the HRSG to the stack. De-pressurization of steam in the HRSG is also speeded up by controlled opening of the start up vent valve De-pressurization rate is not to exceed 10kg/cm2 per hour. However forced cooling is not done unless absolutely essential.
7
1. Check for unusual noises. This may be from steam or water leakages. 2. Check for steam or water leaks from valves, connections and fittings. 3. Check for unusual traces of water on floor. 4.
Check for air / flue leakage from windbox, HRSG casing and ducting.
5.
Walk around the furnace exterior and observe for any hot spots or gas leaks.
6.
Check for passing from safety valves at normal operating pressure. Check that the drain lines and drip pans are not plugged.
N atural Cooling
The HRSG after a shut down is allowed to cool slowly in a ‘boxed up condition’. The following valves are also closed. • HP,IP & LP dosing to Drum • CBD /EBD valve of all HP ,IP & LP Drum • Sample line to HRSG water/saturated steam / SH steams to Swas The HRSG cools slowly, loosing its heat by radiation to the environment. Till the HP ,IP & LP steam drum pressure drops to 2-bar (g), permissible water level is maintained in the drum (+150mm to – 250mm) by intermittent feeding. After the steam drum pressure falls below 2-bar (g) maintaining water level in the drum is not essential. When the steam drum pressure is less than 2-bar (a) , the access doors in the HRSG are kept open to create a natural draught through the HRSG to the chimney. HRSG cools to an accessible level in about three-four days.
H RSG Op er a t i on W al k Do w n Checks
7. Check to see that proper water level is being shown by the direct water level gauge. Check for water or steam leak from ports or drain connections, which will cause a false water level in the gauge glass. Inspect the glass for discoloration or fouling. 8. Check for expansion.
8
any
obstruction for
thermal
D o’ s a n d Do n ’t s Fo r H RSG Operation
Do’s 1. Maintain all instruments in good working condition. 2. All equipment interlocks should always be in line.
6.2 Forced Cooling
3. Maintain normal water level in steam drum.
If the HRSG has to be made available for inspection or repair and the shut down time has
4. Maintain water quality as per the recommended limits. A table showing the
Section C
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Operation & Maintenance Manual
DM water & drum water quality is included at the end of this section .
17. In case of power failure, close the steam stop valve.
5. Pressure raising from cold start must be done as per the cold start up curve.
18. If the water level goes up above the limits operate the emergency blowdown valve immediately and maintain the water level to normal .
6. All the duct joints must be leak proof. 7.
Use proper lubricant and maintain the schedule as recommended by the manufacturers.
8. Operate the HRSG within the recommended operation limits . 9. HRSG, piping, insulated.
ducts must be properly
19. Maintain the feedwater temperature at economizer inlet and flue gas temperature at economizer outlet as recommended . 20. Use genuine spares. 21. HRSG surroundings and equipments must be properly illuminated. Don’ts
10. Servicing of equipment should be done as per the manufacturer’s schedule .
1. Don’t bypass any instruments and safety interlocks
11. Maintain regularly.
2. Don’t use raw water as HRSG feedwater
proper
operation
log
sheets
12. Maintain the instrument air free from moisture and oily matters and the pressure as recommended . 13. Carry out regular cleaning of direct water level gauge glasses of HRSG drum. 14. Use proper valve gland packing to avoid leakage . 15. Use proper gaskets for flange joints . 16. Operate the blowdown recommendation.
Section C
valves as
per
3. Don’t operate the operation limits.
HRSG
beyond
the
4. Don’t leave the furnace door open while the HRSG is in operation 5. Don’t mix up different lubricants 6. Don’t alter schedule
the
equipment
maintenance
7. Don’t leave the instrument control panel unattended 8.
Don’t allow unauthorized persons to operate the HRSG and associated equipments
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9
Bo i le r Lo g Sh ee t
5. HRSG trips with reasons and time
It is suggested to record the HRSG parameters during startup and normal operation. Observed abnormalities (if any) recorded can be used for analysis, troubleshooting and maintenance purposes.
6. HRSG running hours. 7. HRSG shut down details (forced or planned, outage hours, jobs carried out, etc.,) Sample log sheet is enclosed.
1. Log sheet to be filled once in every hour by the operating staff. 2. Feedwater, HRSG water quality are also to be noted once in four hours
9.1
3. Total steam production of a day to be noted.
Date:
4. Logbook should furnish the details about
Shift:
SL. NO
PARAMETER
UNIT
1
GT LOAD
MW
2 3
HP
DRUM LEVEL
mmWC
IP DRUM LEVEL
mmWC
DRUM LEVEL
mmWC
5
HP MAIN STEAM PRESSURE
Bar (a)
6
IP MAIN STEAM PRESSURE
Bar (a)
7
LP MAIN STEAM PRESSURE
Bar (a)
4
8 9 10
LP
HP
STEAM FLOW
TPH
IP
STEAM FLOW
TPH
LP
STEAM FLOW
TPH
11
FEED WATER PRESSURE AT HP CONTROL STATION INLET
Bar (a)
12
FEED WATER PRESSURE AT IP CONTROL STATION INLET
Bar (a)
13
FEED WATER PRESSURE AT LP CONTROL STATION INLET
Bar (a)
14
CONDENSATE TEMP.BEFORE CPH
DEG C
Section C
TIME
Log Sheet for HRSG
TIME
TIME
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Operation & Maintenance Manual
SL. NO
PARAMETER
UNIT
15
CONDENSATE TEMPERATURE AFTER CONDENSATE PRE-HEATER
DEG C
16
FEED WATER TEMP. AT HP ECO I INLET
DEG C
17
FEED WATER TEMP. AT HP ECO 1 OUTLET
DEG C
18
FEEDWATER TEMP. AT HP ECO 2 OUTLET
DEG C
19
FEED WATER TEMP. AT HP ECO 3 OUTLET
DEG C
20
FEED WATER TEMP. AT IP ECONOMIZER INLET
DEG C
21
FEED WATER TEMP. AT IP ECONOMIZER OUTLET
DEG C
22
FLUE GAS TEMP. AT DD OUTLET
DEG C
23
FLUE GAS TEMP. AT HP SUPERHEATER 3
DEG C
24
FLUE GAS TEMP AFTER REHEATER
DEG C
25
FLUE GAS TEMP AFTER HP EVAPORATOR
DEG C
26
FLUE GAS TEMP. AFTER HP ECONOMIZER 3
DEG C
27
28
FLUE GAS TEMP. AFTER IP ECONOMIZER FLUE GAS TEMP. AFTER LP EVAPORATOR
Section C
TIME
TIME
TIME
DEG C
DEG C
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Operation & Maintenance Manual
SL. NO
PARAMETER
UNIT
29
FLUE GAS TEMP. AFTER CONDENSATE PRE-HEATER
DEG C
30
FLUE GAS PR. AT DD OUTLET
mmWC
31
FLUE GAS PRESSURE AT HP SUPERHEATER 3
mmWC
32
FLUE GAS PRESSURE AFTER REHEATER
mmWC
33
FLUE GAS PRESSURE AFTER HP EVAPORATOR
mmWC
34
FLUE GAS PRESSURE AFTER HP ECONOMIZER 3
mmWC
35
FLUE GAS PRESSURE AFTER IP ECONOMIZER
mmWC
36
FLUE GAS PRESSURE AFTER LP EVAPORATOR
mmWC
37
FLUE GAS PRESSURE AFTER CONDENSATE PRE-HEATER
mmWC
38
FLUE GAS TEMP. AT STACK
DEG C
Section C
TIME
TIME
TIME
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SL. NO
PARAMETER
UNIT
TIME
TIME
TIME
Feed Water Analysis pH Conductivity 39
TDS Silica Hardness Oxygen Drum Water Analysis: pH
40
TDS Alkalinity as CaCo3 Silica Phosphate Po4
as
Sulphite as SO3 Sat. & Sh Steam Analysis: pH 41
Conductivity TDS Silica
Operator Name:
Date:
Signature:
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10 Boiler Emergency Safety Procedures
1. Feedwater control malfunction
10.1 Emergency Procedures
3. Instrument air supply failure
Low Water Level
Action
Causes
1. Take the drum level control loop into manual mode
1. Feedwater control system failure. 2. BFP failure 3. Tube leak Action Compare control room indication with gauge glass level. If the water level falls out of sight due to momentary failure of water supply system, due to negligence of the operator, due to momentary fluctuations that might occur with extraordinary changes in load, appropriate action should be taken at once to trip the fuel. Any decision to continue to operate, even if only for a short time at a reduced rating would have to be made by someone in authority who is thoroughly familiar with the circumstances that led to the emergency and positively certain that the water level can be restored immediately without damaging the boiler.
2. Operator error
2. Reduce the water level immediately by operating the intermittent blow down to maintain the drum level 3. Reduce the necessary
steam
discharge
rate,
if
4. If instrument air supply failure, then open the by manual operated pass valve to maintained the drum level Boiler Explosion Causes 1. In-sufficient purging of furnace With the mixture of unburned fuel with air in explosive proportions and the application of heat sufficient enough to raise the temperature of the mixture to ignition point.
In the absence of such a decision
Action
1. Shut off the main steam stop valve .
1. Analyse the reasons for explosion and rectify the system
Simultaneously, if feedwater has become available and the operator is assured that no pressure part has been damaged
2. Evacuate or clean the furnace to the possible extend
1. Take the feedwater control system into manual mode
Conditions f or Boiler Restart after Furnace Explosion
2. Allow the water flow to boiler gradually to normal water level. (Do not hurry up which may lead to sudden quenching and tube leak) if pressure part damage is suspected
After a case of furnace/ boiler explosion, the restart of the boiler has to be carried out only after a thorough and detailed investigation & understanding of the cause of explosion. Following necessary actions have to be completed to prevent the repeat incidence of explosion and before restart of the boiler.
3. Reduce the steam pressure gradually 4. Open the drum air vent when the pressure drops below 2 kg/cm² 5. Cool the boiler so as to examine the extent of damage 6. Drain the boiler after cooling 7. If any tube rupture and bulging is observed rectify the same 8. If any tube leakage were observed rectify / repair the leaking tubes and after the repairs conduct hydrotest 9. Determine the cause of low water High Water Level Causes
Section C
Find out the root cause for the explosion and rectify the same. 1. Inspect the furnace for any signs of bulging or damage to the tubes. 2. Inspect the expansion bellows in the air and flue ducts for damages 3. Inspect the economizer casing for damages 4. Assess the damage if any and rectify the same. 5. Carry out the hydro test of the boiler. In the event of a failure of the hydro test, identify the tubes that have failed and proceed to rectify
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the same as explained in the maintenance section.
Section C
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10.2 Alarms and Trips Note
1. These Alarm and Interlock values can be revised at the time of commissioning of the boiler. The final revised alarms and interlocks list shall be submitted post commissioning of the boiler.
10.3 Operational Precaut ions for Safety Operating the HRSG with low feedwater temperature will result in corrosion of economizer coils. The raising and lowering of steam parameters should be restricted to the value given in the starting diagram. Exceeding these values will result in reduced fatigue life of pressure parts. In case of tube failure, which can be identified by hearing the noise in the HRSG gallery and increase in draught pressure, flue gas and steam temperature, the HRSG should be shutdown at the earliest by regular procedure for maintenance work. Otherwise large number of surrounding tubes may fail due to steam erosion and impingement. Boiler salt in the wet steam will accelerate corrosion. Always use deaerated de-mineralized water for boiler feeding. Carryover of salt in steam occurs either due to mechanical or vapor carryover from steam drum. Efficient drum internals can only reduce mechanical carry over. Silica is always carried over in vaporous form. Continuous monitoring of sodium and silica in boiler water and steam is desirable. Before operating a HRSG, ensure complete knowledge of water chemistry. Whenever HRSG is started after a shutdown of more than 3 days, check all safety interlocks before HRSG start up for proper functioning. The steam drum should normally be filled up to the point when water is showing in the bottom part of the gauge glass. This is to allow for the swell on heating and to reduce any blowing down resulting from this cause to a minimum. Once the HRSG is boxed up, the water level in the steam drum must be raised to the very top of the drum. Filling the drum like this will prevent
Section C
excessive temperature differentials along the drum wall. The water is then shut-off and the HRSG is allowed to cool.
10.4 Tube Failures Operating the boiler with a known tube leak is not recommended. Steam or water escaping from a small leak at pressure can cut other tubes by impingement and set up a chain reaction of tube failures. Large leaks can be dangerous. The boiler water may be lost, the ignition may be lost and boiler casing can get damaged. Small leaks can sometime be detected by the loss of water in the cycle or system. A loss of boiler water chemicals or by the noise made by the leak. If a leak is suspected the boiler should be shut down as soon as possible by following the normal shutdown procedure. After the exact location of the leak or leaks is located, the leaks may be repaired by replacing the failed tube or by splicing in a new section of tube, conforming to relevant ASME code. An investigation of the tube failure is very important so that the condition causing the tube failure can be eliminated and future failures can be prevented. This investigation should include a careful visual inspection of the failed tube and in some cases a lab analysis. It is recommended that every effort be made to find the cause of tube failures before operation is resumed.
10.5 Safety in Boiler House It is expected that the final user will evolve a comprehensive safety code for all operations in the plant. A few suggestions are listed below which can form part of the plant safety code for the HRSG. • The boiler operation and maintenance staff must recognize hazards of high pressure, high temperature steam and water . • Furnace explosion is also possible if boiler operating instructions are not followed or if the protections are bypassed. • Before startup of a HRSG, ensure that all maintenance personnel, tools, scaffolding etc. have been withdrawn from the HRSG. (Steam Drum, gas ducts, stack etc.) Ensure that all manholes, peepholes, inspection doors have been properly closed and pad locked.
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Operation & Maintenance Manual
• Do not attempt to open the observation ports in a working HRSG without observing proper safety procedure.
• Before entering through gates and dampers, ensure that their drive mechanism have been locked.
• Use a full face mask and tinted glass for safety
• Before removing manholes or flanges in drum or pipeline, ensure that the drum/line has been isolated and drained.
• For personal safety in handling hot valves, piping, oil guns etc. wear protective gloves while working around the HRSG. • Never enter drums, ducts, furnace etc., until the HRSG has been shut down and cooled. The Natural gas, steam and water valves should be checked closed and tagged. The confined spaces where you are entering have to be cooled, ventilated and assured safe for human entry. • When you need illumination for inspection, only use low voltage extension cords with low voltage bulbs with the cords properly earthed. The power supply be from an earth leak circuit breaker (ELCB)
Section C
• Do not use toxic fluids like CTC for cleaning in a confined space without adequate ventilation. • Install and strictly follow a system of permits and tagging for any maintenance or inspection work to be done by any person in the boiler house. • Operators trained in Fire fighting, First aid, handling electric shocks etc may save lives and property in an emergency.
11 Trouble Shooti ng Chart The following chart is to be used for solving problems arising during operation.
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Operation & Maintenance Manual
Indication
Unable to maintain HRSG water concentration
Sound of steam blowing in furnace or seeing visible steam from the stack.
Steam explosion in furnace followed by inability to maintain water level.
High conductivity
High gas temperature
Excessive water level fluctuation
Section C
Probable Cause
Repair method & Preventive Measures
Tube Leak Hideout
Slight leakage from pitting or cracking of tube or tube seat leak.
Remove HRSG from service at first convenient time. Hydrostatic test to be done to locate leak. Repair by welding or splicing as indicated and as approved by insurance or State Inspection. Determine cause of failure and correct it. Operation at normal loads should put chemical back in solution.
Tube leak
Substantial leak from tube/tubes. Over-heating as from scale or tube seat leakage.
The same as above plus tubes re-rolling.
Failure of tube from low water, tube blockage or erosion of exterior metal surface.
Remove HRSG from the line immediately. Inspect or determine whether tube splicing or wholesale tube replacement is necessary.
Solids carry over in the steam or high CO2 or NH3 in HRSG water
High boiler water concentrations, excessive water level fluctuation drum baffle leakage or deposits on scrubbers
Check for baffle leaks in steam drum when out of service, or boiler water contamination. Check of degasified steam sample will indicate if CO2 or NH3 is high
High excess air
Improper control /adjustment of airflow.
Check excess air at furnace HRSG outlet, and correct airflow if required
Water load or control conditions
High boiler concentrations, extreme load swings, varying supply pressure or control loop adjustment
Correct condition leading to the problem
Probable Source
Tube rupture
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Operation & Maintenance Manual
Indication
Bowed water wall generating tubes
Tube blisters
Internal pitting sharp edged and covered with barnacles in drum or tubes.
Probable Source
Overheating
Localised overheating
Corrosion
Probable Cause
Repair method & Preventive Measures
Internal deposit or low water. Usually internal deposits result in tubes bowing away from the furnace & low water /starve results bowing toward the furnace.
Severity of bowing will determine extent of tube replacement. Internal scale will call for internal cleaning. If low water is indicated a thorough inspection for drum damage and tube seat leakage must be made. Take steps to prevent recurrence or low water condition
Internal deposit
Repair by retubing or welding in tube section or by heating and driving back blister depending upon insurance carrier or State Inspector’s approval. Clean internally by turbining or acid cleaning.
Oxygen in Boiler water
Depth and extent of pitting determines need and extent of tube replacement. Extensive drum pitting can be welded but is subject to approval by either the manufacturer & insurance carrier or State. Source of oxygen must be located and eliminated
Internal loss of metal not sharply defined and accompanied by black iron oxide (Fe 3 O4 )
Section C
Overheating resulting in breakdown of water into H & O2 Corrosion
Cause is usually from or sludge letdown pluggage .
Individual inspection will determine extent or replacement, internal cleaning and correction of water conditions are required
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Operation & Maintenance Manual
Indication
External pitting
Probable Source
Corrosion
Probable Cause
From corrosive ash deposit and moisture either from dew point or external source such as leaking soot blowing tube.
Repair method & Preventive Measures Extent of repair must be determined by individual inspection. In emergency tubes out of high heat zone can be plugged, being sure they are cut to vent and to prevent differential expansion with adjacent tubes. Proper external cleaning can prevent out of service corrosion. Locate and eliminate source of moisture. If dew point is from in -service corrosion, take steps to raise metal temperature
Tube cracking
External metal loss. Highly polished area
External metal loss. Oxidized fire scale area.
Section C
Mechanical stress or a combination of stress corrosion or tube variation.
Erosion
Overheating
Interference with expansion or differential expansion with adjacent parts to give mechanical stress or this stress plus corrosion attack. Vibration set up by turbulent gas flow characteristics over tubes.
When accessible and with insurance or State approval, the cracks can be ground out and welded, otherwise splice in section or replace tube. Locate & eliminate source of expansion difficulty by inspection or hot to cold expansion measurements. Using tube spacers can stop vibration.
Mechanical abrasion from soot blower action.
Where accessible and with insurance or State approval pad weld or splice in a tube section. Eliminate channeling of steam from soot blowers or use tube shields
Prolonged or repeated overheating.
Extent of metal loss will determine extent of tube or tube section replacement. Inspection or a thermocouple installation will determine cause of overheating
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Section D Topics Covered in this Chapter ♦ Section Overview ♦ Welding Procedure Specifications (WPS) ♦ Boiler Preservation Procedure ♦ Tube Failures ♦ General Principal of Weld Repairs ♦ Failure Reporting Format ♦ Water Chemistry ♦ Feed & Boiler Water Conditioning
1
Se ct i o n Ov er v i ew
This section describes the various maintenance practices, overhauling, and preservation techniques. Also discussed are failures and repair techniques
1.1 Recomm ended Maintenance Practices Systematic maintenance is essential to keep the boiler and its auxiliaries in good condition and to obtain reliable operation of the boiler with high availability and plant load factor. Effective maintenance aims at timely inspection of parts to repair or replace defective components and to prevent their failure when the boiler is in service. Maintenance can be classified as • Preventive maintenance – mostly condition based •
Annual Boiler overhauls to clean and inspect pressure parts. The shutdown period of the overhaul is also utilized to attend to systems and parts which cannot be attended during short shutdowns or when the boiler is in operation
The vendor manuals of the fans, motors, control valves with their positioners and actuators, instruments and controls, power cylinders etc., prescribe certain minimum maintenance requirements which are to be carried out in one of the above two maintenance categories. 1.1.1Preventive Maintenance The objective of the preventive maintenance program is to obtain trouble free service from the component till the next maintenance. Vendor manuals for various equipments suggest inspection periods, checks to be done and
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recommended spares. The true objective of the maintenance program can only be realized, if a master plan of maintenance of all the components is prepared as per vendor instructions. Full benefits of maintenance can be obtained only if proper parts are used. Mandatory spare part list covers most of the spares required. It may be found that in the first two years of operation due to variations of site conditions, some additional spares not included are also required. Action has to be initiated to procure such spares. Some equipment have 100% reserve standby units. (Feedwater pumps etc.). Maintenance of such equipments can be organized even when the boiler is in service, although some minimum risk is involved. Equipment such as igniters, scanners have replacement spares which can be utilized when the working equipment are to be maintained without affecting the boiler operation. The prepared master plan for maintenance should be periodically reviewed during the first three years of the boiler operation. It may be found that due to varying site conditions, the frequencies and quantum of work scheduled as per vendor manuals are either too much or too less. Based on site experience, the frequencies and work schedules can be modified. A scientific method of preparation of the preventive maintenance schedules is to make them condition based. In condition based maintenance, the equipment and components of the plant are inspected daily, weekly monthly etc., as per a suggested schedule by the local operators and deteriorating conditions if any observed are reported. Suggested inspection program is given in this section. Based on operator reports of such inspection, maintenance works are planned for the next available planned shut down. Mandatory inspections prescribed by the vendors are also taken care of, irrespective of the equipment condition. 1.1.2Schedule of I nspecti ons for Condit ion Based Maint enance The schedule of daily, weekly and monthly inspections given in the following pages do not require a boiler shutdown and in fact can only be done when the boiler is in service. Three and six monthly inspections are done utilizing an available planned shutdown approximately in the specified time period. Objective of these inspections is to ensure that • The components are in trouble free condition
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• To carry out any minor repairs or adjustments which can be done with the boiler in service • To plan for repair of such items, which cannot be attended when the boiler is in service, during the next available shutdown • To collect a database to determine optimum service life of the systems and components before maintenance is required
Daily Checks To be done once a day by the local operator during his walkdown checks. Such walkdown checks are to be encouraged to be done in each shift by the operators. Only those operational checks that require maintenance work for correction have been included.
The schedule can be expanded, curtailed or modified based on experience in the first two years of operation. EQUIPMENT
CHECK
1. Local level gauge on steam drum
• Check illumination is proper.
WORK TO BE DONE
• Leaking valve glands.
• Replace fused bulbs
• Leaking ports.
• Isolate level gauges and tighten leaking glands
• Blurred level.
• Replace leaking ports •
Steam wash mica as suggested by vendor (Not to be done too frequently)
2. Comparison of levels indicated by local level gauge with that of remote level indicators in the control room
Compare the levels after verifying there are no leaks from valves, glands etc., of the level gauge and indicators. Report discrepancies.
If there are serious discrepancies, calibration of the remote level indicators has to be planned immediately.
3. Traces of water on boiler cladding etc.
Such spots are indicative of valve leaks, Instrument tapping leaks, boiler tube leaks etc., Trace the source of leak.
Maintenance to be planned to eliminate the source either immediately or during next planned shut down (depending on the source and quantity of leak and accessibility for maintenance)
4. Fans & drive motors.
• Check bearing temperatures
If higher than normal bearing temperatures are noticed check for cause-proper oil level / oil circulation, correct grade and quality of oil, abnormal sound or vibration. If bearing temperatures are very high, start the reserve equipment (if avl.) and plan for a maintenance check.
• Check for vibration levels.
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EQUIPMENT
CHECK
WORK TO BE DONE
5. Drum safety valves.
Check for passing of safety valves (noise or wisp of steam through silencer)
• Hand pop the affected safety valve one or two times to clear any dirt sticking to the valve seats. • Lightly tap on the stem of the safety valves. • If these measures do not succeed, request for check of the safety valve during next planned shutdown.
6. Purity of Instrument air
• Check by visual observation that the instrument air is oil and moisture free • If there is a feel by visual inspection, Oil and moisture content can also be checked by laboratory examination as per standards
• Oil and moisture in the instrument air is likely to clog the positioners of pneumatic controllers / solenoids and make their operation sluggish or unreliable. • Open drain valves of air-receivers for short time to drain condensate if any. •
If these measures are not successful, inform the Maintenance Group
7. Scanner cooling fan suction-damper linkages and power cylinders.
Check for their proper operation
Sluggish operation of fan suction damper may be due to stuck linkage, stuck damper, faulty power cylinder, and faulty positioners. Check for possible cause. Maintenance works have to be planned.
8. Steam or water leakages from valves and from flange joints
• Loose valve gland
• Tighten the gland nuts. If the leakage not getting arrested, plan for maintenance during shut down.
• Loosened bolts of flange joint and / or failed gasket
• Tighten the bolts. If the gasket failed then plan for the maintenance during shut down. 9. Boiler cladding, air duct or flue gas duct
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Check for hot spots
Hot spots may be due to leakage of flue gas or hot air. Source of leakage has to be located after selective removal of insulation (to be planned for the next planned shut down)
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Monthly Checks EQUIPMENT
1. Fans and blowers.
CHECK
WORK TO BE DONE
With a vibration analyzer record vibration and measure bearing temperature. Also note the operating condition of the equipment at the time of the above observations and record them.
By monthly recording of data, establish a database for deciding the overhaul time of the equipment. An overhaul once in two or three years may be adequate. Such a database will help in deciding the time frame. Sharp increase in vibration levels bearing temperatures or sound levels may call for early scheduling of overhauls
Checks Every Six Months
During a planned shut down of the boiler, the following checks can be done.
EQUIPMENT
CHECK
WORK TO BE DONE
1. Boiler Pre-interlock, purge interlocks, start permissive, boiler trip protection.
Coinciding with a planned shut down of boiler, carry out the checks to identify malfunctioning or sluggish pressure, temperature switches, solenoid operated valves, positioners, proximity switches, actuators etc.,
Plan for maintenance or re-calibration of defective items if any noticed, during the shut down period.
2. Burner refractory work.
Visual check that there are no loose bricks, spalling or cracks
If any abnormalities are seen repair works to be planned during next available shut down
3. UV Scanner components
Clean UV Scanner cell and check its output as per vendor manual. Check its amplifier and flame relay
Replace scanner cells if output is suspect. Adjust amplifier flame relay if required.
Checks Every Year EQUIPMENT
(Refer also work listed under Boiler overhaul) CHECK
Utilizing the boiler annual shut down for overhaul, re-calibrate 1. Pressure temperature, Flow level, all pressure, temperature, flow, differential pressure controllers level and d/p controllers as per vendor manuals
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WORK TO BE DONE Carry out any maintenance replacement or adjustment needed to secure initial calibration values as per commissioning records
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EQUIPMENT
CHECK
WORK TO BE DONE
2. Pressure gauges, temperature gauges, Pressure/temperature Switches
Re-calibrate, Verify functioning of pressure/temperature switches as per design
Repairs or adjustments as necessary
Verify functioning of positioners and actuators by feeding current inputs to positioners and measuring the air pressure output of the positioners and opening closing of actuators
Repairs or adjustments as necessary as per vendor manuals to obtain performance as per commissioning records. Verify functioning of proximity switches where provided. Clean filters of air regulators. Check functioning of air regulators. Verify tightness of air connections
3. Positioners, actuators
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1.1.3Boiler Annual Maintenance and Overhaul In addition to the check and inspections listed under preventive maintenance, the boiler requires an annual shut down of about 10 to 15 days for cleaning, inspection ad overhaul of boiler pressure parts. The shut down period is restricted to a minimum by deploying adequate resources. If required, Field Engineering department of TBW can assist the customer in carrying out the boiler overhaul. The annual shutdown is utilized for cleaning and inspection of the pressure parts and to collect data on the wear pattern of boiler, superheater and economizer pressure parts. The shutdown opportunity is also utilized for overhaul of safety valves, regulating and isolating valves and components, which can not be attended when the boiler is in service. (The valve overhauls need not be done every year).
Annual Overhaul Planning Before Overhaul • Prepare a list of jobs to be done during the overhaul based on earlier inspection reports and the jobs listed below. • Ensure availability of spares required for the proposed jobs. • Ensure tools, tackles, scaffolding materials required for the job. • Ensure availability of manpower required for the job (Own sources, contract labor etc.) Services of TBW are also available for carrying out annual overhauls and inspections.
Shutdown and Cooling the Boiler Shutdown the boiler in a planned manner. Cool the boiler. Open all access and inspection doors. Refer to the Section B of this volume for the shutdown procedures.
I nspect ion After Cooling Carry out a preliminary inspection after cooling to check cleanliness and any sign of deposition on water wall panels and the need for water wash.
Drums I nspection • Open the access doors at either end of the drums • Allow the drum to ventilate for about 8 hours. If necessary two fan coolers can be fitted over temporary stands to force air through the drum
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• From the time the drum manholes are opened till they are closed after inspection, the area around the drum must be cordoned to restrict entry only to specifically authorized personnel • The names of persons who are entering the drum for inspection, along with tools they carry must be entered in a register. Persons coming out of the drum after inspection should be asked to account for the material they carried into the drum. This precaution is to prevent accidental dropping of foreign material through the water wall tubes, which may block water circulation through them and can cause tube failures • Carry out a preliminary inspection of the drum to check for any deposits on the waterside of the drum • Using nylon brushes, the deposits (which are normally soft) are cleaned, collected on trays and disposed off outside the drum. Washing down the deposits to the boiler tubes is not recommended • In case of excessive deposits, the chemist is asked to analyze the nature of the deposits. A review of phosphate concentrations and boiler water quality control, (high conductivity) may be made to reduce the deposits in the next year of operation. • After cleaning the following examinations are made – Examine the boiler drum metal for scale, pitting, corrosion and metal wastage. (Drum thickness is measured at a few selected spots using ultrasonic instruments and compared to design thickness) – Inspect fastenings of the baffles and demisters to see that they are intact, without corrosion pitting or holes. Eroded or corroded drum internals to be attended. No welding however is permitted on the drum metal. The demisters can be examined in position. They need not to be dismantled. Reasonable water tightness of the baffles is to be ensured – Examine that feedwater pipe is intact with flange connections tight and discharge exit correctly oriented – Examine that the continuous blowdown and dosing pipes are not plugged or corroded, their supports are normal, and their holes have been correctly oriented After the inspection, clean the manhole seats and provide new gaskets. After the inspection
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and verifying that all men and material have been removed from the drum, close the manholes and bolt them tight.
I nspections in th e Furnace Check the water wall tube panels in the furnace for • Evidence of pitting / erosion / corrosion on tube outer surfaces (exposed to the flue gas path) • Evidence of overheating (bulging of tubes, blue color of tubes, blisters, disturbed vertical alignment of panels)
damages due pitting, hotspots, dislocation etc. Repaired as necessary.
Other Equipment Overhaul of seal air fans, control valves, actuators etc., is scheduled as per vendor instructions and condition monitoring described under preventive maintenance
Light Up of the Boiler aft er Maintenance and Overhaul
• The scaffolding inside the furnace should be removed after such inspection (if any) and manhole door to be closed tightly after ensuring that the refractory blocks is placed in the manhole.
The pressure-raising rate during the first light up after the overhaul should be slower than usual giving time for check of equipment and components. Valve flange joints and glands must be checked for absence of leaks and can be re-tightened where necessary when the boiler pressure is less than 5 Kg/cm2. Burner performance has to be verified and its axial position corrected if required. If overhauled, performance of the safety valves must be verified by floating them. The boiler expansions must be verified during pressure raising. A boiler overhaul is considered successful if it enables another twelve months of trouble free boiler operation.
Safety Valves, Start Up Vent Valves and other I solating Valves
1.1.4Tube Thickness Survey
• On suspicion of any abnormalities consult TBW or a metallurgist for advice. • Check the duct burner & accessories as per R& V manual & its setting.. • Any loose material inside the furnace needs to be cleared.
These valves require regular overhauls, normally once in three years even if condition reports do not indicate any abnormality. Earlier overhauls can be scheduled if condition reports warrant. Overhauls of the valves can be staggered after the first two years of operation in a manner that certain number of valves are overhauled every year. Overhauls of the valves are as per their vendor manuals enclosed.
Expansion Joint s Examine the expansion joints. Eroded / corroded parts can be patched by welding. When severe erosion is noticed (after several years of service) the expansion joints are to be replaced. Collapse or stretching of the expansion joints is usually due to forces exerted by the connecting ducts. Readjustment of duct supports will solve the problem and will assist the expansion joints to regain their original dimensions.
I nsulation and Cladding Verify insulation as per drawings and correct wherever necessary. Inspect cladding for
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To make a quantitative assessment of wastage of tubes (both internal and external) a tube thickness survey using ultrasonic tube thickness gauges is recommended. For a useful tube thickness survey program measurement location on water wall, super heaters and economizers’ tubes must be specified and indicated on a drawing. Vulnerable locations are usually chosen. On request, the Field Engineering Department of TBW can establish such a program. The following are the suggested areas for a tube thickness survey • Boiler bank, economizer coils, deaerator panel tubes & MUWH.. Tube thickness measurements at the selected locations are made and recorded after water washing and drying, during the first annual overhaul. The base value is the design thickness of the tubes. Subsequent measurements are made at the same locations, every alternate year. The tube thickness survey provides useful data on corrosion / erosion rates and can alert the owner when serious loss of thickness is noticed.
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2
W el di ng Pr oced ur e Speci fi cations (WPS)
The pressure part of the boiler is made of several types of steel of varying thickness. Welding is the basic technique used in the fabrication of the boiler. The joints produced by welding should have strength not less than that of the parent metal. In the weld joint, the parent metals should fuse together, without cracks, blowholes, slag inclusions or defects of any kind. The weld joint apart from proving its mechanical strength in tension must also be able to resist bending without cracking. Such requirements can only be met if the welding process used is strictly controlled. ASME (and other organizations) classify materials into categories (P1 P2, P3, P9) as per carbon content and alloying metals (chromium, Nickel, Molybdenum etc.) and specify the procedure to be used for welding materials of the same category or one category with another category. A specification of the materials and shapes adopted by TBW can be obtained on request. The welding procedure distinguishes between welding of thin and thick material. The welding process specification defines the following for each category of welding. • Edge preparation (angle, shape) • Joint preparation (cleaning, gap) and tagging • Joint pre-inspection before welding • Pre-heat of the weld joint, if any required (method of pre-heating, temperature method of checking temperature) • Root weld (gas welding, TIG or Arc, size of electrode, type of electrode)
category of welding. As the electrode deposits materials, the composition of the electrode must be compatible with the material welded and add strength. The coating of the electrode also must meet specific requirements. The WPS must be used not only during fabrication of the boiler, but also when any repair or maintenance works are to be done. TBW has WPS to cover every welding job connected with fabrication of the boiler in the factory and erection of the boiler at site, conforming to IBR requirements. The Field Engineering Department of TBW will be glad to provide a WPS for any site repair weld jobs required for maintenance.
3
Boiler Preservation Procedure
Introduction Both the gas and waterside of a boiler should be protected against corrosion during out of service periods. It is known that many of the corrosion problems of boiler and auxiliary equipment have their inception during storage. Rusting of tube surfaces, as indicated by the formation of the red hematite (Fe2O3), not only cause a roughened tube surface but also results in attack of parent metal. The advantages of efficient feedwater and boiler water treatment during operation may be lost if the same diligence is not applied to protect heat. Transfer surfaces during idle periods. Protection from corrosion during storage becomes vitally important considering the number of times during the life of a boiler when it and its auxiliary equipment are idle.
• Post weld heat treatment if any required (temperature, rate of increase of temperature, method of increasing temperature, holding time, rate of cooling)
To minimize the possibility of corrosion, boiler to be placed into storage must be carefully prepared for the idle period and closely watched during the outage. There are two methods available for storing the unit dry storage and wet storage. Although the wet storage procedures is preferred such factors as availability of good quality water, ambient weather conditions, length of storage period, auxiliary supply of heat, etc may dictate that the dry storage procedure is more practical.
• Radio graphic examination of the weld joint, indicating defects if any to be corrected
3 .1
• Radiographic inspection of root weld if required • Subsequent runs of welding (TIG, Arc or other methods, size of electrode, type of electrode, number of runs)
• Correction of weld defects • Final acceptance of the weld joint The WPS indicates compatible categories of materials that can be welded. The WPS also lays down the type of electrode to be used for each
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De fi nit ions of Wat er Quality
Some cleaning procedures, hydrostatic testing and storage require water of higher quality than others. For the purpose of economy and convenience the lowest water quality consistent with requirements is specified in these various procedures. The terms that identify the different
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water qualities along with their definitions are list below: Station service water - Water normally used for drinking, fire protection, etc. Softened water - Filtered, sodium zeolite softened water with total hardness less than 1 ppm. Two- bed demineralised water - Water then has been passed through cation and anion ion exchanges in series. Mixed bed demineralised water - Water that has been passed through a mixed bed demineraliser. Water from an evaporator is considered to be of equal quality. Treated demineralised water - Mixed bed demineralised water that has 200 ppm of hydrazine and enough ammonia added to give final concentration of 10 ppm (or a pH of 10.0). In this procedure, condensate is considered to be treated demineralised water.
3.2 Dry Storage Preservat ion When it is known that a boiler is to be idle for a considerable length of time and that a brief period will be allowed for preparation to return it to service, the dry storage method is recommended. In this method the unit is emptied, thoroughly cleaned internally and externally dried, and then closed up tight to exclude both moisture and air. Trays of lime, silica gel, or other moisture absorbent may be placed in the drums to draw off the moisture in the air trapped by the closing up of the boiler. The following general procedure is recommended when placing a unit into dry storage: 1. Fire the boiler according to the normal start-up procedure and establish upto 3.5-kg/cm2G-drum pressure. Stop firing. Secure the boiler and when the pressure decays to 1.3 kg/cm2G, immediately drain the boiler and headers under air. As soon as possible, open the drums to allow air to circulate for drying of all internal surfaces. This step is included for a unit that has been in service and is to be placed into storage. For a unit that has never been in service, start with Step 2. 2. If the unit is full of water and cold, drain the unit under air. All non-drainable boiler tubes should be blown with compressed air. If an external source of heat is available such as a steam coil air heater, portable heaters, etc.,
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operate these heaters to assist in drying the internal boiler surfaces. Install trays (of non-porous construction and capable of passing through the drum manhole) containing the moisture absorbent (silica gel is preferred) into the drums. Insert the trays into the drum being certain that none of the absorbent comes into contact with the metal surface of the drum. To insure against an overflow of corrosive liquid after the moisture has been absorbed, the trays should not be more than ½ full of dry absorbent. The amount of absorbent can vary but the recommended minimum is one Kg of absorbent per 1000 Kg per hour steam flow capacity of the unit. 3. Open the isolation valve for nitrogen connection, on the steam drum, close all other vents and drains and pressurize the boiler to 0.3 to 0.6 kg/cm2G with nitrogen. The amount of nitrogen required will vary according to the volume of the unit. 4. With the boiler pressurized, alternately open all boiler drains to purge air from the unit until pressure decays to zero. It may be necessary to repeat this process several times to reduce the amount of oxygen left in the unit to a minimum. The unit should now be stored under 0.3 to 0.6-kg/cm2G nitrogen pressure maintained at the steam drum. To maintain the nitrogen pressure, all connections and valves should be blanked or tightly closed. Check gas pressure daily to ensure protection. We would recommend that periodic inspection of the unit be performed every 3 months to assure that no corrosive action is taking place and to replenish the absorbent as required. Since air will enter the unit during this inspection, it will be necessary to repeat Steps 3 & 4 to expel the air.
The unit should be properly tagged and the appropriate warning signs attached noting that the boiler is stored under nitrogen pressure and that complete exhaustion of the nitrogen must occur before anyone enters the drum. Before entering drums test to prove that the oxygen concentration is at least 19.5 %. The above procedure is intended to include the economizer.
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3.3
Wet Storage
The advantage of employing the wet storage procedure is that the unit is stored completely wet with the recommended levels of chemicals to eliminate a wet-dry interface where possible corrosion can occur. It is suggested that volatile chemicals be used to avoid increasing the level of dissolved solids in the water to be used for storage. In preparing a unit for wet storage, the following procedure is recommended. The unit should be filled with deaerated, Demineralised water treated with 200 ppm hydrazine (N2H4) for oxygen removal and sufficient ammonia (NH3) in order to attain a pH of 10 (for demineralised water, this will require approximately 10 ppm ammonia). We strongly recommend pre-mixing of the chemicals with the water to insure a uniform mixture entering the boiler. This can be accomplished by the blend-fill method. The blend-fill method consists of blending the chemicals with the demineralised water at a continuous rate such that a uniform mixture is entering the boiler. Simply introducing the chemicals through the drum after establishing water level will not insure adequate dispersion of chemicals to all internal surfaces, unless sufficient heat is delivered to the furnace (i.e. firing the boiler) to induce natural circulation throughout the boiler. Fill the unit with the treated demineralised water to the normal centerline of the steam drum. Stop filling further. Back-fill the with treated Demineralised water until a rise in steam drum level is noted. Continue filling until water exits from the steam drum vents. After filling, all connections should be blanked or tightly closed. A source of low-pressure nitrogen should be connected at the steam drum to maintain 0.3 to 0.6 Bar G to prevent air from entering the unit during the storage period.
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The unit should be properly tagged and the appropriate warning signs attached noting that the boiler is stored under nitrogen pressure and that complete exhaustion of the nitrogen must occur before anyone enters the drum. Before entering drums test to prove that the oxygen concentration is at least 19.5%. If storage continues into winter, ambient temperatures below the freezing point of water create a real hazard to the boiler pressure parts and it will be necessary to provide a means of keeping the unit warm to avoid damage. At some later date when the unit is to be placed into service, the boiler can be drained to normal start-up water level and placed into operation. In some cases, an expansion tank or surge tank (such as a 55-gallon drum) above the steam drum elevation may be required to accommodate volume changes due to temperature changes. This tank is equipped with a tight cover and sight glass and contains properly treated water. The tank should be connected to an available opening, such as a vent line at the top of the steam drum in order to create a hydrostatic head. This tank will provide a ready, visual check of water level or in leakage during lay up. A source of low-pressure nitrogen should be connected to the surge tank to maintain 0.3 to 0.6 Bar G to prevent air from entering the unit during the storage period. The treated demineralised water should be analyzed weekly, and when necessary, sufficient chemicals should be added through the chemical feed line, to establish the proper levels recommended. Samples of the treated water can be taken at the continuous blowdown line or any suitable drain connection. No unit should be stored wet when there is any possibility of a temperature drop to the freezing point unless sufficient heat can be provided to the unit to eliminate the danger of water freezing and subsequent damage to pressure parts.
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3.4
N itrogen Blanket
Nitrogen can be introduced at the following locations 1. Through the steam drum 2. Through the main steam line The nitrogen required to seal the drainable components may be supplied from a permanent nitrogen system or portable tanks located near the vent elevations. Due to differences in plant layout, the owner should choose his own method of piping the nitrogen, either from their permanent system or from portable tanks, to the vent (or drain) locations listed.
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The unit should be properly tagged and the appropriate warning signs attached noting that the boiler is stored under nitrogen pressure and that complete exhaustion of the nitrogen must occur before anyone enters the drum. Before entering drums test to prove that the oxygen concentration is at least 19.5 %
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3.5
Boiler Lay Up Procedures TYPE OF SHUTDOWN
PROCEDURE
Short Outages 4 Days or Less. Unit Not Drained
Maintain the same hydrazine and ammonia concentration as present during normal operation. Establish 0.3 to 0.6 kg/cm2G nitrogen cap on the steam drum
Short Outages 4 Days or Less. Unit is Drained
Drain and open only those sections require repair. Isolate remainder of the unit under 0.3 to 0.6 BarG nitrogen pressure where possible. Maintain the same nitrogen and ammonia concentration for water remaining in the cycle
Long Outages Longer than 4 Days Upto 15 Days. Unit is Drained
Fill the boiler with Polish water having 200 ppm of hydrazine and 10 ppm of ammonia to maintain pH 10. Establish nitrogen cap of 0.3 to 0.6 kg/cm2G over the steam drum.
Long Outages More than 15 Days - Unit is Drained.
Dry storage of boiler with nitrogen alone is preferred procedure. Nitrogen cap of 0.3 to 0.6 kg/cm2G to be maintained on the steam drum. Installed silica gel tray in the steam drum to soak moisture if any present in the drum atmosphere.
3.6
Preservation of Rotating Equipments
1. Put the rotating equipment in service once in every 48 hours or atleast once in a week 2. If the equipment is going to be under long shutdown a. Fill bearing block full of oil to preserve the bearing and rotate the Fan/Pump Shaft by 90o once in every 48 hours b. Cover the bearing block & uncovered portion of shaft with plastic sheets to prevent dust/water ingress c.
3.7
Ensure no dust/water accumulates on the rotating equipment
2. Power up the panel instruments and check the operation 3. Keep the control room dust and moisture free 4. Operate control valves, power cylinders once a week and check operation. 5. Operate quick shutoff valves frequently (Twice a week) 6. Ensure that O2 analyzer is powered up and reference air supply is given when flue gas is present. 7. Check operation of Ignition Transformer once in 2 weeks 8. Check operation of Flame Scanners & Flame Amplifiers once in 2 weeks
Preservation of I nstrum ents
1. Cover all field instruments with plastic sheets
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4
Tu b e Fa il u r es
Operating a boiler with a known tube leak is not recommended. Steam or water escaping from a small leak can cut other tubes by impingement and set up a chain reaction of tube failures. Large leaks can be dangerous. The boiler water may be lost, the ignition may be lost, and the boiler casing may be damaged. Small leaks can some times be detected by the loss of water in the cycle or system, a loss in boiler water chemicals or by the noise made by the leak. If a leak is suspected the boiler should be shut down as soon as possible by following normal shut down procedures (If situation permits). After the exact locations of the leak or leaks are identified, the leaks may be repaired by replacing the failed tube or by splicing in a new section of tube as per relevant codes.
SAME MAY BE SENT TO TBW ALONG WITH TUBE SAMPLE FOR ANALYSIS.
Obj ect ives of Failure I nvesti gation Boiler tube failures are the largest cause of forced outages experienced by a utility. To avoid or minimize outages and the associated economic penalties, it is important to identify the mechanism and root cause of tube failures. Informed visual inspection is often adequate for this purpose, however failure analysis involving detailed metallurgical investigation is necessary. Tube failures may be due to overheating, corrosion, erosion, fatigue, hydrogen damage etc. A failure investigation and subsequent analysis should determine the primary cause of a failure, and based on determination, corrective action should be initiated that will prevent similar failures.
Stages of Failure Analysis Although the sequence is subject to variation, depending upon the nature of a specific failure, the principal stages that comprise the investigation & analysis of a failure are:
An investigation of tube failure is very important so that the condition causing the tube failure can be eliminated and future failures can be prevented. This investigation should include a careful visual inspection of the failed tube and in some cases a laboratory analysis. 1. It is recommended that every effort be made to find the cause of tube failures before operation is resumed. 2. It should be ensured that, whenever a spool piece is inserted in the failed zone, the weld joint needs to be of proper weld quality. 3. Free from excess weld penetration to avoid any obstruction in the water / steam mixture flow inside the tube. Excess weld penetration can cause internal tube erosion and results in tube failures. 4. It is suggested to have all the joints are x-rayed and interpreted by qualified / experienced radiographer.
4.1
Tube Failure I nvestigation / Analysis Met hod
Investigation / analysis methodology is listed as follows, which needs to be followed to find the actual root cause of the problems. PLEASE FILLUP THE ENCLOSED (end of this sub-section) OBSERVATION FORM AND THE
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• Collection of background & selection of samples • Preliminary examination of the failed part (visual examination & record keeping) • Non destructive testing • Mechanical testing (including hardness & toughness testing) • Selection, identification, preservation, and/or cleaning of all specimens • Macroscopic examination and analysis (fracture surfaces, secondary cracks, & other surface phenomena) • Microscopic examination and analysis • Selection & preparation of metallographic sections • Examination and analysis of metallographic sections
Collection Data:
of
Background Operating
Boiler operating data just before & at the time of a tube failure is very important, as it will give information of the service conditions faced by the tube at the time of failure. This operating data should also be co-related with the past operation data & abnormalities if any should be taken care off. Water chemistry analysis, fuel analysis should also form an important part of this data. This data
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& the metallurgical analysis will help us in true sense to arrive at the exact cause of a tube failure.
I nvestigat ion of Tube Failure in aBoiler Study the boiler log sheet & water chemistry record prior to tube failure and after tube failure. Preserve the copies of these log sheets. Record, if any abnormality noticed, such as mal operation, malfunction, very high or low temperature/loads, fluctuating loads, sudden increase in load or temperature, poor water chemistry, start up vent crack open / close etc. etc. (if possible collect and send the water samples, internal scale from drum & tubes, external scale samples). After entering in boiler and before proceeding to tube failure location inspect & record the condition of boiler and pressure parts without disturbing the evidence i.e. distortion of pressure parts/coils, bulging of pressure parts, scaling / lump formation on pressure parts, blockage of flue gas path, other / secondary failures etc. etc. In such case taking photographs will help in great extent in analyzing of the tube failure, boiler problem. The failed pressure part tube should not be hammered, any mechanical impact should be avoided. Inspect the failed tube and record all findings on the same as well as its adjacent tubes. Carry out dimensional measurement of failed tube and affected adjacent tubes. Number mark the failed tube for its location, flue gas flow, steam flow with oil paint. After completion of inspection, recording and photography, cut the failed tube and affected adjacent tube, if any, with the help of HACKSAW only. Gas cutting of the tubes should be avoided as much as possible. The failed tube, keeping
the failed portion in middle should be cut for total length of minimum 350 mm. Immediately after cutting the tube sample both the ends should be covered with plastic caps. While doing this, internal or external scale of tube should not fall down. The failed tube samples should be carefully packed in plastic bag / wooden case accompanying duly filled format with water chemistry of boiler log sheets should be sent to TBW, Pune.
Removal of Failed Tube Sample • The tube sample should be cut with a hacksaw blade. Gas cutting should be avoided • The sample should be cut approx. 8-10 inches above & below the affected area • The exact location & elevation should be marked on the tube sample • The direction of the fluid flow should be marked on the tube sample • Immediately after cutting the tube sample both the ends should be covered with plastic caps. Internal or external scale of tube should not fall down The failed tube sample nicely packed in plastic bag / wooden case accompanying duly filled format as given below with water chemistry of boiler log sheets should be sent to TBW H.O for metallurgical investigations.
Tu b e Fa il u r e Sheet SR.NO:
An al y si s
Ob se rv at i o n
DATE:
NAME OF THE CUSTOMER Boiler Specifications Capacity Steam Pressure Steam Temperature Fuel Fired Location of Tube Sample Duration of Service of Boiler Duration of Service of Tube Sample Date of Failure Sample Received on No. of Samples Handed Over to Lab on (With Identification Mark/No) Nos. / Date Visual Inspection Report
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NAME OF THE CUSTOMER With Sketch / Nature Of Failure Tube Material ( Specified) Tube OD X THK (Specified) Orientation of Tube Fluid Flow Direction (With Marking) Boiler Operating Condition At the Time of Failure (Water Chemistry & boiler operation log sheets) 4. The weld preparation shall be made as per the Figure #1. The fit up of the patch weld gap shall be 2.4 0.8 mm
ANY OTHER RELEVANT INFORMATION ABOUT THE FAILURE
4.2
Window Patch Welding
Welding Purpose The purpose of the window patching method is to allow the welding of tubes that could not otherwise be welded because of limited access to part of the tube diameter. This procedure is restricted to that use.
Preparation 1. The area to be patched shall be cleaned to bare metal 2. The patch shall be made from tube material of same type, diameter and thickness, as the tube being welded 3. The area of the tube to be removed shall be carefully marked out as close as possible to contour of the patch. The tube section may then be removed using an oxyacetylene gas cutting torch or by mechanical means
1. A welder qualified to the requirements of ASME shall make the tube and patch welds in accordance with an approved weld procedure. 2. The root pass shall be done with GTAW process. The weld may then be completed with either SMAW or GTAW process. Some acceptable weld procedure specifications are listed in Table below
Testing 1. All the tube and patch welding shall be subject to close visual inspection and 100% radiography in accordance with the requirements of ASME section V. The standard for accepting /rejecting is specified in ASME section I 2. Completed welds are subject to hydrostatic test
BASE MATERIAL
FILLER METAL
P1 TO P1
Carbon Steel to Carbon Steel
ER 70S.2
E7018
P3 TO P3
Carbon ½ Moly to Carbon ½ Moly
ER80S.B2
E7018A1
P3 TO P3
½ Cr ½ MOLY TO ½ Cr ½ MOLY
ER80S.B2
E8018B2L
P4 TO P4
1-1/4 Cr TO 1-1/4 Cr
ER80S.B2
E8018B2L
P5 TO P5
2-1/4 Cr 1 MOLY TO 2-1/4 Cr 1 MOLY
ER90S.B3
E9018B3L
P8 TO P8
Stainless to Stainless
ER308
ER308-16
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Figure 7
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5
Ge n er a l Pr i n ci p al of W el d Repairs
Furn ace and Boiler Tubes • The minimum replacement tube length should be not less than 150 mm. A damaged tube should be cut at least 75 mm each side of the defective area. • Backing rings must not to be used in welding heat absorbing tubes carrying water or mixture of steam and water. • If a backing ring is not used, the first pass of the weld must be made with inert gas-arc or oxy acetylene. The weld passes may be completed by either process, or by a manual metal arc. • Pre heat or post heat is not required for welding carbon steel furnace or boiler tubes. • Prior to welding, clean the tube ends to bright metal inside and outside for at least 40 mm from the weld area. Remove all deposits of oxide, boiler water salts and slag to avoid gas or slag inclusions in the weld. • Fit-up of the weld joints is important. It is difficult to obtain accurate cuts on furnace tubes especially those in welded furnace walls. However, it is worth to spend extra time to get the existing tube ends squared and correctly chamfered and to cut the replacement tube to the correct length. Poor fit-up increase the possibility of an unsuccessful weld. • Allow for shrink in the welding, remember, the weld metal and parent metal are melted in the welding process and the molten metal shrinks as it solidifies. A butt weld in the tube will shorten the total tube length about 1.6 mm. • Use a clamp or guide lug to hold one end of the replacement tube alignment while the first weld is made. Do not tack weld both end of the replacement tubes particularly if the existing tubes are rigidly supported • As a general rule, first complete the welds at the lower end of the replacement tube. Do not start welding the upper end of the replacement tube until both the replacement and the existing tubes have cooled to ambient temperature. Weld Repair of Small Cracks in Tube In the interest of saving time and cost, it is better to weld small cracks rather than replace a length of the tube. The crack must be ground out to form an acceptable welding groove. The groove should continue well beyond the ends of the crack. Inert
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gas arc or oxy acetylene process must make the first pass of the weld. Note
This type of the repairs entails some risk. Internal deposits. Particularly copper, may exist under the crack which will result in damaging the parent and/or weld metal causing failure in a short period of time. Over-heating the tube may have caused the longitudinal crack. In this case, the tube has swollen and the weld thickness reduced. In the modern welded wall construction, it is difficult to accurately measure the tube diameter or circumference to detect the minor swelling. If visual indicates swelling and reduction of wall thickness at the crack, a complete replacement of the damaged tube length is the best solution. A circumferential crack indicates a failure due to excessive stress applied by expansion restriction, bending or fatigue; welding can repair such cracks. However, unless the cause of failure is diagnosed and corrected, another similar failure could occur at or near the original crack. Also the tube cannot be cleaned from inside and there is always a possibility internal deposits will contaminate the weld. Plugging Tubes in Drums & Headers Often after a tube failure, it is desirable to plug the failed tube in the drum or header shell so the boiler may be returned to service with the least possible delay. It is recommended that the failed tube be replaced whenever possible in lieu of plugging. If the leak is remote from the tube seats and accessible, the faulty section of the tube should be cut out and replaced rather than plugging. Water wall tubes (space tube) should be replaced if possible and plugged only as a last resort. The plugged tube must be free to expand and distort with respect to the adjacent tubes. Membrane tubes must be repaired and not plugged. When tubes are plugged, the old tube should be removed from the boiler setting since it probably will burn off due to lack of cooling and could become displaced and obstruct gas lanes, foul
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up soot blowers, be dangerous to personnel after shutdown, and etc. If the tube is not removed from the setting, a definite hole must be punched or drilled in the tube to prevent a possible dangerous buildup of pressure between the tube plugs. A expanded tube leaking at the seat should be removed from its seat and 1. a new tube rolled in, 2. a new short stub rolled in and plugged, 3. the tube end seal welded to the shell or, if the drum shell is internally counter bored, a cylindrical plug must be installed and seal welded to the drum shell. Note
No. (1) is the preferred fix with No. (3) the least preferred. Seal welding of tube ends, tapered plugs, or cylindrical plugs to the shell should be done in such a manner as to minimize the heating of adjacent tube seats, which may become loose. It is essential that the welding process should be as per standard procedure for carbon steel shells and tubes to be followed very closely to ensure success. Deviations from these parameters will normally result in unsatisfactory connections. The major welding parameters for shells or tubes other than carbon steel may be obtained from qualified welding procedures. Ensure that welders are qualified in accordance with ASME Section IX and local provincial requirements. They must also ensure that the welding is done to the applicable qualified weld procedure. It also to be ensured that the proposed repair has been approved by the Boiler Inspection Branch of the local jurisdiction. Machined tube stubs and plugs are used where the old tube can be removed from its seat without seat damage and for new construction that is drilled for future addition of tubes. The rolled-in tube stub extends into the shell and a solid plug is installed and seal welded to the stub. These stubs and plugs are standardized to have only one tube stub and one plug for each standard tube hole. Before rolling stubs in, they should be cleaned inside and outside with a wire brush, abrasive paper, or a liquid cleaner until the metal is free of all foreign substances. In general, stubs do not require cleaning beyond the removal of dirt, rust, scale or foreign material.
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The stub seat (tube hole) should be similarly cleaned. If a liquid solvent is used to clean either the stub and/or tube hole, care must be taken to dry the metal completely. Liquid trapped between the stub and its seat prevents contact of the two metal surfaces. Before the expanding tool is inserted, the inside of the stub should be lubricated with a suitable compound. The compound selected should be water soluble to facilitate cleanup. The rolling process should not be rushed since heat generated during rolling is detrimental to the strength of the rolled joint. The tube stub is properly expanded when the wall thickness in the seat is reduced by 6 to 10 percent for generating tubes and 10 to 14 percent for other boiler tubes. The tube stub wall reduction for thin shells should be less than that for thicker shells. This is to prevent over rolling which could cause adjacent tube seats to leak. Since the stub wall itself cannot be measured after it is rolled in its seat, the only alternative is to calculate the increase in the stub ID that is necessary to prove that the wall has in fact been reduced by the required percentage. This depends upon the tube seat ID (hole diameter), tube stub OD, the clearance between these two and also the stub wall. An example of this conversion for a 2 ½" OD by 0.150-inch wall tube stub for a 10% wall reduction is as follows Measure = Hold Dia
2.531
Measure = Stub OD
2.500 / 0.031 Clearance
Measure = Stub ID
2.200
Clearance =
0.031 / 2,231 Stub ID @ Contact
Stub ID @ Contact
=
2.231
10% of 0.150 x 2
=
0.030 / 2.261 Stub ID after expanding
Plug all internal counter bored holes in the field with the cylindrical plug when the tube is still in the seat. Some counter bores may be shallow enough that the tube ends are exposed sufficiently to permit seal welding to a tapered plug. See Figure 2. If the tube seat is leaking, then the tube must either be seal welded to the drum shell or the counter bore can be plugged with the cylindrical plug and seal welded per Figures 3 and 4. It
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may be necessary to machine the tube ends back in order to provide a seat for the cylindrical plug installation. See Figures 3 and 4. Figure 5 shows the details of this cylindrical plug and gives instruction for the specific plug size desired. Tapered plugs are used to plug existing tubes where it is not practical to remove the tube from its seat and there is no internal counter bore. These plugs must be tailor made for each tube diameter and tube wall thickness. Figure 6 shows the details of this tapered plug and give instructions for a plug to fit tube diameters from 1-3/4" through 4 ½" OD and any wall thickness. Figure 7 shows the arrangement of the tapered plug seal welded to the tube. The plugs and seal welds described above are designed for the boiler pressure to be on the head (seal weld side) of the plug only. The ¾ inch diameter by 1/8-inch thick button weld on the plug is to eliminate leakage through the “piping” which can occur at the center of some bar stock. Figure 8 shows a tube seal welded to the shell. This arrangement may be used when the tube seat is leaking and it is not practical to replace or remove the tube and use a rolled stub and plug. Economizer headers and superheater headers may be plugged as shown in Figure 9 & 10 where external access is available and the conditions shown on the figures are met. If those conditions cannot be satisfied, tube replacement is recommended. In these two figures, the pressure is on the internal end of the plug and the external strength weld restrains the plug. Plugged tubes that are below the horizontal centerline of the shell will not drain. Therefore, after chemical cleaning it is necessary that the plug to be removed and the stub swabbed out to remove the chemicals in these stubs. The plug can then be welded back in or in some cases it will have been destroyed in the removal process and anew one will have to be installed. Care must be taken in the plug removal process to not damage or thin the tube stubs wall. Replacement of Secti ons of Tubes Experienced personnel must do the replacement of a section of failed tube. The length of the replaced section should be a minimum of 12 inches. Usual practice is to cut out the defective section with an oxyacetylene torch, but it is preferable to use a saw or wafer disc. Care must be taken to prevent slag from entering the tube.
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The ends are prepared for welding by grinding or with special tools. The root pass of the joint should be deposited with the gas tungsten arc process. A 3/32-inch diameter shielded metal arc-welding electrode is recommended for the remainder of the joint. The welding parameters for tubes may be obtained from qualified Welding Procedures. Removi ng Tubes From Drum s, Headers & Tube Plates The removal of tubes from their tube seats must be done very carefully to prevent damage to the tube seats. If the tube seat is damaged, it may be impossible to ever roll another tube in and make a tight seal. Gouging of the tube seat could also affect the ligaments between tube holes and integrity of the shell. Tubes can be removed from their seats without seat damage if the following procedures are carefully followed. With light- gage tubes, it is often possible to cold crimp the tube end to loosen it in its seat, then drive or "jack" the tube out. When the tubes are too heavy for cold crimping, the two-stage heating method may be used. Heat is applied to the inside of the tube end with a torch. Heat is first applied for a short period - not long enough for it to be transferred to the tube sheet. When the tube end cools, the joint will have loosened enough so that the second heat will not be transferred readily to the tube sheet. The tube end can then be heated sufficiently for crimping and the tube can be pushed out of its seat. If neither of these methods is applicable, the following methods may be employed. To remove light tube tubs, it is advisable to cut grooves about 3/4 inch apart with a round nose chisel. When the tongue (the metal between the two grooves) is knocked free, the tube can be collapsed and removed. To remove heavy gage tubes, the type of grooving tool shown in figure 12 is used to prepare the tongues without damage to the tube seat. It is used with a pneumatic hammer, but it is necessary that the tool be suited to the tube thickness so that it will cut the grooves as deep as possible and yet leave a minimum thickness of metal over the tube seat. In very heavy gage tubes, a third groove is often cut, as nearly opposite the tongue as possible, so that less heavy pounding will be required to collapse the stub. These latter two methods require that the flare on the end of the tube be crimped straight before starting, to cut the grooves for collapsing the tube. Of course, the
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seal weld around the end of any tube must be ground or machined off before attempting to cut the grooves for collapsing the tube. This must be done carefully to prevent damage to the drum shell.
Attached Figures 2 to 10
Figure 8
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Figure 9
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Figure 10
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Figure 11
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Figure 12
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Figure 13
Figure 14
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Figure 15
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Figure 16
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6
Fa il u r e Re po r t i n g Fo r m a t
Enclosed is a format for reporting of failure of equipment etc. The enclosed formats are exclusively for the use by O & M engineers of the client for reporting any malfunctioning or failure of the boiler pressure parts and its auxiliaries. Most of the boilers at site need to be investigated with the help of pas experience and guidance from the O & M. The O & M, in turn, required precise and systematic information on which the failure analysis will have to be based. TBW request the boiler users to report to TBW any problems that they may come across during routine O & M of the plant, immediately on occurrence.
It is suggested that enclosed formats be used for this purpose and help provide better and quicker services for trouble shooting. There may be cases when problems arising during the O & M are resolved on temporary or permanent basis by the O & M engineers and there may not be any immediate need for service of TBW or OEM. Even in such cases it is the request of TBW with the enclosed reporting formats be filled in and faxed over to TBW, Pune. This will go a long way to generate a data bank on the auxiliary equipments and come out with improvement rather for the final users. Customer Feed Back Form CUSTOMER DETAILS:
Company Name Communication Address
Telephone Number Fax Number E-Mail Address Contact Person Other Details (If Any) Boiler Details: Boiler Number : Date of Commissioning Boiler Capacity – MCR Steam Pressure Steam Temperature Fuel Fired Feed Back Details: SL.NO
PROBLEM DETAILS
Other Informations : Expectations from TBW :
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Equipment Details: OBSERVATIONS
CORRECTIVE ACTIONS TAKEN
COMMENTS / RECOMMENDATIONS
Reply Awaited / Service Engineer Visit : Signature & Date:
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7
W at e r Ch em i st r y
Introduction The natural water contains solid, liquid and gaseous impurities and therefore, this cannot be used for the generation of steam in the boilers. The impurities present in the water should be removed before its use for steam generation. The necessity for reducing the corrosive nature and quantity of dissolved and suspended solids in feed water has become increasingly important with the advent of high pressure, critical and supercritical boilers. The impurities present in the feed water are classified as given below 1. Un dissolved and suspended solid materials. 2. Dissolved salts and minerals. 3. Dissolved gases. 4. Other materials (a soil, acid) either in mixed and unmixed forms.
7.1
Undissolved and Suspended Solid Materials
A) Turbidity and Sediment: Turbidity in the water is suspended insoluble matter including coarse particles (mud, sediment sand etc,) that settle rapidly. Amounts ranges from almost zero in most ground waters and 60,000 ppm. in muddy and turbulent river water. The turbidity of feed water should not exceed 5 ppm. These materials can be removed by settling coagulation and filtration. Their presence is undesirable because heating or evaporation produces hard stony scale deposits on the heating surface and clog fluid system. Both are objectionable as they cause damage to the boiler system. A standard of measurement of hardness is taken as being the amount of calcium carbonate (CaCO3) in the water and is referred to in part per million (ppm) or grains per gallon (grain/gallon) X 17.1 = ppm. B) Sodium and Potassium Salts: These are extremely soluble in water and do not deposit unless highly concentrated. Their presence is troublesome as they are alkaline in nature and accelerate the corrosion. C) Chlorides: Majority of the chloride causes increased corrosive action of water.
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D) Iron: Most common soluble iron in water is ferrous bicarbonate. The water containing ferrous bicarbonate deposits becomes yellowish and reddish sediment of ferric hydroxide if exposed to air. Majority of ground surface water contains less than 5 ppm but 0.3 ppm, can create trouble in the feed water system by soft scale formation and accelerating the corrosion. E) Manganese: It also occurs in similar form as iron and it is also equally troublesome. F) Silica: Most natural water contains silica ranging from 1 to 100 ppm. Its presence is highly objectionable as it forms very hard scale in boilers and forms insoluble deposits on turbine blades. In modern high-pressure boilers its presence is reduced as low as 10-50 ppm. G) Microbiological Growths: Various growths occur in surface water (lake and river). The microorganisms include diatons, molds, bacterial slimes, algae; manganese and sulfate reducing bacteria and many others. These can cause coating on heat exchanger and clog the flow passages and reduce the heat transfer rates. H) Color: Surface waters from swampy areas become highly colored due to decaying vegetation. Color of feed water is objectionable as it causes foaming in boilers and may interfere by chlorinating of absorption by activated carbon.
7.2
Dissolved Salts and Minerals
A) Calcium And Magnesium Salts: The calcium and magnesium salts present in the water in the form of carbonates, bicarbonates, sulfates and chlorides. The presence of these salts is recognized by the hardness of the water (hardness of water is tested by soap test). The hardness of water is classified as temporary and permanent hardness. The temporary hardness is caused by the bicarbonates of calcium and magnesium and can be removed by boiling. The boiling converts the soluble bicarbonates into less soluble carbonates, which can be removed by simple blow-down method. The presence of chlorides, sulfates and nitrates of calcium
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cause the permanent hardness of the water and magnesium and they cannot be removed just by boiling because they form a hard scale on heating surfaces.
7.3
Dissolved Gases
A) Oxygen: It presents in surface water in dissolved form with variable percentage depending upon the water temperature and other solid contents in water. Its presence is highly objectionable, as it is corrosive to iron, zinc, brass and other metals. It causes corrosion and pitting of water lines, boilers and heat exchangers. Its effect is further accelerated at high temperature. B) Carbon Dioxide: The river water contains 50 ppm & well water contains 2-50 ppm of CO2. It also helps to accelerate the corrosive action of oxygen. The other gases are H2S, CH4, N2 and many others but their percentage are negligible Therefore their effects are not discussed here.
7.4
Other Materials
A) Free Mineral Acid: Usually present as sulfuric or hydrochloric acid and causes corrosion. The presence is required by neutralization with alkalis. B) Oil: Generally the lubricating oil is carried with steam into the condenser & thorough the feed system to the boiler. It causes sludge, scale & foaming in boilers. Strainers and baffle separators generally remove it. The effects of all the impurities present in the water are the scale formation on the different parts of the boiler system and corrosion. The scale formation reduces the heat transfer rates and clogs the flow passage and endangers the life of the equipment by increasing the temp above the safe limit. The corrosion phenomenon reduces the life of the plant rapidly. Therefore it is absolutely necessary to reduce the impurities below a safe limit for the proper working of the power plant.
7.5
pH Value of t he Water and it s Importance
The pH value of the feed water plays very important controlling the corrosion. pH is a
Section D
number denoting the degree of acidity or alkalinity of a substance. It does not indicate the quantity of acid or alkali in a solution as found by filtration method. It is derived by measuring the amount of hydrogen ion (H+) in grams per liter of solution. The greater the amount of hydrogen ions present in solution its acid reaction becomes stronger. Therefore, pure water is being neutral solution, any solution producing more hydrogen ion than pure water will be acidic and degree is governed by difference and other solution producing less hydrogen ions than pure water will be alkaline and the degree is also governed by the difference. The Role Of pH in Corrosion: The role of pH in corrosion of metals is extremely important. The corrosion rate of iron in the absence of oxygen is proportional to pH up to a value of 9.6. At this point, hydrogen gas formation and dissolving of iron practically stops. This is the came pH produced by a saturated solution of ferrous hydroxide Fe (OH) 2. The Oxygen in the water unites with ferrous hydroxide to form ferric hydroxide. This reaction lowers pH of the solution and levels to stimulate corrosion. Alkalinity adjustment and film formation are closely related. The pH value of feed water should be maintained greater than 9.6 to reduce the corrosion effects caused by the reason mentioned above. The required alkalinity of feed water is adjusted by adding soda ash caustic soda or trisodium phosphate. The calcium hardness, alkalinity and pH are inter-related variables in scale control. Calcium carbonate is one of the most troublesome deposits responsible for scale formation.
7.6
Effects of I mpurities
The major troubles caused by the feeding of water of undesirable quality are scale formation, corrosion, foaming, caustic embrittlement, carry-over and priming. The details described below: 1. Scale Formation Feed water containing a group of impurities in dissolved and suspended form flows into the Boiler for continuos generation of Steam. With conversion of water into steam in Boiler, solids are left behind to concentrate the remaining water. The scale formation tendency increases with the increase in temperature of feed water. Because, the solubility of some salts (as calcium sulphite) decreases with the increase in feed water temperature. Calcium sulphite has solubility
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of 3200 ppm. at 15 Deg. C and it reduces to 55 ppm. at 230 Deg. C and 27 ppm. At 320 Deg. C. Scale formation takes place mainly due to salts of calcium and magnesium. Sometimes, it is cemented into a hard mass by Silica. Among all, calcium is the principal offender and particularly, Calcium sulphate, magnesium sulphate and other Chlorides are sufficiently soluble in water and are not much troublesome. Sodium salts are highly soluble in water and are non-scale forming. The scale formation takes place mainly in feed water piping and Boiler Tubes. Its first effect on the piping system is to choke the flow of water by reducing the flow area and increases the pressure required to maintain the water delivery. Another effect of scale formation is to reduce the transfer of heat form the hot gases to water. Real dangers of the scale formation exist in radiant heat zone where boiler tubes are directly exposed to the combustion. The scale formation retards the flow of heat and metal temperature increases. Even a thin layer of scale in high heat zone can over-heat the metal enough to rupture the tubes. The metal tubes weakened due to over-heating yield to pressure providing a protrusion known as bag. Such bag provides a pocket for the accumulation of sludge and scale, which eventually causes failure. The over-heating of metal causes layer of metal to separate and form a blister. 2. Corrosion The corrosion is eating away process of boiler metal. It causes deterioration & failure of the equipment, eventually this cause for major repairs or expensive shut -downs or replacements. The corrosion of boilers, economizers, feed water heaters & piping is caused by an acid or low PH in addition to the presence of dissolved oxygen & carbon dioxide in the boiler feed water. The presence of oxygen is mostly responsible for corrosion among all other factors. The permissible limit of oxygen content varies with the acidity of water. Generally it should not should exceed 0.5 cc per liter .O2 generally enters into closed system through make up condenser leakage and condensate pump packing. CO2 is next to O2, which is responsible for corrosion. The CO2 comes out of bicarbonates on heating and combines with water to form weak acids known as carbonic acid. This acid slowly reacts with iron and other metals to form their bicarbonates. The newly formed bicarbonates of metals decompose by heat once more and CO2 is again liberated. This gas again unites with water
Section D
to form carbonic acid and the cycle is repeated. Adding alkali solution to neutralize acids in water and raise the PH value can minimize the corrosion. The effect of CO2 is minimized by the addition of ammonia or neutralizing the amines in water. This is necessary because CO2 lowers the PH of the boiler feed water and dissolved solids to leave the boiler. The priming is a violent discharge of water with steam from the boiler. It can be compared to the pumping of water that frequently accompanies rapid heating in a open vessel. In priming the water level in the boiler undergoes rapid and great changes and there are violent discharges of bursting bubbles. Therefore ‘sludge’ of boiler water is thrown over with the steam. The priming is caused due to improper boiler design, improper method of firing, overloading, sudden load changing or a combination of these factors. The priming effect is reduced by installing steam purifier, lowering water level in the boiler and maintains constant load on boilers. The foaming is the formation of small and stable bubbles throughout the boiler water. The high percentage of dissolved solids, excessive alkalinity and presence of oil in water are responsible for foaming. Boiler water solids are also carried over in the moisture mixed with steam even when there is no indication of either priming or foaming. This is known as ‘carry-over’. The carry-over of boiler water solids is partly a mechanical and partly a chemical problem. The amount of suspended solids and alkalinity in the boiler water is also important in addition to other reasons like boiler design, high water level, and overloading and fluctuating loads on boiler. 3. Caustic Embrittlement The caustic embrittlement is the weakening of boiler Steel as a result of inner crystalline cracks. This is caused by long exposure of boiler steel to combination of stress and highly alkaline water. The course of embrittlement takes place under following condition: a) When boiler water contains free hydroxide, alkalinity and some silica. It has been always found that the feed water was high in sodium bicarbonate, which broke down into sodium carbonate in the boiler and partially hydralized as shown by the following reaction in case of embrittlement.
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Na2CO3 + HOH = CO2 + 2 NaOH b) Slow leakage of boiler water through a joint or seam. c) Boiler metal is highly stressed at the point of leakage. This may be caused by faulty design and expansion etc. The prevention of caustic embrittlement consists of reducing the causticity or adding inhibiting agents to the feed water. The most practical method of preventing caustic embrittlement is to regulate the chemical composition of the boiler water. The obvious solution to embrittlement is to eliminate all free NaOH from feed water by addition of Phosphates.
8
Feed & Boiler Water Condit ioning
1. Introduction The successful use of boiler is dependent on proper water conditioning and treatment. The quality of water must have accurate for trouble free operation of boiler. The water as available to industry is not suitable for boiler use. A complete pre-treatment and internal chemical treatment is necessary to make raw water suitable for boiler feed. The objective of the water treatment is: • Eliminate scaling - deposition in boiler which cause tube over heating leading to accidents. • Control corrosion of boiler system, which cause failure of boiler tubes, leading to unscheduled shutdowns. • Reduce carry over of water with steam, which is the cause of deposition on super heater/turbine blades, leading to the expensive failures.
boiler entirely depends on the rate of corrosion of boiler metal. In order to protect boiler from corrosion, pre-treatment is done to remove excessive corrosion ions like chloride, sulphate etc. However, further chemical conditioning is required to protect boiler and auxiliary systems from corrosion. Tri sodium phosphate, caustic, ammonia and amines are used as corrosion inhibitors. These chemicals form a protective film over metal surface and reduce corrosion. It is necessary to maintain prescribed concentration of these chemicals in boiler water systems continuously. B. Oxygen Corrosion Inhibitor: Oxygen is present in dissolved form in water. At high temperature, oxygen reacts with metal to cause pitting corrosion. Thus prevention of oxygen lead to pin holes in economizer, steam drums and steam tubes. Most of the oxygen is removed externally by deaerator and preheating of feed water. However, traces of residual oxygen must be removed by chemical conditioning. Sodium sulfite, hydrazine and amines are recommended for oxygen removal. These chemicals react with residual oxygen making it inactive and protect metal against pitting corrosion. Catalyzed oxygen scavengers are used for quick reaction. C. Scale / Deposit Control: Raw water contains dissolved solids, hardness salts and suspended matters. External treatment is used to remove such impurities. • Clarification - To remove suspended matters.
• To maintain peak boiler efficiency by keeping complete boiler water system clean.
• Filtration - To remove residual turbidity
In order to meet above objectives, it is necessary to maintain certain chemical conditions in boiler, condense and feed water systems. A brief review of important factors is given in this section to assist those taking charges of new boiler equipment. It is not possible to cover the subject fully, there fore, it is recommended that the care and control of water quality be entrusted to water treatment specialist.
Dealkaliser - To remove hardness salts and excessive alkalinity
• Softening - To remove hardness salts
• Demineralization - To remove residual salts and silica • Mixed bed - To remove residual salts and silica from DM water.
2. Need for Water Treatment
A combination of above equipments are used to remove undesirable impurities in raw water.
A. Corrossive Control
Scale Control
Water is corrosive to boiler metal. Typically corrosion due to water will reduce thickness of tube @ 1 mm/year. Thus the life and safety of
Hardness salts in feed water cause formation in boiler. Under temperature and pressure inside the boiler and due to concentration, hardness salts
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precipitate in tubes as calcium carbonate, calcium sulphate and Ca/Mg silicate scales. External treatment like softening, demineralization or de-alkalisation removes most of the hardness salts from boiler feed water. However, malfunctioning of this equipment, occasional bypassing of the softener/DM plant or contamination of condensate or feed water with raw water often led to ingress of hardness in the boiler. All hardness salt precipitate inside boiler leading to hard scale formation on tubes. Such scale has lower conductivity causing increase in metal temperature, leading to bursting of tubes in extreme conditions. Therefore, inspire of elaborate external treatment, internal chemical conditioning is always recommended as additional safety. Following chemical methods are used for internal treatment. Phosphate Conditioning Trisodium phosphate is commonly used. Hardness salts react with trisodium phosphate to form calcium phosphate precipitate. This precipitate above pH of 9.5 colloidal in nature and therefore do not allow for form hard scale of carbonate and silicates. The precipitated hardness salts are then removed through blow down as sludge and boiler tubes are kept scale free. Trisodium phosphate, apart from acting as hardness conditioning agent, also is a good corrosion inhibitor. The recommended concentration in boiler water is given in Table -1 Note 1 : TSP will act as hardness conditioner, only when boiler pH is above 9.5 . Below 9.5 pH TSP may cause hard scale formation of Ca3 (PO)2. Therefore, coordinated or congruent phosphate treatment is recommended. The water treatment experts can advise you right treatment after studying your water quality and operation conditions. Thermax Chemicals can provide services for arriving at right chemical treatment for your boiler. Chelant- Polymer treatment: Hardness scales do not precipitate in presence of chelant like NTA/EDTA The chelant treatment is recommended when hardness ingress in boiler is experienced regularly.
Section D
Excessive chelant dosing cause corrosion of boiler Hence balanced chelant program as recommended by experts should be used. Organic polymer conditioners are used to prevent hardness scales. Such organic polymer disperse scale forming compounds like CaCO3 & Ca(PO4)2 in colloidal form facilitating their removal through blow down. Polymer and copolymer of acrylic, methacrylic, styrene maleic acrylics are commonly used. Most of the polymers are proprietary in nature and therefore dosage is best recommended by manufacturer. D. Fouling Control Suspended matter, oil/grease /oxygen & iron salts commonly cause fouling inside the boiler. Most of the suspended matter and iron salts are removed by external treatment. However due to mfg. of these equipment, contamination through condensate and concentration in boiler cause fouling of boiler tubes. Similar to hardness scales, such foulants are poor conductor of heat. Thus fouling causes overheating of tubes. Fouling can best be avoided by maintaining quality of feed water as per norms. In case of upsets or occasional contamination, polymeric disersent help to prevent fouling due to turbidity and organic matter. Iron is picked up mostly in condensate system due to corrosion of condensate line. In such case, condensate corrosion inhibitor like ammonia cyclohexylamine and filming amine is recommended. E. Turbine / Superheater Deposition Control: The solids in boiler feed water get concentrated in boiler. The concentration of solids in boiler is decided blowdown and feed water quality. The carryover of boiler water with steam depends on; Mechanical Factors: • Boiler load - Higher the load, lower is the steam purity • Water level in boiler - Higher the water level in drum, lower is steam purity. • Load Variation - Sudden increase in load reduce steam purity for short time.
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• Separation efficiency - Higher efficiency, better is steam purity. Chemical Factors: • TDS - Higher TDS in boiler, lower is steam purity. • Total Alkalinity - Higher alkalinity as % of TDS lower is steam purity • Organics - Higher the organic contamination, lower is steam purity. • Foaming - Higher the foaming character of water, Lower is steam purity. The water carried over with steam due to above reasons is exactly similar in quality to blow-down or boiler water. In superheater or in turbines, water evaporates, leaving dissolved and suspended matter as scales or deposits. Thus severity of scaling and fouling of superheater and turbine depends on boiler water quality and steam purity. Maintaining boiler water quality as per norms and maximum steam purity is the only way to prevent deposition due to carryover of water with steam. Antifoam agents help to some extend to improve steam purity in case of excessive in boiler.
F. Silica Deposit Control: Silica is volatile under high temperature and pressure inside boiler. In turbines, the evaporated silica precipitates during pressure and temperature reduction and form hard scales. Maximum allowable concentration of silica depends on water analysis. Expert’s best decide the maximum permissible concentration after striding the operating parameters. G. Condensate Corrosion Control: The carbon dioxide is present in boiler feed water in dissolved and combined from as carbonate. Under boiler pressure and temperature it is liberated and carried over with steam as CO2 gas. This gas re dissolves in steam condensate to form carbonic acid. CO2 + H2O = H2CO3 H. Maintenance of Peak Efficiency: Corrosion, scaling, fouling carryover and condensate corrosion can cause unscheduled shutdown, accidents and deterioration of system efficiency.Therefore for trouble free operation and maintenance peak operation efficiency, a combination of various internal chemical treatments is essential along with a good control over boiler water quality. Maintaining boiler water quality by using commodity chemicals likes TSP, Hydrazine, and Sodium sulfite. However, it is recommended that the care and control of water chemistry be entrusted to specialist.
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Section E
Spare Part List Spare part list
This section holds the Lubrication Schedule, Spare Part List & Curves for HRSG.
Curves Cold start up Curve - HP Section.pdf
Lubrication Schedule Lubrication Schedule
Section E
Hot start up Curve - HP Section.pdf Warm start up Curve - HP Section.pdf
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Volum e 2 — Draw ings Chapters Covered in this Part ♦ List of Drawings
List of Drawings 01. G.A. of HRSG_D11-0HR-10102_3.pdf 02. Pressure Parts Assly Elevation & Sectional Views_D11-0HR-10513_0.pdf 03. Pressure Part Assly Showing Down Comer, HP & RH Attemp._D11-0HR-10514_0.pdf 04. Pressure Parts Assly for IP Economiser_D11-1HR-70558_0.pdf 05. P & ID for HP Section_D12-1HR-7970P_3.pdf 06. P & ID for IP Section_D12-1HR-7971P_4.pdf 07. P & ID for LP & CPH Section_D12-1HR-7972P_4.pdf 08. P & ID for Gas Path_D12-1HR-7973P_3.pdf 09. P & ID for Drain,Vent & Blowdown system_D12-0HR-4496P_5.pdf 10. HP Steam Drum_P21-0HR-10693_3.pdf 11. Steam Purifier Assly_P21-1HR-71575_0.pdf 12. I.P. Steam Drum_P25-0HR-10792_2.pdf 13. Steam Purifier Assly for IP Steam Drum_P25-1HR-72514_0.pdf 14. LP Steam Drum_PF5-0HR-10985_2.pdf 15. Steam Purifier Assly for LP Steam Drum_PF5-1HR-73637_0.pdf 16. LP Superheater Assly_PF1-1HR-69636_1.pdf 17. LP Evaporator Assly_PF2-1HR-69634_1.pdf 18. Condensate Preheater Assly_PF4-0HR-10365_1.pdf 19.HP Superheater -1,2 & 3 Assly_PG1-0HR-10762_1.pdf 20. Assly & Details of HP Evaporator_PG2-0HR-10657_1.pdf 21. Assly & Details of HP Eco-1A, 1B & Eco.2_PG3-0HR-10450_1.pdf 22. H.P. Economiser -3 Assly_PG3-0HR-10449_0.pdf 23. IP Superheater Assly_PH1-1HR-69759_1.pdf 24. Assly & Details of I.P. Economiser_PH3-1HR-67149_0.pdf 25. Assly & Details of IP Evaporator_PH2-1HR-71022_1.pdf 26. Arrangement of Pressure Part Supports_PI1-0HR-11151_1.pdf 27. Assly & Details of Reheater (RH1 & RH2)_PQ1-0HR-11006_1.pdf 28. Assly & Details of CBD Tank_W31-1HR-72751_1.pdf
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Volu m e 3 — E & I Speci fi cations Chapters Covered in this Part ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦
Section 1 Section 2 Section 3 Section 4 Section 5 Section 6 Section 7 Section 8 Section 9 Section 10 Section 11 Section 12 Section 13
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Section 1 1. Instrument Hook Up Diagram.pdf
Section 2 2.1 Control Schematic Diagram.pdf 2.2 Control Scheme Narrative.pdf
Section 3 3. DCS IO List.pdf
Section 4 4. Logic Diagram for drives.pdf
Section 5 5.1 EMS1.pdf 5.2 Electrical load list.pdf
Section 6 6. Specification for Motorised Actuator.pdf
Section 7 7. Local Control Station.pdf
Section 8 8. Junction Box and Cable Schedule.pdf
Section 9 9. Instrument canopy.pdf
Section 10 10.1 Transmitter.pdf 10.2 Gauges and Switches.pdf 10.3 Valves and actuators.pdf 10.4 Sensors.pdf 10.5 CEMS.pdf
Section 11 11. EMS2 for recirculation pump.pdf
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Section 12 12.1 Motorised valves.pdf 12.2 Valve Schedule.pdf
Section 13 13.1 CBD Valve for LP Drum.pdf 13.2 CBD Valve for IP Drum.pdf 13.3 CBD Valve for HP Drum.pdf
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Volum e 4 — Vendor Manuals Chapters Covered in this Part ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦
Section 01 Section 02 Section 03 Section 04 Section 05 Section 06 Section 07 Section 08 Section 09 Section 10
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Section 01 Recirculation Pump - Sulzer O & M Manual Pump Manual Datasheet & Curves Pump Datasheet & Curves Drawings Drawings
Section 02 Dosing System - Metapow O & M Manual VK Pump Manual_Model PR10 VK Pump Manual_Model PR15–20 Drawings 1.
HP Dosing for HP Drum Drawing
2.
HP Dosing for IP Drum Drawing
3.
LP Dosing for LP Drum Drawing
Test Certificates 1.
HP Dosing for HP Drum Certificates
2.
HP Dosing for IP Drum Certificates
3.
LP Dosing for LP Drum Certificates
Section 03 HP Drum Level Gauge Glass – Hi tech. O & M Manual HP Drum Level Gauge Manual Drawing and Data Sheet HP Drum Level Gauge Glass Drawing
Section 04 I P & LP Drum Transparent Level Gauge Glass - Chem t rols O & M Manual IP & LP Drum Transparent Level Gauge Glass Manual Drawing and Data Sheet IP & LP Drum Transparent Level Gauge Glass Drawing
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Section 05 Blow Down Tank Refl ex Level Gauge Glass - Chem t rols O & M Manual Blow Down Tank Reflex Level Gauge Glass Manual Drawing and Data Sheet Blow Down Tank Reflex Level Gauge Glass Drawing
Section 06 Stack Damper — Indira Damper O & M Manual Stack Damper Manual Drawing GA of Damper
Section 07 Spring Hanger – Pipe Support O & M Manual Spring Hanger Manual Data Sheet Z1E Support Datasheet Z1B Support Datasheet
Section 08 Flow Nozzle — Micro Precision Datasheet Flow Nozzle Datasheet
Section 09 Safet y Valve — Tyco Sanm ar O & M Manual 1. Installation Instuctions for SV 2. HCI SV IOM 3. HSJ SV IOM Drawing & Data sheet Safety Valve Data Sheet and Drawing
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Section 10 Relief Valve — Tyco Sanmar O & M Manual 1. JOS_JBS_JLT RV IOM 2. JOS_JBS_JLT RV Product Range Drawing & Data sheet Relief Valve Datasheet & Drawing
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Volum e 5 — Vendor Manuals Chapters Covered in this Part ♦ ♦ ♦ ♦ ♦ ♦ ♦
Section 01 Section 02 Section 03 Section 04 Section 05 Section 06 Section 07
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Section 01 1.1 Different ial Pressure Transmit t er ( EJA) – Yokogaw a O & M Manual Differential Pressure Transmitter (EJA) – Yokogawa_Manual Datasheet Differential Pressure Transmitter (EJA) Datasheet
1.2 Absolute & Gauge Pressure Transmitter (EJA) – Yokogawa O & M Manual Absolute & Gauge Pressure Transmitter (EJA) – Yokogawa_Manual Datasheet Pressure Transmitter (EJA) Datasheet
1.3 HART Protocol (EJA Series) - Yokogawa O & M Manual HART Protocol (EJA Series) - Yokogawa_Manual
Section 02 2.1 Temp eratur e Transmit t er ( YTA Series) - Yokogaw a O & M Manual Temperature Transmitter (YTA Series) - Yokogawa_Manual Datasheet Temperature Transmitter Datasheet
2.2 HART Protocol (EJA) – Yokogawa O & M Manual Temperature Transmitter (YTA Series) - Yokogawa_Manual
Section 03 3.1 O2 Analyser (ZR 402G) — Yokogawa O & M Manual O2 Analyser (ZR 402G) — Yokogawa — Manual
3.2 HART Protocol — Yokogawa O & M Manual HART Protocol — Yokogawa — Manual
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Section 04 Motor for Recirculation Pump - Siemens O & M Manual Motor Manual Datasheet Motor Datasheet
Section 05 Therm ocouple - Pyroelectr ic O & M Manual Thermocouple Manual_100 series Thermocouple Manual_400 series Thermocouple Manual_500 series Drawing & Datasheet Thermocouple Drawing
Section 06 Elect ronic Level Sw it ch – Levelst ate O & M Manual Electronic Level Switch Manual Datasheet Electronic Level Switch Drawing
Section 07 DO2 Analyser - Emerson O & M Manual DO2 Analyser Manual 1 DO2 Analyser Manual 2
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Volume 6— Vendor Manuals Chapters Covered in this Part ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦
Section 01 Section 02 Section 03 Section 04 Section 05 Section 06 Section 07 Section 08
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Section 01 I n-Situ St ack Gas Analysers - CODEL O & M Manual In-Situ Stack Gas Analysers_Manual
Section 02 Process Valve – Xomox Sanmar O & M Manual Process Valve_Manual Forged Gate, Globe & Check Valves_Manual LPBB Gate, Globe & Check Valves_Manual Stem Replacement Process Datasheet Process Valve Datasheet
Section 03 Motor ised Valve – Xomox Sanmar O & M Manual Cast Steel Gate Valve Cast Steel Globe Valve Drawings Forged Motorised Valve Drawings PS Motorised Valve Drawings LPBB Motorised Valve Drawings
Section 04 Motorised Actuat or - Auma O & M Manual Motorised Actuator - Auma_Manual Wiring Diagram
Section 05 Blow Down Valve - BHEL O & M Manual Blow Down Valve_Manual
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Section 06 Pressure Gauge - Bourdon O & M Manual Pressure Gauge Manual
Section 07 Temperatu re Gauge – General I nstrum ent O & M Manual Temperature Gauge_Manual Datasheet Temperature Gauge Datasheet & Drawing
Section 08 Control Valve – Fisher O & M Manual HP control valve ET & EAT CV IOM EHD & EHT CV IOM ED CV IOM EWT CV IOM YD CV IOM 657 Actuator IOM 667 Actuator IOM 667–6010–6020 Controller IOM DVC 6000 Series IOM Datasheet & Drawing Control valve Datasheet & Drawing
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I nd ex
A Alarms and Trips .......................................... 95 Automatic Controls ....................................... 53
GENERAL PRINCIPAL OF WELD REPAIRS ..................................................116
H B BOILER ANNUAL MAINTENANCE AND OVERHAUL ............................................. 105 Boiler Emergency Safety Procedures ............. 93 Boiler Log Sheet ........................................... 89 BOILER PRESERVATION PROCEDURE........................................... 107
C CBD Drain Temperature Control .................... 59 Charging & Operation Of CPH ....................... 80 Charging HP Steam to Reheater.................... 79 Charging IP steam to reheat .......................... 79 Chemicals for Dosing ......................................9 Condensate Pre heater (CPH) ....................... 33 CONTINUOUS BLOWDOWN .......................... 6 Cooling of a Shutdown Boiler......................... 87 CPH Recirculation Temperature Control ......... 61
D Description of HRSG Operation ..................... 16 Design Code ..................................................4 Design Specifications......................................2 Dissolved Gases ........................................ 129 Dissolved Salts and Minerals ....................... 128 Do’S and Don’ts For HRSG Operation ........... 87 Drain & Dosing System ................................. 45 Drum Level Control ....................................... 53
E Effects of Impurities .................................... 129 Emergency Procedures................................. 93 Evaporating Heating Surface Area ................... 6 Exhaust Gas Analysis .....................................6
F Feed & Boiler Water Conditioning ................ 131 Flue Gas System .......................................... 43 FORCED COOLING ..................................... 87
Hot and Warm Start up of HRSG ................... 81 HP Attemperator Control ............................... 60 HP Boiler Components Description ................ 17 HP Boiler Feed water Control Station............. 17 HP Drum.................................................20, 28 HP Economiser ............................................19 HP Evaporator.........................................23, 31 HP Main Steam line ...................................... 25 HP Superheater............................................ 24 HP/IP/LP Dosing System .............................. 10 HRSG Cold Start Up Curve ........................... 78 HRSG Emergency Trips ................................ 86 HRSG Operation Walk Down Checks ............. 87 HRSG Shutdown .......................................... 86 HRSG Start Up & Pressurisation.................... 75 HRSG Start Up and Shut Down ..................... 63 HRSG System Protection .............................. 51
I IP Boiler Feed water Control Station .............. 26 IP Economiser ..............................................26 IP Line Back Pressure Control....................... 61 IP Main Steam line........................................ 32 IP Section Components Description ............... 26 IP Superheater .............................................31
L Levels With Respect To Center Line ................. 4 Log Sheet for HRSG ..................................... 89 LP Drum / Deaerator ..................................... 35 LP Drum Pressure Control ............................ 60 LP Evaporator ..............................................38 LP Feed Regulating Station........................... 35 LP Section Components Description .............. 33 LP Superheater ............................................ 38
M Maintaining Quality Of Steam ........................ 42 Material Specifications ....................................4
G
N
GAUGE GLASS ........................................... 12
Natural Cooling.............................................87
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O OPERATION ................................................63 Operational Control....................................... 39 Operational Precautions For Safety ............... 95 Other Materials........................................... 129
P Parallel HRSG To The Plant Steam Mains .........................................................80 pH Value of the Water and its Importance ............................................... 129 Planned Shutdown........................................ 86 Pressure Parts ...............................................4 PREVENTIVE MAINTENANCE ................... 100
Site Condition.................................................9 Stack Damper ..............................................13 Stack Temperature (CPH Bypass 3- Way) Control .......................................................59 Start up Vent (HP, IP & LP) Control ................ 61 Steam & Water System ................................. 17
T Taking Reheater On Line............................... 79 Trouble Shooting Chart ................................. 96 Tube Failures ...............................................95 TUBE THICKNESS SURVEY ...................... 106
U R Recirculation Pump....................................... 10 Recommended Boiler Water Quality ................ 7 Recommended HP Feed Water Quality ............ 7 RECOMMENDED MAINTENANCE PRACTICES............................................. 100 Reheaters ....................................................32 Relief Valves ................................................15 RH1 Attemperator Control ............................. 60
S Safety in Boiler House................................... 95 Safety Valves ...............................................13 SCHEDULE OF INSPECTIONS FOR CONDITION BASED MAINTENANCE........................................ 100 SECTION OVERVIEW........................... 63, 100
Undissolved and Suspended Solid Materials .................................................. 128 Utilities...........................................................8
V Valve Positions Chart For HP, IP & LP Section (Before Light Up) ............................ 66
W Water And Steam Quality Control And Monitoring ..................................................40 Water Chemistry......................................... 128 WELDING PROCEDURE SPECIFICATIONS (WPS).......................... 107
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