(2) Boiler Proper

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INSTRUCTIONS

FOR THE

CARE AND OPERATION

OF

CIRCULATING FLUIDIZEDBED BOILER

(CFB)

1



FOREWORD

The instructions are to be used as a guide for operational reference and

should not take the place of Boiler Operation Specifications.These instructions are issued for the purpose of assisting operators in

obtaining the best possible results of HANGZHOU BOILER GROUP

CO.,LTD(HBG) equipment. The instructions can only supplement the

experience and judgment of those in charge of operation. They should be

interpreted and applied after due consideration for the requirements of other

equipment and for any particular set of circumstances. These instructions do

not purport to cover all details or variations in equipment nor to provide for

every possible contingency to be met in conjunction with operation and /or

maintenance.

The recommendations contained in these instructions are issued by HBG

based upon the knowledge and experience representing our best judgment at

the time of issuance. In offering these instructions for pre-operation, operation,

maintenance and safety, HBG assumes no responsibility for any failure or

incident resulted from incorrect operations.

The instructions involve quite a number of HBG’s technology, Without

permission, no one that is not involved in this Project is allowed to make any

copy of these Instructions.

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Contents

FOREWORD...............................................................................................................................2

1.CONSTRUCTION DESCRIPTION OF BOILER PROPER.....................................6

1.1.Design Conditions.................................................................................................................61.1.1.Boiler Specifications:.................................................................................................6

1.1.2.Boiler Main Dimensions............................................................................................6

1.1.3.Fuel.............................................................................................................................6

1.1.4.Optimum Size distribution for coal (shown in fig 1-1)Ash Analysis........................7

1.1.5.Limestone...................................................................................................................7

1.1.6.Sand............................................................................................................................8

1.1.7.Igniter Type................................................................................................................9

1.1.8.Igniting Oil.................................................................................................................9

1.1.9.Feedwater Quality......................................................................................................9

1.1.10.make-up water........................................................................................................10

1.1.11.boiler water.............................................................................................................10

1.1.12.Site Conditions:......................................................................................................11

1.1.13.Operation Mode......................................................................................................11

1.1.14.Draft Mode.............................................................................................................11

1.2.GENERAL DESCRIPTION OF BOILER..........................................................................11

1.3.GENERAL ARRANGEMENT OF THE BOILER............................................................13

1.3.1.Steam and Water Flow.............................................................................................13

1.3.2.Air and Gas Flow.....................................................................................................15

1.3.3.Combustion Process.................................................................................................161.3.4.Economizer...............................................................................................................17

1.3.5.Steam Drum and Drum Internals.............................................................................17

1.3.6.Furnace.....................................................................................................................19

1.3.7.Cyclone Inlet circuit.................................................................................................21

1.3.8.Cyclone.....................................................................................................................21

1.3.9.Heat Recovery Area (HRA).....................................................................................22

1.3.10.Low temp. superheater...........................................................................................23

1.3.11.Primary Attemperator.............................................................................................23

1.3.12.Superheater Wing Wall...........................................................................................23

1.3.13.Secondary Attemperator.........................................................................................24

1.3.14.High Temp. Superheater.........................................................................................24

1.3.15.Air Preheater..........................................................................................................24

1.4.FUEL, LIMESTONE AND ASH REMOVAL SYSTEMS................................................25

1.5.CIRCULATING SOLIDS REINJECTION SYSTEM.......................................................25

1.6.UNDER-BED BURNER....................................................................................................25

1.7.BOILER PROPER STEEL STRUCTURE.........................................................................26

1.8.OPERATING PHILOSOPHY.............................................................................................26

1.9.EXPANSION SYSTEM......................................................................................................27

1.10.WATER VOLUMES OF MAJOR BOILER PARTS:.......................................................29

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2.SAFETY PRECAUTIONS AND PREPARATION FOR OPERATION....................30

2.1.SAFETY PRECAUTIONS.................................................................................................30

2.2.HYDROSTATIC TESTS.....................................................................................................33

2.3.DRYING OUT REFRACTORY.........................................................................................372.4.BOILING OUT...................................................................................................................38

2.4.1.General.....................................................................................................................38

2.4.2.Recommended Chemicals for Boiling Out..............................................................39

2.4.3.Preparations for Boiling Out....................................................................................40

2.4.4.Boiling Out Procedure..............................................................................................43

2.5.FEEDWATER AND BOILER WATER TREATMENT.....................................................45

2.6.CHEMICAL CLEANING OF ECONOMIZER AND STEAM GENERATING

CIRCUITS ...............................................................................................................................45

2.6.1.General.....................................................................................................................45

2.6.2.Determining the Need for Chemical Cleaning........................................................46

2.6.3.Solvent Systems.......................................................................................................47

2.6.4.General Cleaning Operations...................................................................................48

2.7.CHEMICAL CLEANING OF SUPERHEATERS.............................................................49

2.7.1.General.....................................................................................................................49

2.8.STEAM-LINE BLOWING.................................................................................................50

2.8.1.General.....................................................................................................................50

2.8.2.Initial condition........................................................................................................51

2.8.3.Precaution and matters need attention.....................................................................51

2.8.4.Procedure of steam purging.....................................................................................522.8.5.Return to the raw condition......................................................................................53

2.9.BOILER SYSTEM AIR TEST...........................................................................................54

3.OPERATION AND MAINTENANCE......................................................................55

3.1.GENERAL..........................................................................................................................55

3.2.GENERAL PRECAUTIONS..............................................................................................55

3.3.COLD START-UP PROCEDURE ................................................................................62

3.3.1.Preparation Prior to Start-up....................................................................................62

3.3.2.Purging.....................................................................................................................66

3.3.3.Warming The Unit....................................................................................................70

3.3.4.Start-up (Fuel Firing)...............................................................................................73

3.4.HOT RESTART .................................................................................................................77

3.5.NORMAL OPERATION....................................................................................................80

3.5.1.Firing........................................................................................................................80

3.5.2.Water Chemistry and Steam Purity..........................................................................82

3.5.3.SootBlowing.............................................................................................................82

3.5.4.Spray Attemperation ................................................................................................84

3.6.NORMAL SHUTDOWN....................................................................................................84

3.7.EMERGENCIES.................................................................................................................873.7.1.Main Fuel Trip (MFT)..............................................................................................87

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3.7.1.1.Any of the following conditions will cause a boiler main fuel trip (MFT)..88

3.7.2.Emergency Operating Procedures............................................................................89

3.7.2.1.Tube Leak .....................................................................................................89

3.7.2.2.Excessive Bed Temperatures........................................................................90

3.7.2.3.Clinkered Bed................................................................................................913.7.3.Overpressure Protection...........................................................................................92

3.8.MAINTENANCE................................................................................................................92

4．Figure..................................................................................................................95

Fig。1-1 Optimum size distribution for coal ............................................................................95

Fig。1-2 Sectional side elevation of boiler................................................................................97

Fig。1-3 Steam and water diagram of boiler.............................................................................98

Fig。1-4 Gas and air diagram of boiler......................................................................................99

Fig。1-6 Arrangement of downcomers....................................................................................101

Fig。2-1 The boiling out pressure for different design pressure.............................................102

Fig。3-1 Oxygen measurement of approximately % by volume on a wet basis.....................103

Fig。3-2 Relationship between bed pressure and fluidizing velocity ...................................104

Fig。3-3 The minimum steam temperature after spray...........................................................105

Fig。3-4 Relationship between bed pressure and height of static bed material......................106

Fig。3-5 Cold start curve 。。。。。。..........................................................................................107

Fig。3-8“J”Valve Piping Connection Drawing........................................................................110

5．Table..................................................................................................................111

Table 1 Thermodynamic Calculation Collecting Table for Coal rank COAL2 in Boiler Design..................................................................................................................................................111

Table 2. Boiler check coal rank COAL1 thermodynamic calculation collection table..........115

Table 3. Boiler check coal rank COAL3 thermodynamic calculation collection table..........119

Table 4. Flue Gas and Air Resistance Collection Table.........................................................122

Table 5. Steam water Resistance Collection Table................................................................122

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1.CONSTRUCTION DESCRIPTION OF BOILER PROPER

NG-130/10-M boiler is designed and manufactured for Siam Kraft Industry

Co., Ltd of Thailand.

The Boiler is a single furnace of coal-fired, outdoor, complete steel structures,

full membraned water cooling wall, circulating fluidized bed combustion, high

temperature steam-cooled volute type cyclone Separator for gas solid

separation, water circulation in natural way and flue gas system of balance

ventilation.

1.1. Design Conditions

1.1.1.Boiler Specifications:

Maximum Steam Flow 130t/h

Superheat Steam Outlet Temperature 510℃ +5-10

Superheat Steam Outlet Pressure 100bar(g)

Feedwater Temperature 170℃

Ambient Air temperature 30℃

1.1.2.Boiler Main Dimensions

Furnace Width (Between CL of Side Walls) 7200mm

Furnace Depth (Between CL of Front & Rear Walls) 4480mm

Elevation of Steam Drum CL 39200mm

Elevation of Boiler Top(Front/Rear) 38040/43200mm

Boiler Width (Z1 to Z1 Opposite) 10000mm

Boiler Depth (Z1 to Z4) 17860mm

1.1.3.Fuel

The boiler combusts with Coal 1 (Jorong Coal)。Coal 2 (Banpu Coal) or

Coal 3 (Sub-bituminous coal), and boiler performance with coal 2 shall be

analyzed separately with tests.

Ultimate Analysis (wt. % as received)

Symbol Design fuel

coal2

Check fuel

coal1

Check fuel

coal3

Carbon Car 62.21 48.73 62.74

Hydrogen Har 4.08 3.53 4.76

Oxygen Oar 6.09 14.03 8.89Nitrogen Nar 1.01 0.48 1.02

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Sulfur Sar 0.72 0.11 1.32

Ash Aar 13.89 3.11 10.25

Moisture War 13.89 30 11

Proximate Analysis of the Coals (wt. %。 air dry)

Design fuel

coal2

Check fuel

coal1

Check fuel

coal3

Volatile Matter (%) 40 51.2 40

LHV (Kcal/kg) 5831 4269 6024

1.1.4. Optimum Size distribution for coal (shown in fig 1-1)Ash

AnalysisWithout limestone

ITEMS Units Design fuel

coal2

Check fuel

coal1

Check fuel

coal3

Ash softening point,

reducing conditions

℃ 。1200 。1200 。1200

SiO2 % 46.68 31.6 49

Al2O3%

36.19 37.21 37.7

Fe2O3 % 5.88 12.87 4.5

CaO % 1.4 9.07 2.2

MgO % 3.3 1.12 1.6

K2O % 0.43 0.89 0.5

Na2O % 0.49 0.27 0.4

SO3 % 2.04 4.33 1.2

TiO2 % 2.67 0.48 2.7

P2O5 % 0.8 0.05 0.2

1.1.5.Limestone

a. Limestone analysis (before calcined)

Item Unit Design date

CaCO3 % 90

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MgCO3 % 3.0

Moisture % 0.2

Inert%

1.0

Reactivity index / high

b. Optimum size distribution for limestone

- 100% < 750 um

- 80% < 500 um

- 50% < 300 um

- 10% < 150 um

1.1.6.Sand

Natural sand (feldspar) is used for start-up and make-up bed material.

The typical analysis is as follows:

Item Unit Data

SiO2 % 82.2

Al2O3 % 9.7

Fe2O3 % 1.8

CaO % 1.2MgO % 0.4

Na2O % 1.9

K2O % 2.8

H2O % 0.1

loss of ignition % 0.95

Density kg/m3 1500

Softening point °C 1200

Optimum Size distribution for Inert

Particle size distribution

Weight 。 Unit Size

100% µm <1000

75% µm <450

50% µm <350

25 % µm <250

100 % µm >100

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1.1.7.Igniter Type

under-bed Igniter (burner).

1.1.8.Igniting Oil

Unit Design Range

Fuel As-Received

Type light oil

Net calorific value MJ/kg 42.60 42.6-42.9

Total moisture % 0.05 0.0-0.05

Analysis of dry solids (%-weight)

Carbon, C % 86.08

Hydrogen, H % 13.71

Oxygen, O % 0.02

Nitrogen, N % 0.02 0.01-0.02

Sulfur, S % 0.15 0.05-0.15

Ash % 0.02

Specific weight, at

15°C

kg/m3 855 835-855

Viscosity, at 20 °C mm2/s 5.9 3-6

1.1.9.Feedwater Quality

Be in compliance with Requirement of High pressure water Quality in

the Quality Standards of Water and Steam for Thermal Power

and Steam Generating Units (GB12145).

Parameter Units Results

Hardness μmol/L ≤2.0

oxygen,O2 μg/L ≤7total iron,Fe μg/L ≤30

copper, Cu μg/L ≤5

Na content μg/L /

SiO2 content /should satisfy with

steam

requirement:≤20μg/kg

pH(250C) / 8.8-9.3

Hydrazine μg/L 10-50

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Oil mg/L ≤0.3

feedwater is used for spray control of steam temperature,the

feedwater TDS must not exceed 1 ppm.

TDS:mean total dissolved solids.

1.1.10. make-up water

Be in compliance with Requirement of High pressure water Quality in the

Quality Standards of Water and Steam for Thermal Power and Steam

Generating Units (GB12145).


Hardness μmol/L ≈0

SiO2 content μg/L ≤20

conductivity(250C) μS/cm ≤0.2

1.1.11. boiler water

Be in compliance with Requirement of High pressure water Quality in

the Quality Standards of Water and Steam for Thermal Power

and Steam Generating Units (GB12145).


Total salt content mg/L ≤100

SiO2 content mg/L ≤2.00

PO34- content mg/L 2-10

pH(250C) / 9.0-10.5

conductivity(250C) μS/cm <150

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1.1.12. Site Conditions:

1.1.13. Operation Mode

Constant or various pressure operation mode and the load change

rate may be greater than or equal to 7%/min.

1.1.14. Draft Mode

Balanced draft and pressure balance point is located at outlet of

furnace (inlet of cyclone separator).

1.2. GENERAL DESCRIPTION OF BOILER

This steam generator is a natural circulation, circulating fluidized bed

boiler and out-door arrangement.

The steam generator consists of a water-cooled furnace enclosure,

two (2) steam-cooled cyclone enclosures and one back pass

Site

Elevation above sea level m 10Ambient air Pressure kPa 101.3Temperature, average °C 30Temperature, minimum °C 21Temperature, maximum °C 38 Air temperature for boiler efficiencycalculations

°C 30

Relative HumidityPerformance design % 70Minimum % 60

Maximum % 80Wind Analysis Maximum Wind Speed m/s 20Wind direction / NE and SWMaximum precipitation Over 1 day period mm 80Seismic intensity Grade 6Field Classification / Grade II

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convective cage. The furnace and back pass cage are rectangular in

plan view while each cyclone is circular.

In the upper furnace, there are uniformly two (2) superheater wing

wall across the furnace width.

The back pass cage is made up of two parts, the upper part is a

steam-cooled convective heat recovery area (HRA) enclosure, the

lower part is a steel plate casing structure. the HRA contains high

temp. and low temp. superheaters, the casing structure contains

economizer and air preheater.

Between the low temp. superheater, superheater wing wall and high

temp. superheater there are two (2) stages water spray

attemperators to control final superheater steam temperature.

Fig. 1。2 consists of a sectional side elevation of boiler. The elevation

sketch locates the major steam generating components and

structural dimensions.

Heat to generate steam comes from the fluidized bed system. Initially

combusted bed materials are forced by flue gas upward through the

furnace and exit at the top to the two (2) steam-cooled cyclone

separators. Coarse hot bed material is separated from the flue gas in

the cyclones and sent back to the furnace via J-valves connected to

the bottom of the cyclones. The hot bed material re-enters the

furnace just above the grid plate to complete the circulation cycle

combustion. Flue gas exits via the outlet at the top of the cyclones

and enters the HRA through a gas screen near the top of the HRA

front wall. After flowing down the HRA, heating the HRA walls and

components, the hot gas leaves the steam generator through air-

preheater via the flue near the bottom of the HRA enclosure.

The circulating fluidized bed boiler is supported by other system,

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including fuel and limestone feed systems, bottom ash drain cooler

and conveyer system, air and gas systems, control and

instrumentation systems.

1.3. GENERAL ARRANGEMENT OF THE BOILER

1.3.1.Steam and Water Flow

Fig. 1 。 3 shows that the steam generating circuitry consists of

economizer, one drum, furnace waterwalls, steam-cooled cyclone

inlet sections, steam-cooled cyclone separators, HRA steam

enclosure, low temp. superheater, superheater wing wall, high temp.

superheater and the piping.

Feedwater enters the economizer located in HRA through the lower

economizer inlet header (EL. 17700) located right side of the HRA

enclosure. The feedwater rises through four (4) serial-connected banks

of horizontal economizer tubes and is directed through an outlet header

and then through three Φ108×8 economizer pipes to the steam drum.

During start-up, when there is no feedwater flow to the drum, one

economizer recirculating system is provided to prevent the stagnant

water in tube steaming by recirculating drum water via the

downcomer to the pipes connected ahead of the economizer inlet

header.

The feedwater forms a water reservoir in the drum which is

connected to the lower inlet headers of the furnace walls via two (2)

drum downcomers and feeder tubes. The water flows upward

through the furnace wall tubes while being heated to a steam/water

mixture; the mixture then leaves through the furnace walls upper

outlet headers and re-enters the drum through riser tubes. The

13



steam drum separates the water from the entering steam/water

mixture and directs it back to the drum water reservoir for

recirculation to the furnace walls. The separated steam is dried and

flows out the steam lines at the top of the drum.

From the drum, the steam flows separately through two (2) φ159×12

steam supply pipes to inlet headers of both side flue gas inlet

circuits, steam flows through the inlet circuits downwards into lower

outlet header, then steam is gathered into the upper ring header of

left cyclone via individual two(2) φ159×12 pipes, Flow through the left

cyclone circular wall is downwards into the lower ring header. Then

the flow is directed through four (4) φ159×12 transfer pipes to the

lower ring inlet header of the right cyclone enclosure, upwards into

upper ring header of right cyclone and finally four (4 ) φ 159×12

transfer pipes carry the steam to the HRA front wall upper inlet

header at elevation of 40900. Flow in the HRA is down through the

HRA front wall up through both HRA side walls and then through the

roof and down the HRA rear wall.

Steam leaves at elevation 29930 the HRA rear wall lower header

which also serves as the low temp. superheater inlet header, steam

flow through the horizontal low temp. superheater tubes which is in

an upward direction counter to the flow of hot flue gas in the HRA

then to the low temp. superheater outlet header at elevation of

31440. From only left ends of low temp. superheater outlet heater,

steam flow via one (1) φ 273×20 transfer pipes which involve the

14



primary spray attemperators is directed to furnace front wall

superheater wing wall inlet header at elevation 17960. From the inlet

distributing header, the steam flows into two (2) upper furnace

superheater wing walls. Then through the superheater wing wall

outlet distributing headers at elevation 36200 the steam flows into

superheater wing wall outlet header. Between this header and high

temp. superheater inlet header located at HRA rear wall at elevation

32710, there is one (1) φ325×25 transfer pipes which involve the

secondary spray attemperator. Steam flow through the horizontal

high temp. superheater tubes is also in an upward direction to the

high temp. superheater outlet header at elevation 35710, finally the

satisfied main steam through six(6) Φ133×13 tranfer pipes is

gathered into the main steam contain header, and main steam leaves

the unit on the left side of boiler.

1.3.2.Air and Gas Flow

Circulation of the fluidized bed material is initiated and maintained by

forced draft (FD) fans ( including primary and secondary fans) and

one induced draft (ID) fan. Initially heated by air-preheater,

combustion air from primary fan is divided into three (3) paths. The

first is introduced into the plenum at the bottom of the furnace and

fluidizes the bed material through nozzles in the grid floor and

establishes solids circulation upwards through the furnace. In this

line, there are parallelly connected air bypass for boiler igniting

startup and low load stable fuel oil burner, The second is introduced

to three(3) air swept coal feeders to assist in transporting fuel into

furnace. The third is employed as sealing air for coal conveying belt.

However, the combustion air from the secondary FD fan is heated by

15



air-preheater and directed into furnace through secondary wind box

at upper furnace.

The flue gas and entrained solids exit the furnace, through two (2)

cyclone inlet circuits, to the two (2) cyclones where coarse solids are

separated from the gas stream which exits the top of each cyclone.

From the cyclones, the flue gas flows down through the HRA and

passes over the horizontal convection surfaces. Having given up its

heat to the steam circuits in the HRA, the gas passes through the

tubular air 。 preheater and enters the ESP for removal of fine

particulate. The cooled dust-free gas is then exhausted through the ID

fan to the stack for release to atmosphere.

The air and gas flow paths through the steam generator are shown in

Fig. 1。4.

For J-valve, there are two (2) blowers each is for 100% capacity. one

(1) of the blowers are in operation and one stands-by. Excess air is

directed through by-pass line to the first path of primary air since each

J-valve blower is constant volume device.

Dampers are provided throughout the air and gas flow system to

obtain proper control, shut-off and isolation during operation and

shutdown.

1.3.3.Combustion Process

After the bed is initially charged, the under-bed burners are fired,

during a cold start-up, to preheat combustion air to the ignition point

of solid fuel. After entering the plenum, the air enters the fluidized

bed through an air distribution grid plate. This grid plate consists of

bell-shaped air nozzles inserted on the fins of a water-cooled grid

floor. The nozzles provide a uniform distribution of air throughout the

bed. The layer of refractory casting between the top of the grid plate

16



and the ends of the nozzles provides an anti-corrosion and insulation

layer which results in a lower grid plate operation temperature.

Within the fluidized bed, air mixes with the fuel and limestone

products to facilitate combustion and sulfur capture. Solids, swept up

in the furnace by air and flue gas, exit through furnace rear wall

openings and enter the cyclones. The coarser particles are

separated in each cyclone for reinjection to the furnace.

NOx formation is controlled and furnace temperature is properly

maintained due to staged combustion. introducing a portion of the air

to burn the fuel in lower furnace and completing combustion in upper

furnace by introducing the remaining air as overfire air

1.3.4.Economizer

The economizer located in HRA consists of four (4) banks of φ32×4

bare 20G tubes with an in-line arrangement on 90 longitudinal

spacing,. The first bank is 38 sections in wide direction with on 82

transversal spacing, which has four loop-in-loop tubes. The other

banks are 46 sections in wide direction with on 68 transversal

spacing, which have three loop-in-loop tubes. The economizer has

one inlet, one intermediate and one outlet header (each 219 OD).

Feedwater enters the right side lower inlet header at the elevation of

17700 and flows upward through the outlet header at the elevation of

28640, and is piped into the steam drum.

1.3.5.Steam Drum and Drum Internals

The steam drum is located at the top and across the width of the

furnace. the steam drum serves as a water reservoir for the steam

generation circuits. The drum contains steam separating equipment

17



and internal piping for distribution of chemicals to the water, for

distribution of feedwater and for blowdown of the water. Fig. 1 。

5shows the arrangement of the steam internal components.

Inner diameter of drum is 1600mm, length of straight drum body is

8.4m (excluding spherical end plate). The inner equipment is as

following:

Cyclone separators ----- total 32 sets in two rows in-line arranged.

corrugated moisture separators ---- total 21 sets.

Steel wire mesh separators ----total 21 sets.

Cleaning orifice ---- total 21 pieces.

Feedwater inlet pipe ---- feedwater pipe is evenly introduced into

drum along drum body axially.

Continuous blowdown pipe ---- lacunaris, confluxed to two outlet

pipes to be drained.

Dosing pipe ---- lacunaris, confluxed to one outlet pipes in the middle

of drum.

The arc plate are mounted along whole straight section of drum,

forming a casing space at two sides of drum. Steam mixture introduced

from furnace rises enters the casing, and then goes into cyclone

separator for primary separation: separated water goes along wall

through discharge outlet into water space; while steam flows up

through cyclone separator top corrugated sheet separator into steam

space, and then through cleaning orifice, finally it is educed via steam

connecting pipe at the top of drum through wire mesh separator and

corrugated sheet separator. Water from economizer flows to cleaning

orifice plate through feedwater pipe and then into water space for next

primary circulating.

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1.3.6.Furnace

The furnace is a 28770 high×7200 wide×4480 deep combustion

chamber consisting of front, rear and side walls. At the bottom of the

furnace, the rear wall splits to form both the plenum floor and the

fluidized bed grid floor, together with both side walls, they form the

water-cooled air plenum, the bottom of which is at the elevation of

3880. The elevation of the grid floor is 5980. At the top of furnace,

the front wall bends toward the rear wall to form the furnace roof

which terminates with an upper header. The elevation of the furnace

top is 36100. two (2) rear wall lower headers at the bottom of furnace

( elevation 3880, 4780) serve also as inlet headers for the plenum

and grid floors ( formed by the rear wall tubes). There are one (1)

front wall upper headers and one (1) rear wall upper headers, all

located at elevation 36100. There are one (1) lower headers and one

(1) upper headers for each side wall , the lower headers of which are

at elevation 3480, the upper headers are at 35700. The furnace is

divided into upper part and lower part and the border of the division

is at elevation 12792.2. The longitudinal section view of lower

furnace is trapezoid shaped as the front and rear walls intersect with

the horizontal plane at a angle of 80° . The furnace depth, at

elevation 5980 where the grid floor is located, is 2200. Wearproof

material layers of 55 mm thickness are made to water wall of furnace

combustion area, and also made to rear wall, side walls, roof tubes,

all area near the gas outlet of upper furnace. The drum water is

connected to the circuitry via downcomer. Fig. 1 。 6shows the

arrangement of downcomers.

The tube spacing for front wall (and roof), rear wall and side walls is

19



80 ( φ60×5 tubes). Front wall and rear wall are each comprised of

89 tubes, side walls are each comprised of 56 tubes. The grid floor is

made of 44 riffled tubes (Φ63.5X7.5) with tube spacing of 160. The

plenum floor is comprised of 44 finned tubes (Φ60×5) with tube

spacing of160. The furnace waterwall inlet and outlet headers are all

φ219×30, 20G.

Cross section ratios of inlet pipe, outlet pipe and riser of each circuit are

indicated in the following table. Cross section ratios of downcomer and

furnace water wall riser is 0.295.

Name Cross section ratio of

inlet pipe vs. furnace

water wall riser

Cross section ratio of

outlet pipe vs. furnace

water wall riser

Front water wall 0.344 0.401

Rear water wall 0.344 0.401

Side water wall 0.365 0.365

Three (3) fuel feed points are provided on the front wall of the

furnace approximately 1200 above the grid floor. Two (2) limestone

feed points are located respectively within the front and rear wall

8420 above the grid floor. Secondary air ports are arranged in two

layers on the furnace front wall and rear wall as follows:

Furnace Wall Location Quantity Elevation

Front Wall 10 12080Rear Wall 9 12080

Front Wall 6 8420

Rear Wall 4 9880

Rear Wall 6 8420

There are two(2) normal exkaust and one(1) emergency openings

located on the water grid floor, the two(2) bottom ash coolers are

connected to normal exhaust opening, ash coolers drain cooled ash

at the 1700 elevation, the emergency ash drain pipe(Φ219×10) outlet

20



is at the 1000 elevation.

Two (2) flue gas outlets center line is at the 32200 elevation near the

top of the rear wall.

1.3.7.Cyclone Inlet circuit

There are two (2) cyclone inlet circuits. Each cyclone inlet circuit

connects the rear wall flue gas outlet of the furnace to a

corresponding cyclone and is shaped to form a wide gas-tight tunnel

through which the flue gas can travel.

Each cyclone inlet circuit consists of steam cooled, refractory lined

tubes, connected by a lower header and an upper header at

elevation 34465 and 29930 respectively. There are total 26 tubes, 13

on each side per each cyclone inlet circuit. The tubes are 20GΦ51×5

and the inlet and outlet headers are 20G Φ219×30. Steam from the

drum is connected respectively by two (2) Φ159×12 transfer pipes to

the inlet header of each cyclone inlet circuit. Steam then flows down

through the tubes of each circuit, in parallel fashion, to the outlet

headers which are connected to the left-hand cyclone upper inlet ring

header by transfer pipes.

1.3.8.Cyclone

Two (2) identical cyclones separate coarse particles from furnace

flue gas sending the fines out of the top into the HRA and allowing

the coarser particles to fall down corresponding J-valves for

recirculation back to the furnace.

The top half of the cyclone is volute shaped and the lower half is

conical (funnel shaped). The flue gas outlet are made of many

pieces, which shaped altogether to form an open ended cylinder

extending nearly half way down into the center of the cyclone. The

21



fines and flue gas enter the bottom of the cylinder and flow up to exit

the cyclone. The coarse particles drop down into the funnel which is

directly connected to the J-valve.

The entire cyclone enclosure is steam cooled and is of membrane

wall construction with a ring header at the bottom and a ring header

at the top. The wall tubes bend inward at the top to form a seal

between the cyclone tubes and the flue gas outlet cylinder.

Each cyclone consists of 114 tubes (Φ42×6). Each ring header is

273 O.D.

1.3.9.Heat Recovery Area (HRA)

The heat recovery area (HRA) means back pass cage, which is an

approximately 6295 wide×3025deep convection heat enclosure of

membrane wall and ends at the approximately 29930 elevation,

below which the remainder of the HRA is constructed of steel plate. A

flue gas outlet is at the elevation of 6700, the bottom of the HRA is

formed into an ash hopper which allows a portion of the particles to

drop down before entering ESP and decreases the gas solids

concentration. The HRA houses the horizontal banks of convection

economizer, low temp. superheater and high temp. super-heater tube

surfaces.

All four walls are connected by inlet and outlet header. The HRA front

wall tube spacing increases from 95 to 285 near the top to form an

inlet screen for flue gas. The HRA rear wall tubing bends toward the

front wall near the top of the wall to form the HRA roof tubes. The

front and rear walls are each comprised of 65 tubes (Φ42×5, and the

14 support tubes in the front wall screen areΦ60×11) and each side

wall is comprised of 32 tubes (Φ42×5). The HRA front wall upper

header is Φ273X36,20G, low temp. superheater outlet header l is

22



Φ273X20,12Cr1MoVG, high temp. superheater inlet header l

isΦ325X25,12Cr1MoVG, high temp. superheater outlet header l

isΦ273X36,12Cr1MoVG, while other HRA superheater headers are

Φ219X30,20G.

1.3.10. Low temp. superheater

The low temp. superheater is located in the HRA and the inlet header

is at 29930 elevation, and consists of 16 loops of 2 loop-in-loop

horizontal tubes (Φ42X5 ) arranged in 65 sections across the width

of the unit, in counter to the gas flow. Along the steam flow, the first 8loops are of 20G tubes, the other 8 loops are of 15CrMoG tubes. The

low temp. superheater outlet header ( 12Cr1MoVG, Φ273×20) is

located near the HRA rear wall at the 31440 elevation.

1.3.11. Primary Attemperator

The primary spray water attemperator is located in the steam transfer

pipe between the low temp. superheater outlet header and

superheater wing wall inlet header. The attemperator is equipped

with a mixing liner and spray water piping. The liner is installed at

downstream of the spray piping to protect the attemperator shell from

thermal shock. Instrumentation are installed in spray water piping to

measure the temperature before and after the attemperator to control

the water flow entering attemperator.

1.3.12. Superheater Wing Wall

There are two (2) pieces of wing wall arranged at upper furnace near

the front wall. The wing wall is membrane wall construction with tube

spacing of 63.5. Each piece consists of 25 tubes( 12Cr1MoV,

φ42×7). Below elevation 20540, wing wall is refractory lined. The

23



whole wing wall expands upward. An outlet header ( φ325×25) is

located at the elevation 36200.

1.3.13. Secondary Attemperator

The secondary spray water attemperator is arranged in the steam

transfer pipe between the wing wall outlet header and the high temp.

superheater inlet header located at the HRA rear wall. The

superheated steam temperature is further controlled in the secondary

attemperator. The construction of secondary attemperator is basically

the same as the primary attemperator.

1.3.14. High Temp. Superheater

Steam from the secondary attemperator flows through transfer pipe

into the high temp. superheater located at upper HRA gas flue. The

steam is introduced into one ends of high temp. superheater inlet

header at the elevation 32710 and counter flow with the gas through

the high temperature superheater loops into high temp. superheater

outlet header located at the elevation 35710, and then gather to the

main steam pipe via transfer pipes. The high temp. superheater

contains 20 loops of 2 loop-in-loop tubes (Φ42X6). The whole loops

are 12Cr1MoVG tubes. There are 65 sections across the width of the

HRA.

1.3.15. Air Preheater

The air preheater is of three circuits installed vertically behind the

HRA. The primary and secondary tube boxes are stagger-arranged,

the upper circuits are common φ40×1.5 carbon steel tubes and the

lower circuit is vitreous enamel steel tube. The horizontal and

24



longitudinal spacing of the windbox are 65. Each three tube-groups is

connected by air duct to form independent paths. Primary and

secondary air are supplied by independent fan and directed through

the two air ducts and heated by flue gas which flows intersect with

the air. The primary and secondary air flow ratio is 52% and 48% of

total combustion air. The air temperature at the outlets is 185 .℃

1.4. FUEL, LIMESTONE AND ASH REMOVAL SYSTEMS

Three (3) coal feed systems located at furnace front wall, Two (2)

limestone feed points located respectively at furnace front and rear wall, two biomass gas gun located in lower secondary air ports,

one(1) inert material accession port located at the left of furnace. A

spent bed (ash) removal system is connected to the bottom ash

cooler outlet, the air preheater ash drain and the ESP ash drain.

1.5. CIRCULATING SOLIDS REINJECTION SYSTEM

This system is used to reinject heavy circulation solids particles from

the cyclone back into the furnace. It consists of two (2) J-valves(trap)

connected between the solids outlets of the cyclones and the solids

inlets on the furnace rear wall.

Each J-valve utilizes the bed material exiting the J-valve stand pipe

to “seal” the trap. This trap maintains proper flow direction of the

circulation bed towards the furnace with the motive force of thedifference pressure between upward and downward stream of the

trap. The air is supplied by high pressure blower.

1.6. UNDER-BED BURNER

two oil burners for start up is provided on both side of air plenum

below the grid floor. Combusted hot gas heats the primary air to

870 which in turn heats bed material through air distribution air ℃

25



nozzles to ignition temperature. The burner utilizes mechanic oil

atomizing gun to get good combustion to prevent nozzle damage

resulted from oil re-burn in the air distribution device. Oil

consumption of each oil gun is 480kg/h; oil pressure is 1.96Mpa at

burner inlet. When oil is already fired air flow for each gun burning is

at least 9000Nm3/h. High energy ignitor and flame scanner is

provided for the burner.

1.7. BOILER PROPER STEEL STRUCTURE

The boiler steel structure is welded connection type and out-door

arrangement. There are eight (8) main columns for boiler supporting.

The columns are connected to the base-work 。 foundation 。 at the

elevation of +200mm by anchor bolts. Horizontal beams and vertical

supports are provided between columns to withstand the loads of boiler

proper, wind and earthquake.

The major pressure parts of the boiler except steam drum are hung

by hangers from the top steel. Steam drum and other components of

the boiler, such as economizer, air preheater, under-bed burner,

loopseal, etc. are all stand on horizontal beams by supporting or

reinforcements.Platforms and stairs are provided where maintenance

or inspection is needed during boiler operation.

1.8. OPERATING PHILOSOPHY

The purpose of a fluidized bed boiler is to produce a required

quantity of steam, at the desired pressure and temperature by

burning fuel and operating at the optimum economic efficiency all in

an environmentally acceptable manner.

Load change with a fluidized bed steam generator is accomplished

by changing fuel and air flows, as same with any steam generator. A

26



fluidized bed steam generator differs in that it contains a solids

inventory in the form of lime and ash particles which constitute the

fluidized bed.

From the standpoint of combustion stability and NO x emission levels,

there is an allowable bed temperature variation and an optimum range

of bed temperature for SO2 capture. Outside this optimum range,

significant increases in limestone feed rates may be required to

maintain emission levels within acceptable limits. If load change

flexibility is required, the temperature should be maintained within a

specific range. This is accomplished by staged combustion and solids

loading control in the freeboard. Staged combustion serves two

purposes, the controlled combustion in the lower furnace help to

maintain the bed temperature in a suitable range for low NOx emission.

This unit utilizes fuel and limestone as the predominant bed material.

At normal operating bed temperatures, limestone is easily calcined

( CO2 is liberated ) resulting in a material that partially reacts with

SO2 in the burning fuel to form calcium sulfate (gypsum).

1.9. EXPANSION SYSTEM

The expansion centers (zero expansion points) are designed

according to the features of boiler arrangement and supporting

structures. The orientation of furnace waterwalls, cyclone separators

and HRA expand from the top downwards as they are all hung to the

top steel. There are three expansion centers designed for the boiler:

the center line of furnace rear wall, the center line of cyclone, the

center line of HRA front wall. The furnace expands from furnace

center line ( zero expansion point) toward two sides due to

expansion control devices installed in two (2) steel structure levels at

the elevation of 26800 and17100 respectively. The HRA expands

27



from boiler center line (zero expansion point) toward two sides due to

the expansion control devices supplied at two (2) steel structure

levels at the elevation of 33630 and 30730 . Bed material reinjection

device(loopseal) and air preheater expand upward from their

supporting base, and uniformly to front, rear, right and left.

28



1.10. WATER VOLUMES OF MAJOR BOILER PARTS:

Part Name During Hydrotest During Operation

(m3) (m3)

Steam Drum 19 6.8

Waterwalls 31 31

Cyclones (including cyclone inlet circuit) 4 0

Superheaters 15 0

Economizers 10 10

Total 79 47.8

Note: 1. The volume of waterwall includes downcomers, feeder pipes,

and headers.

2. The volumes of cyclones, superheaters and economizers all include

their headers and transfer pipes.

29



2. SAFETY PRECAUTIONS AND PREPARATION FOR

OPERATION

2.1. SAFETY PRECAUTIONS

The following instructions are some of the general precautions which apply

when placing a steam generator into operation. They are intended to

supplement the experience and judgement of those in charge of operation

and cannot cover all precautions which should be observed.

The manufacturer has complied with the national boiler code (GB china

standard) pertaining to the design and fabrication of the unit. A newly erected

unit, prior to being placed into operation, must be carefully inspected by

authority to assure that all component parts are properly assembled.

All of the steam generator’s auxiliary equipment must be in first class

operating condition, suitable for operation at design conditions and operatedin accordance with the manufacturer’s recommendations and instructions.

The following is offered as an initial start-up check list for this auxiliary

equipment.

NOTE

These checks should be completed prior to start-up of

the steam generator.

a. All fans and blowers shall be operated. Lubrication systems shall be

operable. Equipment shall be balanced and operate within vibration

tolerances.

b. All dampers, operators and actuators shall be subjected to internal and

external inspection. This auxiliary equipment shall be operated through

30



the full range of operation and shall be free of binding or jamming.

Confirm that dampers actually move to the positions called for by the

controls.

c. Ensure that the ash removal system connection has been made to the

cooler and that the cooler is ready for operation.

d. All remotely operated valves shall be operated and limit switches

checked to ensure that proper installation has been accomplished,

thereby yielding accurate position indications.

e. All conveyors shall be operated to substantiate readiness.

f. All critical flow elements shall be calibrated.

g. The under-bed burners, shall be ready for operation with all safety

equipment verified operable, e.g., flame scanner, interlocks, etc.

h. All critical thermocouples and pressure transmitters shall be checked

for proper connections and to ensure that they are operable.

Calibrations shall be completed.

i. All flues, ducts, pipes, chutes or conduits through which air, gas, water,

steam or solids flow shall be connected securely; check to ensure that

proper flow paths have been maintained.

j. All expansion joints shall be inspected to ensure that proper

connections have been made.

k. The precipitator shall be checked to verify that the system is operating.

l. All electrical connections shall be inspected to ensure that they have

been properly installed and that all insulation is in good condition.

When preparing a new steam generator for service, see that the following is

done as required:

a. The drum level gage glasses must be checked and installed in

accordance with the drawings prior to preliminary operation.

31



When the water level in the steam drum is lowered below the lowest

visible point of the gage glass, all water should drain out of the glass. Any

time a repair or change is made to the gage glass, this should be

checked.

b. Blowdown lines from water columns of drum level gage must be

properly piped and drain valves must be closed. The gage glasses

must properly illuminated and clearly visible to the operators from the

operating floor.

All vent, drain and blowdown lines must be readily accessible and properly

piped to a blowdown tank or other safe location so as not to endanger the

operator at any time.

Valves that are located between the steam drum and water column of water

gage must be in the full open position and locked.

All safety valve gags and hydrostatic test plugs must be removed and the

valves must be in proper operating condition. Discharge pipes and drains

should be arranged and supported in accordance with the safety valve

manufacturer’s recommendations.

Drum internal must be properly installed in accordance with the drawings to

assure that there will not be any steam bypassing the internals.

All test connections deemed necessary must be installed.

A leak test shall have been conducted on the steam generator’s air and fluegas systems; all leaks shall be corrected in accordance with paragraph 2.8.

Expected hot areas of the steam generator shall be insulated or roped off to

provide suitable protection for personnel.

In addition to the above, the following items should be thoroughly checked

each time a steam generator is placed into operation:

a. All necessary operating instruments, both permanent and temporary,

32



must be installed, operating properly and correctly calibrated.

b. All areas must be sufficiently illuminated.

c. No hazardous walkways, ladders or stairway should be used. Providesubstantial walkways and platforms where needed.

d. Air and gas passages must be free from obstruction and the unit

capable of being thoroughly purged by the circulation of air through the

unit.

e. The source of feedwater must be ample and uninterrupted once the

unit is in operation.

f. An ample fuel and limestone supply should be available.

g. All access and observation doors must be closed after it is ascertained

that no one is inside the unit.

h. Drum manhole openings must be properly closed.

When it is assured that the above precautions are fully understood and have

been complied with, then, and only then, should subsequent operations such

as“Drying Out”,“Boiling Out”,“Initial Starting”and“Normal Starting” be initiated.

2.2. HYDROSTATIC TESTS

The steam generating unit shall be subjected to a hydrostatic test when

erection of the pressure parts is completed. A hydrostatic test shall also be

made upon the completion of each general overhaul or repair affecting anypressure part of the unit, or at other times when it is desirable to inspect for

leaks.

CAUTION

THE BOILER TO BE HYDROSTATICALLY TESTED

SHALL BE FILLED WITH TREATED WATER.

33



If the unit is not to be placed into service after the test, treatment

shall be with hydrazine in the range of 200 to 300ppm plus sufficient

ammonia or morpholine to raise the pH to 10. If the unit is to be

placed into service within a short time using the test water, the

treatment may be as for normal operation. It is strongly

recommended that the unit be filled with the demineralized water or

condensate system for the test.

If the quantity of demineralized water or condensate is limited,

certain sections of the unit may be filled with treated potable water or

other water free of corrosive and suspended materials. This water is

not to remain in the unit for wet storage as all wet storage should be

made with treated demineralized water or condensate.

Drainable sections may be tested with other than demineralized

water or condensate provided the chloride content of the test water is

less than 50ppm, the temperature is less than 52 and that the℃

sections will subsequently be rinsed with condensate or

demineralized water prior to operation.

“The Steam Boiler Safety Supervisory Regulations”, stipulated by

the Labor Ministry of the People’s Republic of China, specifies that

the unit shall be subjected to a hydrostatic test with test pressure of

1.25 times the design pressure and test water temperature of 20 。

70 , which, however, shall be higher than the ambient temperature.℃

In order to satisfy with custom requirement, the hydrostatic test

pressure can be reached one and one-haif times the drum operating

pressure. This hydrostatic test is the test to be applied prior to the

unit is initially operated and after repairs or revisions are made to

pressure parts. Before applying a hydrostatic test on the unit, make a

thorough internal and external inspection to be absolutely sure that:

34



a. All foreign material and tools have been removed.

b. No one is inside the unit.

c. The pressure gage has been correctly calibrated and is connectedproperly, with valves open, on the drum outlet piping.

d. Any part not designed to withstand the hydrostatic test pressure is

properly isolated or blanked off from such pressure.

e. All valves operate freely and seat properly.

f. All steam circuit spring hangers are pinned in a fixed position.

g. All safety valves are blanked or gagged.

When the foregoing have been carefully checked:

a. Verify that drum manhole are properly closed.

b. Close stop and check valves, all drain and blowdown valves and valves

to any gages or other integral equipment not designed to withstand the

hydrostatic test pressure.

c. Open vents on the highest points of each component part of the unit.

d. Be sure that the water will not freeze during test and the unit will not be

subjected to freezing conditions following the hydrostatic test. If

hydrostatic testing of a drum will be at temperatures above 49 ,℃

exercise care during close examination to avoid possible burns from

water leakage.

e. Check that only authorized personnel are in the vicinity of the unit to be

tested.

f. Start filling the unit with water, which should be relatively close in

temperature to that of the pressure parts, so that the temperature of

drum metal and water is in accordance with the following before

applying a hydrostatic test pressure. All other pressure parts must be at

35



a temperature of not less than 20 .℃

CAUTION

WHENEVER HYDROSTATIC TEST PRESSURE IS IN

EXCESS OF 5.1Mpa, THE MINIMUM DRUM METAL AND

WATER TEMPERATURE。 20℃。MUST BE OBSERVED

TO INSURE THAT HYDROSTATIC TESTING IS

PERFORMED ABOVE THE BRITTLE TO DUCTILE

TRANSITION TEMPERATURE FOR THE METAL.

To obtain this hydrostatic test temperature, the following procedures

are recommended ( items a and b).

(1)IF STEAM GENERATOR UNDER-BED BURNER SYSTEM IS NOT

FUNCTIONING ( AS MAY BE THE CASE FOR INITIAL

OPERATION ), ANY ONE OF THE FOLLOWING METHODS

(1), (2), OR (3) IS RECOMMENDED. Heat from an external

source, to obtain the recommended minimum temperature as

indicated by the drum surface thermocouples.

(2) Use small oil and/or gas burners aimed through doors or

resting on the grid nozzles to raise the temperature to that

recommended. The burner flame should be kept away from

the boiler tubes.

(3) If the drum must be warmed above 20 , the additional℃

temperature may be obtained by connecting a saturated

steam supply to drum blowdown or chemical feed line to heat

water and drum shell. Start out with drum at normal operating

level and heat the water to a temperature 2 。5 above the℃

desired temperature so that subsequent water addition does

not lower the final temperature below the recommended

36



minimum.

b. IF STEAM GENERATOR UNDER-BED BURNER SYSTEM IS

FUNCTIONING, THE FOLLOWING METHOD IS RECOMMENDED.

(1) After filling the unit to normal water level, fire the under-bed

burners to raise the drum temperature to 2 。5 above that℃

recommended. Extinguish fires and continue to fill unit.

Inspect drains and manhole for leaks as the unit fills. Close

the high point vents when water issues from them.

(2) Raise pressure to the intended figure slowly to avoid shock.

The recommended rate of pressure increase should not

exceed 0.3Mpa per minute.

(3) If hydrostatic test was applied at pressure above design

pressure, reduce pressure slowly and thoroughly inspect unit

for leaks only at operating or design pressure. When

inspection is completed, release pressure slowly at the

recommended rate of pressure release not exceeding 0.3Mpa

per minute, open vents and drain. Superheater system must

be thoroughly drained.

(4) If temporary manhole gaskets were used during initial

hydrostatic test, they are to be replaced with proper gaskets

before refilling unit for operation.

(5) Remove blanks or gags from safety valves and pins from

spring hangers after test has been completed.

2.3. DRYING OUT REFRACTORY

All refractory should be cured and dried at the field by erection

company in accordance with the refractory manufacturers’

recommendations to assure that the actual performance of refractory

37



shall meet our requirements.

2.4. BOILING OUT

2.4.1.General

Boiling out is the process of internally cleaning for the removal of oil

and grease, and the solvent usually consists of a strong alkaline

solution.

The presence of even very thin films of oil or grease or their

decomposition products on the boiler heating surfaces will seriously

retard heat transfer. This film acts as a dangerous heat insulating film

and retards the rapid transmission of heat from the metal to the boiler

water. The resultant increase in metal temperature may be sufficient

to cause overheating and blistering of boiler tubes and ultimate

failure at high loads.

During the boiling out process, the gage glass may become badly

discolored and permanently etched. We have supplied replacement

of mica and mica repair kit, Our suggestion is that Restore the

inoperable gage glass to its original condition after boiling out and

chemical cleaning, and before the next filling of the unit with treated

condensate. The gage glass manufacturer’s instructions should be

consulted for the identification and the replacement procedure.

The chemical should be dissolved in water before being added to the

boiler and should never be added to the boiler in solid form. In

handling caustic materials, care should be exercised to avoid contact

with the eyes, skin or clothing. When mixing this material, it is

recommended that goggles, rubber gloves and cotton clothing be

employed.

The chemical solutions should not be added to the boiler in high

38



concentrations through the regular chemical feed system since these

high concentrations may plug the chemical feed piping and valves.

If the boiling out chemicals must be injected to the boiler drum

through the chemical feed system, the concentration should be

reduced to a five (5) percent solution in the mixing tank ahead of the

chemical feed pump suction, and the pump and chemical lines be

flushed thoroughly after the pumping is completed.

2.4.2.Recommended Chemicals for Boiling Out

Alkaline chemicals such as soda ash and caustic soda are commonly

used for boiling-out a unit since these agents possess the ability to

saponify the oils and greases and form a soap compound that is

easily removed by high pressure blowdown during the boiling out

process, and after completion of boiling out, by flushing with a high

pressure hose using cold water.

Phosphate has also been used as an agent to provide thorough

cleaning of internal boiler surfaces. Both trisodium phosphate and

disodium phosphate, accompanied by either caustic soda or soda

ash, have been used. In this connection, an embrittlement inhibitor

has been used in the boiling-out solution.

It is known that intercrystalline cracking ( caustic embrittlement ) has

been caused by the caustic soda used during the relatively short

boiling out period. the alkaline concentrations developed in the boiler

water during boiling out are quite high in comparison to standard

boiler water concentrations. It is safer practice therefore, to add an

adequate concentration of an embrittlement inhibitor to the boiler

water. Sodium nitrate is the preferred agent for this purpose.

For the most effective removal of oil from boiler metal surfaces, it is

recommended that a“wetting agent”be incorporated in the boiling out

39



mixture. These agents increase the“wetting power”of the water by

reducing the surface tension and therefore reduce the adherent

characteristics of oils and greases to a minimum. The combination of

a “wetting agent”along with the regular boiling out chemicals will

therefore break down the oil-sludge bond and remove the oil and

grease from the metal surfaces.

The following chemical dosages have proven successful on many

installations and will clean a unit satisfactorily. The proportions of

each chemical should be accurately weighed before being placed in

the mixing tank.

The chemical charge should consist of the following proportions:

Trisodium Phosphate (crystalline) 5.25 1g/1kg of water

Soda Ash 1.0 1g/1kg of water

Sodium Nitrate 0.15 1g/1kg of water

Wetting Agent 0.10 1g/1kg of water

Refer to Item 1.10 for the amount of water required for normal filling

of this unit.

If trisodium phosphate is not obtainable, it is permissible to substitute

disodium phosphate (anhydrous); however, the weight of this

chemical should be based on 2.5g/1kg of water.

NOTE

The following procedure is based on the assumption

that a trisodium phosphate solution (Na3PO4-12H2O)

will be used.

2.4.3.Preparations for Boiling Out

Prior to boiling out a steam generator, the items previously outlined

under“Safety Precaution”and“Drying Out”should be consulted and

40



followed. Generally, drying out and boiling out are combined as one

continuous operation.

A careful cleaning and inspection of the interior and exterior surfaces

of the boiler and auxiliaries should be made for the purpose of

removing all scrap metal, borings, wood, tools, rags and other

miscellaneous materials. It is very important that these material be

removed before the boiling out, otherwise, foreign material in the

interior boiler sections is likely to interfere with operation of blowdown

valves and future operation of the boiler.

No attempt should be made to set safety valves when the boiler

contains water of high chemical concentration such as that used for

boiling out purposes. The safety valves should be set when the boiler

contains water of approximately normal concentration during the

initial start-up phase.

NOTE

Initial charging of bed material can be accomplished

before or after boiling out.

a. If beds are to be charged at this time, add bed material, in accordance

with procedures specified in Section 3, Paragraph 3.3.

When workman enter the furnace, proper precautions must be taken

including:

(1) Station a second workman by the furnace access door to

observe the progress of work and immediately advise plant

personnel of any problems.

(2) All fuel and limestone feed equipment and fans should be

secured and tagged“Out of Service - Men Working in

Furnace”.

41



(3) Anyone entering the furnace should be provided with proper

breathing equipment and eye protection as is required for a

dusty environment.

(4) The furnace should be cool, well ventilated and tested,

utilizing normal industry standards, for proper air constituents

before anyone enters it.

b. Open the vent valves indicated in the list within Paragraph 3.3. so that

air can be expelled as the boiler is being filled. Isolate gage glasses,

remote level indicators, pressure connections, sensitive

instrumentation and anything that could be damaged during boiling

out. Filling the unit should be accomplished using the feedwater

pumping and piping system normally used during boiler operation.

This will have a tendency to flush out the piping and auxiliaries ahead

of the boiler.

c. Inject chemicals into the boiler feed line downstream of the main feed

pump but upstream of the economizer. A main feed line piping drain or

economizer drain connection may be used for this purpose.

NOTE

Chemical injection should be carried out only when

main feedwater is flowing. Also, injection must be

completed well in advance of reaching the desired

drum level so that the chemicals in the boiler feedpipe

will be flushed out during the final stages of the boiler

fill cycle.

d. Raise the water level so that it is just visible in the bottom of the lower

gage glass.

e. When the desired steam drum level is reached, close boiler feedwater

42



flow control by-pass valve.

NOTE

At this point, all steam drum valves, with the exception

of instrument connections and vents, should be closed.

2.4.4.Boiling Out Procedure

a. Start the induced draft and combustion air fans in accordance with the

fan manufacturer’s instructions and in the sequence outlined in

Section 3, Start-up Procedures.

b. Purge the boiler in accordance with Section 3, start-up procedures.

c. Set the combustion air damper to maintain sufficient air flow to the

under-bed burner.

Establish stable firing at the burner fire rate.NOTE

To protect the drum from undue thermal stress, the

metal differential temperature between the top and

bottom of the drum should not exceed 50 . Monitor ℃

this temperature differential during start-up and normal

operation.

e. Close the steam drum vent valves when boiler pressure reaches

0.1MPa.

f. Continue to fire the under-bed burner or feed coal into the furnace

until the steam drum boiling out pressure reaches the value

corresponding to the design pressure for this unit. (See Figure 2。1).

g. The boiler feed pump must be kept available for operation should

make-up feedwater be required.

h. Fire the under-bed burner or feed coal into the furnace intermittently

43



as required to maintain steam drum boiling out pressure for at least

eight (8) hours.

i. Raise the water level to approximately 50mm from the top of the gage

glass.

j. When the high water level and steam drum boiling out pressure have

been reached, shut down the under-bed burner or interrupt coal

feeding.

k. Start blowing down each blow-off line by opening the drum mass

blow-off valve, furnace lower waterwall header drain valves. It is

recommended that, when blowing down these lines, the root valve

(closest valve to boiler) be opened first and closed last. The second

valve in the line should be used to control flow. A sufficient blow can

be accomplished by spinning the valve open and then spinning it

closed again (approximately 10 seconds.)

l. A cooled sample from the drum should be checked for phosphate, pH,

silica and total alkalinity and a record kept of the chemical

concentrations.

m. If the water in the steam drum falls to within 50mm from the bottom of

the gage glass, refill the steam drum and fire the under-bed burner or

feed coal into the furnace to maintain steam drum boiling out

pressure.

n. Repeat steps k and l once every four (4) hours for at least 24 hours

until all signs of oil have disappeared from the cooled boiler water

sample. Repeat step m. as required.

After boiling out, When the boiler has been cooled and drained, the

drum(s) should be inspected and any sediment removed. If the

quantity warrants, inspect headers. Where inspection nipples are not

provided on headers, inspection may be accomplished by cutting a

44



feeder or riser tube at the stub and bending the tube out of the way. If

any foreign material is found in a header, It can be removed

manually or flushed with a high pressure water hose. In addition to

checking for sediment, inspection should assure that the metal

internal surfaces are free from oil adherence.

After the drum and headers have all been cleaned and inspected,

the unit can be closed. New manhole gaskets should be installed on

the drum and inspection nipple caps or tubes cut for cleaning and

inspection should be replaced.

2.5. FEEDWATER AND BOILER WATER TREATMENT

Feedwater and boiler water samples must be inspected to meet

desired water quality requirement.

The quality of feedwater should be in compliance with section 1.1.9

the high pressure water quality. The treatment of feedwater and the

conditioning of boiler water are beyond the control of HBG.

Therefore, HBG shall not be held responsible for damage due to

formation of scale or deposits or caustic embrittlement caused by

chemical conditions of the water. Sludge accumulations in tubes will

impair heat transfer and resulting in overheating and will affect boiler

performance.

2.6. CHEMICAL CLEANING OF ECONOMIZER AND STEAM

GENERATING CIRCUITS

2.6.1.General

The cleaning of modern high duty steam generators with chemical

solutions is an effective tool. A cleaning performed prior to initial operation

or a very short time thereafter, for the purpose of removing mill scale,

provides a thin, uniform protective coating of iron oxide and removes, from

45



the unheated portions of the system, much material that may be

redistributed to the heat transfer areas. There is merit to postponing this

type of cleaning until after some short period of operation as considerable

iron oxide and silica-bearing materials may be carried into the steam

generator from the feedwater and condensate system during initial

operation, unless the feedwater and condensate system are also

chemically cleaned.

The need for removal of operational deposits will vary considerably

from plant to plant depending on the type of feedwater used and the

history of make-up and feedwater problems. Because of the wide

variety of materials that make up operational scales, their removal

may be much more complex than the removal of mill scale. No steam

generator can operate dependably if the heat transfer surfaces are

fouled with scale.

2.6.2.Determining the Need for Chemical Cleaning

The need for a pre-operational cleaning will depend primarily on how

much rusting of all cycle components can be expected to take place

during construction. Factors influencing this are storage precautions

and weather conditions at the plant site. Much rust, loose mill scale

and silica-bearing material will be removed from the steam generator

during the alkaline boiling out which should be performed on every

unit. If the rest of the cycle is not extensively cleaned, material will be

carried into the steam generator and cleaning may be warranted.

Deposits formed during operation can be quite varied and complex

and the maximum tolerable amounts are difficult to establish. Tube

samples should be removed from the unit on an annual or biannual

basis and the deposit weight measured. Generally, without reference

46



to the specific deposit composition, a unit with 20 to 40 mg/cm 2 of

deposit on the cold side of the furnace tube should be considered

dirty enough for chemical cleaning at the next maintenance outage.

2.6.3.Solvent Systems

Solvent selection is made on the basis of two primary considerations.

The first is compatibility with the materials of construction and the

second is the suitability for removal of the deposits. The two are not

independent of each other since dissolution of deposit material by

the solvent may create corrosion conditions for a tube material that

would not be attacked by the solvent in the absence of the deposits.

Mineral acids, such as hydrochloric acid, are commonly used as the

solvent base for mill scale or operational deposit removal. If copper is

present in the deposits, complex agents must also be used, as

copper will plate on the boiler surfaces in the acid solution. Solution

strength will depend on the deposit analysis, weight and structure.

When using hydrochloric acid for a pre-operational cleaning, the

following is commonly used:

Hydrochloric acid concentration 5% max. by wt.

Metal or solvent temperature 68℃

Solvent contact time 6 hours

Inhibitor concentration Per cleaning contractor spec.

Organic acids, single or in mixture, and in combination with various

other materials are also used as solvents. While they generally are

less aggressive than the mineral acids, proper inhibition and

preliminary testing are still a necessity. In addition, because of the

lesser dissolving capacity of the organic materials, some means of

circulation within the unit may be required to insure against local

depletion of the solvent before the deposits are completely dissolved.

47



2.6.4.General Cleaning Operations

Chemical cleaning of a steam generator should never be attempted

by inexperienced personnel. There is danger of extensive damage

should conditions get out of hand or improper materials be used.

Careful planning is required to assure that the specified chemical

conditions are attained, that conditions hazardous to life and property

do not occur.

To bring the unit to cleaning temperature, the unit may be filled with

condensate or demineralized water and heated by one of themethods specified in paragraph 2.2. Using drum thermocouples, and

temporary thermocouples if necessary, monitor unit temperature to

assure that there are no areas above the limits for the solvent system

and inhibitor used. The limits must be specified by the solvent

system supplier. When the proper temperatures are attained, the

water may be drained to storage.

The unit is then filled with solvent by pumping the stored heated

water back into the unit and metering in the concentrated solvent to

give the desired concentration. Before the solvent pumping is

started, it should be checked for proper inhibition. If the water

temperature must be adjusted while refilling the unit, steam should

be injected ahead of the solvent to avoid corrosion of the mixing

equipment.

NEVER FIRE THE UNIT WHEN IT CONTAINS ACID AS INHIBITOR

BREAKDOWN MAY OCCUR.

While the solvent is in the unit, the acid strength, iron concentration,

temperatures and any condition or constituent necessary for control

of the particular solvent system should be monitored on a regular

basis. When the cleaning is complete, as indicated by the leveling of

48



the iron concentration, the solvent is drained from the unit under a

nitrogen blanket.

The unit may be filled and drained one or more times to flush the

solvent from the cleaned area. The rinse may contain an iron

complex agent to prevent precipitation of iron on the cleaned

surfaces.

When the rinsing is complete, the unit is filled with an alkaline

solution to neutralize any residual solvent and passivate the surfaces

to prevent after-rusting. The alkaline solution may be heated prior to

filling the unit or the unit may be heated as in paragraph 2.2 to attain

the desired temperature.

Upon completion of the passivation, the unit should be drained for

inspection and removal of any temporary piping .

2.7. CHEMICAL CLEANING OF SUPERHEATERS

2.7.1.General

Chemical cleaning of superheaters may be performed in those cases

where, because of particular cycle requirements, the operating

company elects to do a pre-operational cleaning or where an upset

operating condition creates deposits which must be removed.

The same general precautions regarding suitability of solvents and

compatibility of solvents with materials of construction, as required

for steam generation circuits must be observed.

Many superheaters contain sections that are either non-drainable or

non-ventable. This prevents a cleaning from being done by a fill and

soak method. To assure that all tubes can be filled with solvent and

then flushed successfully, all air must be purged from the circuitry

prior to introduction of the solvent. This may be accomplished by

49



pumping water at high flow rates or by purging with low pressure

steam. The former method requires such high flow rates that, for any

but the smaller units, it is impractical. Steam purging for several

hours, followed by filling with hot water, in a manner to preclude entry

of air, and then displacement with solvent will permit a circulation

type cleaning with moderate pumping requirements.

2.8. STEAM-LINE BLOWING

2.8.1.General

Solids, such as scaling in the pipe, which is carried by steam

with extreme high velocity, can cause severe damages to the

blades and valves of turbine. Normally, need install a filter at the

inlet of the turbine and blow the superheater and the steam

piping before the first operation of the turbine. Steam-line

blowing is to clean all the solids in the pipe which will do

damage to the blades and valves of the turbine (ferric ironoxide, rolling skin and some other external articles)Acceptance

gage

According to the acceptance goal value and the sampling of the

steam purity, which are the two successes, consider the steam

piping as purity.Prerequisite

a. Having continuous supply of feed water to make-up water lost in the periodof the steam purging.Check of electric drawings

b. Check of the duct pilot layout drawings

c. Finish the check of the meters

d. Test of the safety chains

e. Set and check the safety valves

f. Have finished the test of the boiler and all auxiliaries

g. Install the temporary purging piping, purging valve and silencer, also the

50



check and pressure test

h. Strike all the temporary scaffolds, devices and some other unnecessary

equipments in the area of steam purging

2.8.2.Initial condition

a. Continuous communication has been established between device

operators, field persons and the master-control room

b. When the boiler runs in the condition which has lower steam pressure and

lower temperature for 5%-10% than required, the boiler and the

assistant system is steady. The required steam purging power is

determined by the following formula: R=(W/ Wr )2V/Vr( R: steam

purging power W: steam flow during the period of steam purging Wr:

the designed steam flow V: the specific volume in the inlet of the

superheater during the period of steam purging, is expressed by

cubic feet/pound). If we apply continuous purging method, R should

be 1.5—1.6 and for impulse or intermittent purging R should be 1.0—

1.2. Because the thermal impact and dynamic force generated by thefast variation of the steam condition ( pressure and temperature )

accelerates the purging progress, intermittent method is better than

continuous method.

c. All valves on the steam piping, until all the temporary steam purging valves

is opened, all piping have been blowd and been preheated

d. Warning limit should be set in the adjacent area of steam purging and

temporary piping, and suspend the standards to prevent people enter

this area

e. All adjacent people have been informed

2.8.3.Precaution and matters need attention

a. Piping arrangement. The arrangement of the temporary piping should be

convenient to the purging of all steam piping located in the lower

51



course of the boiler. All the temporary piping nozzles and valves

should have the same dimension as the piping need purging so as to

prevent the reduce expenditure. The temporary pipes which are used

to emit to the air should be consolidated so as to stand up with the

strong reacting force generated by the nozzles during the period of

ejecting. Purging should have only one direction to avoid hurt of

people or damage of objects which may cause by the carried material

with extreme high velocity. Whether silencer will needed depends on

its position and the silencer should be selected to meet the condition

of low pressure loss and high velocity. According to the cleanliness

the system, collectors and filters may need in the upper course of the

silencer to prevent blockage. The temporary piping should also

include the drain joints located in the low point and the upper course

of the purging valve. The outlet is used to heat and discharge

condensate liquid for the steam piping during the interval time of

steam purging. Also the safety valve may be needed for overpressure

protect, this depends on the pressure limit condition of the temporary

piping. All temporary piping near the work area should be isolated for

personal safety.

b. Valve. All selected temporary purging valves should have the function of

intermittent purging according to the high velocity. The steam valve

should be the type of quick-open and should have the remote control

structure which is suitable for this function. The steam purging valve

is not a part of the permanent system and this type of valve will be

damaged. The gate valve for hydraulic operation can open(about 3

seconds) or close(about 10 seconds) quickly. The purging valve

should be installed in the upper cause of the silencer

2.8.4.Procedure of steam purging

a. Rising pressure according to the normal pressure-rise curve and the

52



marked condition to metal temperature and stop it until reach the

purging pressure. The purging pressure can be determined by

calculation of purging force.

b. When rise pressure, heat the temporary steam piping by the drain joint

located near the temporary steam purging valve

c. Set the water level a little lower than the normal level and then shutdown

the start-up burner

d. Open the steam purging valve quickly. When open the purging valve,

because the pressure of the steam drum falls down, the water level of

the steam drum will rise instantly and then falls down soon. Because

of this, the water level controller of the steam drum should be in

manual position. By doing this, when the operator can increase feed

water manually the moment he notices the falls of the water level of

the glass tube

e. Try your best to maintain the normal water lever, shutdown the steam

purging valve as soon as reaching the predetermined purging time.

The actual purging time is determined by the variation of the boiler

pressure and the water level of steam drum

f. In order to assure the water level of the steam drum be a constant, the

amount of feed water should be adjusted. When the purging valve is

shutdown, the water level of the steam drum will fall down

g. All piping which has been blowd should be drained

If necessary, do all the procedures again till the cleanliness is acceptable

2.8.5.Return to the raw condition

a. According to the requirement of liability, please make sure that the boiler

can generate steam

b. Isolation is for the temporary joints of the steam piping

c. Make sure that all temporary joints be drained, cooled and striked

d. Recover the piping and valves of the permanent devices to their raw

53



condition.

2.9. BOILER SYSTEM AIR TEST

Upon completion of erection, an air test shall be performed to detect

any air and flue gas leaks in the boiler system. The leaks shall be

corrected to insure tightness and the safe operation of the system. A

typical recommended procedure is as follows:

a. Install a blanking plate at the ID fan inlet.

b. Close all access doors and observation ports.

c. Cap all instrumentation penetrations.

d. Open all passageways to be tested.

e. Operate the FD fan to pressurize the system to 80mmH2O pressure.

f. Inspect entire system using suitable visual/audio method. Soap films,

smoke bombs and sonic detectors are useful and one or more should

be employed.

g. Identify all leaks.

h. De-pressurize system.

i. Repair all leaks.

j. If leaks were found, repeat the air test following leak repair.

k. Remove blanking plates and caps.

54



3. OPERATION AND MAINTENANCE

3.1. GENERAL

a. The operator should be thoroughly familiar with the function and

controls of the boiler, components and auxiliary equipment before

operating the unit. The information given in this section is not intended

to be a detailed procedure for operation of the steam generator but is

meant to serve as guide. This guide, together with the instructions of

the auxiliary equipment and with knowledge derived from initial unitoperation, can be used to develop a detailed operation procedure.

b. Circulation fluidized bed boilers are chemical process reactors,

without a defined fireball. The boiler fireside contains a circulating

solid inventory of considerable thermal energy.

c. The operator should be aware of the limitations imposed on the

various parts of the boiler and its auxiliaries and be alert to the actualoperating conditions during start-up and while operating per system

demands.

d. The boiler can be operated at a maximum continuous rating (MCR) of

130t/h superheated steam at 510 and 100bar(g) at the superheater ℃

outlet with feedwater entering the unit at 170 while firing the fuel℃

specified in Item 1.1.3.

3.2. GENERAL PRECAUTIONS

The Critical precautions that the operator must observe and exercise

during all phase of operation of this unit are listed below.

a. All doors at lower furnace must not be opened during normal unit

operation to protect personnel from any danger as this steam

generating unit will have internal pressure greater than atmospheric

55



pressure.

b. Furnace Pressure Limits

Exposure to excessive negative or positive furnace pressure canresult in serious damage to the unit and auxiliary equipment.

The following controls should be in service and operable prior to

start-up for protection against excessive furnace pressure or draft.

1. The furnace draft, as measured at the balance point in the

furnace exit, should be monitored constantly and automatically

controlled to be between -130。

250Pa.

2. The Main Fuel Trip (MFT) should be set at ±2500Pa pressure

in the furnace outlet (cyclone inlet) with a 5 second delay.

3. The FD and ID fan trips should be set at ±3750Pa pressure in

the furnace area with no time delay.

On any Main Fuel Trip (MFT) the following occurs:

(a) Fuel feeders trip.

(b) Limestone systems trip.

(c) under-bed burners trips.

(d) Bottom coolers trip.

(e) All air flow controls transfer to manual mode and hold last

position.

(f) FD fan controls transfer to manual mode and hold last

position unless the cause is a fan trip. In that case, fan

controls follow fan logic.

(g) Output signal to combustion control limits ID fan automatic

control from going above the furnace draft limit.

56



(h) “Boiler Purge Required”logic is set unless it is a“Hot

Restart”condition.

4. The operator should not allow the furnace pressure at the

balance point to exceed ±500Pa (alarm point).

5. On loss of FD or ID Fans or all J valve blowers (MFT will be

initiated), the bed will collapse and the collapsed bed may

contain combustibles. Access doors should be left closed. Air

flow should be slowly re-established to purge combustibles

from the unit.

NOTE

At all times, the operator should remember that the unit

maintains a considerable amount of stored energy even

following an MFT. Drum level and an adequate flow of

steam to control pressure should be maintained at all

times.

c. Drum Water Level and Temperature Differential

The normal drum water level is 180mm below the centerline of the

drum. The alarms are set at 75mm below and 75mm above normal

water level and the trips are set at 120mm below and 120mm above

normal water level.

NOTE

A low low drum water level condition (120mm below

normal water level) or a high high drum water level

condition (120mm above normal water level) initiates a

main fuel trip (MFT) and the FD and ID fans are tripped

57



to protect the drum from undue thermal stress; the

metal temperature differential between top and bottom

of the drum should not exceed 40 . The drum metal℃

temperature should be monitored and indicated in the

control room.

d. Safety Valve Adjustment

All safety valves are set by the valve manufacturer but should be

rechecked under actual operating conditions as the boiler is being

brought up to pressure during initial operation. If a safety valve does

not lift at the pressure stamped on its nameplate or reseat properly,

the valve should be readjusted. It is not allowed to change the

settings of any safety valve without authorization.

e. Excess Air Requirement

Care should be exercised to ensure that the proper fuel-air ratio for

good combustion is maintained. The excess air requirement at 100%

MCR load is measured at the HRA outlet and corresponds to an

oxygen measurement of approximately 3.1% by volume on a wet

basis. (See Figure 3-1.) It is just for reference and should be set by

combustion adjustment. Operation with less than the specified

excess air can be detrimental from the standpoint of good

combustion and safe operation of the unit.

f. Bed Temperature Profile

Normal operating bed temperature is 790 。 920 (measured by℃

thermocouples on the grid plate). This temperature should be

monitored during operation and attempts should be made to operate

at this level. The bed high temperature alarm point is 955 . A main℃

fuel trip is automatically initiated at 990 . The minimum operating℃

temperature for the bed is 790 . Do not allow temperature to drop℃

58



below this level without support fuel. The low bed temperature alarm

is 760 . A main fuel trip is automatically initiated at 650 unless℃ ℃

the under-bed burner is in operation. The solids fuel feeds will

automatically trip off line if the bed temperature drops below 540℃

regardless of burner operation.

g. Cyclone Tube Protection

If the unit experiences a trip, steam temperatures in the cyclone

tubes may tend to rise rapidly. Thermocouples have been installed

on cyclone wall tubes to monitor these temperature rises and

transmit them to the control system. If any one of these

thermocouples rises above 420 , the control system automatically℃

opens the cyclone cooling steam vent to increase the cooling steam

through the cyclone tubes. The vent then automatically closes when

all of the thermocouples show temperatures below 410 .℃

h. Readiness Inspection

The following precautionary steps must be taken to insure reliable

operation of the unit:

1. It is recommended that the heat recovery area (HRA) gas side

surfaces be inspected for particulate deposit accumulation each

time the boiler is taken out of service. The surfaces should be

cleaned accordingly before boiler restart if any serious

particulate accumulation is detected.

2. For purposes of monitoring start-up conditions during the life of

the boiler, thermocouple assemblies are installed in various

locations in the steam generating circuit. These thermocouples

are to be used as an aid in determining acceptable firing rates

during start-up. The thermocouples are located as follows:

59



Thermocouples Location Total

Qty

Alarm Limitation

Steam Temp.

Steam Drum Top & Bottom 8

SH Wing Wall Outlet Tubes 1 500℃

Low Temp SH Outlet Tubes 1 450℃

High Temp SH Outlet Tubes 1 535℃

These thermocouples are located in a zone where flue gas does not

sweep over them; therefore, the temperature obtained will be equal

to the steam temperature. These and other thermocouples should be

checked and made ready for service (including control room

indications).

The unit can be operated continuously up to the steam temperature

limits indicated in the table above. To protect the equipment, the

operator should correct any condition which has caused an alarm.

In addition to the thermocouples mentioned above, there are 8

thermocouples per cyclone, 4 upper and 4 lower in left cyclone and 4

upper and 4 lower in right cyclone. All are located at equidistant

points in the roof tubes near the top ring headers and at equidistant

points in the gas-heated hopper tubes near lower ring headers.

There are also four (4) thermocouples in transfer pipes between the

right cyclone outlet and the HRA inlet.

3. To prevent plugging, rusting and oxidation and faulty operation

of equipment, air used on the boiler for operational purposes,

whether for sealing, aspirating or atomizing, should be free of

dirt, oil and water.

4. All high and low furnace pressure safety interlocks should be

checked for proper values and correct switching action and be

60



in service before starting the induced draft fan.

5. The sootblower system should be ready to operate. The

sequence of operating the sootblowers should be from down to

up ,then from top downward as a sootblow circulation.

Eight(8) couples of sootblowers are installed in the HRA as shown in

the following listing, on both side for low and high S/H and air-

preheater, on rear side for economizer.

LOCATION TYPE ELEVATION QUANTITY

High Temp. S/H Long retracting 35700 2

Low Temp. S/H Long retracting 32630 2

Economizer IV Rotary 28740 2

Economizer III Rotary 25930 2

Economizer II Rotary 23030 2

Economizer I Rotary 20130 2

Air-preheater II Rotary 13400 2

Air-preheater I Rotary 10650 2

6. Oxygen (O2) is monitored continuously during operation of the

boiler. O2 levels should not fall below 3.1%, by volume on a wet

basis. It is recommended that the O2 analyzer be properly

maintained and calibrated before any start-up and on a regular scheduled basis, as dictated by industry standards. O2

controller should hold last value when calibration is in progress.

7. It is strongly recommended that the reliability of all drum level

indicators be checked at least once a shift. This would include

all gage glasses, remote level indicators and level recorders.

This can only be done by changing drum level and observing

61



the response of all indicators and gage glasses.

8. The furnace bed fluidizing velocity should not be allowed to

drop below 1.2m/sec (minimum velocity required to maintain

proper fluidization). Refer to Figure 3-2.

3.3. COLD START-UP PROCEDURE

The operating sequence recommended to ensure a safe and proper

start-up is given below. Modifications may be necessary as

subsequent operating experience dictates. Follow the manufacturers’

instructions for operating auxiliary equipment.

3.3.1.Preparation Prior to Start-up

NOTE

A general unit equipment patrol should be made by at

least two (2) people to verify that all equipment is ready

for start-up. See Paragraph 3.3.2 for initial bed charging

criteria.

a. Operation of the Pressure Tap Purge System

The pressure tap purge system should be put into operation.

Establish a low flow of air through the pressure taps into the bed.

Periodically, the pressure taps should be manually purged with a

blast of high pressure instrument air. The frequency of this purging

must be established by experience. Always close the appropriate

valves to protect the purge system’s instrumentation when the high

pressure purge is to be performed.

A similar procedure should be used for all other pressure taps on the

air and gas side of the steam generator.

b. Make sure the test gags and/or plugs are removed from all safety

62



valves.

c. Check availability of utility services, power, ignition and main fuel, and

suitably treated feedwater.

d. Check operation of all valves and dampers.

e. Check the start-up (under-bed) burners and all boiler auxiliaries,

assuring that all are operable and that associated valves are in their

proper open or close positions.

f. Check availability of thermocouples in representative locations to

measure steam drum metal temperatures.

g. Close all access doors and observation ports after it is proven that no

one is inside the unit. Release all safety tags on equipment to be

placed in service.

h. Place the boiler vent, drain and instrument valves in the following

position. This list assumes the unit is empty.

VALVE DESCRIPTION POSITION QUANTITY

(PER BOILER)

Steam Drum Safety Valve Set at 118.9 bar 1

High temp SH outlet Safety Valve Set at 105 bar 1

Main Feed Stop Valve Closed 2

Main Feed Check Valve Automatic 1

Drum Steam Connection Vent Open 2

Drum Pressure Transfer shut-off Open 3

Drum Water gage Shut off Open 14

Drum Chemical Feed Closed 1

Drum Emergency Drain Closed 2

Drum Continuous Blowdown Closed 2

Drum Water Sampling Closed 2

Drum Pressure Instrumentation Valve Open 2

63



Drum Steam Sampling Closed 2

Drum Auxiliary Steam Shut-off Closed 1

Downcomer Drain Closed 4

W/W Lower Header Periodic Blowdown Closed 12

Left Cyclone Upper Header

Cooling Steam Vent

Automatic 2

Cyclone Lower Ring Header Drain Open 4

HRA Front & Rear Wall Upper header Vent Open 4

HRA Front Wall, Rear Wall, Side Wall

Lower Header Drain Open 4

SH Wing Wall Inlet Header Drain Open 2

SH Wing Wall Outlet Header Vent Open 2

High Temp SH Inlet Header Drain Open 2

High Temp SH Outlet Header Vent Open 2

Main steam pipe Outlet Pressure

Instrumentation Connection Open 1

Attemperator moterized Shut-off Closed 2

i. Fill the boiler by admitting water, via By-pass Feed Control Valve, to

the economizer using water from the regular feedwater source.

j. The temperature of the water should be between 20℃ 。 70 and℃

should not be below the temperature of the drum metal. Close the

vent valves as each vent shows water flow.

k. Check that the drum remote level indicators are operating in the

control room and that they compare accurately with local gage glass

readings.

l. Check that all pressure and draft gages are calibrated and functioning

properly.

m. Check all safety interlocks for proper operation.

64



n. Verify that drum level is visible in the gage glass.

o. Check that all lubricating and cooling systems for all driving facilities

meet the manufacturers’ technical requirements and all cooling

mediums are available for equipment that requires cooling.

p. Position dampers in the air ducts and gas flues as indicated below.

Damper positions are displayed in the control room. All fuel,

limestone and other manual isolation and / or slide gate dampers

should be closed at this time.

65



DAMPER DESCRIPTION POSITION

ID Fan Inlet Vanes Open

Primary and Secondary FD Fan Inlet Vanes Open

Limestone Inlet Closed

Upper Secondary Air Open

under-bed Burner & Furnace Fluidizing Air Open

J-Valve Upleg and Downleg Fluidizing Air Open

J-Valve Bottom Fluidizing Air Open

Lower Secondary Air Open

Fuel Sweep Air Open

Fuel Feeder Seal Air Open

q. The following operation sequence is recommended to ensure safe

and proper start-up. Modifications may be necessary as subsequent

operating experience dictates.

3.3.2.Purging

Note

Prior to purge (and firing of under-bed burner ), it is

essential that an internal inspection of the combustion

air duct, downstream of the under-bed burner, and the

plenum, be made for back sifting of bed material. All

bed material should be removed from the duct and

from the plenum, to preclude grid nozzle plugging.

Immediately prior to each start-up and prior to starting

after a main fuel trip (MFT), the furnace, cyclones and

HRA must be purged (except the special procedure for

hot restart ). The following steps must be taken to

66



prepare for the purge.

a. Ensure that no hot start condition exists (average bed temperature

less than 650 ).℃

b. Ensure that boiler is in MFT but no MFT conditions exist.

c. Ensure that the fuel supply valve to the under-bed burner is closed.

d. Check that all limestone fuel feeders are off and spent bed removal

system is off.

e. Start the induced draft (ID), forced draft (FD) and one J-Valve blower

as follows:

CAUTION

THE FOLLOWING PROCEDURE PROVIDES FOR A

CLEAR AIR FLOW PATH FROM THE FD FAN INLET TO

THE STACK DURING START-UP OF EACH FAN TO

PREVENT POSITIVE OR NEGATIVE PRESSURE

DAMAGE TO THE FURNACE AND DUCTWORK.

NOTE

The general procedure will be to start one (1) J-valve

blowers, the ID fan , the Primary and Secondary fan. Air

flow is then set to purge requirements and all fans put

on AUTO control. Purging will be accomplished and

fans will be left in operation for subsequent start-up.

1. Ensure that all flue and duct dampers are in the positions specified in

Paragraph 3.3.1, Step p.

2. Start one J-valve blowers. Set the J-valve aeration rates to correspond

67



to those values listed in attached table 6 and fig.3-8 for each J-valve.

J-valve operation is automatically controlled by a program input to the

system in the pre-commissioning stage. Adjustment of air flows to the

various aeration taps should not be necessary during unit operation.

However, J-valve operation should be monitored closely for

abnormalities following start-ups or upsets.

Verification of proper operation or minor adjustment of aeration flow

rates should be performed in accordance with the following:

(a) Refer to Table 1, Fig.3-5 Fig3-6 and Fig.3-7 for proper operating

parameters.

(b) Place J-valve upflow and downflow plenum air flow controls on

auto.

(c) Place J-valve blower pressure control valve on auto and check

that it is properly functioning.

(d) Set shut-off valves to individual aeration taps to a 65% open

position.

(e) Place upflow leg and downflow leg aeration flow control on

auto.

(f) Confirm flow in individual aeration tap lines.

A no-flow indication in any line may be plugging of the tap. Correct or

establish a clear line by a high pressure air purge. Do not attempt to

mechanically rod out the line with the unit in service.

(g) Record aeration air flow rates, and J-valve temperature and

compare to Table 6.

(h) Air flow rates that vary widely from values given in Table 6

should be adjusted to agree. Switch to a manual aeration

mode. Adjust air flow towards the tabulated value in 14Nm 3/h

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increments while recording pressure differentials. Set air flow at

lowest stable pressure differential.

(i) A unit shutdown will be necessary to clear plugged or

inoperable aeration taps as soon as possible. Continued unit

operation may be possible for a limited time provided the

inoperable or plugged aeration tap locations are known and that

horizontally or vertically adjacent taps are not plugged. Unit

shutdown is mandatory to avoid a plugged J-valve when

several taps are confirmed inoperable.

(j) Record J-valve aeration flows, pressures and temperatures at

unit loads of 40%, 60%, 80% and MCR. If necessary, perform

adjustment procedures as in step (h) above.

3. Start the ID fan. The ID fan inlet control vanes will close, the ID fan

breaker will close and the motor will start running. Once the motor is

proved running and up to speed, the inlet control vanes are released

to furnace pressure control.

4. Start the Secondary and Primary fan. The fan inlet control vanes will

close, the fan breaker will close and the motor will start running. Once

the motor is proved running, the inlet control vanes are released to

combustion control. However, the Secondary FD fan should be started

and adjust the air flow to minimum prior to start-up of the Primary FD

fan.

5. The control system will automatically adjust the unit to a“ready for

purge”condition.

f. Charge furnace beds with material as follows:

69



1. The furnace bed should be charged with bed material , either rough

limestone or burned material of 0。6mm size, to a static bed depth of

400mm. Stop charging when bed pressure indicates 3500Pa.

g. Purge the unit with at least 25% (but not greater than 40%) total air

flow for at least 5 minutes.

h. After the steam generator has been completely purged, reset the

master fuel trip (MFT) and perform the following:

1. All secondary air control dampers should be at minimum open

position.

2. Position the following equipment in the indicated positions:

(a) Position the under-bed burner and furnace fluidizing air (to

plenum) control damper for proper combustion air.

(b) Establish combustion air flow at a minimum of 26600Nm3

/hr by

adjusting FD fan inlet vanes.

(c) Ensure that there is a supply of fuel available to the under-bed

burner and that purge air to the scanners is on.

3.3.3.Warming The Unit

CAUTION

PRIOR TO LIGHT-OFF, THERE MUST BE BED

MATERIAL IN THE FURNACE EQUIVALENT TO A

400mm STATIC BED AND THE UNIT MUST HAVE BEEN

PURGED.

NOTE

70



the superficial fluidizing velocity should not be allowed

to drop below 1.2m/sec, the minimum superficial

fluidizing velocity required to maintain fluidization.

CAUTION

TO PROTECT THE DRUM FROM UNDUE THERMAL

STRESS, THE METAL TEMPERATURE DIFFERENTIAL

BETWEEN TOP AND BOTTOM OF THE DRUM SHOULD

NOT EXCEED 40 . MONITOR THIS TEMPERATURE℃

DIFFERENTIAL ON THE DRUM METAL TEMPERATURE

INDICATORS.

a. Check that between economizer inlet and drum recirculation shut-off

valves are open.

Close fully and then open 1/2 turn the following drain valves:

Cyclone Lower Ring Header Transfer Pipe Drains

HRA Front wall Lower Header Drains

SH Wing Wall Inlet Header Drains

b. Following the burner instructions, light-off the under-bed burner.

Observe the light-off via the observation ports for good flame quality.

c. In the manual mode, place limestone feeder systems in service at

minimum speed per instructions. Verify and monitor tracking and

movement of rotating equipment prior to and during start-up and

during operation.

NOTE

Bed make-up is added as necessary during operation.

d. Monitor the O2 to ascertain complete combustion is taking place.

71



Control mixture gas flue temperature below 900 .℃

e. Having confirmed light-off in the under-bed burner, place on automatic

temperature control at various cooling air rate.

f. Heat the bed material and raise the drum pressure. Mixture gas flue

temperature should be regulated to increase drum pressure and

temperature at a rate not exceeding 50 /hr.℃

g. While the unit is heating up and building drum pressure, check drum

metal temperature and drum level.

h. Raise the bed temperature to 450℃ while maintaining a combustionair flow of 26600Nm3/hr. During the heating of the unit, the drum level

will rise. Maintain the drum level within range using the continuous

blowdown valve and the feedwater control valve. It may be necessary

to use the emergency release valve in conjunction with the continuous

blowdown valve to maintain drum level.

NOTE

Under no circumstances should downcomer or water

wall drain valves be used as blow- off valves.

j. When the drum pressure reaches 0.69 。1.03bar, close the following

vent valves:

Drum Vents (On transfer pipes between drum and cyclone)HRA Front Wall Upper Header Vents

HRA Rear Wall Upper Header Vents

SH Wing Wall Outlet Header Vents

Main steam Outlet Header Vents (On transfer pipes

between High Temp. SH and Main steam Outlet Header)

k. Close completely the following drain valves:

72



Cyclone Lower Ring Header Drains

HRA Front Wall Lower Header Drains

SH Wing Wall Inlet Header Drains

High Temp. SH Inlet Header Drains

l. At this time, the drain valve(s) downstream of the main steam outlet

header should remain open to ensure that all water is drained from

the steam circuit.

m. After achieving approximately 1.7 bar in the drum, recheck the drum

water gage glass operation by a short blowdown. Maintain visible

water level in the gage glass. Water level in the drum will rise due to

swelling of water in the system. Blow down the drum as required by

opening the steam drum continuous blowdown and / or emergency

release valves.

n. Place the drum level control loop in automatic control in the single

element (drum level control) mode.

o.If the boiler water silica or solids contents is above the recommended

limit, the drum water should be blown down using the steam drum

continuous blowdown valve until the recommended limit is reached.

No further increase in pressure should be allowed until silica level is

below the respective pressure value.

p. Continue heating to build up boiler drum pressure and maintain bed

temperature of 450 . If necessary, feed limestone into the furnace℃

during warm-up to maintain bed inventory indicated by bed pressure.

3.3.4.Start-up (Fuel Firing)

The following procedure must be integrated with the boiler and main

steam piping, such that a flow path is maintained for the steam being

produced by the circulating fluidized bed boiler.

a. Place the ash handling system in service following the own

73



instructions.

b. Check that the spray control isolation block valves are open.

Place the steam temperature control loop on automatic with thedesired steam temperature setpoint.

c. Start three coal feeders and adjust to feed fuel into the furnace at 15%

capacity. Operate at this capacity for 5 minutes and then shut down

the feeder. Monitor O2 and average bed temperature (ABT) to

establish a trend over time. During the first several minutes, average

bed temperature should decrease initially and then start increasing.

O2 should remain steady initially and then begin to decrease

preceding average bed temperature rise. Establish a time interval

required to completely and safely combust the quantity of fuel just

fed. This time interval should be measured from the time of feed

commencement to the highest average bed temperature and lowest

O2. The time interval may be set by the field after having experienced,

but the duration may be changed with varying fuels. With some low

reactivity fuels coupled with varying unit designs, it may be necessary

to change the duration of batch feeding.

NOTE

Monitor individual bed thermocouples in conjunction

with the above procedure. A localized decrease in

temperature will usually be seen at the feed point with

gradual increases in temperature at adjacent

thermocouples.

d. Start the same feeder again at 15% capacity and batch feed fuel for

another 5 minute period. Shut down the feeder. Monitoring average

bed temperature and O2, restart the feeder at 15% capacity just prior

74



to reaching peak bed temperature. Add fuel for another 5 minute

period.

e. Repeat steps c and d gradually increasing average bed temperature

(ABT) to 760 . Once ABT and O℃ 2 are responding properly, the feeder

can be left in operation. Boiler load can then be increased by

increasing feeder capacity. As ABT increases, the combustion rate of

the batch feed fuel will also increase. This will actually cause a

shortening of duration time that the feed is left out of service. As the

feed rates increase, some caution must be taken not to overfeed the

unit. If the unit has been overfed with fuel, several indicators will

show disproportionate changes. O2 will decrease rapidly, perhaps to

zero. ABT will climb steadily in large increments. Several courses of

action can be followed dependent on the severity of overfed material:

1. Wait it out but do not introduce additional fuel; monitor the

trends.

2. Increase the limestone or bed make-up feed rates; this cooler

material will absorb the increased heat release.

3. Lower the air supply to the bed to starve the combustion

process.

f. As O2 continues to decrease and bed temperature increases to

790 , gradually begin increasing combustion air flow above℃

26600Nm3/hr and, at the same time, lower under-bed burner gas flue

mixture temperature to 540 . At this point, follow established feed℃

rates and air flow requirements.

g. Required superheat steam temperature should be maintained during

start-up by using the following:

The First and Secondary superheater attemperator inlet. It is

75



important that the steam temperature entering the superheater tubes

downstream of the spray be not less than 11 above saturation℃

temperature. See Figure 3-3for this limiting steam temperature.

h. When the proper steam pressure and temperature are available,

warm, roll and synchronize the turbine.

i. After turbine synchronization and after constant feedwater flow is

being maintained, or when the steam flow is greater than 7%, close

the economizer to downcomer recirculating shut-off valves.

j. As the amount of steam delivered to the turbine approaches 10% of

the steam generator rated capacity, close the drain valves

downstream of the H/T superheater outlet.

k. When conditions permit, put drum level, steam temperature and air

flow on automatic control.

l. Gradually increasing fuel feed rate, until bed temperature is above

830 and O℃ 2 is stable.

m. Adjust combustion air flow and fuel flow to establish bed temperature

of 900 while removing the under-bed burner; maintain O℃ 2 at 3.1%.

n. During normal operation, limestone feed rate will be varied, as

dictated by a ratio to the fuel feed. The ratio should be adjusted

according to the concentration of SO2 in exhaust gas.

As mentioned before, Figure 3-4 is a graph of static bed height

versus bed differential pressure and should be checked and cold-

tested prior to start-up or during trial operation. While firing the fuel,

the fluidizing velocity should not be allowed to drop below 1.2m/sec.

p. At this time begin operating the bottom ash coolers continually as

cooler instruction.

q. Unit load can now be raised to 100% (MCR) by using the boiler

76



master control. Observe the following guide lines:

1. Do not operate the bed at a differential pressure greater than

500mmH2O or less than 200mmH2O. The 200mmH2O limit is to

protect the grid tubes from overheating and bed material

fluidized from unstable.

3.4. HOT RESTART

The boiler may be shut down for a period of time and held in the hot

condition (slumped but ready to operate again). When the boiler is to

be hot slumped, the fuel feed should be stopped and the O 2 indicator

at the boiler exit monitored. As soon as the %O2 starts to increase,

stop the fluidizing air flows to the furnace to minimize bed heat loss.

This O2 increase indicates that most of the fuel has been burned and

the beds can be slumped by decreasing fluidizing air flows to zero.

the FD and ID blowers and the limestone feed system are stopped.

The J-valve blower should remain in operation after the fans and

other blowers are shut down.

NOTE

To prevent damage to J-valve components, the J-valve

blower should remain on until valve cools to below

260 .℃

All valves and air control dampers are closed so that a minimum

amount of heat is lost. No fire is maintained or introduced into the

furnace; therefore the pressure in the steam drum will decrease, but

proper drum level must be maintained.

NOTE

Figure 3-4 is a graph of static bed height versus bed

77



differential pressure. Figure 3-2 is a curve of fluidizing

velocity versus air flow. With the measured air flow,

Figure 3-2 may be used to obtain the superficial

fluidizing velocity at a given bed temperature. While

firing the designed fuel, the fluidizing velocity should

not be allowed to drop below 1.2m/sec. A hot condition

is one in which the average bed temperature (after

being slumped) is above 650 . If the average bed℃

temperature is below 650 , follow the procedures℃

described for a cold start-up in Paragraph 3.3.

To start-up the boiler from a hot condition, proceed as follows:

a. Check water level in steam drum. If necessary, make

adjustments to bring water to normal level (180mm below drum

centerline).

b. Prepare fuel and limestone feed systems and bed material

extraction systems for operation.

c. Start one (1) J-valve blowers and set air flow for proper

fluidizing velocity. Place on Auto.

d. Start ID fan and FD fan per the procedures described for a cold

start-up, Paragraph 3.3.2.

CAUTION

IF LARGE AMOUNTS OF UNBURNED CARBON EXIST

OR ARE SUSPECTED WITHIN THE BED, COMBUSTION

AIR FLOW MUST BE INCREASED GRADUALLY IN

ORDER TO PURGE THE BED AND ESTABLISH A

CONTROLLED BURNING RATE.

e. Adjust combustion air for 25% MCR conditions. When all fans

78



are running, proper air flows must again be established along

with restart of the fuel feeds. Since the bed temperature can

drop rapidly, it is important to acquire proper air flows and fuel

feed rates. Otherwise, bed temperatures and O2 values will not

respond accordingly. If the unit does not respond to the proper

feed rates of air and fuel, discontinue the hot start-up procedure

and begin the cold start-up methods. Make certain to purge the

unit of combustibles prior to lighting the under-bed burner.

f. If during the hot restart solid fuel has been overfed into the bed

and has not fully combusted as a higher bed temperature is

again established, the bed temperatures may rise rapidly and

O2 decrease rapidly. If this should happen, no further fuel feed

should be added until the bed has stabilized. If the temperature

rise appears to be rapid enough to climb above 930 , the℃

following should be implemented in advance of achieving

930 .℃

1. Lower the air supply to the bed to starve the combustion

process.

2. If the unit doesn’t stabilize as indicated by O2 and bed

temperature trends, the fluidizing air control damper

should be closed to smother the fire.

NOTE

When re-establishing air flows in a hot start condition,

bed temperatures may drop rapidly. Establish overfire

air (secondary air) first and then grid air to minimize

heat loss.

g. Continue with hot restart following procedures listed in

79



Paragraph 3.3.4, steps f through q.

NOTE

if bed temperature does not rise within five minutes of

the fuel feed, ignition has not occurred. The feed must

be stopped, the unit purged and the unit started

following the normal cold start-up procedure.

3.5. NORMAL OPERATION

3.5.1.Firing

The fluidized bed steam generator superheater outlet pressure

should be maintained at its normal value of 100bar at all times during

operation with the exception of start-up and shutdown of the boiler.

a. The primary technique for changing the boiler load involves varying fuel

feed rate and air flow. Bed temperature may be varied between

790 and 920 to permit large increments of change within a short℃ ℃

period of time. However, after obtaining the desired steam rate, bed

temperature should be re-established at 900 and boiler load held℃

steady by adjusting bed inventory and firing rate. Normally when

changing load, the best method is to maintain the bed temperature at

a constant value if possible. In all cases, make sure that air flow

tracks fuel flow either manually or automatically, to maintain a setexcess O2 value.

b. The SO2 emissions from the boiler should be monitored at all times. The

limestone feed rate must be adjusted, either manually or

automatically, to maintain an SO2 emissions level at the stack that is

in compliance with concerned regulations.

NOx emissions are inherently low within the furnace at the normal

80



temperature operating range. NOx emissions are increased as

furnace temperature is increased. The NOx emission level at the

Continuous Emission Monitoring System (CEMS) (stack) should be

checked periodically. Adjustments, if necessary, should be made to

operating furnace temperature and secondary air distribution through

various airport levels.

c. Periodically inspect the fluidized beds for even fluidization. A low

temperature at any of the lower bed thermocouples is an indication

of loss of fluidization. If a portion of the bed is not fluidizing, increase

bed air flow and temporarily increase bed material extraction rate. If

this increase does not improve fluidization, it may be necessary to

shut down the boiler and inspect for plugging of the air distribution

grid, clinkers in the bed or rock accumulation.

d. Continuously monitor the gas side pressure differential through the

convection heat transfer surface and periodically inspect the heater

transfer surface for buildup of ash material.

e. Periodically inspect the fuel and limestone feed systems for plugging,

improper sounds, vibration, belt tracking, lubrication and

temperatures.

f. Continuously monitor the fluidized bed level and maintain it at its normal

level by adding limestone or increasing bed extraction rate. Bed

material extraction will be required to maintain proper bed material

inventory and SO2 control.

NOTE

To minimize line expansion and other system stresses,

average temperature of ash leaving the cooler should

be maintained below 150 . From an efficiency℃

81



standpoint, cool the ash temperature as lower as

possible.

g. Continuously monitor the air distribution grid pressure differential. If this

differential decreases significantly, check instrumentation for proper

operation and sensing lines for plugging. If instrumentation operating

properly, shut down the boiler and inspect the air distribution grid.

3.5.2.Water Chemistry and Steam Purity

a. Assure that the desired boiler water salt concentration and chemistry are

maintained. Improper boiler water can lead to fouling or corrosion of

internal surfaces, reducing the efficiency of the unit and possibly

resulting in overheating of tubes leading to tube failure

b. Assure that moisture carryover from the drum is within permissible limits.

For operation within design condition, the steam separation

equipment will keep salt carryover within acceptable limits. Moisture

carried over can include salt and other impurities which may deposit

on surfaces downstream of the boiler.

c. The operation of the continuous blowdown valves should be determined

by monitoring the boiler water chemistry. Use of these valves will

increase input to the boiler for a given output. Note that drain valves

on the lower waterwall headers should never be used for blowdown

purposes when the unit is in operation.

3.5.3.SootBlowing

a. All external surfaces of tubes and elements must be kept reasonably

free of deposits if full capacity and efficiency are to be maintained.

Sootblowing should be used as often as necessary to accomplish

this.

b. After the unit is placed in service, operate the sootblowers to remove any

82



deposits which may be present. Sootblowing should always be done

on the pre-established schedule basis regardless of the operating

load; however, below 50% load the FD and ID fans should be in

manual control during the sootblowing operation.

c. Sootblowing operations are considered a part of the boiler operations

and require frequent monitoring to achieve optimum cleaning.

Monitoring or inspecting the following will insure an early

establishment of the optimum sootblowing sequence:

1. Properly operate the drain valves of sootblowing. The result of

improper operation of the drain valves or trap is tube erosion

occurring within the first several feet of blower travel and is

caused by water droplets entrained in the steam being

propelled against the tube surface.

2. Check the settings of individual sootblower blowing pressures.

Refer to manufacturer’s instructions for exact settings.

3. During unit down time, visually inspect the furnace convection

passes for ash accumulations.

4. Monitor the high temp. (H/T) superheater final steam

temperatures.

5. Monitor the changes in attemperator spray flows.

6. Monitor economizer and airheater exit gas temperatures.

7. Monitor airheater air and gas side pressure differential

variations.

8. Monitor gas side system resistance through the HRA.

Typically, when the sootblowing system is first commissioned, the

aforementioned boiler parameters are monitored and an optimized

sootblowing sequence is adapted. Periodic monitoring of the system

83



can help prevent an unscheduled outage.

3.5.4.Spray Attemperation

Do not desuperheat the steam entering the SH wing wall and H/T

superheater inlet header to less than 11 above saturation℃

temperature at the inlet pressure of the transfer pipes.

3.6. NORMAL SHUTDOWN

a.Normal shutdown involves reducing the load on the unit in an orderly

manner, thus allowing the turbine and boiler to be decoupled

without causing temperature and pressure swings, while at the

same time retaining as hot a unit as possible. Unit load reduction

can be accomplished with all control in AUTO.

b.Sootblowing before reducing load and taking unit out of service.

c.During shutting down, do not exceed an maximum temperature

difference of 40 between top and bottom of the drum.℃

d.Control, as necessary, the superheater outlet temperature by regulating

the attemperator spray water flow. Close the water shut-off valves

when attemperation is no longer required.

e.Check and maintain drum level at normal.

f. Reduce unit load to minimum stable. Maintain minimum unit load for

approximately 30 minutes to help cool cyclone refractory, otherwise

cyclone tube temperatures will rise to greater than 420 . In such℃

case, opening the cyclone upper header vent system.

g.Transfer the boiler master control to manual.

h.close all fuel silo hopper outlet shut-off valves and run all fuel off the

feeders ( if an extended shutdown is expected). Also, empty the fuel

storage silos to their lowest safe levels.

84



i. Stop limestone feeder systems.

j. Monitor boiler oxygen levels and bed temperatures; when oxygen starts

to increase and bed temperatures start to decrease, closing off the

air (to plenum) control damper.

k.As the load is reduced below approximately 10 percent of rated boiler

capacity, open drain valves of the main steam line and H/T

superheater outlet header. Pay attention to the control of the

furnace cooling rate and these drain valves should not be

completely closed off as long as steam is still generated during the

process.

l. After all fires have been extinguished, leave the FD and ID fans in

operation for at least five minutes to purge the setting of

combustibles.

m. If pressure is to be maintained on the steam generator after being

taken out of service, shut down the fans after purging the unit.

Close any associated fan dampers to retain heat. Be sure bottom

ash coolers have been emptied of material. When the drum

pressure has fallen below the lowest set safety valves, and there is

insufficient heat remaining in the setting to pop the safety valves,

close the drain valves of the H/T superheater. The drain and vent

valves should remain closed when not firing the unit. Exception to

the foregoing may occur automatically by activation of cyclone tube

protection system.

n.Before firing a unit to maintain steam pressure, the H/T superheater

outlet header downstream drain valves must be opened. Keep the

drains open during firing and keep the feedwater supply system in

operation as long as steam is generating from the unit. Maintain

drum water level visible near normal level indication on the gage

85



glass when firing.

o.If the boiler is to be out of service for an extended period or entered for

maintenance, continue to cool down the unit using the fans, while

removing bed material via the bottom ash cooler. The H/T

superheater outlet header downstream drain valves may be

regulated along with other superheater drains to decrease drum

pressure at the desired rate. Cool the unit as uniformly as possible.

The residual heat in the setting and the boiler components will

continue to generate steam for considerable time. During this

period, the boiler water level should be maintained near the upper

limit of gage glass visibility. Once all bed material is removed from

the unit, purge the boiler setting for five (5) minutes. The bottom ash

cooler should then be removed from service. When the unit is cool

enough for entry, the fans can be taken out of service.

p.Stop the feeder systems. Shut down the FD and ID fans.

q.The J-valve blower should remain in operation after the FD and ID f air

fans are shut down. To prevent damage to J-valve components, the

J-valve blower should remain on until valve cools to below 260 .℃

r. Stop ash system.

s.If the unit is to be drained, open all vents and drains when the drum

pressure has decreased to 1bar. Temperature of the boiler water

should not exceed 120 when the unit is drained. Draining the unit℃

when there is still a small amount of pressure on the unit is

preferred as the residual heat will assist in drying the internal

surfaces.

t. Superheater header drain and vent valves should remain open during

short outages.

u.Idle boilers should not be allowed to remain partially filled with water for

86



any appreciable length of time. Fill them completely with deaerated

alkaline water into which hydrazine has been added as a protection

against corrosion. If the outage will amount to several weeks or

months, or should weather prohibit filling the unit, drain and dry the

unit, placing shallow pans of a predetermined quantity of silica gel in

the drums to absorb moisture and maintain the internal surfaces in

a dry condition. When the unit is to be out of service for several

days or longer, all ash and soot deposits should be removed since

moisture absorbed by sulfur bearing ash or soot causes corrosion. It

is advisable to sootblow the unit just before taking it out of service, if

possible.

3.7. EMERGENCIES

3.7.1.Main Fuel Trip (MFT)

On a main fuel trip, the following actions will take place:

a.Fuel feeders trip.

b.Limestone systems trip.

c.under-bed burner trips.

d.Bottom ash cooler trip.

e.All air flow controls transfer to manual mode and hold last position.

f. Fan controls transfer to manual mode and hold last position unless the

cause is a fan trip, in which case, fan controls follow fan logic.

g.Output signal to combustion control limits ID fan automatic control from

going above the furnace draft limit.

h.“Boiler Purge Required”logic is set unless it is a“Hot Restart”condition.

87



3.7.1.1. Any of the following conditions will cause a boiler

main fuel trip (MFT).

1. Both MFT push buttons pressed simultaneously.

2. Bed temperature greater than 980 (from Combustion Control℃

System).

3. Loss of logic power.

4. Furnace pressure high high, +260mmH2O (2 out of 3 logic) (with

time delay).

5. Furnace pressure low low, -260mmH2O (2 out of 3 logic) (with

time delay).

6. Steam drum level high high, +120mm above normal ( with time

delay ) (2 out of 3 logic ).

7. Steam drum level low low, -120mm below normal ( with timedelay ) ( 2 out of 3 logic ).

8. ID fan tripped.

9. Primary & Secondary fan tripped.

10. Total air flow low, less than 25% (with time delay) (from

Combustion control System).

11. Combustion Control System Power failure (from Combustion

Control System ).

12. Total air/fuel ratio less than minimum (from Combustion Control

System).

13. under-bed burner not in service and bed temperature is less

than 650 .℃

14. High furnace plenum pressure (with time delay) (from

88



Combustion Control System).

15. Two J-valve blowers tripped.

16. Turbine trip.

17. Cyclone level high high (with time delay).

18. Start-up time exceeded.

3.7.2.Emergency Operating Procedures

3.7.2.1. Tube Leak

If a boiler tube leak is suspected (either through high make-up water

usage, abnormal deviation between feedwater flow and main steam

flow, or audio or visual inspection), the unit must be taken out of

service as quickly as possible, under a controlled shutdown, to

minimize moisture getting into the bed material. The unit load should

be ramped down as quickly as possible and all fuel feed to the unit

stopped. Close the isolation gates on all fuel feeders. Restart or

continue to operate the bottom ash coolers and ash removal system

at a maximum rate.

Continue to operate fans and maintain air flow to the furnace to keep

material moving into the bottom ash cooler. Some air flow to the

secondary air ports should be established to keep moisture out of

ducts. Reduce drum pressure as slowly as possible and maintain

drum level, if possible. Continue to cool the unit and extract bed

material until the unit is empty of bed material and cool enough to

enter. During cool-down, do not exceed a 40 differential℃

temperature between top and bottom of the steam drum. The drum

level should be maintained until the boiler water temperature is

reduced below 120 ; then the boiler should be drained. If the tube℃

89



leak is in the furnace, it may be necessary to use the under-bed

burner while removing the bed material from the furnace to assist

with evaporation of the lost boiler water. If the bed is damp and drops

below 180 , it may plug the ash handling system or stay within the℃

furnace. If the under-bed burner is utilized, it is important that the

burner temperature be kept below 315 .℃

Before entering the unit for any reason, check that safe temperature

has been reached, conduct gas sniff test for safety levels and wear

proper protective clothing.

When access to the bed is possible and all bed material that is

possible to remove is extracted, enter the unit to assess the extent of

the tube leak and amount of bed material remaining. Any material,

wet or dry, left in the beds should be removed as soon as possible

before it has a chance to solidify. Solidified bed material below the

level of the grid nozzles need not be removed. However, the grid

nozzles must be inspected and any plugged nozzles cleaned out by

rodding with high pressure air from below the nozzles. Make certain

no one is working on the opposite side of the nozzle.

3.7.2.2. Excessive Bed Temperatures

Excessive high bed temperature can lead to clinkers (fused ash) and

damage to in-bed thermowell, thermocouples, grid nozzles, etc.

High bed temperature should be avoided by increasing limestone

feed rates and shutting down the bottom ash coolers in an effort to

increase bed inventory and cool bed temperatures. Load should be

reduced and fuel flow reduced, until bed temperatures start

decreasing to avoid the formation of clinkers.

90



3.7.2.3. Clinkered Bed

“Clinkers”in the bed are considered to be agglomerated masses of

fusing or cemented ash which can be formed when firing fuel with

low air/fuel ratios, elevated temperatures of bed or reduced

superficial velocity. The risk of forming clinkers is greater at

temperatures exceeding 920 .℃

If any of the above abnormal operating conditions are encountered,

the operator should monitor the individual bed thermocouples. If

clinkers form, a localized hot spot will appear, followed by localized

defluidization and a zone of low bed temperatures. If it is confirmed

that the isolated zone of low bed temperatures is not due to faulty

instrumentation or lack of fluidizing air, a clinker is to be suspected

and the instructions for normal shutdown should be followed, the unit

taken out of service and all possible bed material removed from the

cell.

The actual cool-down time is dependent upon the boiler load and

bed temperature at the time of shutdown. Also, When the drum water

temperature drops to 120 , the unit can be drained to aid cooling.℃

During cool down, a maximum of 40 differential temperature℃

between the top and bottom of the drum should not be exceeded.

Maintain minimum air flow, equivalent to 1.2m/sec superficial

velocity, to the bed for cooling and to ensure transfer of loose bed

material to the bed drain. When the unit is cool and no more bed

material can be removed through the bed drain system, shut down

the fans and make the necessary safety preparations to enter the

furnace. Enter the unit and evaluate the extent of the clinkers. Small

accumulations can be broken up and removed. Inspect for any

damage to the bed thermocouples and grid nozzles. Repair or

91



replace as necessary. All grid nozzles should be inspected for

plugging and cleaned out as required.

3.7.3.Overpressure Protection

To protect the steam generator and associated equipment during

operation malfunction resulting in an over pressurization of pressure

parts, the following safety valves and relieving devices are installed

for the unit.

Description Location Qty. Set Pressure

(Bar)

Safety Valve Main steam header 1 105

Safety Valve Steam Drum 1 118.9

3.8. MAINTENANCE

a.During long-term boiler shutdowns, observe the following:

CAUTION

DO NOT FILL THE BOILER WITH NITROGEN UNTIL

AFTER ALL INTERNAL PRESSURE PART

INSPECTIONS AND/OR MAINTENANCE PROCEDURES

ARE COMPLETED. PROVISION SHOULD BE MADE

FOR NITROGEN PROTECTION OF THE IDLE BOILER

BY CONNECTING A NITROGEN SUPPLY, THROUGH A

REGULATING VALVE, TO A DRUM VENT.

If an idle boiler is not drained, the areas above the water level in the

drum should be filled with nitrogen through the above mentioned

access on the drum. The nitrogen cap should be established when

the pressure of the boiler being removed from service decreases to

92



about 0.35Bar. Maintain the nitrogen cap during the shut down

period. During idle periods, the boiler must be protected against

freezing conditions. This may be done by firing the under-bed burner

with low heat input to maintain temperatures throughout the boiler

above freezing.

If weather or other conditions prevent leaving the unit filled, it should

be drained and dried. Place several shallow pans of a predetermined

quantity of silica gel in the drum to absorb moisture and maintain the

internal surfaces in a dry condition.

b. When the unit is shut down for repairs, it should never be entered until it

has been determined that all fuel shut off valves and dampers are

locked in the closed position. Should there be some questions about

their tightness, it is recommended that the fuel lines be blanked off.

CAUTION

THERE ARE ACCESSIBLE AREAS IN THE BOILER

THAT COULD EXPOSE PERSONNEL TO

HAZARDOUS CONDITIONS. SOME OF THESE

AREAS ARE THE FURNACE VESTIBULE AT THE

CYCLONE INLET, WHERE QUICK DROP-OFFS

INTO THE FURNACE AND CYCLONE EXIT, THE J-

VALVE, WHERE HOT BED MATERIALS COULD

ACCUMULATE, AND VIRTUALLY EVERY ACCESS

DOOR, WHERE BACK KICK COULD OCCUR.

BEFORE OPENING ANY ACCESS DOOR, FOR ANY

REASON, EXERCISE EXTREME CAUTION TO

GUARD AGAINST THESE DANGERS. WEAR

PROTECTIVE CLOTHING AND STAND TO ONE

SIDE (DO NOT JUST FACE THE DOORS) WHEN

93



OPENING DOORS. USE SUITABLE BREATHING

APPARATUS AND SAFETY CLOTHING, AS

NECESSARY, WHEN ENTERING THE BOILER.

CARRY OR INSTALL ADEQUATE LIGHTING AND

ALWAYS BE AWARE OF IMMEDIATE

SURROUNDINGS WHEN INSIDE.

CAUTION

PROPER GAS SNIFF TESTING SHOULD BE

ACCOMPLISHED AND PROPER O2 LEVELS

ESTABLISHED.

c. Only approved safety types of lights and flashlights should be used when

inspecting and working in the boiler.

d. During outages, the pressure containing parts and other internal

surfaces should be inspected when possible. Unusual signs of wear or

accumulations should be investigated and the causes corrected.

e. Inspect each air distribution grid plate nozzle for plugging and clean out

as necessary.

f. When inspection door are opened for access, the used gaskets should

be replaced with new ones.

g. During overhaul periods, the under-bed burner should be carefully

inspected for any damage and maintenance repairs be made.

h. Repair all tube leaks as soon as possible. Leaks which are allowed to

persist can cause further damage due to water or steam cutting of

adjacent tubes.

Repairs should not be attempted on parts which are still subjected to

pressure. Repair to pressure parts should be accomplished when all

pressure has been removed and the system isolated.

94



i. Combustion control equipment and other control equipment such as

feedwater regulators and steam temperature controllers should be

kept in optimum adjustment at all times. Efficiency depends upon the

proper functioning of these equipments.

j. Check all fuel and limestone feed piping and bed material extraction

piping for plugging, erosion, overheating, etc. Repair or replace as

necessary.

k. All valve and packing leaks should be repaired during the outage period.

This will help prevent forced outages.

l. Thoroughly inspect the general conditions of all thermocouples and

pressure taps and repair as necessary for reliable operation.

m. Check plenum floor for accumulation of spent bed material due to back

sifting through grid plate air nozzles. Remove material if excessive.

n. Careful inspection of the boiler pressure parts should be made to

monitor any erosion of tubes. Ultrasonic wall thickness measurements

as well as tube outside diameters should be recorded on a regular

basis (1 。 2 times a year). The areas to be monitored include the

furnace wall tubes, HRA inlet screen tubes, superheater tubes and

economizer tubes.

o. The cyclone, J-valve, furnace bottom/roof and furnace exit refractory

should be inspected on a regular basis and repaired as necessary.

4。Figure

Fig。1-1 Optimum size distribution for coal

95



96



Fig。1-2 Sectional side elevation of boiler

97



Fig。1-3 Steam and water diagram of boiler

98



Fig。1-4 Gas and air diagram of boiler

99



Fig。1-5 Drum internals

100



Fig。1-6 Arrangement of downcomers

101



Fig。2-1 The boiling out pressure for different design pressure

102



Fig。3-1 Oxygen measurement of approximately % by volume on a wet basis

103



Fig。3-2 Relationship between bed pressure and fluidizing velocity

104



Fig。3-3 The minimum steam temperature after spray

105



Fig。3-4 Relationship between bed pressure and height of static bed material

106



Fig。3-5 Cold start curve 。。。。。。

107



Fig。3-6 Warm start curve

Fig。3-7 Hot start curve

108



109



Fig。3-8“J”Valve Piping Connection Drawing

110



5。Table

Table 1 Thermodynamic Calculation Collecting Table for Coal rank COAL2 in

Boiler Design

Boiler Specification

Name & sign Unit Result Name & sign Unit Result

Boiler rating vapour

volume D

t/h 130 Rating steam outlet

temperature tgr

℃ 510

Steam outletpressure Pgr Bar (g) 100 Drum workingpressure Pgt Bar (g) 111

Feedwater

temperature tgs

℃ 170 Economizer inlet

feedwater pressure Pgs

Bar (g) 116

Continious

blowdown rate Ppw

% 2 Cooling air

temperature tlk

℃ 30

Fuel Calculation


As-received basis

Cy

% 62.61 As-received basis

Hy

% 4.08

As-received basis

Oy


Ny

% 1.01

As-received basis

Sy


Wy

% 13.89

As-received basis

Ay

% 13.89 Combustionable

group volatile

% 40

Low heating value

Qdwy

kcal/kg 5831 Fuel check value

Qv

kcal/kg 5820

Theoretic air value

VAirA

Nm3/kg 6.43

Furnace outlet

excessive air

coefficient

/ 1.2 Boiler outlet excessive

air coefficient

1.25

Temperature of

bottom ash

discharged from

furnace bottom

℃ 200 Material circulation

ratio

21.2

Carbon contents in

fly ash

% 5 Carbon contents in

bottom bottom ash

% 1

111



Limestone Features

Calcium carbonate

CaCO3

% 90 Magnesium

carbonate MgCO3

% 3.0

Moisture % 0.2 Inertia index % 1.0

Ca/S Moore ratio / 2.5 Desulfurazing

efficiency

% 83

Heat Balance Calculation


Heat loss due to

flue gas exhaust q2

% 5.29 Loss due to chemical

incomplete combustion

q3

% 0.1

Loss due to

mechanical incomplete

combustion q4

% 1.07 Loss due to heat

radiation q5

% 0.4

Decalescence in

calcining limestone

% 0.39 SO2 sulfation

radiation

% -0.37

Heat loss due to

bottom ash

radiation q6

% 0.04 Manufacturer

margin

% 0.25

Calculated boiler heat

efficiencyηgl

% 93.09 Guaranteed boiler

heat efficiency

% 92.8

Calculated fuel

consumption Bj

kg/h 15224 Fuel consumption B Kg/h 15389

Limestone

consumption

kg/h 952 Total burnt air Mn3/h 118800

Inertia material kg/h 0

Flue gas at boiler

outlet

mn3/h 132400 Total bottom ash Kg/h 3071

Fly ash kg/h 2303 Bottom bottom ash Kg/h 768

Primary input air in

furnace bottom

mn3/h 53500 Coaling input air Mn

3/h 10000

Secondary input air mn3

/h 55300 input air for returning material

Mn3

/h 1150

Furnace


Bed temperatureθ" ℃ 899 Outlet flue gas

temperatureθ"

℃ 917

Boiler outlet discharge

Fly ash

concentration at

boiler outlet

g/mn3 17.5 Primary discharge

of SO2

mg/mn3 1671

112



Discharge of SO2

after desulfurization

mg/mn3 284

Discharge

concentration of

NOx

mg/mn3 <300 Discharge

concentration of

CO

mg/mn3 <250

Desuperheater calculation


Desuperheater

type

Desuperhe

ating by

water

spray

Spraying water

temperature T

℃ 170

Total water sprayed

by desuperheater

D△

T/h 7.4

Water sprayed by

desuperheater I D△

T/h 3.5

Steam temperature at

desuperheater I inlet t1

℃ 409 Steam temperature at

desuperheater I outlet

t2

℃ 388

Water sprayed by

desuperheater II D△

T/h 3.9


desuperheater II inlett1


desuperheater II outlett2

℃ 426

Heat transfer component calculating results collection

Name & sign Unit Screen

type

superhe

ater

Cyclone

separator

Wall

enclosur

e

superhe

ater

High

temp.

superheat

er

Low

Temp.

superhe

ater

Tube size mm φ42×7 φ42×6 φ42×5 φ42×6 φ42×5

Flue gas inlettemperature

℃ / 917 867 822 668

Flue gas outlet

temperature

℃ / 867 / 668 576

Working medium

inlet

temperature

℃ 388 319 344 426 370

Working medium

outlet

temperature

℃ 453 344 370 510 409

113



Flue gas average

velocity

m/s / / / 11.7 10.3

Name & sign Unit Economize

r IV

Economizer

III

Economize

r II

Economizer

I

Primary

ducting

air

preheater

Secondary

ducting air

preheater

Tube size mm φ32×4 φ32×4 φ32×4 φ32×4 φ40×1.5 φ40×1.5

Flue gas inlet

temperature

℃ 576 466 389 313 260 /

Flue gas outlet

temperature

℃ 466 389 313 260 / 135

Working medium

inlet temperature

℃ 240 214 188 170 30 30

Working medium

outlet temperature

℃ 275 240 214 188 185 185

Flue gas average

velocity

m/s 8.4 8.1 8.0 6.9 7.6 7.2

114



Table 2. Boiler check coal rank COAL1 thermodynamic calculation collection

table

Boiler Specification



volume D


temperature tgr

℃ 510

Steam outlet

pressure Pgr

bar(g) 100 Drum working

pressure Pgt

bar(g) 111

Feedwater

temperature tgs


feedwater pressure Pgs

bar(g) 116

Continious

blowdown rate Ppw

% 2 Cooling air

temperature tlk

℃ 30

Fuel Calculation


As-received basis

Cy


Hy

% 3.53

As-received basis

Oy


Ny

% 0.48

As-received basis

Sy


Wy

% 30

As-received basis

Ay

% 3.11 Combustionable

group volatile

% 51.2

Low heating valueQdwy

kcal/kg 4269 Fuel check valueQv

kcal/kg 4274

Theoretic air value

VAirA

Nm3/kg 4.804

Furnace outlet

excessive air coefficient


air coefficient

1.25

Temperature of

bottom ash

discharged from

furnace bottom


ratio

20.1

Carbon contents in

fly ash


bottom bottom ash

% 1

Limestone Features

Calcium carbonate

CaCO3

% 90 Magnesium

carbonate MgCO3

% 3.0



efficiency

% 30

115



Heat Balance Calculation


Heat loss due to flue

gas exhaust q2

% 6.03 Loss due to

incomplete chemical

combustion q3

% 0.1

Loss due to incomplete

mechanical combustion

q4


radiation q5

% 0.4

Decalescence in

calcining limestone


radiation

% -0.03

Heat loss due to

bottom ash radiation

q6

% 0.05 Manufacturer

margin

% 0

Calculated boiler heatefficiencyηgl

% 91.75 Guaranteed boiler heat efficiency

% /

Calculated fuel

consumption Bj

kg/h 20881 Fuel consumption B kg/h 20936

Limestone

consumption

kg/h 160 Total burnt air mn3/h 121200


Flue gas at boiler

outlet

mn3/h 142000 Total bottom ash kg/h 4732

Fly ash kg/h 3549 Bottom bottom ash kg/h 1183Primary input air in

furnace bottom

mn3/h 54600 Coaling input air mn

3/h 10000

Secondary input air mn3/h 56600 Input air for

returning material

mn3/h 1150

Furnace



temperatureθ"

℃ 900

Boiler outlet dischargeFly ash

concentration at

boiler outlet

g/mn3 25 Primary discharge

of SO2

mg/mn3 325

Discharge of SO2


mg/mn3 228

Discharge

concentration of

NOx


concentration of

CO

mg/mn3 <250

116





Desuperheater type Desuperhe

ating by

water

spray

Spraying water

temperature T

℃ 170

Total water sprayed by

desuperheater D△

T/h 8.1

Water sprayed by


T/h 3.5





t2

℃ 389

Water sprayed bydesuperheater II D△

T/h 4.6


desuperheater II inlet t1


desuperheater II outlet

t2

℃ 421

Heat transfer parts calculation result collection

Name & sign Unit wing wall Cyclone

separator

Wall

enclosure

superheater

High

temperature

superheater

Low

temperatur

e

superheater Tube size mm φ42×7 φ42×6 φ42×5 φ42×6 φ42×5

Flue gas inlet

temperature

℃ / 900 855 817 665

Flue gas outlet

temperature

℃ / 855 / 665 574

Working medium

inlet temperature

℃ 389 319 344 421 367

Working medium

outlet temperature

℃ 452 344 367 510 410

Flue gas average

velocity

m/s / / / 12.7 11.1

117




r IV

Economizer

III

Economizer

II

Economizer

I

Primary

ducting air

preheater

Secondary

ducting air

preheater


Flue gas inlet

temperature

℃ 574 467 392 316 262 /

Flue gas outlet

temperature

℃ 467 392 316 262 / 141

Working medium

inlet temperature

℃ 245 218 190 170 30 30

Working medium

outlet temperature

℃ 282 245 218 190 185 185

Flue gas average

velocity

m/s 9.1 8.8 8.6 7.5 8.3 7.8

118



Table 3. Boiler check coal rank COAL3 thermodynamic calculation collection

table

Boiler specification



volume D


temperature tgr

℃ 510

Steam outlet

pressure Pgr

bar(g) 100 Drum working

pressure Pgt

bar(g) 111

Feedwater

temperature tgs


feedwater pressure

Pgs

bar(g) 116

Continious

blowdown rate Ppw

% 2 Cooling air

temperature tlk

℃ 30

Fuel calculationName & sign Unit Result Name & sign Unit Result

As-received basis Cy % 62.74 As-received basis Hy % 4.76

As-received basis Oy % 8.89 As-received basis Ny % 1.02

As-received basis Sy % 1.32 As-received basis Wy % 11

As-received basis Ay % 10.25 Combustionable

group volatile

% 40

Low heating value Qdwy kcal/kg 6024 Fuel check value Qv kcal/kg 5990

Theoretic air value

VAirA

Nm3/kg 6.587

Furnace outlet

excessive air

coefficient


air coefficient

1.25

Temperature of

bottom ash

discharged from

furnace bottom


ratio

22.3

Carbon contents in

fly ash


bottom bottom ash

% 1

Limestone features

Calcium carbonate

CaCO3

% 90 Magnesium

carbonate MgCO3

% 3.0



efficiency

% 90

119



Heat balance calculation


Heat loss due to

flue gas exhaust q2

% 5.26 Loss due to chemical

incomplete combustion

q3

% 0.1

Loss due to

mechanical incomplete

combustion q4


radiation q5

% 0.4

Decalescence in

calcining limestone


radiation

% -0.71

Heat loss due to

bottom ash

radiation q6

% 0.04 Manufacturer

margin

% 0

Calculated boiler heatefficiencyηgl

% 93.14 Guaranteed boiler heat efficiency

% /

Calculated fuel

consumption Bj

kg/h 14726 Fuel consumption B Kg/h 14888

Limestone

consumption

kg/h 1687 Total burnt air Mn3/h 116400


Flue gas at boiler

outlet

mn3/h 129900 Total bottom ash Kg/h 3123

Fly ash kg/h 2343 Bottom bottom ash Kg/h 781Primary input air in

furnace bottom

mn3/h 52400 Coaling input air Mn

3/h 10000

Secondary input air mn3/h 54000 Input air for

returning material

Mn3/h 1150

Furnace



temperatureθ"

℃ 883

Boiler outlet dischargeFly ash

concentration at

boiler outlet

g/mn3 17.9 Primary discharge

of SO2

mg/mn3 2988

Discharge of SO2


mg/mn3 298

Discharge

concentration of

NOx


concentration of

CO

mg/mn3 <250

120





Desuperheater

type

Desuperhe

ating by

water

spray

Spraying water

temperature T

℃ 170

Total water sprayed by

desuperheater D△

T/h 7.2

Water sprayed by


T/h 3.5





t2

℃ 387

Water sprayed by

desuperheater II D△

T/h 3.7


desuperheater II inlet t1


desuperheater II outlet t2

℃ 427

Heat transfer parts calculation result collection

Name & sign Unit Wing wall Cyclone

separator

Wall

enclosure

superheater

High

temperature

superheater

Low

temperature

superheater

Tube size mm φ42×7 φ42×6 φ42×5 φ42×6 φ42×5

Flue gas inlettemperature

℃ / 883 866 820 668

Flue gas outlet

temperature

℃ / 866 / 667 575

Working medium

inlet

temperature

℃ 387 319 344 427 369

Working medium

outlet

temperature

℃ 452 344 369 510 408

Flue gas average

velocity

m/s / / / 11.7 10.2

121




r IV

Economizer

III

Economize

r II

Economizer

I

Primary

ducting air

preheater

Secondary

ducting air

preheater


Flue gas inlet

temperature

℃ 575 465 388 312 259 /

Flue gas outlet

temperature

℃ 465 388 312 259 / 135

Working medium

inlet

temperature

℃ 239 214 188 170 30 30

Working medium

outlet

temperature

℃ 274 239 214 188 185 185

Flue gas average

velocity

m/s 8.3 8.0 7.8 6.8 7.5 7.1

Table 4. Flue Gas and Air Resistance Collection Table

Coal rank Unit Primary air resistance Secondaryair

resistance

Flue gasresistance Loop-sealdevice

high

pressure air

resistance

Coal 1 Pa 14000 9500 4000 48000

Coal 2 Pa 13500 9000 3700

Coal 3 Pa 13500 9000 3700

Table 5. Steam water Resistance Collection Table

Superheater resistance。 Unit。bar 11

Economizer resistance。 Unit。bar 5

Table 6. “J”Valve Air Nozzle Charge VolumeTemperature 。。。100890Descend tube air

flow 。 Nm3/hr 。 NANozzle button 15070A17~A20Charge aperture3520A13~A16Charge

122



aperture3520A1~A4Charge aperture5510A5~A8Charge aperture2010Subtotal。 295130Ascend

tube air flow 。 Nm3/hr 。 NBNozzle button 12050A9~A12Charge aperture2010Subtotal 。

14060Total。435190

(2) Boiler Proper

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