O & M Manual for Boiler

.

.

OPERATION & MAINTENANCE MANUAL FOR 1 X 41TPH 100% INDIAN COAL FIRED

ATMOSPHERIC FLUIDISED BED COMBUSTION BOILER

SUPPLIED TO

HARE KRISHNA METALLICS LIMITED KOPAL, KARNAKATA

Operation & Maintenance Manual

Contents Volume 1 — Boiler Description....................................................................................................1

Section A................................................................................................................................2 1 Design Specifications of Steam Generator....................................................................3 2 Design Code...............................................................................................................3 3 Material Specifications — Pressure Parts .....................................................................3 4 Heating Surface Area ..................................................................................................5 5 Fuel ...........................................................................................................................5 6 Fuel Analysis (% By Wt.) .............................................................................................5 6.1 Ultimate Analysis...............................................................................................5 6.2 Fuel size ...........................................................................................................5 7 Bed Material ...............................................................................................................6 7.1 Bed Material Specifications - Crushed Refractory ................................................6 8 Continuous Blowdown .................................................................................................6 9 Intermittent Blowdown .................................................................................................6 10 Feed Water Recommended Quality ............................................................................6 11 Boiler Water Recommended Quality ...........................................................................7 12 Utilities .....................................................................................................................7 12.1 Electrical Power...............................................................................................7 12.2 Cooling Water..................................................................................................7 12.3 Instrument Air..................................................................................................8 12.4 Service Air.......................................................................................................8 13 Chemicals for Dosing ................................................................................................8 14 Site Condition ...........................................................................................................8 15 Fans.................................. ..............8


4 Main Steam Piping.................................................................................................... 21 5 Boiler Blow Down System.......................................................................................... 21 5.1 Drain Lines...................................................................................................... 22 5.2 CBD Drain.......................................................................................................22 5.3 IBD Drain ........................................................................................................ 22 5.4 Other Drains....................................................................................................23 5.5 Blow down Tank ..............................................................................................23 6 Air and Gas System .................................................................................................. 24 6.1 System Description:......................................................................................... 24 6.2 FD Fan ...........................................................................................................24 6.3 Air Pre Heater ................................................................................................. 24 6.4 PA Fan............................................................................................................25 6.5 Air Ducts ......................................................................................................... 25 7 Flue Gas System ......................................................................................................27 7.1 System Description.......................................................................................... 27 7.2 Electrostatic Precipitator (ESP)......................................................................... 27 7.3 ID Fan............................................................................................................. 27 8 Fuel Feeding & Firing System ....................................................................................28 8.1 Fuel Bunker.....................................................................................................28 8.2 Rotary Feeders................................................................................................28 8.3 Fuel Mix Nozzles .............................................................................................29 8.4 Combustor ..................................................................................................... 29 8.5 Bed Drain System............................................................................................ 30 8.6 Ash Drain........................................................................................................30 9 Chemical Dosing & Sampling System.........................................................................30 9.1 HP Dosing System...........................................................................................30


11.1 Emergency Procedures .................................................................................. 53 12 Operational Precautions for Safety ........................................................................... 55 Section-D ............................................................................................................................. 59 1 Section Overview ...................................................................................................... 59 2 Recommended Maintenance Practice ........................................................................59 2.1 Preventive Maintenance...................................................................................59 3 Conditioned Based Maintenance................................................................................60 3.1 Daily Checks ................................................................................................... 60 3.2 Daily Maintenance ...........................................................................................62 3.3 Weekly Checks................................................................................................63 3.4 Monthly Checks...............................................................................................63 3.5 Checks Every Six Months................................................................................. 64 3.6 Checks Every Year ..........................................................................................64 3.7 Annual Maintenance Check Sheet ....................................................................65 4 Boiler Annual Maintenance and Overhaul ...................................................................72 4.1 Planning Before Overhaul ................................................................................72 4.2 Shutdown and Cooling the Boiler ......................................................................72 4.3 Inspection after Cooling.................................................................................... 72 4.4 Drum Inspection ..............................................................................................72 4.5 Inspection of Screen, Primary & Secondary Superheater, Evaporator I/ II & Economiser................................................................................................ 73 4.6 Expansion Joints .............................................................................................73 4.7 Insulation and Cladding.................................................................................... 73 4.8 Other Equipment .............................................................................................73 4.9 Feed & Boiler Water Conditioning .....................................................................73 4.10 Fans .............................................................................................................75


8.3 Weld Repair of Small Cracks in Tube ................................................................98 8.4 Plugging Tubes in Drums & Headers................................................................. 98 8.5 Replacement of Tube Section......................................................................... 100 8.6 Removing Tubes from Drums, Headers & Tube Plates ..................................... 100 8.7 Attached fi gures 13 to 21 ............................................................................... 101 Section E............................................................................................................................ 110 Volume 2 — Drawings.............................................................................................................. 111

List of Drawings .................................................................................................................. 112 Volume 3 — E & I Specifications.............................................................................................. 113

Section 01 .......................................................................................................................... 114 Section 02 .......................................................................................................................... 114 Section 03 .......................................................................................................................... 114 Section 04 .......................................................................................................................... 114 Section 05 .......................................................................................................................... 114 Section 06 .......................................................................................................................... 114 Section 07 .......................................................................................................................... 114 Section 08 .......................................................................................................................... 114 Section 09 .......................................................................................................................... 114 Section 10 .......................................................................................................................... 115 Volume 4 — Vendor Manuals ................................................................................................... 116

Section 01 .......................................................................................................................... 117 Fan — TLT Engineering................................................................................................ 117 Section 02 .......................................................................................................................... 117 H.P / LP. Dosing System - NM Enterprises..................................................................... 117 Section 03 .......................................................................................................................... 117


Section 07 .......................................................................................................................... 120 Local Indicator— Nishko...............................................................................................120 Section 08 .......................................................................................................................... 121 Control Valves— MIL.................................................................................................... 121 Section 09 .......................................................................................................................... 121 Power Cylinder— Keltron.............................................................................................. 121 Section 10 .......................................................................................................................... 121 ACVFD Drives — ABB.................................................................................................. 121 Index.................................................................................................................................. 123



Volume 1 — Boiler Description Chapters Covered in this Part

Section A ♦ Section B ♦ Section C ♦ Section-D ♦ Section E ♦


Section A Topics Covered in this Chapter

Design Specifications of Steam Generator ♦ Design Code ♦ Material Speci fications — Pressure Parts ♦ Heating Surface Area ♦ Fuel ♦ Fuel Analysis (% By Wt.) ♦ Bed Material ♦ Continuous Blowdown ♦ Intermittent Blowdown ♦ Feed Water Recommended Quality ♦ Boiler Water Recommended Quality ♦ Utilities ♦ Chemicals for Dosing ♦ Site Condition ♦ Fans ♦ HP Dozing System ♦ Rotary Feeders ♦ Gauge Glass ♦ Safety Valves ♦ Temperature Profile ♦ Flue Gas Pressure Pro file ♦ Process Flow Diagram ♦


Number and Type of Boiler 1 no. AFBC, Bi Drum, outdoor, water tube, natural circulation, balance draft, Under-bed firing system, Bottom Supported with RCC construction..

1

Design Speci fications of Steam Generator

Parameters

Unit

Value

Boiler Rating [MCR]

TPH

41

Steam Pressure at Main Steam Stop Valve Outlet from minimum Load upto MCR

Kg/cm2(g)

66

Steam Temperature at the Main Steam Stop valve at MCR

Deg C

490+/- 5

Main Steam Temperature Control range at the Main Steam Stop Valve Outlet.

% MCR

60 – 100

Feed Water Temperature at Economiser Inlet / Spray

Deg C

130


Description

RH Panel

Front Panel

LH Panel

Rear Panel

Details

Size In Mm

Material

Top Header

200 NB X SCH 160

SA 106 Gr B

Bottom Header

200 NB X SCH 160

SA 106 Gr B

Panel Tubes

63.5 O.D x 4.06 Thk

SA 210 Gr A1

Bend Tube

63.5 O.D x 4.06 Thk

SA 210 Gr A1

Top Header

200 NB X SCH 160

SA 106 Gr B

Bottom Header

200 NB X SCH 160

SA 106 Gr B

Panel Tubes

63.5 O.D x 4.06 Thk

SA 210 Gr A1

Opening Tubes

63.5 O.D x 4.06 Thk

SA 210 Gr A1

Top Header

200 NB X SCH 160

SA 106 Gr B

Bottom Header

200 NB X SCH 160

SA 106 Gr B

Panel Tubes

63.5 O.D x 4.06 Thk

SA 210 Gr A1

Opening Tubes

63.5 O.D x 4.06 Thk

SA 210 Gr A1

Top Header

200 NB X SCH 160

SA 106 Gr B

Bottom Header

200 NB X SCH 160

SA 106 Gr B

Panel Tubes

63.5 O.D x 4.06 Thk

SA 210 Gr A1

Opening Tubes

63.5 O.D x 4.06 Thk

SA 210 Gr A1

DC1-DC11

100 x Sch 80

SA 106 Gr B

Reducer

200 x 100Nb x Sch 80

SA 234 WPB


4

Heating Surface Area Zone

Unit

Value

Boiler Bank Zone

Sq.Mtr

354.0

Water wall Zone

Sq.Mtr

242.1

Super Heater Zone

Sq.Mtr

688.0

Inbed coils

Sq.Mtr

81.6

Economiser

Sq.Mtr

566.0

Sq.Mtr

1931.7

Total Heating Surface

5

Fuel Fuel Type

Main Fuels Start up Fuel

6

Fuel Name

• Indian Coal • Charcoal sprayed with Diesel fuel.

Fuel Analysis (% By Wt.)

6.1 Ultimate Analysis Composition

Hydrogen

Unit

Indian Coal

% Wt

2.30

Char

0.42


7

Bed Material

Required Per start Up

:

60 Metric Tonnes (Approx.)

Lump Size

:

0.8 mm to 2.36 mm (100 %)

Bluk Density

:

Chemical Composition

:

1000–1100 AL2O3 %— 35 to 45 SiO2 % — 55 to 65

7.1 Bed Material Specifications - Crushed Refractory

Material

:

Sieved natural sand/Crushed

refractory Bulk Density

:

1200 – 1400 Kg/m3

Temperature

:

>1300 deg C

SIZE

:

0.7 to 2 (for sand) Fusion

Shape

:

Sub Angular / Spherical. Percentage limits

Chemical Composition

SIO2

:

AL2O3

:

50–60 37-40 Min 30% required


Parameters

Unit

Value

Total Fe

ppm

<0.01

Total Cu

ppm

<0.003

Total O2

ppm

<0.007

Oil & Organic.

ppm

Nil. 8.5 – 9.5

pH Value at 25 Deg C Total Dissolved Solids

ppm

Silica as SIO2

ppm

Hyderzine residual

ppm

0.1

<0.02 0.02 – 0.04

11 Boiler Water Recommended Quality Parameters

Unit

Value

pH at 25 deg C

-

9.5 – 10.2

Phosphates PO4

ppm

2- 6

Total Alkalinity

ppm

4 max.

Sodium Sulphite

ppm

Nil

Oil & Organic

ppm

Nil

“p” value

mval/kg

0.1


Parameters

Unit

Supply Temperature

Deg C

Value

Ambient

Quality

SOFT & Chlorine free

Duty

Sample Cooling.

12.3 Instrument Air Parameters

Unit

Value

Kg/cm2(g)

6–7

Dew point

Deg C

-40

Temperature

Deg C

Pressure

Ambient

12.4 Service Air Parameters

Pressure Temperature

Unit

Value

Kg/cm2(g)

7

Deg C

Ambient

Quality

Dry & Oil Free

Duty

General purpose

13 Chemicals for Dosing


FD fan

ID Fan

PA Fan

Duty conditions

Unit

Test Block Conditions



Quantity

Nos.

1

1

2

Clean Air

Flue Gas

Clean Air

Nature of medium Air /Gas density

Kg/N M3

1.29

1.31

1.29

Volume

Kg/hr

77486

86970

15300

Gas Temperature at Fan Inlet

Deg C

45

150

45

Absorbed Power / Rated Fan Power

KW

250

90

50

Differential static head

mmWc

860

200

760

‘Fan Speed

Rpm

1480

980

2920

Static Pressure

mmWC

8437

1962

2920

22220 EK/C3

222216 EK/C3

222176 EK/C3

SNH-520

SNH-516

LOE-217

22220 EK/C3

222211 EK/C3

222174 EK/C3

SNH-520

SNH-511

LOE-214

Free/Fixed Bearing Housing


Description

Make

HP

Crompton/Siemens

Type

0.5HP, 1500 RPM, TEFC-IP55, 50 Deg C amb. ,415 V, 50 Hz

Rating

0.5 HP / 1500 rpm

Make

N M Enterprises

Type

AG — 2 Model, Motorised propeller type 750 rpm (material SS 304)

Rating

0.5 HP / 1500 rpm

Storage Working Volume

300 litres

Fluid To Be Handled.

Tri sodium phosphate.

Motor for agitator

17 Rotary Feeders Make - Nova Bulk Handlers (P) Ltd. Refer – G.A for Drag Chain Feeder. Drg No : Nova /48/ 07–08. 2 sheets Description

Rotary Feeder

Type

Horizontal

Capacity

See Table Below


Char

Unit

Speed Through Loading Capicity Per Unit time per Revelation

Design

100% MCR

50% MCR

Min

RPM

3.14

2.62

1.31

0.65

%

95

Kg/hr/reve 0.00234

18 Gauge Glass 18.1 Drum Level Gauge Description

Details

Make

HI- TECH SYSTEMS AND SERVICES LTD.

Tag No.

LG-600A & LG-600B

Type

Bicolor Port type

Location

Steam drum

Operating Pressure

72.7 kg/cm2 (g)

Design Pressure

78.8 kg/cm2 (g)

Hydrotest Pressure

315 BAR

C/C Distance

800 mm

Visibility Range

403 mm


Description Application

Unit

Tag No Model Rated Capacity Quantity

Kg/Hr

Drum LHS

Drum RHS

SH

B7

B8

S4

HC–56 W-IBR-SPL

HC–56 W-IBR-SPL

HCA–58– W-IBR-SPL

19027

19313

13892

1 / BLR

1 / BLR

1 / BLR


20 Temperature Profile 20.1 Gas Temperature

At the outlet of furnace

:

875 Deg C.

At the outlet of bank tubes

:

445 Deg C.

At the outlet of economiser

:

250Deg C.

At the outlet of air-preheater

:

160Deg C.

At the outlet of ESP

:

160Deg C.

Condensate from process

:

47 Deg C.

Process return

:

100 Deg C.

Make up water

:

32 Deg C.

inlet of FW Pumps

:

130 Deg C.

the inlet of economiser

:

130 Deg C.

At the outlet of economiser

:

216Deg C.

20.2 Water Temperature


Section B Topics Covered in this Chapter

Section Overview ♦ Feed Water System ♦ Boiler Pressure Part Description ♦ Main Steam Piping ♦ Boiler Blow Down System ♦ Air and Gas System ♦ Flue Gas System ♦ Fuel Feeding & Firing System ♦ Chemical Dosing & Sampling System ♦


1

Section Overview

This section gives a brief overview of the boiler and its associated systems. The description of the various systems that form part of the boiler package is also included. The aim of this section is to make the reader familiar with the boiler package components before introducing the operation and maintenance sections..

GENERAL DESCRIPTION

The main parameters of the boiler are Maximum Continuous Rating

41TPH

Steam Pressure

66 kg/cm2

Steam Temperature

490+/- 5 Deg C

Fuel Fired

Indian Coal and Char

Brief Overview

The boiler package supplied by Thermax Ltd, Pune, India and has been designed for 41 TPH steam generation, 66 kg/cm2 (g) pressure, 490 +/- 5 deg C Super Heated Steam output designed for firing with 100% Indian Coal and secondary fuel 70% Indian Coal + 30% Char. This boiler is AFBC, Bi-Drum, outdoor, natural circulation, Water tube, fluidised bed combustion, Underbed Fuel Feeding System, balance draft, Bottom Supported with Steel construction & Hopper Bottom design. Fuel Combustion will be in an Atmospheric Bed Combustor (AFBC) fixed at the Boiler bottom. Fuel is stored in Bunker. Rotary feeders are

The boiler has been designed to con firm to Indian Boiler Regulations (IBR)

The boiler is divided into a combustion zone i.e. furnace and non-combustion zone i.e. economiser, air heater etc. The furnace sides, front and rear are of membrane panel construction providing a gas tight sealing. For all the four water wall bottom headers, water is fed through supply pipes from water drum. The sidewall, front wall and rear wall panel tubes top headers are connected to the steam drum through risers. The front wall panel tubes form the roof of the furnace. Feed water is pumped by feed water pumps from deaerator to economiser through feed water control station. The feed water from economiser


• Maintains the super heater temperature by controlled combustion. Balanced draft conditions inside the furnace suitable for combustion is being maintained by I.D fan. Air pre-heater, ESP and fi nally into the stack by ID fan. The starting, stopping and safe shut down of boiler are done by manual intervention systematically and sequentially through DCS control system from control room. Details of equipment’s, their brief operational and maintenance features are elaborated in the subsequent sub-sections and chapters of this manual.

2

Feed Water System

(Ref. P & I Diagram D12-1PD-6499P, R-2)

Feed water system consists of the following: 1. Feed water control station. 2.1 Feed Water Control Station

kept closed. This drain is to be opened only to drain the line when control valve has to be opened for inspection/maintenance. Following instruments are provided at the inlet of feed water control station: • Flow nozzle FE-500 with flow transmitter FT-500 is provided for total feed water flow measurement. Flow transmitter transmits the water flow signal to flow indicating controller at control panel. • A 25 NB pipe tapping with W33 valve for the SH desuperheater. Control valve is operated through the Flow indicating controller (FIC-600). Input signals are given to FIC-600 by Level indicating controller (LIC-600), steam flow transmitter (FT-604) and feed water flow transmitter (FT-500). Ref. three element control for detail operation of drum level controller. From the control station feed water flows to economiser inlet header (bottom) through an 100 NB non return valve (W-24). Thermocouple TG-501 is located before the Eco. inlet header to measure the feed water temperature prior to Eco. Pressure gauge PG-501 is provided with isolation


and a suitable control signal is generated which is used to drive the 100% control valve. The major advantage of the loop is its ability to maintain drum level during load swings, variations & throw conditions that are certain to occur during the operating regime of any steam generator. Though this loop is advantageous from an operation point of view, it is recommended to use this loop at loads > 30%, as the single element control loop is optimised for low load conditions with its control valve sizing & parameter tuning 2.2 Attemperation Control Station

A tapping 25 NB from Feed Water line is provided, to supply spray water for Attemperator. This line is provided with a manual isolation valve W-33 & NRV W37. A temperature control valve TCV-604 with isolation valves W-34 is provided. A by-pass manual valve W-35 is provided. This line connects to Attemperator through a NRV W-36.

3

Boiler Pressure Part Description

This boiler is AFBC design, BI-Drum, outdoor, natural circulation, Water tube, fluidised bed

Provision of this additional heating surface, increases the ef ficiency of the steam-generating unit and saving in fuel consumption is achieved. Economiser is located in between boiler bank outlet and Air Pre-heater. A continuous loop tube Economiser assembly is constructed with rows of 38.1 O.D x 3.66 thick tubes, and two headers. Both the ends of the coil were terminated to the top and bottom headers by welding. Feed water flows from the bottom header to the top headers through these coils. Heated water flows out from the top header to steam drum through the connecting pipe. The economiser is fully drainable by the drain valves W-26 located on the inlet header. Economiser top header is provided with the following attachments:

• 25 NB air vent with two valves (Tag No. W 28 which will be kept open during initial filling to remove the air trapped between the coil. Closed after free fl ow of water from the vent. • Pressure indicator PG-502 with twin isolation valve W 27.


drum. DWLG‘S are provided at both ends of the drum.

ensure the uniform distribution of feed water in the entire length of the steam drum.

• Two nos. Level transmitters are provided LT 600A B C which transmit the actual water level to the remote indicators i.e. at control room and provide drum level signal to the drum level controller

Pipe is made in two pieces for installation ease and provided with fl anged joint.

• Drum safety valves B 7 & B 8 which protects the boiler and the personnel against the consequences of abnormal pressure increase because of sudden load decrease, malfunctioning of firing system, steam stop valve etc. • Level indicator LI 600: this gauge is mounted at the fi ring fl oor, so as the fi ring fl oor attendant can view the drum level. • H.P dosing connection: To dose phosphate in to the steam drum to maintain the boiler water quality. • Continuous blow down (CBD): To drain the boiler water during operation to maintain the water concentration. Also the water sample is taken from this blow down. It is connected to the common IBD tank directly as well as through CBD tank.

Continuous blow down pipe (CBD) – 1 no 25NB

perforated pipe with 6-7 holes is installed in the drum with holes at 6 O’ clock position. CBD pipe is provided to drain the boiler water to maintain the boiler water concentration at the specified limit. Pipe is made in two pieces for installation ease and provided with a drain hole to drain the water during shut down. HP dosing pipe – 1 no 25NB perforated pipe with

6-4 holes is installed in the drum with holes at 12 O’clock position. As the pipe is of perforated type the chemical is uniformly distributed across the length of the drum. Chemical dosing at steam drum is, to maintain boiler water concentration as per the specified limit. Pipe is made in two pieces for installation ease and provided with a drain hole to drain the water during shut down.


There are two main down comers from water drum which supplies water to all bottom headers these have O.D 323.9 and 33.32 thk. And material is SA 106 Gr. B. Two branch supply pipes are taken from these downcomers to supply water to bottom headers. Supply pipes are taken for RHS and LSH evaporator panel bottom header each had been provided. And supply pipes are taken for front wall bottom header & for rear wall bottom header each.

shape under the expansion conditions. Front wall tubes are supported through rod slings with rocker washer from the super structure. Front wall bottom header is provided with a 25 N.B. drain connection, which normally remains closed during operation of the boiler. It is to be used to drain the boiler during shut down and start-up.. 3.5.2 Rear Wall (Refer Drg no. P45-1PD 45012)

3.5 Furnace

Furnace is the part of the boiler where the chemical energy in the fuel is converted into thermal energy by absorbing the heat produced through combustion of fuel. The furnace is designed for ef ficient and complete combustion, with due consideration to the factors that effect, combustion ef ficiency like fuel residence time inside the furnace, temperature and the turbulence required for complete mixing of fuel and air.. Following are the distinct advantages of the furnace design:

• Heat transfer is facilitated inside the furnace in

Rear wall is formed with rear bottom header (200 NB x SCH 160 THK) and 63.5 OD x 4.06 thick tubes (One end is welded to the bottom header and the other end is terminated to the top header. Rear wall tubes receive water from steam drum through supply pipes. To strengthen the wall tubes buck stay beams have been provided. Rear wall tubes are supported through rod slings with rocker washer from the super structure. Rear wall bottom header is provided with a 25 N.B. drain connection, which normally remain closed during operation of the boiler. It is to be used to drain the boiler during shut down and start-up. 3.5.3 R.H & L.H Side Wall


seale sealed d encl enclosu osure re suit suitab able le for for balan balance ced d draf draftt operati operation. on. Adequa Adequate te number number of access doors doors (which normally remain tightly closed) have been provided in the furnace and in the second pass for inspection of observation of the bed/Flame and for addition bed material during regular operation. 3.6 Inb Inbed ed Evap Evaporat orator or (Drg No. PD1-1PD-45751, PD1-1PD-45751, R-1) Figure 1 — Inbed Evaporator Evaporator

In-bed coils (50.8 50.8 OD x 6.35 6.35 THK THK Tubes) are provided inside the furnace. Water mixture enters the the in bed bed evapo evapora rator tor botto bottom m heade headerr throu through gh down comers from steam drum (D1 to D4) and the stea steam m wate waterr mixt mixtur ure e exit exitss throu through gh in bed evaporator top header and then through water wall panel tubes to water wall top headers. Both R.H R.H & L.H L.H Inbed Inbed Evap Evapora orato torr bott bottom om heade headers rs recei receive ve wate waterr from from the stea steam m drum drum thro through ugh supp supply ly pipes. Inbed evaporator outer and Inner coils bottom loops are provided with round studs at an angle of 120 deg to reduce direct impingement of particles on the bare tubes and to avoid erosion. Phoscast Phoscast

Superheated steam also eliminates the formation of condensate in steam piping which is harmful to the turbine blades and pipelines. There There are are two two stag stages es of supe superhe rheat ater er in this this boiler. They are SH-1 & 2. From the steam drum dry dry satura saturate ted d steam steam enter enterss the the SH-1 SH-1 i.e. i.e. 1st 1st stage inlet header (O.D 219.1 x 18.26) through satur saturat ated ed steam steam suppl supplyy tubes. tubes. From From the 1st stage inlet header, steam fl ows to 1st stage outlet header through through 44.45 O.D x 4.06 Thk coils. SH-1 is installed vertically above the goose neck zone with with adequate adequate suppor supports. ts. The SH headers headers are are supported through saddle supports. 1st stage outlet header is connected to SH-2 i.e.2n i.e.2nd d stage stage inlet inlet header header with with Attemp Attemperat erator or.. From the 2nd stage inlet header, steam flows to 2nd outlet header through 44.5 OD x 4.06 thick coils. 150 NB Steam outlet line is taken from the 2nd stage outlet header of Superheater SH-2. Following connection is attached to primary S.H. Inlet header:

• 15NB sampling sampling line with with isolation isolation valve S-17, which is used to take saturated steam sample.


• Thermoc Thermocoup ouple le (TE-601) is provided on inlet pipe for panel mounted temperature indicator (TI-601).

• Thermoc Thermocoup ouple le (TE –602) is provided at the outlet of the Attemperator header for panel (TI-602) . mounted temperature indicator (TI-602) After Attemperator steam enters the secondary super-heater inlet header. 3.10 Convection Bank (Refer Drg no. P61-2PD-40326, P61-2PD-40326, R-1) The name

itself indicates that heat transfer in this area is by convecti convection on mode. This This is a Bi-dru Bi-drum m boiler boiler, the steam drum (Top drum) and the water drum (mud drum) is connected by a set of tubes called convection bank tubes. Convection bank tubes are constructed of 50.8 O.D O.D x 4.06 4.06 thk. thk. Both Both ends ends of the the tubes tubes are are terminated at water / steam drum, and the ends are fi xed to drums by expansion expansion of the tubes. Bank Bank sides sides were were covered covered with with refract refractory ory tiles tiles follow followed ed with with insula insulatio tion n and outer outer MS casing casing.. Also the tubes are strengthened by buck stay arrangement at one elevations.

of pressure at panel, for steam density correction and for pressure indicating PI 404 for Steam flow compensation. • Start up vent: Start up vent, with pneumatic control control valve (S3) and manual isolation isolation valve (S2) is used to vent the steam to atmosphere during boiler start up, as the main steam stop valve & by-pass by-pass valve remains closed till the boiler reaches reaches the operating operating pressure. This also protects the SH coils from over heating during start up. To redu reduce ce the the nois noise e leve levell from from the the stea steam m venting to atmosphere, a silencer is provided to the start up vent line. If there is any interruptions in steam fl ow due to sudden turbine trip / load cut by the end users, start up vent valve to be opened immediately to maintain boiler pressure else safety valve will blow. • Drain connecti connection on with twin twin valves valves S8 & S8 before the main steam stop valve. Drain is terminated terminated to Blow down tank. • 150 NB Main Steam Stop Valve (MSSV) S-9 (M 131 ), along with a integral bypass/equalising


System Descript Description ion D12-1PD-6499P, R 21)(Steamand P&IDiagram(D12-1PD-6499P Water system) show the various drains from the boiler boiler,, main main steam lines, lines, etc. A common drain drain system has been provided for both he boilers.

Large Large quan quantititities es of stea steam m of high high press pressur ure e / temperature water are not drained through open canals for the following reasons: a) Such Such drai draini ning ng will will caus cause e spla splashi shing ng of high high volumes of steam, which can be a nuisance by the noise it creates, and also it affects the visibility around the draining draining area. b) High temperatures of these drains can cause scalding injuries to workmen who may come in contact with it. c) The force and temperature of these drains will erode the linings of the drain canals. d) Low-pressure steam, which can be recovered, if required, is wasted. 5.1 Dr Drai ain n Li Line nes s

– LH In-bed evaporator bottom header h eader – RH In-bed evaporator bottom header • Economiser Economiser header drains – Eco I/L header Drain header has following following • A 50 NB -thk drain line for draining Furnace Drain Header to nearest trench. • An 50 NB thk initial filling line with W -26 and isolation valve W-26. The water is supplied from DM water transfer pump. Drai Drain n line line is conn connec ecte ted d to IBD IBD tank tank with with an isolation valve W - 40 5.1.2 SH Drain Line

Following drains (All 25 NB) are connected to the SH drain header ). • Main steam steam line drain drain before and after after main steam stop valve. Main steam line drain before main steam stop valve has 25 NB drain line with isolation valve


SOURCE

VALVE TAG NOS.

TEMP. OF DRAIN °C

FREQUENCY OF USAGE

Draining of condensate S.H. & Main steam FOR M.S. LINE isolation valves Varying from during start-up and after a drain S-8 70 to 520 shut down. For ECO drains isolation valves Furnace & Economiser are W-26, and for furnace W.W ~70 - 150 drains isolation valves are W-39. Drains indicated in the above Table are connected to the common intermittent blow down (IBD) tank except CBD drain and various samples. CBD tank is connected to IBD tank while samples to the nearest drain trench. 5.4 Other Drains

Other drains of the boiler are open drains and are connected to the nearest trench within the boiler area. The drains are • • • •

All level control station drain All pressure control station drain Steam drum level indicator. Steam drum safety valve drains

During boiler start-up and shutdown.

of the tank, such that the drain fluid is directed circumferentially around the inner wall of the tank. Tangential flow of the drain fluid into the tank separates steam from the water. Steam rises to the top of the tank and water collects at its lower portion. A vent is provided at the top of the tank. Following connections are connected to the common BD tank. • A Level gauge glass LG-550 with isolation valves D6 & D6 has been fitted on the tank to verify water level in the tank. • Tank is provided with a 50 NB drain pipe with a valve (Tag no. D-7) for fl ushing purpose. • Connections from CBD line, from IBD line, from Drain line, and from MS Drain line.


6

Air and Gas System

( P & I DIAGRAM – D12-1PD-6500P, R- 2)

the required fan output pressure and flow. The VFD receives input signal from furnace pressure indicating controller (HZ 200).

Air System

Fan Discharge Duct

This chapter describes supply of primary and secondary air to the boiler. The components that form part of air system are –

1. To minimise the force due to possible movement of the discharge duct on the fan, as well as to isolate fan vibrations being passed on to the duct, the fan is connected to the discharge duct through bellows type expansion joint (1no)

• FD Fan • Air Pre-Heater (APH) • Air ducts – Combustion air to Windbox – Secondary Air OR Over fi re air. – Secondary Air For Air Spray Nozzle

Test pockets temp. gauge and pressure gauge is provided on outlet duct. A Draft Gauge (DG 200) is provided with an isolation valve (A1)attheoutlet duct. Fan outlet is connected to air pre-heater (APH) through a ducting.

6.1 System Description:

Aerofoil

6.2 FD Fan

An Airfoil to measure the air flow is provided (AFM 200). The air flow is measured by the principle of pressure drop across the element being proportional to the air flow passing across it. Flow transmitter (FT-200) gives input to a controller (FIC-200), which also get inputs from combustion control and ultimately it controls suction air by power cylinder.

Figure 2 — FD Bearing

Each Boiler is provided with 1x 100 %. F.D fans driven by electric motor to supply main combustion air to the furnace and various other equipment FD fan is of centrifugal type with


APH-II. APH is provided with common hopper for APH-II & APH-I. Due to change in direction and sudden pressure drop in APH hopper, fl y ash gets collected in the hopper. Hot air duct from Bed Ash Cooler is connected to APH hopper. Ambient air from FD passes through APH to absorbs sensible heat from flue gases. A manually Operator damper is provided at the inlet of APH. Access doors are provided in connecting ducting for inspection of air heater tubes. Hot primary air is then connected to Windbox Compartments below Combustor (Bedplate) from bottom & hot secondary air to SA duct to furnace. Following are the attachments to APH inlet duct:

• Aerofoil AFM-200 for total air flow measurement.

A pneumatically operated inlet guide vane damper is provided at PA fan inlet, to maintain the required pressure at the fan outlet. The actuator is provided with limit switches for 0% positions, which are used as safety interlocks for fan start permissive. Tight shut-off dampers are provided at the upstream & downstream of PA fan, to isolate fans in case of maintenance. A pressure Indicator ( Draft Gauge DG-300 with Isolation Valve (A–6 ) is provided at common outlet duct for indicating the Primary Air pressure to fuel feeding system. To minimise the forces due to possible movement of the discharge ducts on the fan, as well as to isolate fan vibrations being passed on to the duct, the fans are connected to the discharge duct through bellow type expansion joints. 6.5 Air Ducts

• Pressure Indicator ( Draft Gauge) DG-200 with isolation valve A1 for remote indication in panel.

6.5.1 Combustion Air To Windbox

Following are the attachments to APH outlet duct:

Hot air duct after APH terminates to 3 compartments in the windbox through branch ducts. The main duct is branched into 6ducts and connected to each compartment through

Pressure Indicator ( Draft Gauge) PG-202 with


30 nozzles of 33.4 O.D x 2.87 thk pipe inclined horizontally. Ducting is provided with damper at the inlet of Header to adjust the air pressure. A pressure pocket and test pocket is provided each on LH and RH OFA headers. 6.5.3 Secondary Air Duct To Air spreading nozzle

A Secondary air tapping is taken from APH fan outlet duct. One main branch is taken from the APH outlet duct, which is further divided into two sub-branches, One branch is connected to the HEADERS 1 & 2 on both sides and other branch is connected to the HEADERS 3 & 4. And one

another branch is connected to Air spreading nozzle, which is used for Fuel spreading inside the furnace. Manual dampers are provided at inlet of air spreading nozzle on both LHS & RHS. Boiler RHS & LHS Air spreading nozzles are located at 733 -mm & 1408-mm distance from C/L of IB Evaporator bottom header. This spreading nozzle consists of Holes & Openings. Suf ficient Ducting supports are provided at suitable locations to strengthen the branch ducts. Suf ficient Expansion Bellows had been provided at suitable locations in air ducts to take care of thermal expansion.


7

Flue Gas System

Flue gas from the furnace passes through S.H coils, Convection bank tubes, Economiser coils, Air Pre-heater tubes and ESP to I.D Fans. From the I.D fan gas is blown through chimney to atmosphere..

Temperature Indicators

Flue gas temperature at Air-heater outlet

(TE-109)

Flue gas temperature at ID fan inlet

(TI-110)

Pressure Indicators ( Draft Gauge)

7.1 System Description

Combustion products of gases exits from the furnace and passed to S.H zone. Furnace is provided with the following attachments in the fl ue path. • Furnace pressure transmitters, PT-100 with isolation valves FG- 1 and Pressure Indicator PIC–100 are provided to Measure Furnace Pressure • Furnace pressure high and low alarm / trip (PAHH-100 & PAH-100, PALL-100 & PAL-100) are also generated from above transmitters. • A Temperature Elements 3 no (TE-102 A B C ) at the top of the furnace. • Temperature Element (Tag no. TE-100) with

Flue gas pressure at Economiser inlet Flue gas pressure at Economiser outlet

(DG-106)

Flue gas pressure at Air-heater outlet

(DG-108)

Flue gas pressure at ID fan inlet

(DG-109)

(DG-107)

O2 Analyser

A probe connection to measure the O2 % by O2 Analyser Tag no AP is provided in ID Fan Inlet duct. 7.2 Electrostatic Precipitator (ESP)


required furnace Draught. The VFD receives input signal from furnace pressure indicating controller (PIC-100). Also two manual field operated dampers are provided at fan inlet & outlet duct. Pressure Gauge DG-109 are provided on individual ID fan inlet duct for remote indication. To minimise the force due to possible movement of the discharge duct on the fan, as well as to isolate fan vibrations being passed on to the duct, the fans are connected to the duct through bellows type expansion joints. ID fan outlet ducts are connected to chimney.

8

Fuel Feeding & Firing System

(Refer

Fuel Feeding F59–1PD-46483, R-0)

System

DRG

Description

Details

Indian Coal: 100%< 6 mm, 30% (max) < 1 mm. Fuel Size

Char: 100%< 3 mm 30% (max) < 1mm. Iron particles < 0.5% by wt. Coal: Non caking type.

Feeders Type and Size

Horizontal , Dia 208 mm x 625mm Long.

8.1 Fuel Bunker no

Aim

Fuel feeding system is of UNDERBED FEED type and the fuel is burnt in an ATMOSPHERIC FLUIDISED BED COMBUSTOR. Fuel is fed through fuel feed ROTARY FEEDERS with the

From the fuel processing plant the fuel enters the fuel bunker of different capacities as mentioned above, through belt conveyors. Fuel is stored in separate bunker and fed through feeders to a chute above Rotary Feeders and then fed to boiler through under bed feed system. A manually operated isolating sliding gate is provided at the bottom of bunker before fuel


achieved by varying the speed of the feeder. Fuel from feeder discharge is conveyed to Combustor with the help of air spreading nozzle. Fuel Distribution Chutes

Fuel from the fuel drop chute is fed into the MIXING NOZZLE provided below the fuel drop chute, where fuel and air mixes for conveying the fuel pneumatically to the Combustor. 8.3 Fuel Mix Nozzles

Air from the PA fan enters the mixing nozzle and creates the suction to allow the fuel to enter the mix nozzle for conveying to Combustor. In the mixing nozzle fuel and air mixes and enters the fuel-conveying pipe. Total 9 nos. mixing Nozzles are provided. PA lines from respective PA headers, for nozzles is provided with manual butter fly type damper (125 NB) Below the fuel mixing nozzle there is a drain provided to clean the mix nozzle in case of any foreign materials / big size particles accumulation. 8.4

Comb

to

Ash drain-pipe per compartment is provided to the Combustor, at suitable locations. Bed drainpipe from the Combustor is provided with a hand operated sliding gate to drain the ash. 8.4.3 Bed Thermocouples

There are 6 bed thermocouples having 35 mm of holes. 2 thermocouples for each compartment for indication of the bed temperatures. Details of bed thermocouplesTemperature Indicators

1st Compartment (Start-up Compartment) 2nd Compartment 3rd Compartment

TE-101 A, TE-102 A TE-101B & TE-102E TE-101C & TE-102C

The above temperature element gives input to Temperature controller TIC-101 A to C which provides Temperature High & Low Alarms Indicators (3 nos. each provided, Tag nos. 101


8.5 Bed Drain System

To maintain bed level and to drain out bed ash / shale / stones etc from the fluid bed Combustor, Manual ash drainpipe per compartment is provided to the Combustor with slide gate, at suitable locations.. 8.6 Ash Drain

During the boiler operation ash is generated in the Combustor. Fine ash goes along with the flue gas, which will be collected in the ESP, and the coarse particles remain in the bed and gradually increase the bed level. Bed ash quantity depends upon the ash content in the fuel, foreign materials like stones and shells etc. Since bed height needs to be maintained for trouble free operation, it is necessary to drain the excess material to maintain the desired level.

9

One mixing water connection, one drain, one over flow connection with isolation valves, one motorised agitator for proper mixing of the solution and a perforated screen at the inlet to avoid foreign material entry. Two pumps with motors are mounted on the base frame. One pump is operating while another is stand by. Pump suction line is tapped of from the bottom of the tank. It is connected to the pump through an isolation valve and a strainer. A direct connection of the DM water is given in between strainer and isolation valve for flushing of the discharge piping & strainer. Pumps are high precision positive displacement type, in which feeding volume can be controlled. In the discharge line a pulsation dampener is given to dampen intermittent discharge from the pump. After that one NRV, a pressure gauge and isolation valve is provided. One relief valve to maintain the pressure in the system is given.

Chemical Dosing & Sampling System

(Please refer Vendor Manual for relief valve set pressure)

Chemical dosing system consists of chemical

Discharge of the relief valve is connected back to the tank Pressure gauge is provided with


the chemically concentrated water is replaced with the clear water; thus choking of piping can be avoided. Please refer Vendor manuals for technical data & safe Operation and Maintenance of dosing system.

9.3 Sampling System

Sampling system consisting of sample cooler and the cooling water sub-system for providing steams & waters samples suitable for SWAS system. Sample Coolers

There are three sample coolers provided on the boiler for the Feed water sample, Drum water sample and Superheated Steam sample.

The sample coolers are simple shell and coil type heat exchangers. In these sample coolers, the sample is passed through the coils while the cooling media is passed around the coils on the shell side. Individual sample coolers are provided with isolation valves on the cooling water inlet & cooling water return lines. The cooling water is provided from the plant via the terminal point at pressure of 3.5 Kg/cm2 (g) & temp. 33 Deg C. The supply & return line is provided with isolation valves


Section C

knowledge of all components their design, purpose, limitations and relationship with other components is must for the operators.

Topics Covered in this Chapter

Boiler Start Up ♦ Operational Control ♦ Balance of Plant Start Up (Boiler) ♦ Part Load Operation By Bed Slumping ♦ Warm / Hot Start Up ♦ Boiler Shutdown ♦ Do’s and Dont’s ♦ Controls ♦ Troubleshooting Chart ♦ Walkdown Checklist during Operation ♦ Boiler Safety ♦ Operational Precautions for Safety ♦

Section Overview

This section describes the start-up and shutdown procedures of the boiler.

1

Boiler Start Up

This chapter describes the boiler start up and shut down procedures as applicable for the following boiler conditions: 1. Start up of a cold boiler 2. Start up of a warm / Hot boiler 3. Boiler shut down NOTE

• Procedures explained in this chapter apply for start up of the boiler already commissioned. Commissioning a new boiler calls for several additional requirements.

Note

• It is assumed that operators are fully familiar with the design and construction features described in the earlier section.

• The procedures explained in this section apply for start up of a boiler already commissioned. Commissioning a new boiler call for several additional requirements which are not explained

• It is assumed that Operators are trained in operation of similar type of boilers and have been licensed to operate boilers by the State Boiler Authority.


1. Furnace, Super heater and convection bank area are clear, all maintenance personnel have been removed and no scaffolding or inspection devices have been left inside. 2. Furnace floor, water wall and convection tubes are clean and there is no evidence of any water drips, slag or any other deposits. 3. Steam drum is clean and manholes are closed properly. 4. Confirm the evaporator and furnace wall drain valves are in closed position. 5. Verify the in-bed super heater supports are intact and in its rest position 6. Verify that all access doors, inspection doors of furnace and wind box are tightly closed. 7. Verify that all peepholes have been tightly closed and sealing/ cooling air connections are intact and the air valves are open. 8. Verify that the air duct, windbox, economiser, air pre-heater, dust collecting equipment’s and flue gas ducts are clear and that all maintenance personnel have been withdrawn. Ensure that the manhole doors closed properly.

5. Verify that the drains and vents of standpipes provided for level transmitters, indicator & gauges are closed. WATER DRUM

1. Close the IBD line isolation valve(D-3 ) and the IBD valve (D-4). ID, FD & PA FANS

1. Check that the fan inspection doors are closed. 2. Ensure that the bearing lubrication is done properly. 3. Check that the coupling and guards are installed properly. 4. Check that the manual isolation dampers at inlet and out of the fan are kept closed. 5. Ensure that the control damper actuator is properly fixed to the operating lever and air supply is open to actuator and I/P Conver ter. DEAERATOR

(DEAERATOR IS NOT IN THE SCOPE OF SUPPLY, YET FOLLOWING ARE THE CHECKS TO BE DONE PRIOR TO START UP OF THE


4. Check that the manual isolation valves at pump suction, minimum re-circulation and balancing lines are kept in open position and the discharge valves are close position.

ROTARY FEEDER

5. Check that the cooling water supply is available.

3. Confirm the tightness of the feeder chain.

FEEDWATER AND SPRAY WATER LINE

1. Verify the bearing lubrication is done properly. 2. Confirm the tightness of the drive chain. 4. Open the slide and rod gate above the feeder and admit the coal to the feeder.

1. Select the drum level and feed water flow controllers( LCV-120)in manual mode and close the control valves (FCV-500B ) also close the bypass motorized control valve 100 % W-17. and 30% FCV500B

5. Confirm the outlet chutes are clear with out any blockages.

2. Open the isolation valves of 40 % control valve.

2. Pa line/duct leakage to be checked.

3. Select steam temperature controller TIC 604 in manual mode with 0% output

4. Dampers proper operation to be checked.

4. Close the manual isolation valves of the spray water control valve (W34 & W34) for Attemperator, along with the bypass valve (W35). SAMPLE SYSTEM

1. All the sample lines isolation valves to be closed. Sample coolers can be taken into

UNDER BED FIRING SYSTEM

1. Pa nozzle bolts tightness to be checked. 3. Pa line blockages to be checked. 5. Verify the open/close operation of the compartment PA damper and keep the damper in close position. 6. Verify the individual pipe isolation vales are in open position. APH

1. Ensure the soundness of the tube rolling joints.


5. Pilot gas [LPG] up to terminal point isolation valve. 6. LDO tank is filled with suf ficient quantity. 7. LDO pump is ready for operation. 8. Ensure cooling water supply to the various equipments. 9. Coal bunker is fi lled up with specified coal. 10. Lime stone bunker is fi lled with limestone. 11. Availability of initial filling and makeup bed material. 12. Availability of chemical for feed and boiler water treatment. 13. Availability of lubricants for normal operation. 14. Ash handling system is ready for normal operation.

1. Start the feed water pump as per the start up procedure. On confirming the pump start-up, open the filling line isolation valve gradually. Valve to be opened in such a way that the load on the pump motor is with in the operating limit. Since there is no backpressure from the boiler side at this stage, pump outlet pressure also to be maintained by manipulating the valve opening. 2. Close the economiser air vent, on confirming the free flow of water from the vent outlet. Continue the filling, till the water level in steam drum reaches to 50mm below the normal operating limit. Stop the pump after filling and close the drain valves at furnace bottom headers, economiser bottom header and water filling line isolation valves & open the furnace drain header isolation valve.

1.1.2 System Line Up PRELIMINARY REQUIREMENTS

1. Power supply: Ensure that the power supply is switched ’ON’ and available for all the feeders in MCC and for all panels. 2. Operating station -is ensured for readiness

While filling the water care should be taken to maintain the metal temperature above 21°C to avoid brittle fracture. Hence, the water temperature must be


accumulation of material at the drop point and restrict the fluidisation of bed material at this location. 13. Bed material shall be filled up-to 275 to 300mm heights above the bubble cap top, which is to be verified physically. 14. Prior to confirm the bed height, it is recommended to fluidise the compartments thoroughly to spread the material uniformly. It may require fluidising the compartments one by one with higher windbox pressure so as to distribute the bed materials evenly across the combustor. 15. On confirming the uniform distribution of bed material, it is a must to study the minimum fluidisation windbox pressure. Record the minimum fluidisation windbox pressure and air flow for the start-up compartment as the same is a guiding parameter during coal firing. 16.

After confirming the minimum fluidisation windbox pressure, start-up compartment (only) bed height to be increased to 450mm above the bubble cap by adding additional bed material.

3. After completion of fluidisation check. Feed dry charcoal uniformly over entire (start up compartment) bed, afterwards feed charcoal mixed with kerosene into the bed and spread it evenly across the complete start up (over dry charcoal). Ignite the charcoal by throwing a burning cotton waste 4. After ensuring fire over the entire bed, start ID, FD fans, increase the air fl ow gradually to bring the charcoal to red hot condition by this top level bed material will start getting heated up. After achieving the above condition mixing of the bed should be carried (such that all the burning charcoal get mixed up with the bed material) by using the damper markings established during fluidisation check. After 2- 3 minutes reduce the air flow to minimum (i.e.; minimum bubbling). All the burning charcoal will disappear for a little while as they get covered with the bed material. Within a short period, the whole surface again will start glowing due to charcoal burning, carefully observe bed temperature raise and correspondingly increase the air flow to raise the temperature more than 600 degrees. If required, add charcoal to the bed for raising the bed temp tur Onc the bed


bed material, which will result in more inbed area immersion, the bed temperature can be brought under control.. 6. The ‘High’ and ‘Low’ set points for the bed temperature should be set at 900 and 650 Deg C. respectively. During start-up, the ‘Low” temperature set point can be set below ambient temperature and after start-up, re-set again at 650 Deg C. 7. During start up it is advisable to go with the specified fuel and after complete stabilisation of the boiler with recommended bed height, combination fuels can be started. Ultimate care to be taken to avoid higher bed temperature than recommended, 2 The following are the predicted normal operating parameters for the start up.

• Bed temperature (Deg C) : 800-850 • Fluidizing air pressure (mmwc) : 550-575 1. Close the drum vent valve when the pressure reaches to 2 kg/cm2(g). Do not close the start up vent and drain valve on the S.H steam out let header.

pressure is too negative all the fine fuel particles will either fire close to S.H. zone or fly as un-burnt. Firing at free board is to be avoided for the protection of S.H. coils from overheating.. 1. Increase the boiler pressure as per the cold start up curve, to have a control on the pressure raise, rate of fi ring is to be varied as per the requirement. 2. At times feeder may have to be stopped, but ensure that feeding is not discontinued for a long time so that the bed temperature will be maintained. 3. Once the boiler reaches close to the operating pressure make preparation for charging the main steam and other distribution lines viz. opening the drain valves. 4. First open the main steam valve by-pass valve to warm up the Main steam line also to equalise the pressure at the in/out let of the Main steam stop Valve (MSSV). 5. When ever the steam line is warm and condensate (if any) is removed, open the main steam stop valve slowly. Fast opening may cause sudden increase in drum level


Cold Pressure Raising Curve


2

Operational Control

2.1 Load Operation

necessary to raise the start-up compartment temperature with the help of start up burner if necessary. 8. Above procedure to be followed for the activation of the remaining compartments. Note

While loading the boiler care to be taken that the feed and boiler water parameters to be brought to the recommended limit before increasing the load beyond 50% of the MCR.

To meet the steam flow demand, following parameters are to be maintained to achieve the desired output; 2.1.1 Number of Compartments in Active Condition

Depends on the load requirement number off compartments to be activated. Compartment activation may be as per the following procedure; COMPARTMENT TRANSFER 1. Compartment transfer means, activating a static (cold) compartment of the Combustor adjacent to the activated compartment. This

After every compartment transfer stabilize the active compartments to the required parameters i.e bed temperature and wind box pressure.

2.1.2 Fuel Feed Lines Cleaning

Moist coal, foreign materials and bigger size fuel may choke fuel feed lines. This may results in bed temperature drop. Following are the guidelines during such situations: 1. Ensure that PA air available with suf ficient pressure at the fuel feed line. 2. To identify the line thoroughness, carefully drain the vertical portion of the feed line. Once cold bed material is drained, hot particles fl ow out along with a jet of air. This indicates that the fuel feed line is clear. 3. If the air is not coming out of the lin this


During low bed level operation some of the inbed tubes surface will be exposed from the active bed, thus reducing the steam generation. NOTE:

1. Bed level should not be less than 350mm during boiler operation. 2. During low bed level operation, the bed temperature may be high and possibility of high bed temperature fluctuation even for small upset in process changes, which is to be taken care suitably. 3. While increasing the boiler load it is suggested to increase the bed level to the required level of around 450-500mm. During low bed level operation if the boiler trips necessaryquick care to be taken to re start the unit as there is a high possibilities of faster bed cooling and furnace blackout situation may happen. 2.2 Bed Level Control

1. During boiler operation, portion of ash generated will be accumulated in the bed and should be drained at regular intervals to maintain required bed level & bed bulk

for high bed ash accumulation. Apart from sizing, ash content in the fuel also re flects the ash accumulation levels in the bed. 6. Along with fuel stones/shales also enters the furnace which accumulates in the furnace bottom, and increase the bed bulk density and warrants increase in wind box pressure to maintain required air flow to the compartment. During higher bed bulk density situations, bed draining to be done frequently to remove the accumulated stones/shells to maintain the bed bulk density to the desired limit maximum of 1250Kg/m3 to avoid de-fluidisation and clinker formation. Also fresh bed material to be added to maintain the required bed height during bed draining. 7. Restrict shales/slates and stones entering with coal before fed to the crusher/bunker. Adequate arrangement to be made for picking up these foreign particles in the conveying system suitably. This is to avoid packing of bed and air-lancing, which shall lead to greater erosion of bed coils. 2.2.1 How low performance?

bed

level

affects


d. In case of high alkali content in the fuel, bed-draining cycle should be strictly adhered to maintain the limits, this is to avoid agglomeration of bed. 2.4 Adequate Bed Temperature Bed temperature is a function of

• Operating load • • • • •

No of active compartments Bed height Bed bulk density Bed material chemical composition Excess air

• Moisture in fuel. 2.4.1 Low Bed Temperature Operation

1. Bed temperature varies depends on the bed level, quality of fuel & boiler load. Fuel and air should be adjusted to get the required bed temperatures depends upon the load. Apart from varying fuel feed rate, air fl ow and bed level, boiler load also can be controlled by slumping and activating compartments.

5. Similarly, if the bed material chemical property is not as per the design recommendations, the bed temperature may fl uctuate during fuel feed upset conditions. If the alumina content in the bed material is lower than the limit, bed may not retain the heat during interruption in fuel feeding, also when ever the unit is trips, the bed temperature drops quickly and cause trouble for hot start-up. 6. Also if excess air is pumped into the bed, it will cool the bed and warrant additional fuel to maintain the bed temperature. Hence there should be a balance between the air to fuel ratio along with the bed height. 7. Whenever the moisture in the fuel increase, bed temperature drops equally as additional heat energy is required to evaporate the moisture in the fuel. Similarly, if the moisture is less than the design value bed temperature increase for the same steam flow conditions. High moisture fuel require increase in PA pressure also, it may also leads to the erosion of bed coils. 2.5 Fuel and Bed Material Sieve Analysis as per the Designed


• Bulk Density • Shape • Fusion Temperature Ensure bed material bulk density is always between 1000 - 1100 kg/m3. . Whenever the boiler is to be shutdown, it is recommended to stabilise the boiler operation with coal firing prior to slump the bed

3

Balance of Plant Start Up (Boiler)

ASH HANDLING:

Fly ash handling system shall be started one hour prior to coal firing. ESP

Rapping mechanism should be started one hour prior to start the firing. Hopper and insulation heater should be switched on 4hrs prior to charge the ESP. 4hrs. after attaining the required flue gas temperature at ESP inlet, the ESP shall be

Cross check with the level indication available at control room through the level transmitter . Stop the water supply to the deaerator when normal water level has reached. 5. In the mean time charge the steam up to the pressure control valve to warm up the line and keep the steam readily available for charging into deaerator. Once, water level has attained NWL, then slowly admit the steam into deaerator through the pegging steam line. It will take minutes or one or two hours to heat the water with pegging steam. Whenever the water temperature reaches 60 to 70 0C, deaerator is ready for charging the steam through main supply line. 6. Try to maintain a low water level before admitting the steam through the main supply line. Level may be maintained well above the very low level and below the centreline of the tank. Due to direct scrubbing of steam with warm or cold water there may be little hammering or vibration in the storage tank. By keeping the low Water level the quantity of the water in the storage tank will be less and less steam will be required initially to heat it. Thus vibration or hammering can be reduced


10.

flow

will lead to condensing of steam and will result into reduction in deaerator pressure, even to vacuum pressure.

may require to slump one or more beds depend upon the situation.

As the deaerator pressure increases the water temperature will start increasing. If the water outflow from deaerator is faster, then the temperature rise will be faster.

4.1 Bed Slumping Procedures

11. Once the level and pressure are reached the set values the controllers can be put into auto. Temperature will reach automatically to the operating value. 12. Flash steam if any from the boiler system can now be admitted into deaerator. 13. The vent valve on the vapour tank can be throttled to optimise the venting steam flow. 14. In the event of taking the deaerator into line, if abnormal hammering or vacuum situation is created, stop admitting the steam and repeat the whole charging process once again.

While slumping the bed, following proceduresmay be followed1. Reduce coal feeding gradually and stop the feeder of the compartment to be slumped. 2. Observe the dropping trend of bed temperature, whenever the temperature drops steadily stop the air flow to the compartment by closing the compartment damper. 3. Maintain air fl ow through the PA lines to clear the lines.

3.2 Air Pre Heater

4. Due to slumping of the bed, FD outlet pressure may increase, which is to be controlled to maintain the required air flow and wind box pressure for the active compartments.

1. When the boiler backend flue gas temperature increase above 160ºC, APH to be taken in line. Opening of APH inlet &

5. Adjust / increase the fuel flow to the active compartments to meet the steam demand. Maintain the bed temperature and should not increase more than 950ºC, or less than


1. While converting the slumped bed in to active bed the following procedures may be followed: 2. Open gradually the slumped bed wind box damper for few minutes to fluidise the beds, by observing the furnace pressure. 3. Observe the bed temperature, and while mixing the bed temperature will rise in the slumped bed and the bed temp will drop in the adjacent active bed, fuel fl ow needs to be increased to the active bed, to maintain the bed temperatures within safe limits, above 750 deg.c. 4. Meanwhile allow air to the coal feed P.A. lines and clear the vertical line of the coal feed line and keep ready the fuel feed system to inject coal to the compartment. 5. Open / close the wind box damper of slumped bed and increase the bed temperature more than 600 deg. C. and allow steady air flow to the bed. 6. At this point fuel flow to the new bed to be initiated, which will increase the bed temperature in the new bed.

4. Start the ID Fan, FD Fan and PA Fan as per fan start-up procedure. 5. Load the ID fan to maintain furnace pressure, load the FD and PA fans with pressure of 600 and 1300 mmWC at the fan outlet respectively. 6. Open the PA compartment dampers and clear the PA lines of the start-up compartment. 7. Once PA lines are cleared in the start up compartment, start the fuel feeder without delay otherwise bed may cool down rapidly. 8. Open the windbox damper such that the bed is just bubbling, ensure that fluidisation is uniform and satisfactory. 9. Gradually increase the fuel and air flow, observing the rise in bed temperature. 10. Adjust the air flow and fuel fl ow to stabilise the start up bed temperature. 11. Proceed with compartment transfer procedures mentioned earlier according to steam demand. 12. Take feed water control and furnace draft on auto mode.


of 600 and 1300 mmWC at the fan outlet respectively.

11. Verify the IBD valve is closed. 12. Allow the boiler to cool naturally

6. If the bed level is too high drain the bed and bring down the bed height to the required level.

13. Whenever the steam drum pressure drops to 2-kg/cm2 (g), open the steam drum vent and the start-up vent.

7. Start the start up oil burner as per burner light up procedures.

14. If the unit is to be shut for a short period,

8. Repeat the cold start-up procedures mentioned earlier and stabilise the boiler with coal firing.

6

Boiler Shutdown

Boiler shut down can be of two types: 1. Planned Shutdown, where the operator gets advance notice and adequate time to shut down the boiler in an orderly manner. 2. Boiler Trip on interlock protection or emergency shutdown by the Operator. If the shut down is only for few hours, it is not recommended to cool the bed material. If the shut down is for few days, it is recommended to cool the bed material.

no personnel should be admitted to the boiler . If the operating personnel need

to enter the unit, the boiler, economiser, air heater hoppers, and the ash collection equipment hoppers (ESP) must be emptied of any solids and the enclosure temperature cooled below 50 15. All solids must be removed completely from the boiler and the boiler temperature must be below 50 deg C before personal are allowed to enter for maintenance or inspection. • a) Use air flow to fl uidise the bed. • b) Start the bed draining system 16. After the bed material fl ow from the bed drain has stopped, a layer of dead bed material will remain in the bed.


1.

Close main steam stop valve immediately

2. Continue to feed the water flow, if the water level requires to be maintained 3. Check that fuel feeders are stopped. 6.2.2 Boiler Shutdown during sudden Tube Failure

1. In case of a sudden tube rupture followed by a severe loss of drum water level, it is advised immediately to stop the burners / fuel feeders, and also isolate the steam & feedwater system. This is to avoid undue thermal stresses on pressure parts. The

drum vent & start up vent have to be opened whenever the pressure falls to 2kg/cm2 (g). Extent of the damage is to be ascertained after cooling the boiler completely. 2. In case of a tube failure and if the water level could be maintained though the fire is not lost, it is recommended to stop the boiler immediately to avoid major damage to the pressure parts. 3. The impingement of steam & water from a leaking tube on adjacent tubes can cause additional failure of tubes. In such cases, the normal planned shutdown procedure is immediately implemented.


7

Do’s and Dont’s

DO’S

1. Maintain all instruments and interlocksin good working condition. 2. Maintain the instrument air free from moisture and oily matters and the pressure as recommended. 3. .All dampers must be in smooth operating condition. 4. Maintain fuel as per the recommendation 1. .

15. Boiler surroundings and equipment must be properly illuminated. 16. Cleared the bed material immediately to make room for emergency. 17. Use genuine spares. DONT’S

1. Don’t by pass any instruments and safety interlocks. 2. Don’t run the Boiler with furnace in pressurized condition.

5. Use the bed material as per the specification.

3. Don’t throttle the feed water pump balancing leak off valve while the pump is in operation.

6. Maintain bed chemistry as per the design limits.

4. Don’t operate the furnace wall header drain valves while the Boiler is in operation.

7. Maintain feed and boiler water as per the design limits.

5. Don’t leave the furnace door open while the boiler is in operation.

8. Use proper lubricants as per the manufacturer recommendation.

6. Do not open the furnace manhole without the permission from control room.

9. Clean all Ash hoppers, feed water and transfer pump suction strainers, Oil gun regularly.

7. Do not reuse the drained bed material.

10. Operate the boiler within the recommended

9. Don’t leave the Instrument Control Panel

8. Do not operate the boiler with clinker.


8

Controls

FURNACE PRESSURE CONTROL:

1. Operate Furnace pressure in auto mode with (–2 to -5) mmWC as set point. Can be switched over to auto mode after the stabilisation of coal firing in start-up compartment. During bed activation and slumping control may be taken into manual mode as the air and gas flow may vary drastically during these operation.

till the boiler is connected to steady load. Whenever the steam flow is increased more than 30% MCR control can be switched over to three-element control mode. O2 CONTROL:

DRUM LEVEL

1. Whenever the boiler load increase above 60% and the operation is stable, O2 control can be taken into service. However close observation may be required as any upset condition like heavy bed, moist fuel and fluctuating steam demand, it will be dif ficult to maintain the O2 as per the predicted values.

1. During start-up level can be maintained in auto mode with single element control,

Please refer Volume-3 , Section-6 for detailed Control Schematic drawings and write-up.


9

Troubleshooting Chart

This section to be used for solving problems arising during operation. 1. Indication: Unable to maintain boiler water concentration Check the probable source — Tube Leak or Hideout Probable Cause: Check Slight leakage from pitting or cracking of tube or tube seat leak. The repair method and preventive measures involves the following — Remove boiler 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.

Repair method and preventive measure — Remove boiler from the line immediately. Inspect or determine whether tube splicing or wholesale tube replacement is necessary. 4. Indication: High conductivity. Check the probable source — Solids carry over in the steam or high CO2 or NH3 in boiler water. Probable Cause: High boiler water concentrations, excessive water level fluctuation drum baf fle leakage or deposits on scrubbers. Repair method and preventive measure — Check for baf fle 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. 5. Indication: High gas temperature.


Check the probable source — Overheating Probable Cause: Internal deposit or low water. Usually internal deposits result in tubes bowing away from the furnace & low water /starve results bowing toward the furnace. Repair method and preventive measure — 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. 8. Indication: Tube blisters Check the probable source — Localised overheating Probable Cause: Internal deposit.

10. Indication: Internal loss of metal not sharply defined and accompanied by black iron oxide (Fe 3 O4 ). Check the probable source — Corrosion Probable Cause: Overheating resulting in breakdown of water into H & O2 Cause is usually from sludge letdown or pluggage. Repair method and preventive measure — Individual inspection will determine extent or replacement, internal cleaning and correction of water conditions are required. 11. Indication: External pitting. Check the probable source — Corrosion Probable Cause: From corrosive ash deposit and moisture either from dew point or external source such as


Repair method and preventive measure — 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 dif ficulty by inspection or hot to cold expansion measurements. Using tube spacers can stop vibration. 13. Indication: External metal loss. polished area

Highly

Check the probable source — Erosion Probable Cause: Mechanical abrasion from soot blower action. Repair method and preventive measure — 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

14. Indication: External metal loss. Oxidised fire scale area. Check the probable source — Overheating Probable Cause: Prolonged or repeated overheating. Repair method and preventive measure — Extent of metal loss will determine extent of tube or tube section replacement. Inspection or a thermocouple installation will determine cause of overheating. Using tube spacers can stop vibration.


10 Walkdown Checklist during Operation 1. Check for unusual noises from steam / water leakages. 2. Check for unusual traces of water on floor, buck stay or leakage from casing joints. 3. Check for oil Spills around burner 4. Look for valve and gland leakage. 5. Discoloration, hot spots and bulging etc. on casing, ducts and hoppers 6. Check for steam and water leaks from connections and fittings to the drum. 7. Watch the furnace for any clinker formation. If possible inspect the slogging condition of furnace walls and super heater coils (if provided) through the observation ports. 8. Walk around the furnace exterior and observe for any hot spots or gas leaks. 9. Listen for any unusual noise around economiser which may indicate economiser leak (i.e. hissing noise)

10. Inspect penthouse for gas leakages. 11. Inspect windbox corners welded joints for any air leakage. 12. Inspect all ash hoppers to make sure they are being emptied properly. 13. Check around all air/ flue ducts for signs of leakage. 14. Check position of fan and field dampers. 15. Check for any gas leakages from refractory sealing. 16. Check for leakages from safety valves at normal operating pressure. Also note the safety valve blow off and shut off pressure. Check that the drain lines and drip pans are not plugged. 17. Make note of any leaky valves and prepare maintenance schedule to repair them. 18. Check to see that proper water level is being shown by the direct water level gauge. Check for water or steam leaks from ports or drain connections, which will cause a false water level in the gauge glass. Inspect the glass for discoloration or fouling.


11 Boiler Safety 11.1 Emergency Procedures Low Water Level Causes

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 f u el. 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. In the absence of such a decision

1. 2. 3. 4.

Feedwater control malfunction Operator error Instrument air supply failure Foaming

Action

1. Take the drum level control loop into manual mode 2. Reduce the water level immediately by operating the intermittent blow down to maintain the drum level 3. Reduce the steam discharge rate, if necessary 4. Start the stand by compressor if required Furnace Puf fing & Back Firing Causes

1. 2. 3. 4.

Uncontrolled feeding of fuel into the furnace Sudden increase in FD fan air Tube rupture Foaming

Action


3. Evacuate or clean the furnace to the possible extend Conditions for Boiler Restart after Furnace Explosion

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. 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 furnace refractory for damages 3. Inspect the air and flue ducts for any signs of damage 4. Inspect the expansion bellows in the air and flue ducts for damages 5. Inspect the economizer casing for damages 6. Assess the damage if any and rectify the same. 7. 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 the same as explained in the maintenance section.


12 Operational Precautions for Safety Introduction

The handling and burning of any fuel is potentially hazardous. Some fuels ignite more readily than others. Safe handling and operation demands knowledge of the characteristics of the fuel and careful observance of necessary precautions. 1. Operating the boiler with low feed water temperature along with high excess air will result in exceeding metal temperature. There should be no hesitation to bring down the load on the boiler if this temperature cannot be brought under control by other means. 2. In the case of tube failure which can be identified by hearing the noise in the boiler gallery and cross checked by difference in steam and water flow, gas and steam temperature, the boiler should be shut-down at the earliest by regular procedure for maintenance work. Otherwise large number of tubes may fail due to steam erosion and impingement. 3. Entry of wet steam into superheater and

prevented by keeping a watch on economiser outlet water temperature. 9. Carryover of salts in steam occur either due to mechanical or vapour carry over from steam drum. Ef ficient drum internals can only reduce mechanical carry over. Silica is always carried over in vaporous form. Continuous monitoring of sodium and silica in steam is desirable. 10. Before operating a boiler, ensure complete knowledge of water chemistry. 11. Whenever boiler is started after a shutdown of more than 3 days, check all safety interlocks before boiler start up for proper functioning. 12. Superheater drain valve should be operated as per recommendations. 13. The steam drum should normally be filled upto 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. 14. Firing should be maintained having regard to the instructions for protection of superheater, which will limit the maximum gas temperature in the superheater zone.


22. Have a lighted torch or spark producing device in operation before introducing any fuel into furnace. 23. 24.

Maintain a positive air flow through the burners into the furnace and up the stack. Maintain adequate oil pressure and temperature for atomisation & also adequate steam or air pressure in case of steam or air atomisers.

25. Ensure operation staff alerts to all abnormal conditions. To observe the above rules, automatic control instruction may include :a. Purge interlocks e.g. requiring a specified minimum air flow for a speci fic time period suf ficient to purge the setting before the fuel trip valve can be opened. b. Flame Detector: Each burner should have its own flame detector connected to an alarm and interlocked to shut-off the fuel to the burner, it serves upon flame failure. c. Closed position switches for burner shut-off valves, requiring that all shut-off valves be closed to permit opening the

over in vaporous form. Continuous monitoring of sodium and silica in steam is desirable. 29. Before operating a boiler, ensure complete knowledge of water chemistry. 30. The threaded portion of the burner tip should be covered with a non-hardening high temperature lubricating compound. This facilitates easier subsequent removal. (Please refer burner manual) 31. Lapped burner tips must be kept in a plastic container to prevent damage for atomising steam with internally mixing type steam atomisers. 32. Whenever boiler is started after a shutdown of more than 3 days, check all safety interlocks before boiler start up for proper functioning. Proper Handling of Access Door

1. Never open an access door while the unit is operating. 2. Any access door can have large amount of material built up behind it even after the bed has been drained. This material will fall out when the door is opened. Bed material can stay hot for many days even after boiler


Handling of Secondary Air Ports

2. Always use a full-face mask with tinted glass.

1. The hand-operated dampers in the secondary air nozzles will be very hot.

3. Do not stand directly in front of open ports or doors especially when they are opened.

2. While handling the dampers / ports protective gloves should be worn and enough attention to be given.

4. Use sealing air when opening the doors / observation ports.

Handling of Solid Piles

1. Always be cautious of piles of bed material. 2. The surface of piled material may be cool in the surface while just below the surface still may be very hot. 3. Bed material in a pile can stay hot for several days. Handling of Furnace Observation Doors

Ports

and

1. Ports and observation doors are open to the positive pressure in the furnace. 2. Never stand directly in front of the ports. 3. Do not leave the poking rod in the furnace for long. It will heat up quickly making the rod hot to handle and hazardous when it is removed from port.

5. Use ear protection devices, whenever it is necessary. 6. Wear protective gloves when working around the boiler. 7. Do not use open-ended pipes for rotting observation doors or ports. 8. Never enter drums, ducts etc. until all the steam and water valves including the drain and blow down values have been closed to check and tagged. 9. Do not enter a confined space until it has been cooled below 30 °C and property ventilated. 10. Completely drain the solids from the bed, hoppers etc. while entering. 11. Always use low voltage extension cords and light bulbs with properly connected ground. 12. Never open or enter the rotating equipment until it has come to a complete stop and circuit


4. Disconnect and isolate the nitrogen purge if it was used during the outage.

5. Open the steam drum vents and the vents.


Section-D Topics Covered in this Chapter

Section Overview ♦ Recommended Maintenance Practice ♦ Conditioned Based Maintenance ♦ Boiler Annual Maintenance and Overhaul ♦ Boiler Preservation Procedure ♦ Tube Failures ♦ Water Chemistry ♦ Welding Procedure Speci fications (WPS) ♦

1

Section Overview

• 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.

This section describes the various maintenance practices, overhauling and preservation techniques. Also discussed are failures and repair techniques.

It is suggested to maintain a defect register in the control room to register all the items, which need maintenance.

This section covers the following

2.1 Preventive Maintenance

• RECOMMENDED MAINTENANCE PRACTICES • PREVENTIVE MAINTENANCE PROGRAM

The objective of the preventive maintenance program is to obtain trouble free service from the component till the next maintenance.

• CONDITION BASED MAINTENANCE

Vendor manuals for various equipments suggest


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.

In condition based maintenance, the equipment and components of the plant are inspected daily, weekly, monthly etc. as per suggested schedule by the local operators and the deteriorating conditions if any observed are reported. Suggested inspection program is given in this chapter. Based on operator reports of such inspection, maintenance works are planned for the next available planned shutdown. Mandatory inspections prescribed by the vendors are also taken care of, irrespective of the equipment condition.

2.1.1Preventive Maintenance Program for Valve

3

A preventive maintenance program for valves once in two years can be done with one or more of the following works: • Dismantle the bonnet, clean the trim and valve seat, lapping them if necessary. • Cleaning the valve stem and re-lubrication of the operating threads • Renewing the bonnet joint, and assembling the trim on the valve seat

Conditioned Based Maintenance

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: 1. The components are in trouble free condition.


EQUIPMENT

CHECK

Local level gauges on steam • Check illumination is proper. drum • Leaking valve glands. • leaking ports • Blurred level

WORK TO BE DONE

• Replace fused bulbs. • Isolate level gauge and tighten leaking glands. • Replace leaking ports. • Steam wash mica as suggested by vendor (not to be done too frequently)

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.

Traces of water, oil spots on Such spots are indicative of valve Maintenance to be planned boiler fl oor, buck stay beams, leaks, instrument tapping leaks to eliminate the source either immediately or during next boiler cladding etc. etc., Trace the source of leak. planned shut down (depending on the source and quantity of leak) and accessibility for maintenance. Lubricating oil levels of Fans, Check adequacy of oil level. & feed pumps bearings, dosing pump gear box etc.

Top up if required (immediately) If leakage through oil seals, gaskets drain plugs etc. are ti d pl fo inte


EQUIPMENT

Purity of instrument air

CHECK

WORK TO BE DONE

Check by visual observation Oil and moisture in the instrument that the instrument air is oil and air is likely to clog the positioners moisture free. of pneumatic controllers / solenoids and make their (Oil and moisture content can operation sluggish or unreliable. also be checked by laboratory examination as per standards) Open drain valves of air receivers for short time to drain condensate if any. If these measures not successful, inform Maintenance group.

Fan suction damper linkages Check for their proper operation and their power cylinders

Steam or water leakages

• Loose valve gland

are the

Sluggish operation of fan suction damper may be due to stuck linkage, stuck damper, faulty power cylinder and faulty positioner. Sluggish operation of air register dampers may be due to stuck air register vanes, faulty power cylinders and faulty positioner. Check for possible cause. Maintenance works have to be planned. •

Tighten the gland nuts.


12. Check for hot spots, bulging etc. on casings, ducts etc.

17. Check all alarm annunciation with respect to set points.

13. Check the positions of dampers and cleanliness

18. Check for water, oil along with instrument air

14. Check for safety valve steam leakages.

19. Check the field instruments for its proper indications.

15. Check the bearings for lubrication and cooling water systems.

20. Check the stack for any unusual smoke conditions.

16. Check the fan damper linkages for lubrication and cleanliness.

3.3 Weekly Checks

Igniters

3.4 Monthly Checks

At Least once a week each • Remove the spark device, ignitor must be tested for clean and check spark gap. its performance by manual • Check insulation resistance command from BMS local panel. of the spark device. If an ignitor fails to light up on command the Ignitor requires be • Check healthiness of the servicing and keeping in working HT transformer. condition. • Check BMS sequence for energizing HT transformer and opening of ’block valve’


Dosing system

Cleanliness of dosing tank, Clean dosing tank with normal operation of pressure relief valve, water, Adjust relief valve ,if lubrication oil level in pump. required Fill lubrication oil , if required

D P Manometer

Choking of impulse tubes Liquid Clean impulse tube with air Keep level in manometer liquid level at zero

Level switch for steam drum Close the steam out let valve and If switch or alarm is not working, water level very low gas by pass damper. Open blow do the rectification work. down valve and check for level switch very low alarm. 3.5 Checks Every Six Months

During a planned shut down of the boiler, the following checks can be done. EQUIPMENT

CHECK

Boiler safety interlocks, Coinciding with a planned start permissive, boiler trip shut down of boiler, carry protection. out the checks to identify malfunctioning or sluggish pressure, temperature switches, solenoid operated valves, positioners, proximity switches, actuators etc.,

WORK TO BE DONE

Plan for maintenance or re-calibration of defective items if any noticed, during the shut down period.


3.7 Annual Maintenance Check Sheet COMPONENT NAME

Drums (water side )

INSPECTION REQD FOR

• Corrosion • Scale / deposits • Pitting • Metal reduction • Manhole seat • Process / instrument tappings • Internal cleanliness

Steam purifier Assly in steam Drum

• Corrosion • Deposits • Erosion • Tightness • Pittings • Sealings • Baf fles

Feed water pipe in steam drum.

• Plugging • Tightness


COMPONENT NAME

INSPECTION REQD FOR

Furnace tubes

• Corrosion

(gas side)

• Build up • Blisters • Sagging • Over heating • Fly ash erosion • Sealing • Supports • Cracks • Expansion clearance • Steam impingement • Refractory status • Insulation • Erosion

Inbed evaporator coils

• Erosion

– fire side

• Corrosion • Build up


COMPONENT NAME

INSPECTION REQD FOR

Super heaters if provided.

• Corrosion

(gas side)

• Build up • Sagging • Over heating • Fly ash erosion • Sealing • Supports • Cracks • Exp clearance • Steam impingement • Refractory status • Insulation

Economiser

• Corrosion

(water side)

• Scale • Pitting

Economiser

• Corrosion

(gas side)

• Build up


COMPONENT NAME

INSPECTION REQD FOR

• Corrosion • Erosion • Leakages • Clearance between • Rotor and casing • Damper operating • Mechanisms • Bearings conditions • Bearings clearances • Lubrication argt. • Cooling water argt. • Fly ash deposits • Shaft seals conditions • Coupling alignment Air preheater

• Cooling discs. • Gas side plugging/Sealings • Gas side cleanliness


COMPONENT NAME

Convection pass

INSPECTION REQD FOR

• Erosion and material accumulation. • Signs of gas channeling. • Water walls for erosion patterns. • Economiser support beams for erosion. • Lower water wall headers for erosion / cracks. • Seal at economiser and superheater piping penetration. • All penetration for erosion. • Superheater supports Furnace rear wall • Riser roof • For penetrations • Sealing and cracks. • Walls for erosion at the top of the tube / refractory interface. • Roof refractory for erosion or damage. • Erosion coupons and pins for the Refractory thinning. • Refractory on furnace rear wall outlet header


COMPONENT NAME

INSPECTION REQD FOR

• Internal deposits • Insulation • High/low water alarms/tripping Valves

• Erosion • Corrosion • Leakages • Spindle movement • Handle rigidity • Drive mechanisms • Lubrications

Safety valves

• Valve nozzle conditions • Disc seat conditions • Corrosion of internals • Pitting • Cracks • Valve spring status • Spring stiffness


COMPONENT NAME

Fuel feed nozzles in the combustor

INSPECTION REQD FOR

• Erosion • Divertor ring condition • Alignment • Sealing

Feed water pumps

As per manuals

Dosing pumps

As per manuals

Power cylinders

As per manuals

Deaerator

• Feed pipe/dosing pipe status • Spray nozzles status • Sediments • Corrosion

Combustor

• Missing nozzles • Erosion • Plugging


4

Boiler 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 Thermax Ltd. 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). 4.1 Planning Before Overhaul

1. Prepare a list of jobs to be done during the overhaul based on earlier inspection reports

2. Allow the drum to ventilate for about 8 hours. If necessary a fan cooler can be fitted over temporary stand to force air through the drum. 3. 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 speci fically authorized personnel. 4. 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. 5. Carry out a preliminary inspection of the drum to check for deposits on the water side of the drum. 6. 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.


their supports are normal, their holes have been correctly oriented. 5. Examine that there are no cracks in the stub welding s of the drum. After the inspection, clean the manhole seats and provide new gaskets. Sometimes the boiler inspector may like to inspect the steam drum. After this inspection and after verifying that all men and material have been removed from the drum, close the manholes and bolt them tight.

4.9 Feed & Boiler Water Conditioning 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.

4.5 Inspection of Screen, Primary & Secondary Superheater, Evaporator I/ II & Economiser

The objective of the water treatment is:

Check the above mentioned sections for any

• Control corrosion of boiler system, which cause failure of boiler tubes, leading to unscheduled shutdowns.

1. Suspicion of abnormalities. If yes, consult M/s THERMAX LTD or a metallurgist for necessary advice 2. Evidence of pitting / erosion / corrosion on tube outer surfaces (exposed to the flue gas path) 3. Evidence of overheating (bulging of tubes, blue color of tubes, blisters, disturbed vertical

• Eliminate scaling - deposition in boiler which cause tube over heating leading to accidents.

• Reduce carry over of water with steam, which is the cause of deposition on super heater/turbine blades, leading to the expensive failures. • To maintain peak boiler ef ficiency by keeping complete boiler water system clean. In order to meet above objectives, it is necessary


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. • Filtration - To remove residual turbidity • Softening - To remove hardness salts Dealkalise

T

hardness salts and

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


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;

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.


3. Top cover of the housing is opened and a visual examination of the bearing is done.

17. The motor coupling is aligned to the fan coupling.

4. The access door of the impeller housing is opened and the impeller blades are cleaned and examined for wear.

18. Trial run of the fan is taken.

5. Defective or worn parts noticed are repaired or replaced.

19. Bearing vibrations, temperatures, noise levels are measured and compared to previous values.

Oil seals ’O’ rings if any, are replaced.

20. Adjustment if any required (alignment, bearing clearances etc.) are done.

7. The tightness of the bolts and nuts, which fix the fan casing to the foundation, are checked with a torque wrench.

21. The maintenance exercise is successful, if the observed values are better than the values before the shutdown.

8. The fan bearing housing cover is assembled and recommended lubricant is filled to the correct level.

22. Another variant of the maintenance can be disassembling the fan to its components level, taking out the bearing, impeller etc.

9. The expansion joints at the discharge end are checked to see that they are not compressed or expanded

23. Checking the trueness of the shaft, checking bearings etc. before re-assembly.

10. Damages if any to the bellows are corrected by patch up. Discharge duct supports are checked and adjusted to their design value.

24. In the drive motor also, the rotor is taken out and the rotor and stator coils are examined for tightness.

11. The suction damper bearings / bushings are checked for wear and repaired or replaced as necessary. The travel of the damper is checked and corrected where required.

25. The coils are cleaned by air blowing and re varnished.

6.

4.11 Safety Valves, Start Up Vent


5

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 ef ficient 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. 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.

final

concentration of 10 ppm (or a pH of 10.0). In this procedure, condensate is considered to be treated demineralised water. 5.2 Dry Storage Preservation

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


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.

a pH of 10 (for demineralised water, this will require approximately 10 ppm ammonia). 2. 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 suf ficient heat is delivered to the furnace (i.e. firing the boiler) to induce natural circulation throughout the boiler. 3. Fill the unit with the treated demineralised water to the normal centerline of the steam drum. Stop filling further. 4. 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.


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.

5.5 Hot Draining

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 shut down AFBC is allowed to depressurize upto 2kg/cm2 (g) pressure on the drum. Water level is maintained upto prescribed levels till that time.

The treated demineralised water should be analyzed weekly, and when necessary, suf ficient 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.

When the steam drum pressure drops to 1.5 kg/cm2 (g), the air vents of the steam drum, Super heaters, economizer are opened and the AFBC is drained through the economizer, evaporator (or only the sections required) by opening the required drain valves.

No unit should be stored wet when there is any possibility of a temperature drop to the freezing point unless suf ficient heat can be provided to the unit to eliminate the danger of water freezing and subsequent damage to pressure parts. 5.4 Nitrogen Blanket

If the AFBC shut down is for a short period of less than seven days and during that period maintenance work on pressure parts have to be undertaken, the AFBC can be preserved by hot draining

When all the water is drained, the residual heat of the water wall, economizer, Super Heater and steam drum, flash dries most of the moisture present on the tube surfaces. As the pressure parts remain dry, corrosion is prevented. This method of preservation however is not effective for move than a week.


5.7 Preservation Of External Surfaces Of Pressure Parts During Long Shut Down

Keeping inspection doors tightly closed (when no inspection is being planned) may minimise such corrosion.

During AFBC shut downs exceeding a few days, the external surfaces of the pressure parts of especially in a chemical plant environment, may come under corrosive attacks by moisture, SO2, SO3 vapors etc.

Water lancing with hot water or mild alkaline water once a month may wash out the corrosive components from the external surfaces of the pressure parts. (See maintenance volume)

TYPE OF SHUTDOWN SHORT OUTAGES

4 DAYS OR LESS. UNIT NOT DRAINED

SHORT OUTAGES

4 DAYS OR LESS. UNIT IS DRAINED

LONG OUTAGES

LONGER THAN 4 DAYS UPTO 15 DAYS. UNIT IS DRAINED

5.8 Boiler Lay Up Procedures PROCEDURE

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 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 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


5.11 Tube Thickness Survey

The following checks relate only to external erosion / corrosion of the tubes and that too qualitatively. 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 locations on inbed evaporators, Furnace water wall, superheaters and economizer tubes must be specified and indicated on a drawing. Vulnerable locations are usually chosen. On request, the Field Engineering Department of TL can establish such a program. Each document should have the following minimum vital information. 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.

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, confirming to IBR code.

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.

• It is recommended that every effort be made to find the cause of tube failures before operation is resumed. • 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. • Free from excess weld penetration to avoid


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: 1. Collection of background & selection of samples 2. Preliminary examination of the failed part(visual examination & record keeping) 3. Nondestructive testing 4. Mechanical testing (including hardness & toughness testing) 5. Selection, identification, preservation, and/or cleaning of all specimens. 6. Macroscopic examination and analysis(fracture surfaces, secondary cracks, & other surface phenomena) 7. Microscopic examination and analysis 8. Selection & preparation of metallographic

2. 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. 3. 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. 4. 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


of boiler log sheets should be sent to H.O for metallurgical investigations.


6.2 Tube Thickness Survey Data Collection – Format (FURNACE / BOILER BANK / ECONOMISER TUBES) CUSTOMER : BOILER NUMBER : UNIT NO : DATE OF INSPECTION : COIL NO

CLOCK POSITION

DATA COLLECTION BY

NAME & SIGNATURE

TUBE THICKNESS

STUD LENGTH

VISUAL OBSERVATIONS


6.3 Failure Reporting Formats THERMAX LIMITED ENERGY BUILDING, D1 BLOCK, MIDC, R.D AGA ROAD, CHINCHWAD, PUNE – 411 019 - INDIA TELEPHONE

020 – 66126464

FAX :

020 – 27479048

WEB SITE : EMAIL :

http://www.thermaxindia.com [email protected] [email protected]

DEAR CUSTOMER, WE WANT TO HEAR FROM YOU,

WE STRIVE TO CONTINUOUSLY IMPROVE THE QUALITY AND PERFORMANCE OF OUR PRODUCTS. WE WOULD LIKE TO HEAR FROM YOU, SHOULD YOU EXPERIENCE PROBLEMS WITH OUR EQUIPMENT OR SHOULD YOU WANT TO SUGESST IMPROVEMENTS, JUST FILL IN THE INFORMATION NEEDED AT THE ENCLOSED FORMAT AND FAX / POST IT TO OUR CUSTOMER SERVICE DEPARTMENT TO THE ABOVE MENTIONED ADDRESS. KINDLY USE ADDITIONAL SHEETS IF REQUIRED.


CUSTOMER FEEDBACK FORM 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 EQUIPMENT DETAILS

CUSTOMER DETAILS:


7

Water Chemistry

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

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,


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 Dis Dissolv solved ed Gas Gases es 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, zinc, brass brass and other metals. metals. It causes causes corrosion and pitting of water lines, boilers and heat exchangers. exchangers. Its effect is further accelerated accelerated at high temperature. temperature. B) CARBON DIOXIDE:

The river water contains 50 ppm & well water cont contai ains ns 2-50 2-50 ppm ppm of CO2. CO2. It also also help helpss to accelerate the corrosive action of oxygen. The other gases are H2S, CH4, N2 and many othe others rs but but thei theirr perc percen enta tage ge are are negl neglig igib ible le Therefore their effects are not discussed here. 7.4 Oth

Materia Mat erials ls

number denoting the degree of acidity or alkalinity of a substance. It does not indicate indicate the quantity of acid or alkali in a solution as found by filtration method. It is derived by measuring measuring the amount of hydrogen ion (H+) in grams per liter of solution. The greater the amount of hydrogen 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 extremely impo import rtan ant. t. The The corr corros osio ion n rate rate of iron iron in the the absence of oxygen is proportional to pH up to a value of 9.6. At this point, hydrogen gas formation and dissolv dissolving ing of iron practical practically ly stops. stops. This is the came pH produced by a saturated solution of ferrous hydroxide Fe (OH) 2. The The Oxy Oxyge gen n in the the wate waterr unit unites es with with ferro ferrous us hydroxide hydroxide to form ferric hydroxide. This reaction reaction lowers pH of the solution and levels to stimulate corrosion.


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 calci calcium um and magnes magnesiu ium. m. Somet Sometim imes es,, 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 suf ficiently soluble in water and are not much troublesome. troublesome. Sodium Sodium salts are highly highly soluble soluble in water and are non-scale non-scale forming. The scale formation takes place mainly in feed water piping piping and Boiler Boiler Tubes. Tubes. Its first effect on the piping system is to choke the fl ow of water by reducing the flow area and increases increases the pressure pressure required required to maintain the water delivery. 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. combustion. The scale formation formation retards the flow of heat and metal temperature increases. increases. Even a thin layer of scale in high heat zone can over-heat the metal enough to rupture the tubes. The metal tubes tubes weake weakene ned d due to overover-he heat atin ing g yiel yield d to pressure providing a protrusion known as bag. Such bag provides a pocket for the accumulation accumulation

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 pumpin pumping g of water water that freque frequentl ntlyy accompan accompanies ies rapid rapid heating heating in a open open vessel. vessel. In priming priming the wate waterr leve levell in the the boil boiler er unde underg rgoes oes rapid rapid and and great changes and there are violent discharges of bursting bubbles. bubbles. Therefore Therefore ‘sludge’ ‘sludge’ of boiler water is thrown over with the steam. The priming is caused due to improper boiler design, improper method of firing, overloading, 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 The foam foamin ing g is the the form format atio ion n of smal smalll and and stable bubbles bubbles throughout throughout the boiler water. water. The high high percent percentage age of dissolv dissolved ed solids solids,, excess excessive ive


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 leak leakage age.. This This may may be caus caused ed by faul faulty ty desi design gn and expansion etc. The prevention prevention of caustic caustic embrittlement embrittlement consists of reduci reducing ng the causti causticit cityy or adding adding inhibi inhibitin ting g agent agentss to the feed water water.. The most most prac practitica call method of preventing caustic embrittlement is to regulate the chemical composition of the boiler water. water. The obvious obvious solution to embrittlem embrittlement ent is to eliminate all free NaOH from feed water by addition of Phosphates. 7.7 Fee Feed d & Boiler Boiler Water Water Condi Conditio tioning ning 1. INTRODUCTIO INTRODUCTION N

The successful use of boiler is dependent on proper proper water water conditio conditionin ning g and treatment treatment.. The quality of water must have accurate for trouble free operation of boiler. The water as available to industry is not suitable for for boil boiler er use. A comp comple lete te pre-tr pre-treat eatme ment nt and and

boiler entirely depends on the rate of corrosion of boiler boiler metal. metal. In order order to protect protect boile boilerr from from corro corrosi sion on,, prepre-tr treat eatme ment nt is done done to remov remove e excessive corrosion ions like chloride, sulphate etc. Howeve Howeverr, further further chemica chemicall condit condition ioning ing is required to protect boiler and auxiliary systems from corrosion. Tri Tri sodium sodium phospha phosphate, te, causti caustic, c, ammoni ammonia a and amines are used as corrosion corrosion inhibitors inhibitors.. These chem chemic ical alss form form a prot protect ectiv ive e film over over meta metall surface surface and reduce reduce corrosi corrosion. on. It is necessar necessaryy to maintai maintain n prescri prescribed bed concent concentrati ration on of these these chemicals in boiler water systems continuously. B. OXYGEN CORROSION INHIBITOR:

Oxygen Oxy gen is presen presentt in dissol dissolved ved form in water water.. At high temperature, oxygen reacts with metal to cause pittin pitting g corrosion corrosion.. Thus prevent prevention ion of oxygen lead to pin holes in economizer, steam drums and steam tubes. Most Most of the the oxyg oxygen en is remov removed ed exte extern rnal ally ly by deaerator and preheating of feed water. However, traces of residual oxygen must be removed by chemical conditioning. Sodi Sodium um sul sulfite, te, hydr hydraz azin ine e and and amin amines es are are


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 the hardn hardnes esss salt saltss from from boil boiler er feed feed wate waterr. Howe Howeve verr, malf malfun unct ctio ioni ning ng of this this equi equipme pment nt,, 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 scale forma formatition on on tube tubes. s. Such Such scale scale has lower conductivity causing increase in metal temp tempera eratu ture re,, leadi leading ng to burs burstiting ng of tube tubess in extreme conditions. Therefore, inspire of elaborate external treatment, inte intern rnal al chem chemic ical al cond condit itio ioni ning ng is alwa always ys recomme recommende nded d as additional additional safety safety.. Follow Following ing chemical methods are used for internal treatment. PHOSPHATE CONDITIONING

Triso risodi dium um phos phosph phat ate e is comm common only ly used used.. Hardness salts react with trisodium phosphate to form calci calcium um phosph phosphat ate e prec precip ipititat ate. e. This This precipitate above pH of 9.5 colloidal in nature

Excessive chelant dosing cause corrosion of boiler Hence balanced chelant program as recommended by experts should be used.

Orga Organi nicc poly polyme merr cond condititio ione ners rs are are used used to prevent hardness hardness scales. scales. Such organic organic polymer disperse scale forming compounds like CaCO3 & Ca(PO4) Ca(PO4)2 2 in colloi colloidal dal form form facili facilitat tating ing their their remo remova vall thro throug ugh h blow blow down. down. Poly Polyme merr and and copolymer copolymer of acrylic, acrylic, methacrylic, methacrylic, styrene maleic acryli acrylics cs are commonly commonly used. used. Most Most of the polymer polymerss are proprietary in nature and therefore dosage is best recommended by manufacturer. D. FOULING CONTROL

Suspen Suspended ded matter matter,, oil/gre oil/grease ase /oxygen /oxygen & iron iron salts commonly cause fouling inside the boiler. Most of the suspended matter and iron salts are removed by external external treatment. treatment. However However due to mfg. of these equipment, equipment, contamination contamination through condens condensate ate and concen concentrat tration ion in boiler boiler cause cause fouling fouling of boiler tubes.


• Load Variatio Variation n - Sudden increase in load load reduce steam purity for short time. • Separa Separatio tion n ef ef ficiency - Higher ef ficiency, better is steam purity. Chemical Chemical Factors:

• TDS - Higher Higher TDS in boiler boiler,, lower is steam steam purity. • Total Alkalinity Alkalinity - Higher Higher alkalinity alkalinity as % of TDS lower is steam purity • Organics Organics - Higher the organic organic contaminat contamination, ion, lower is steam purity. • Foaming - Higher Higher the foaming foaming character character of water, Lower is steam purity. The The wate waterr carr carrie ied d over over with with stea steam m due due to abov above e reas reason onss is exac exactltlyy simi simila larr in qual qualitityy to blow-d blow-down own or boiler boiler water. water. In superheat superheater er or in turbines, water evaporates, leaving dissolved and suspended matter as scales or deposits. Thus severit severityy of scalin scaling g and foulin fouling g of superhe superheater ater and turbine depends on boiler water quality and steam purity. Maintaining boiler water quality as per norms and

F. SILICA DEPOSIT CONTROL:

Silic ilica a is vola volati tile le unde underr high high temp temper erat atur ure e and and pres pressu sure re insi inside de boile boilerr. In turb turbin ines es,, the the evapora evaporated ted silica silica precip precipita itates tes during during pressu pressure re and temperature reduction and form hard scales. Maxi Maximu mum m allo allowa wabl ble e conc concen entr trat atio ion n of sili silica ca depends on water analysis. analysis. Expert’s Expert’s best decide the maximu maximum m permis permissib sible le concent concentrat ration ion after 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. Unde Underr boil boiler er pres pressur sure e and temp temper eratu ature re it is liberated and carried over with steam as CO2 gas. This gas re dissolves dissolves in steam condensate condensate to form carbonic acid. CO2 + H2O = H2CO3 H. MAINTENANCE OF PEAK EFFICIENCY:

Corr Corros osio ion, n, scal scalin ing, g, foul foulin ing g carr carryo yove verr and and condens condensate ate corros corrosion ion can cause cause unsched unschedule uled d shutdown, shutdown, accidents accidents and deterioration deterioration of system ef ficiency ciency.The .Theref refore ore for trouble trouble free operati operation on and and main mainte tena nanc nce e peak peak oper operat atio ion n ef ficiency,


A specification of the materials and shapes adopted by Thermax 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.

of Thermax will be glad to provide a WPS for any site repair weld jobs required for maintenance.

• Edge preparation (angle, shape)

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.

• 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) • 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) • Post weld heat treatment if any required (temperature, rate of increase of temperature, method of increasing temperature, holding time, rate of cooling) • Radio graphic examination of the weld joint,

8.1 Window Patch Welding PURPOSE

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 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


Figure 5

8.2 General Principle of Weld Repairs FURNACE 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 fi rst 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.

an acceptable welding groove. The groove should continue well beyond the ends of the crack. Inert 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 dif ficult 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


will burn off due to lack of cooling and could become displaced and obstruct gas lanes, foul 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

require cleaning beyond the removal of dirt, rust, scale or foreign material. 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


counter bore can be plugged with the cylindrical plug and seal welded per Figures 3 and 4. It 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 fi t 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.

preferable to use a saw or wafer disc. Care must be taken to prevent slag from entering the tube. 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. REMOVING TUBES FROM DRUMS, 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


tube be crimped straight before starting, to cut the grooves for collapsing the tube. Of course, the 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.


8.3 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 gas arc or oxy acetylene process must make the first pass of the weld. Note

1. 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. 2. 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 dif ficult 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.

3. 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 up soot blowers, be dangerous to personnel after shutdown, and etc. If the tube is not removed from the setting, a de finite hole must be punched or drilled in the tube to prevent a possible dangerous buildup of pressure between the tube plugs. 4. A expanded tube leaking at the seat should be removed from its seat and a. a new tube rolled in b. a new short stub rolled in and plugged c. 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: Point. (a) is the preferred fi x with Point.

(c) the least preferred. 5. 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


do not require cleaning beyond the removal of dirt, rust, scale or foreign material.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. 8. 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

a tapered plug. 8.7 See Figure 13, page 101. 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 14 and 15. It may be necessary to machine the tube ends back in order to provide a seat for the cylindrical plug installation. See 8.7 Figure 14, page 101 and 8.7 Figure 15, page 101. 10. 8.7 Figure 16, page 101 shows the details of this cylindrical plug and gives instruction for the specific plug size desired. 11. 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. 8.7 Figure 17, page 101 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. 8.7 Figure 18, page 101 shows the arrangement of the tapered plug seal welded to the tube. 12. The plugs and seal welds described above are designed for the boiler pressure to be on


one will have to be installed. Care must be taken in the plug removal process to not damage or thin the tube stubs wall. 8.5 Replacement of Tube Section

Experienced personnel must do the replacement of a section of failed tube. 1. • 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 hack saw or wafer disc. Care must be taken to prevent slag from entering the tube. The ends are prepared for welding by grinding or with special tools 2. 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.

the tube end to loosen it in its seat, then drive or "jack" the tube out. 2. 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 suf ficiently 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. 3. 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. 4. 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


8.7 Attached

figures

13 to 21










Section E This section holds the Lubrication Schedule and Spare Part List for the AFBC Single Drum — Bed Plate Boiler.

Lubrication Schedule

Lubrication Schedule Spare Part List

Spare Part List for AFBC Boiler


Volume 2 — Drawings Chapters Covered in this Part ♦

List of Drawings


List of Drawings 01 G.A. OF Boiler _D11-0PD-07967_3 02 Foundation Plan & Loading Data_D11-1PD-44268_4 03 Boiler Auxillary Foundation Data_D11-1PD-47979_3 04 Pressure Part Assembly _D11-1PD-43038_1 05 Thermal Expansion Diagram_D11-1PD-49076_0 06 P & I D for Steam & Water _D12-1PD-6499P_2 07 P & I D for Fuel Air & Flue Gas System_D12-1PD-6500P_2 08 Fuel Feed Chute Assly_F28-1PD-48091_0 09 Fuel Feed Chute Details_F28-1PD-48092_0 10 Underbed Fuel Feeding System Layout & Details _F59-1PD-46483_0 11 Steam Drum _P21-1PD-43823_1 12 Steam Drum Internal Assly & Details_P21-1PD-43824_0 13 Internal & External Attachment of Steam Drum _P21-3PD-18383_0 14 Water Drum _P31-1PD-43928_1 15 Internal & External Attachment of Water Drum_P31-2PD-40150_0 16 Primary Super Heater Coil _PA1-1PD-45809_1


Volume 3 — E & I Specifications 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 ♦


Section 01 Electrical System Required for Motor Selection

Section 02 2.1 Electrical Motor Selection For FD Fan 2.2 Electrical Motor Selection For PA Fan 2.3 Electrical Motor Selection For ID Fan

Section 03 Instruments Hook Up Diagram

Section 04 Instruments Loop Diagram

Section 05 5.1 Logic Diagram For Drives 5.2 Control Schematic Write up


Section 10 ACVFD Panel Wiring Diagram


Volume 4 — Vendor Manuals Chapters Covered in this Part



Section 01 Fan — TLT Engineering O & M Manual

ID_FD_PA FAN Drawings

1. GA DRG FOR FD FAN 2. GA DRG FOR ID FAN 3. GA DRG FOR PA FAN

Section 02 H.P / LP. Dosing System - NM Enterprises O & M Manual

HP Dosing System Manual Drawings

1. H.P. Dosing System Drawing


Section 06 Kniff Gate Valve — Orbinox O & M Manual

Kniff Gate Valve

Section 07 Process Valve — KSB O & M Manual

Process Valve

Section 08 Safety Valves — Tyco Sanmar O & M Manual

SAFETY VALVES (HC-HCA Manual)


Volume 5 — Vendor Manuals Chapters Covered in this Part



Section 01 Pressure Transmitter — Emerson O & M Manual

PRESSURE TRANSMITTERS (MODEL 3051)

Section 02 Temperature Transmitter — Emerson O & M Manual

TEMPERATURE TRANSMITTERS (MODEL 644H)

Section 03 I/P Converter— ABB O & M Manual

I/P Converter ABB

Section 04 Pressure Switch — Switzer


Section 08 Control Valves— MIL O & M Manual

MIL 21000 SINGLE PORTED TOP GUIDED CONTROL VALVES - MIL_MANUAL MIL 41000 HEAVY DUTY BALANCED CAGE GUIDED CONTROL VALVES - MIL_MANUAL MIL37 –38 SPRING DIAPHRAGM PNEUMATIC ACTUATOR - MIL_MANUAL MIL 776 Air Lock Valve MANUAL 8013 Electro pneumatic Valve Positioner - MIL_MANUAL 400 L Electric Position Transmitter- MIL_MANUAL Data Sheet and Curves

CONTROL VALVE DATA SHEET

Section 09 Power Cylinder— Keltron Manual

Manual



Index

A Adequate Bed Temperature........................... 41 Air and Gas System ...................................... 24 Air Ducts ...................................................... 25 Air Pre Heater ......................................... 24, 43 AirTemperature............................................. 13 Annual Maintenance Check Sheet ................. 65 Ash Drain ..................................................... 30 Attemperation Control Station ........................ 17 Attemperator ................................................ 20

B Balance of Plant Start Up .............................. 42 Bed Ash Alkali Control .................................. 40 Bed Drain System......................................... 30 Bed Level Control ......................................... 40 Bed Material................................................... 6 Bed Slumping Procedures............................. 43 Blowdown Tank ............................................ 23 Boiler Annual Maintenance and Overhaul .................................................... 72 Boiler Blowdown System ............................... 21

Daily Maintenance ........................................ 62 Deaerator Charging ...................................... 42 Deaerator Level Gauge ..................................11 Description of Dosing System Skid ................ 30 Design Code .................................................. 3 Design Specifications......................................2 Dissolved Gases .......................................... 88 Dissolved Salts and Minerals......................... 87 Do’s and Dont’s ............................................ 47 Down Comer Tubes ...................................... 18 Drain Header ................................................ 22 Drum Inspection ........................................... 72 Drum Level ...................................................11 Dry Storage Preservation .............................. 77

E Economizer .................................................. 17 Effects of Impurities ...................................... 88 Electrical Power ..............................................7 Electrostatic Precipitator ................................ 27 Emergency Procedures................................. 53 Expansion Joints .......................................... 73


HP Dosing System........................................ 30 HP Dozing System.......................................... 9

I IBD Drain ..................................................... 22 ID Fan ......................................................... 27 Inbed Coil .................................................... 20 Inspection after Cooling ................................ 72 Inspection of Screen, Primary & Secondary Superheater, Evaporator I/ II & Economiser ................................................ 73 Instrument Air ................................................. 8 Insulation and Cladding................................. 73 Intermittent Blowdown..................................... 6

L Load Operation............................................. 39

M Main Steam Piping........................................ 21 Material Specifications .................................... 3 Monthly Checks............................................ 63

Procedure For Normal Operation ................... 36

R Recommended Maintenance Practice ............ 59 Removing Tubes from Drums, Headers & Tube Plates .............................................. 100 Replacement of Tube Section...................... 100 Riser Tubes.................................................. 20 Rotary Feeders........................................10, 28

S Safety Valves ................................................11 Safety Valves, Start Up Vent Valves And Other Isolating Valves ................................. 76 Sampling System.......................................... 31 Section Overview.......................................... 59 Service Air ..................................................... 8 Shutdown and Cooling the Boiler ................... 72 Site Condition.................................................8 Slumped Bed to Active Bed ........................... 43 Start Up Firing System .................................. 29 Start-up of a Cold Boiler ................................ 32 Steam Drum............................................17 –18 System Description.................................. 24 27

SUPER HEATED STEAM TO TURBINE 41000 Kg/hr 66 Kg/cm2 (g) O 490 +5 C

38410 Kg/hr 74 Kg/cm2 (g) 130 C

FROM FEED PUMP

FD FAN

SPRAY WATER FLOW

FEED WATER

3000 Kg/hr

41410 kg/hr 76 kg/cm2 (g) O 130 C

74 Kg/cm2 (g) 130 C

g r w h / C m g O k m 6 5 6 2 4 2 5 7 0 + 6

38410 Kg/hr 73.5 Kg/cm2 (g) 216 C

65610 kg/hr 250 OC

65610 kg/hr O

g w m m 5 -

BOILER + SUPER HEATER

-80 mmwg

FLUE GAS

AIR PREHEATER

FLUE GAS

65610 kg/hr 160 OC

65610 kg/hr O

160 C -135 mmwg

-105 mmwg FLUE GAS

ESP

ECONOMISER

HEAT TRANSFER ELEMENTS

CONTINUOUS BLOW DOWN 410 kg/hr

445 C -40 mmwg

SEC. AIR

BOILER

CO2 % BY VOL WET:

12.8

CO2 % BY VOL DRY: O2 % BY VOL WET: O2 % BY VOL DRY:

14.53 4.31 4.89

FLUE GAS

ID FAN

FLUE GAS

65610 kg/hr O

C +5 mmwg

160

72.5 kg/cm2 (g) 290

O

C

COMBUSTOR g r w h / g C m k O m 3 0 0 5 5 5 0 1 6 6 +

SUPERHETAER STEAM TEMPERATURE ST

AFTER 1 STAGE SUPERHEATER:-

FD AIR COAL

O

BEFORE SPRAY

:

439 C

AFTER SPRAY

:

366 C

9600 kg/hr O

60526 kg/hr O 150 C +650 mmwg 10200 kg/hr O 150 C

PA FAN

FUEL : TYPE OF FIRING : LOAD : G.C.V : % MOISTURE :-

+1400 mmwg

SYMBOL

SERVICE STEAM LINE FUEL LINE AIR LINE

ALT. NO.

ALTERATION

MADE DATE

CHKD.BY DATE

APP.BY DATE

COAL UNDERBED 100 % 3500 kcal/kg 8 %

PRODUCT :- BDF - 410 - 41TPH / 66 kg/cm2 g / 490 deg C CLIENT :-

POWER A/C. HAREKRISHNA METALLIKS

TITLE :-

PROCESS FLOW DIAGRAM FOR COAL

OC NO: SCALE NTS

DESIGNED CHECKED APPROVED

PD0161 07.12.07 07.12.07 JRV 07.12.07 JRV GN

WATER LINE FLUE GAS

THERMAX LIMITED

DRG.NO. / PART NO.

CHINCHWAD PUNE -411019

PD0161 0033

BOILER AND HEATER GROUP

( SHEET 1 OF 2)

ALT. NO

0

SUPER HEATED STEAM TO TURBINE 41000 Kg/hr 66 Kg/cm2 (g) O 490 + 5 C

38310 Kg/hr 74 Kg/cm2 (g) 130 C

FROM FEED PUMP

FD FAN

SPRAY WATER FLOW

FEED WATER

3100 Kg/hr

41410 kg/hr 76 kg/cm2 (g) 130 C

74 Kg/cm2 (g) 130 C

g r w h / C m g O k m 2 5 0 7 4 0 5 8 4 + 6

38310 Kg/hr 73.5 Kg/cm2 (g) O 218 C

69240 kg/hr 255 OC

69240 kg/hr O

g w m m 5 -

BOILER + SUPER HEATER

-95 mmwg

FLUE GAS

AIR PREHEATER

FLUE GAS

69240 kg/hr 160 OC

69240 kg/hr O

160 C -155 mmwg

-125 mmwg FLUE GAS

ESP

ECONOMISER

HEAT TRANSFER ELEMENTS

CONTINUOUS BLOW DOWN 410 kg/hr

445 C -50 mmwg

SEC. AIR

BOILER

CO2 % BY VOL WET:

13.75

CO2 % BY VOL DRY: O2 % BY VOL WET: O2 % BY VOL DRY:

15.22 4.38 4.85

FLUE GAS

ID FAN

FLUE GAS

69240 kg/hr 160

O

C +5 mmwg

72.5 kg/cm2 (g) 290

O

C

50%COAL

5250 kg/hr

50%CHAR

5250 kg/hr

COMBUSTOR g r w h / g C m k O m 7 0 5 5 5 1 4 1 7 6

SUPERHETAER STEAM TEMPERATURE ST

AFTER 1 STAGE SUPERHEATER:-

PA FAN

64572 kg/hr O 150 C

STEAM LINE FUEL LINE AIR LINE

ALT. NO.

445 C

AFTER SPRAY

:

359 C

O

FUEL:- 50%COAL + 50%CHAR TYPE OF FIRING : - UNDERBED LOAD : - 100 % G.C.V : - 3350 kcal/kg % MOISTURE :- 5.61 %

715 mmwg

+1410 mmwg

SERVICE

:

FD AIR

10200 kg/hr O 150 C

SYMBOL

O

BEFORE SPRAY

ALTERATION

MADE DATE

CHKD.BY DATE

APP.BY DATE

PRODUCT :- BDF - 410 - 41TPH / 66 kg/cm2 g / 490 deg C CLIENT :-

POWER A/C. HAREKRISHNA METALLIKS

TITLE :-

PROCESS FLOW DIAGRAM FOR 50%COAL + 50%CHAR

OC NO: SCALE NTS

DESIGNED CHECKED APPROVED

PD0161 07.12.07 07.12.07 JRV 07.12.07 JRV GN

WATER LINE FLUE GAS

THERMAX LIMITED

DRG.NO. / PART NO.

CHINCHWAD PUNE -411019

PD0161 0033

BOILER AND HEATER GROUP

(SHEET 2 OF 2)

ALT. NO

0

O & M Manual for Boiler

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