DBR 300 mw.pdf

.

TCE CONSULTING ENGINEERS LTD

BTG PACKAGE FOR 2300MW COAL BASED THERMAL POWER STATION AT

TORANAGALLU, BELLARY

DESIGN BASIS REPORT

FOR BTG MECHANICAL PART

DOCUMENT NO. 50-F271C-J01-01 REV.1

SHANGHAI ELECTRIC GROUP CORPORATION,LTD 3669 Jindu Road,Shanghai,China

JSW Energy (Vijayanagar) Limited

SOUTHWEST ELECTRIC POWER DESIGN INSTITUTE

18 Dongfeng Road,Chengdu,China

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Design Basis Report for BTG Mechanical Part

BTG PACKAGE FOR 2300MW COAL BASED

THERMAL POWER STATION AT


DOCUMENT NO.: 50-F271S-J01-01 REV.1 Page

1

DOCUMENT CONTROL SHEET

PROJECT: BTG PACKAGE FOR 2300MW COAL BASED THERMAL POWER

STATION AT TORANAGALLU, BELLARY

CLIENT: JSW ENERGY (Vijayanagar) LIMITED

/SHANGHAI ELECTRIC GROUP CORPORATION,LTD

DOCUMENT TITLE: DESIGN BASIS REPORT FOR BTG MECHANICAL PART

DOCUMENT NO.: 50-F271C-J01-01

REV. NO. : 1

ENDORSEMENTS

1 10.11.

2006

Revised as per

MOM of second

coordination

meeting

1 08.200

6

REV.

NO.

DATE DESCRIPTION PREP. BY

SIGN.(INITIAL)

REVW. BY

SIGN.(INITIAL)

APPD BY

SIGN.(INITIAL)

SOUTHWEST ELECTRIC POWER DESIGN INSTITUTE

18dongfengRoad,chengdu,China


Design Basis Report for Mechanical Part




DOCUMENT NO.: 50-F271C-J01-01 REV.1 Page

2

CONTENTS

1 GENERAL 1

1.1 Major design principle 1

1.2 Boiler 2

1.2.1 Introduction 2

1.3.1 General 3

1.3.2 Turbine HBD 4

1.4 Generator 6

1.4.1 General 6

2 FUEL 7

2.1 Fuel characteristics 7

3 COMBUSTION SYSTEM AND SELECTION OF AUXILIARY EQUIPMENT

11

3.1 Boiler Fuel Consumption 11

3.2 Design principle of Flue gas and air system & pulverized coal

system 11

3.3 System Description 11

3.4 Calculation results 16

3.5 Major Auxiliary Equipments Selection 18

3.6 Pyrites handling system 23

4 THERMAL SYSTEM AND SELECTION OF AUXILIARY EQUIPMENT 25

4.1 Design principle of Thermal System 25

4.2 System Description 26

4.2.1 Main steam, reheat steam and bypass system 26

4.2.2 Feed-water system 30

4.2.3 Extraction steam system 34

4.2.4 Condensate water system 35

4.2.5 Heater drains and vents system 36







3

4.2.6 Auxiliary steam system 37

4.2.8 Vacuum system 39

4.2.9 Condenser tube cleaning system 39

4.2.10 Closed cycle DM water system 39

4.2.10 Boiler blowdown and drain system 40

4.2.11 Steam turbine lube oil and Lube oil handling system 41

4.2.12 Lubrication Oil System 41

4.3 Major Auxiliary Equipment Selection 45

4.3.1 Feed-water pump 45

4.3.2 Heaters 51

4.3.3 Condensate extraction pump 64

4.3.4 Vacuum pump 66

4.3.5 Condenser 67

4.4 Table of economic index 72

5 INSULATING MATERIAL 73







1

1 GENERAL

1.1 Major design principle

This project is designed to be the coal-fired power plant located in India, with

nominal generator output capacity of 2X300MW.

Main design basis codes and standards will be international codes & standards,

IBR or equivalent standards subject to owners approval as below (refer to

contract technical specification.)

1) American society of testing & materials;

2) ASME Test codes;

3) Technical code for designing fossil fuel power plant

4) Technical code for design of thermal power plant air & flue gas ducts/raw coal

& pulverized coal piping;

5) Code for design of thermal power plant steam/water piping.

6) Guaranteed availability of each unit is higher than 85%.

7) Unit start-up time from ignition to full load






2

8) Plant makeup water3%.

9) The steam turbine, turbine generator and all equipments and auxiliaries are

suitable for continuous operation in the frequency range of 47.5Hz to 51.5Hz.

Also, for all equipments, noise level measured at a distance of 1 m from the

equipment will not exceed 85dBA except for places as mentioned below:

TG unit in which case it will not exceed 88 dBA;

1.2 Boiler

1.2.1 Introduction

The boiler is a natural circulation, subcritical pressure with single steam drum

and single reheat. It is semi outdoor arranged and has a single furnace of

reverse u-form (-type, Double pass) arrangement and full pendant steel

structure, dry bottom type water-cooled, balanced draft furnace and is designed

with tangential firing arrangement of burners. There are six pulverizers with 24

coal nozzles in different elevations in the furnace zone of the boiler. Light diesel

oil will be used for start-up. The light diesel oil will be designed for 10 % BMCR

load and mechanical atomization. The steam generator shall be designed for

firing heavy fuel oil up to 30 % BMCR load. The minimum load without oil

support is 30 % BMCR with design coal and 40 % BMCR with worst coal with

two adjacent mill in service. The HFO will be steam atomization.

1.2.2 Boiler capacity and main parameters

Items Unit BMCR







3

Items Unit BMCR

Boiler Max. Continuous rating (BMCR) t/h 1015

Superheater outlet steam pressure MPa.(a) 17.57

Superheater outlet steam temperature C 541

Reheat steam flow t/h 840.7

Reheater inlet steam pressure Mpa(a) 3.816

Reheater outlet steam pressure Mpa(a) 3.622

Reheater inlet steam temperature 323

Reheater outlet steam temperature 541

Economizer inlet feed water temperature 279

Efficiency(Based on higher heating value of the design

fuel) %

88.77

1.3 Steam turbine

1.3.1 General

The steam turbine will be of a tandem compound, single reheat, and axial flow

type with steam exhausting from one double flow low-pressure cylinder to

condenser.

The unit will be capable of producing rated output of 300mw when operating with

rated steam conditions and design ambient conditions.

Main specification

1







4

Type: Subcritical, Reheat, Tandem compound, Two cylinder, Double flow,

Condensing

Rated Power (TMCR Condition): 300MW

Rated Speed: 3000r/min

Direction of Rotation: Clockwise viewing from Governing End

Steam Inlet Pressure: 16.67MPa(a)

STEAM INLET TEMPERATURE 538

STEAM REHEAT TEMPERATURE538

1.3.2 Turbine HBD

Type N30016.67/538/538 (K156)

1) VWO (valve wide open) condition

Items Unit VWO

Maximum output MW 312.970

Steam pressure at the inlet of MSV MPa.a 16.67

Steam temperature at the inlet of MSV 538

Reheat steam temperature at combined valves 538

Steam flow for main steam t/h 966.623

Steam flow for hot reheat steam t/h 798.881

Back pressure of condenser kPa(a) 10.05

Final feed water temperature 277.8

Circulate cooling water 33

1

1







5

2) Heat Rate Guarantee Condition

Items Unit Heat Rate Guarantee

Rate output MW 300.078

Steam pressure at the inlet of MSV MPa.(a) 16.67


Reheat steam temperature at combined

valves 538



Back pressure of condenser kPa(a) 10.05



guaranteed heat rate Kcal/Kwh 1909.6

3) All HP Heater out of service Condition

Items Unit All HP Heater out

of service

Rate output MW 300.115

Steam pressure at the inlet of MSV MPa.(a) 16.67


1







6

Items Unit All HP Heater out

of service

Reheat steam temperature at combined valves 538



Back pressure of condenser KPa(a) 10.05



1.4 Generator

1.4.1 General

The generator is a two-pole, cylindrical rotor type synchronous machine, directly

coupled with steam turbine.

Generator type: QFSN-300-2

Rated output 353MVA/300 MW

Rated voltage 20 kV

Rated current 10189 A

Power factor 0.85 (Lagging)

Speed 3000 r/min

Frequency 50 Hz

No. of phase 3

Cooling method

Stator winding Direct Water cooled

Rotor winding Direct Hydrogen cooled







7

Exciter method Brushless excitation system

Class of insulation Class F with temperature rise limited to class B

Permissible variation in voltage 5%

Permissible variation in frequency - 5.0% to + 3.0%

Max cooling inlet H2 temperature 48 deg C

Noise level 88 dBA at 1.5 m

2 FUEL 2.1 Fuel characteristics

The fuel and its characteristic data is listed below.

2.1.1 Coal Analysis

1







8

Sl.No Proximate Analysis

Design coal Worst Coal

1 Fixed Carbon % 54.82 41.59

2 Volatile Matter % 23.02 20.09

3 Moisture % 11.04 15.01

4 Ash % 11.12 23.31

5 High Heating Value

Kcal/Kg

6300

5977(LHV)

5000

4679(LHV)

1 Carbon % 64.64 49.19

2 Hydrogen % 4.75 4.24

3 Sulphur % 0.30 0.46

4 Nitrogen % 2.24 1.39

5 Oxygen % 5.94 6.40

6 Moisture % 11.04 15.00

7 Ash % 11.12 23.32

8 Grindability index

(HGI)

53 45

9 Initial Deformation

TEMP. C

1180

10 Hemispherical TEMP. 1240






9

Design coal Worst coal

1 Silico 53.3 37.0

2 Alumina 35.3 45.8

3 Ferric Oxide 4.0 10.7

4 Calclum Oxide 2.2 1.69

5 Magnesium Oxide 0.50 0.44

6 Sodium Oxide 0.30 0.08

7 Potassium Oxide 0.50 0.29

8 Tilanium Oxide 1.40 1.27

9 Phosphate pent

Oxide

1.30 0.67

10 Sulphur Trioxide 0.40 0.94

11 Undetemined 1.1

Sieve analysis +60 Mesh 02-0.4%

+120 Mesh 2.5-6.5%

+200 Mesh 8-11%

-200 Mesh 80-90%

Un-burnt % 4.0-18.0

2.1.2 Fuel Oil

2.1.2.1 LIGHT DIESEL OIL ANALYSIS

LIGHT DIESEL OIL (LDO) ANALYSIS AS PER IS 1460, 1995

Viscosity at 40o C Cst 2.5 to 15.7

Density at 15o C kg/m3 920

Flash point, Min o C 66







10

Pour point, Max. 12o C

21 o C

for Winter

for summer

Water content, Max. % vol. 0.25

Sediment, Max. % wt 0.05

Sulphur, Max. % wt 1.8

Ash content, Max. % wt 0.02

Gross calorific value (Approximate) 9950Kcal/kg

2.1.2..2 HEAVY FUEL OIL ANALYSIS

Sl.No. Particulars Unit

Furnace Oil

Grade MV2

(IS : 1593)

1. Flash point Deg. C min. 66

2. Viscosity @ 150C Maxi. Cst 180

3. Pour point 0C 21

4. Ash content by weight % max. 01

5. Free Water content by volume % max. 1.0

6. Sediments by weight % max. 0.25

7. Total sulphur by weight % max. 4.0

8. Calcium PPM 30.5

9. Sodium PPM 10

10. Lead content PPM 0.2

11. Vanadium PPM 40.50

12. Carbon residence (Rams bottom) % wt 7.74

14. Approximate gross calorific value Kcal/kg 10,000

15 SP gravity at 150C Max. 0.933







11

3 COMBUSTION SYSTEM AND SELECTION OF AUXILIARY EQUIPMENT

3.1 Boiler Fuel Consumption The fuel consumption is about 112.6t/h (design coal) and 146.8t/h (worst coal)

per unit at boiler maximum operation condition (BMCR). At TMCR condition it is

103.3 t/h for design coal and 131.9t/h for worst coal per unit.

3.2 Design principle of Flue gas and air system & pulverized coal system

Considering the high volatile matter and easy burning character of the raw coal,

medium speed mill (MSM) (positive pressure)& direct-firing pulverizing system

with cold primary air fan will be adopted based on heat calculation of coal

pulverizing system.

3.3 System Description 3.3.1 Pulverized Coal System

Direct firing, pressurized cold primary air, pulverized coal system with MSM will

be adopted in this project. Six (6) sets of HP863 (not finalized) type MSMs,

electric gravimetric coal feeders (EGCF) and raw coal bunkers will be matched

with each boiler. The output of four (4) MSMs will meet the requirement of boiler

capacity at BMCR with design coal, and has suitable margin, the output of five

MSMs will meet the requirement of boiler capacity at BMCR with worst coal, and

has suitable margin. Raw coal from raw coal bunker via EGCF will be pulverized and dried in the

MSM, then be separated in the MSM separator. There are four (4) pulverized

coal pipes on each separator connected to four corners of boiler burners in the

same layer. Six (6) sets of MSMs correspond to six (6) layer burners of each







12

boiler. Diameter adjustable device will be placed at pulverized coal pipes, so that

the resistance of each pipe is the same.

Each MSM will be equipped with one EGCF. Inlet and outlet motor operated coal

gates with good seal of the feeder can endure the exploding pressure of

0.35MPa, and have the function of self-clean. At the outlet of the bunker there is

a motor operated rack & pinion gate, and the bunker emptying chute will be

equipped between the two gates. The EGCFs have alarms of coal flow break

and block, coal flow monitor etc, so that operator can handle emergency and

ensures safe operation.

Six (6) bunkers will be set for each boiler. The capacity of series of bunkers per

each unit will be normal sufficient to provided 16 hours requirement at boiler

maximum continuous rate with worst coal firing. The coal bunkers are designed

and supplied by JSW.

System design scope will include raw coal pipe and pulverized coal pipe.

3.3.2 Flue Gas and Air System

Direct firing, pressurized cold primary air system with MSM shall be adopted in

the project. The boiler manufactured by Shanghai Boiler Works Co. Ltd (SBWL)

in China shall be of natural circulation, drum type, double pass, water tube,

direct pulverized coal tangential fired, dry bottom, single reheat, balance draft,

and each boiler will be equipped with two (2) axial flow forced draft fans (FDF)

with adjustable moving-blade, two (2) centrifugal induced draft fans (IDF) with

hydraulic coupling, two (2) centrifugal primary air fans (PAF) and two (2) sealing

air fans. During operation, pressurized air shall be forced into furnace. Flue gas

from the furnace shall be induced to atmosphere.







13

Online vibration monitoring system and bearing metal temperature measurement

system shall be provided for all fans and their drive motors .

3.3.2.1 Primary air system

Main function of the system is to feed pulverized coal and primary hot air heated

by air preheater to MSMs. Primary hot air will be acted as dry medium, and cold

primary air to MSMs (boosted by sealing air fan) and EGCFs will be acted as

seal medium. The inlet vanes of centrifugal primary air fan can adjust air flow

and pressure automatically.

Primary air will be heated in air preheater, and be sent to MSMs via common

manifold. Primary air damper will be placed at air preheater inlet and outlet.

When air preheater failure happen, the damper will be closed.

Pressurized cold air from PAFs will be regarded as regulating temperature for

MSMs. The pressurized cold air will be mixed with hot primary air. Mixed air can

meet the temperature requirement of coal dried in the MSM and pulverized coal

at the MSM outlet.

When one MSM failure happens and shuts down, the corresponding pneumatic

damper on primary hot air duct shall be closed immediately. To avoid primary hot

air enter into the duct of primary cold air, motorized damper on the cold duct will

be also closed immediately. Mixed air flow measurer will be installed on the

mixed duct.

The air velocity in air ducts will be 10-12m/s for cold air and 15-25m/s for hot air.







14

3.3.2.2 Secondary air system

The system shall provide air for furnace combusting. Cold air from FDFs shall be

forced into trisector regenerative air preheater, and hot air shall be sent into

secondary air box and be distributed to furnace for combusting.

Two (2) FDFs will be equipped for each boiler. Cold air liaison duct, which

connect two ducts between FDFs downstream; The hot air liaison duct arranged

at air preheater outlet. Secondary hot air box is special design, when one FDF

out of operation, hot air flow to the boiler four corners will be almost equal, so

that stable combusting and reasonable temperature field in the furnace can be

ensured, and will reduce temperature deviation at two sides of boiler.

Damper and air flow measurer shall be placed at hot air duct of air preheater

outlet, when air preheater is out of operation, the damper shall be closed

automatically.

Two trisector regenerative air preheater will be equipped which primary and

secondary air will be heated in it. Also, water washing system and fire protection

system and soot blowing system will be equipped for GAH.

Forced lubrication oil system (with 2x100% capacity pumps, filters, and

associated piping/ accessories) is provided for air preheater.

The air velocity in air ducts will be 10-12m/s for cold air and 15-25 m/s for hot

air.







15

3.3.2.3 Sealing air system

2x100% centrifugal sealing air fans will be equipped in the system, one in

operation and another standby. Sealing air from cold primary air manifold will be

sent into MSMs via seal fan boost. At sealing air fans inlet, air filters and

motorized control dampers will be arranged, when one fan is in operation,

anothers inlet damper is closed. If pressure difference of the filter inlet & outlet

reaches to setting value, the filter will clean itself via pressure difference.

3.3.2.4 Flue gas system

The system consists of two ESPs and two centrifugal induced draft fans (IDF)

with hydraulic coupling.

Flue gas from economizer will enter into two (2) air preheaters, each one

isolating damper will set at the inlet and outlet of each air preheater. When

emergency happens to one air preheater, the respective damper will be closed.

During air preheater start up or shut down, the damper will be opened or closed.

Flue gas from air preheater enters into ESP with double path, six electric-fileds.

Each boiler will be equipped with two ESPs. Isolating Guillotine type gates will

be placed at ESP inlet & outlet. Fluel gas via ESP, IDF & chimney will be vented

into atmosphere.

Isolating dampers will be placed at IDF inlet & outlet. When IDF failure happens,

it will be overhauled after the dampers closed. During IDFs starting up or

shutting down, the damper will be opened or closed.

Two (2) ID fans are in operating.

1

1







16

The GAH outlet flue gas velocity in gas ducts will be 10-20m/s.

3.4 Calculation results

The results are based on design coal for one boiler at MCR and it can adapt the

characteristic data range of the coal.

3.4.1 Pulverized coal system

NO. Item Symbol Unit Value

(For one unit)

1 Boiler coal consumption (BMCR) Bg t/h 112.6

2 Hard grove grindability index HGI / 53

3 Maximum Size of raw coal at inlet of mill dmax mm






17

NO. Item Symbol Unit Value

(For one unit)

36.72(worst

coal)

7 Medium speed mill max output BSJ t/h 43.1

8 Medium speed mill rated inlet air flow Qv t/h 72.12

9 Primary air temperature at outlet of GAH tkr C 306

10 Air temperature at inlet of medium speed mill t1 C 214(design coal)

239(worst coal)

11 Ratio of air and coal mass at inlet of medium

speed mill / kg/kg

2.28(design coal)

2.31(worst coal)

12 Temperature at outlet of medium speed

mill tm C 80

13 Mill reject rate %






18

Design

coal

Worst

coal

1 Theoretical air volume for combustion (per kg coal) V Nm3/kg 6.8174 5.2988

2 Volume of combustion result at the

outlet of furnace Vy Nm

3/kg 8.7713 6.9371

3 Air temperature at inlet of GAH t 'kg C 35 35

4 Air temperature at outlet of GAH tky C 304 302

5 Flue gas temperature at outlet of

GAH ( corrected) tpy C 138.3 137.2

6 Flue gas volume at outlet of GAH Vy m3/s 455.92 466.18

7 Flue gas excess air coefficient at

outlet of GAH Apy / 1.283 1.283

3.5 Major Auxiliary Equipments Selection

3.5.1 Pulverized coal system

Six (6) medium speed mills and six (6) coal feeders will be furnished for each

boiler. These will be of sufficient capacity to attain the MCR of the steam

generator when boiler firing any specified coal with any one mill out of service. In

other words, when firing the performance coal, four (4) mills will be in operation

and two (2) will be standby, and when firing the worst coal, five (5) mills will be in

operation and one (1) will be standby, together with its associated feeders.

Because of the positive pressure in the mill and coal feeder, two (2) sealing air

fan are furnished to supply the sealing air to avoid the powder leaking.







19

The maximum capacity of mill shall be 43.1 TPH corresponding to 53 HGI,

70% through 200 mesh and moisture content 11.04 %.

Value NO. Item Unit


1 Type of MSM HP863

2 Grindability Index HGI 53 45

3 Moisture(AR) 11.04% 15

4 Powder fineness mesh 200 70% 70%

5 Maximum capacity of mill(HGI=53,

70% through 200 mesh) t/h 43.1 40.8

6 Minimum capacity of mill t/h 10.78 10.2

7 Mill loading % 65.5 71.6

8 Max. air flow rate t/h 72.12

9 Max. resistance kPa 4.5

10 Inlet temperature of mill 214 239

11 Outlet temperature of mill 80 80

12 Inlet air/ inlet coal Kg/Kg 2.28 2.31

13 Rotary speed r/min 38.7

14 Shaft power of mill (BMCR) KW 250 274

1







20

Value NO. Item Unit


15 Rated power of motor KW 400

16 Voltage KV 6.6

17 Gravimetric coal feeder t/h 40

18 Coal feed distance (from feeder

inlet to feeder outlet) mm 2200

3.5.2 Flue gas and air system

Each boiler will be furnished with two (2) sets of primary air fantwo (2) sets of

forced draft fan and two (2) sets of induced draft fan. These fans will be

designed for outdoor installation. Under normal operation, all of PAF,FDF and

IDFwill be in operation. The fans sizing are based on the flow and total pressure

at BMCR conditions with a specific margin as below:

Value NO. Item Unit


1 Primary air fan (2x60%BMCR)

A Type Double suction

centrifugal







21

Value NO. Item Unit


B QBMCR100BMCR with 35 degree

ambient temperaturel m3/s 46.7 57.3

C PBMCR Pa 10907 11913

D

QTB (test block, 60BMCR with 5

degree above maximum ambient

temperature

m3/s /

73.5

E PTB(test block, considering 30%

margindesign coal) Pa / 15934

Speed rpm 1500

F Motor ( with 15 % margin) kW later

G Voltage kV 6.6

2 Primary air fan (2x60%BMCR)

A Type Adjustable moving-

blade axial flow


ambient temperaturel m3/s 109.9 99.8

C PBMCR Pa 3179 3043

1







22

Value NO. Item Unit


D


degree above maximum ambient

temperature

m3/s 148

/


margin,design coal) Pa 4133 /

F Speed rpm Later

G Motor ( with 15 % margin) kW later

H Voltage kV 6.6

3 Sealing air fan (2x100%BMCR)


centrifugal

B Rated flow m3/h 42221

C Rated head Pa 6382

D Motor kW 132

E Voltage kV 0.415

4 Induced draft fan (2x60%BMCR)


centrifugal type

1







23

Value NO. Item Unit



ambient temperature m3/s 239

244

C PBMCR Pa 3738 3775

D


degree above flue gas temperature

margin)

m3/s / 329


margin) Pa / 4908

G

Motor (The motor rating shall be

arrived at considering 15% margin

over the duty point input or 10% over

the maximum demand of the driven

equipment, whichever is higher,

considering highest system

frequency)

later

H Speed rpm later

I Motor kW 2240

J Voltage kV 6.6

Two (2) electrostatic precipitators (double-pass, six electric field) are equipped

for each boiler, The ESP remove particulate from the boiler flue gas to achieve a

guaranteed outlet emission of less than 75 mg/Nm3 with all fields in service,and

100 mg/Nm3 with one field out of service when fired with specified coal range.

1







24

Air in leakage through ESP of the total gas flow is less than 3 %.

No Electrostatic precipitator Unit Value

(design coal)

Value

(worst coal)

1 Double-pass, electric fields

2 Flue gas flow (including 10%

margin and 10 margin,design )

m3/s

per unit 522 534

3 flue gas temperature(including 10

margin,design coal) 145.9 145.4

4 Inlet dust concentration g/Nm3 10.5 29.2

5 Outlet dust concentration mg/Nm3 75 75

6 Efficiency of ESP /

A With (n-1) field in service % / /

B With n field in service % / /

3.5.3 Boiler Igniting and Fire Stabilizing Oil System

The oil of the boiler igniting is diesel oil and fire stabilizing is HFO, and the boiler

ignition mode is high-energy ignition.

The system will be furnished with two 200m3 HFO daily oil tank, one 50m3 LDO

daily tank for both units. (These oil tanks are in the scope of JSW, the capacity

and quantity of tanks will be finalized by JSW/TCE ). 1







25

Two motor-driven HFO oil transfer pumps per unit (one operation and another

standby); Three motor-driven LDO oil transfer pumps and other associated

equipments are common for two boilers. All these equipments are arranged

centralized and located nearly the oil tank area.

Light diesel oil pump capacity: Q8 t/h H450m (Total 3 sets for two units) Heavy fuel oil pump capacity: Q25.4 t/h H290m (Total 4 sets for two units) 3.6 Pyrites handling system Pyrites quantity(not finalized):

Quantity(t/h)

1X300MW 0.11

2X300MW 0.22

Mechanical system will be used for pyrites handling. For details please see

drawing 50-F127C1-J01-36 Pyrites Handling System Diagram.

In each shift, pyrites discharged from each mill will be hold in pyrites hopper for

unloading to chain conveyor by screw conveyor. Pyrites will be conveyed out of

the boiler by chain conveyor then to be lifted to pyrites bunker by bucket elevator

to make pyrites discharge into a truck for further transportation to ash yard.

volume of each bunker is about 20m3. Chain conveyor is located below ground,

each chain conveyors capacity is 10-15t/h. Mechanical system will operate

about one(1) hour each eight(8) hours.

4 THERMAL SYSTEM AND SELECTION OF AUXILIARY EQUIPMENT

4.1 Design principle of Thermal System

1







26

The thermal system will ensure the security, economy and flexibility of the unit.

All of the systems are unit system except auxiliary steam system.

4.2 System Description

4.2.1 Main steam, reheat steam and bypass system

The pipe sizing shall be as per ASME B31.1 and velocities shall be limited to the

values mentioned in specification.

In addition to above, when steam turbine at 100% TGMCR guarantee point :

pressure drop in main steam line from superheater outlet to steam turbine stop

valve is about 5.5 bar; overall pressure drop between HP turbine exhaust and IP

turbine interceptor valves for reheater circuit shall be less than 10% of HP

turbine exhaust pressure

4.2.1.1 Main steam system

Main steam system will convey superheated steam from the superheater outlet

to the HP main steam stop valve. Main steam is unit system. Main steam flow

through single pipe from outlet of boiler superheater header, and then divided

into two branches and connects to left and right main HP steam stop valve

separately.

1) A Motor operated Main steam isolation valve with motor operated integral

bypass valve is set on main steam pipe near boiler outlet for boiler hydraulic test

as well as for normal operation.







27

2) One branch leads to gland steam system as HP steam source when normal

gland steam pressure is too low and one branch leads to turbine casing steam

heating header as heating steam source before turbine startup, another branch

leads to auxiliary steam header when the cold reheat pipe pressure is

inadequate or not available.

3) To prevent water from entering turbine, drain system is set to discharge

condensate water of main steam pipe during warm-up and shut-down. Drain

points are set at the lowest points on main steam pipe. A pneumatic drain valve

and a hand-operated valve are set on drain pipe of each drain point. Drain water

is led to drain flash tank. All drains including drain pot shall be checked with

respect to ASME TDP guideline for turbine water damage protection.

4) Two spring safety valves, Two solenoid PCVs and two motorized venting

valves are set on main steam pipe near superheater outlet.

4.2.1.2 Reheat steam system

Reheat steam system will convey cold-reheat steam from HP casing exhaust

spout to inlet of boiler reheater and convey hot-reheat steam from outlet of

reheater to IP main steam stop valve. Reheat steam is unit system.

One cold reheat steam pipe is connected from turbine HP casing exhaust pipe

and divided into two pipes in front of boiler, then connect to two inlets of boiler

reheater header separately.

Two hot reheat steam pipes are connected at two end of outlet header of boiler

reheater and join one pipe at front of boiler, and divided into two pipes again in

front of turbine, then connect with left and right IP steam stop valve.







28

1) To prevent steam from flowing back into turbine, one pneumatic check valves

is provided on cold-reheat pipes;

2) Desuperheaters are set on the pipe of reheater inlet, to adjust steam

temperature of reheater outlet under emergency condition. Desuperheating

water come from intermediate stage extraction of BFP.

3) Hydraulic test valve is set on each cold-reheat steam pipe near reheater inlet

to prevent pressurized water entering cold-reheat pipe during hydraulic test of

boiler.

4) To prevent water entering turbine, one drain pot is set on the pipe near HP

casing exhaust spout. A pneumatic valve is set on drain pipe to automatically

control drain water into condenser in time.

5) One spring safety valve are set on each cold-reheat pipe near reheater inlet

separately.

6) A hydraulic test valve is set on hot-reheat main pipe to make sure that the

pressurized water is stopped during boiler reheater hydraulic test and cant enter

into the hot reheat pipes.

7) One pipe connecting the outlet of HP bypass valve and the inlet of LP bypass

valve is set to form the heat circuit by pressure difference which is able to warm

the outlet of HP bypass valve and pipe, the inlet of LP bypass valve and pipe.

8) Three spring safety valves are set on hot-reheat pipe near reheater outlet, its







29

set pressure is lower than the spring safety valve on cold-reheat steam pipe near

reheater inlet, so the former will open before the later when over pressure

happens to ensure enough steam through reheater and avoid over heating of

reheater.

9) Drain points are set on hot-reheat steam pipe branches after tee to remove

condensate water during startup and shut-down. Drain water enters into

condenser. A pneumatic valve and a hand-operated valve are set on each drain

pipe.

4.2.1.3 Bypass steam system

The capacity of bypass system is 60% BMCR. HP & LP bypass valves shall be

of angle type and combined throttle cum spray valve, bypass valves and spray

control valves are hydraulic operated valves. This system can convey main

steam bypass HP-casing to cold-reheat piping and convey hot-reheat steam

bypass IP&LP-casing to condenser when unit startup, shutdown and other

various operating modes. TG set is capable of operating on house load during

sudden total export load throw-off and in the event of turbine trip and generator

breaker open, HP-LP bypass system will open automatically. The leakage class

of valves shall be minimum class V. For Spray valve Trim exit velocity of liquid

shall not exceed 30m/s.

1) Desuperheating water of HP bypass is from feed water system, one control

valve and one isolation valve are set on desuperheating water pipe.

2) LP-bypass system is connected with HP-bypass system in series to achieve

the function of whole bypass system. One upstream and one downstream







30

isolation valves are provided for LP bypass spray control valve.

3) One drain pot is set at the lowest point downstream of LP-bypass valve. A

pneumatic valve is set on each drain pipe.

4) Desuperheating water of LP-bypass is from condensate water system.

Table 4.2.1

Item Name Diameter Material Velocity (m/second)

1 Main steam pipe ID368.341.275 A335P91 50

ID273.05x30 A335P91 45

2 Hot reheated steam pipe ID679.5X32 A335P22 67

ID50824.8 A335P22 60

3 Cold reheated steam pipe 812.822.225 A672B70CL32 33

558.816 A672B70CL32 35

4.2.2 Feed-water system

HP feedwater system is unit system. The function of this system is to pump

deaerated feed-water from deaerator water tank to inlet header of boiler

economizer. Feed water is heated to the given temperature in HP-heaters by

turbine extraction steam to improve heat efficiency of the units. There are three

50% capability motorized variable speed feedwater pump in this system, during







31

normal operation, two pumps work and one pump is standby.

The main boiler feed pump and booster boiler feed pump shall be manufactured

of following or superior materials

a) Outer casing Forged Carbon steel

b) Inner casing ASTM A743 CA 6 NM

c) Impellers ASTM A743 CA 6 NM

d) Wearing rings 13 - 17% Chrome steel (Material shall be non-galling

type with differential hardness not less than 100 BHN)

e) Stuffing box bushing & Stuffing box 13% chrome steel

f) Pump shaft 13% Forged chrome steel

g) Shaft sleeves Stellite on 13% chrome steel

h) Base plate Structural steel

i) Diffuser / Volute 13% chrome steel

j) Strainer Stainless steel mesh

k) Hydraulic Coupling

1) Make Voith

2) Coupling wheels & casing Alloy steel

3) Scoop tube Stainless steel

l) Balancing drum ASTM A 182 Grade F6 a

One full flow motorized orifice valve and one full flow motorized gate valve is

located in major feedwater pipe. When the orifice valve in operation, the orifice

valve can be reduce openning by manual remotely in control room when boiler

load is






32

There are three HP heaters. HP heaters are horizontal type. Bypass piping will

be provided to divert feedwater flow around any of the high-pressure heater for

heater isolation of the respective each unit. All bypass and isolation valves will

be motor operated.

Feedwater system can be divided into three parts: LP feedwater, IP feedwater,

and HP feedwater pipes.

1) LP feedwater pipes

Pipes between the outlets of feedwater tank and the inlets of booster pumps are

called LP feedwater pipes. There are motorized valve and strainer on each

pipe. When startup, the strainer can separate the welding slag, impurities etc.,

which were accumulated in feedwater tank, and LP feedwater pipes during

erection and maintenance to protect feedwater booster pumps.

2) IP feedwater pipes

Pipes between the outlets of booster pumps and the inlets of feedwater pumps

are called IP feedwater pipes. Each pipe has a flow metering nozzle to

measure the feedwater flow at the inlet of feedwater pump in order to control

opening and closing of minimum flow unit at the outlet of feedwater pump. There

are also filters in these pipes in order to protect feedwater pumps.

3) HP feedwater pipes

Pipes between the outlets of feedwater pumps and inlet header of boiler

economizer are called HP feedwater pipes, which pass through HP heaters.







33

There are one check valve and one motorized gate valve at the outlet of each

feedwater pump. In order to prevent cavitation of booster pump, one

recirculation pipe is extracted from the feedwater pipe and connected to the

deaerator which has one minimum flow unit including a pneumatic control valve,

two manual valves and one check valve. Signal of the minimum flow unit comes

from the flow metering nozzle at the outlet of booster pipe. Each feedwater pump

has a recirculation pipe which is connected to deaerator.

The interstage extractions from each feedwater pump are collected together and

flow to the reheater attemperator as emergency desuperheating water to adjust

steam temperature of reheater.

One pipe is branched from outlet manifold of feedwater pumps and connected to

boiler superheater primary and secondary spray attemperator. Another pipe is

branched for HP bypass control valve. The former adjust superheating steam

temperature and the latter adjust main steam temperature to cold reheat steam

system.

The feedwater control station is located between outlet of HP heaters and inlet

header of boiler economizer.

One full flow motorized orifice valve and one full flow motorized gate valve is

located in major feedwater pipe. One check valve is located at inlet pipe of

economizer.

The capacity of bypass is 30% rated feedwater flow which adjusts feedwater flow

when unit startup and low load operation.







34

Two motorized isolating valve are located in boiler filling bypass pipe.

One pipe is branched from the economizer inlet heater to drum as the

economizer recirculating water pipe.

Table 4.2.2

Item Name Diameter Material velocity(m/s)

1 HP feed water common pipe 355.630 15NiCuMoNb5-6-4

(EN10216-2)

(DIN17175-79)

5.3

2 HP feed water branch pipe 244.5x20 15NiCuMoNb5-6-4

(EN10216-2)

(DIN17175-79)

4.8

4.2.3 Extraction steam system

The system extracts steam from steam turbine to specified heating device and

increases the temperature of condensate water and feed-water so as to raise

thermal efficiency of the power plant.

There are 8 stages non-adjustable extraction of the steam turbine. Extraction

No.8&7&6 supply steam to three (3) HP heaters, extraction No.5 supplies steam

to deaerator. Extraction No.4&3&2&1 supply steam to four (4) LP heaters. LP

heaters No.2 and No.1 are combined heaters which are located at neck of

condenser.

Pneumatic-driven check valve and motor-driven isolation valve are set in each

1







35

extraction pipe except No2&1 extraction pipes. To prevent condensate water

entering into steam turbine to harm it during startup, shutdown & low load, drain

water pipe is set at the low point of each extraction pipe, near the valves.

Item Name Diameter Material Velocity (m/second)

1 No. 8 extraction pipe 19410 12Cr1MoV 41

2 No. 7 extraction pipe 2197 20 39

3 No. 6 extraction pipe 2739 12Cr1MoV 36




4.2.4 Condensate water system

The system conveys condensate water from hot well of condenser to deaerator

through gland steam condenser and four LP heaters to ensure safe operation

and improve circulation heat efficiency. Beside these, the system also provides

desuperheating water, make-up cooling water and other miscellaneous water

requirements.

The system is unit system. There are two (2) 100% capability vertical

Condensate extraction pumps in the system.

Main control valve, auxiliary control valve and their bypass valve are set on

condensate water pipe before No.1 LP heater to ensure water level control of







36

deaerator under all kinds of condition.

Recirculation pipe at the gland steam condenser outlet pipe is set for the

minimum flow when Condensate extraction pump is startup or the unit runs at the

low load. One water discharge pipe branches from No.4 LP header outlet pipe is

set to discharge unqualified water during startup.

Return water pipe to condenser make-up water tank (surge tank) from the outlet

of condensate extraction pump is set for collecting water when the condenser

hot well water level is high.

There are branches at the low pressure desuperheating water pipe such as

desuperheating water pipe to fuel oil sweeping steam desuperheater turbine

gland steam desuperheater, LP-bypass desuperheater, third-stage pressure and

temperature reducer, LP casing spray, HP emergency drain flash tank; and also

the make-up water pipe of closed circuit cooling water expansion tank.

Pipe is set to generator stator cooling water tank and vacuum pump startup

make-up water from condensate water.

4.2.5 Heater drains and vents system

The functions of the system is recovering condensed water from heating steam

of each HP heater and overflow & drain water of the deaerator, recovering

condensed water of LP heater and gland steam condenser, removing non-

condensable gas in HP heaters, LP heaters and deaerator. The normal cascade

HP heater drain pipes from No.8, No.7 and No.6 HP heater to deaerator, LP

heater drain pipes from No.4,No.3,No.2 and No.1 LP heater to condenser.

Emergency drain pipe from each HP heater to emergency drain flash tank which







37

attach to condenser, and LP heaters to condenser. Non-condensable gas pipes

from each HP heaters to deaerator and from each LP heaters to condenser and

from deaerator vent to atmosphere. Over flow pipe will maintain normal water

level of feed-water tank and discharge pipe can empty water in case of

maintenance. Control valve is designed in each drain pipe to control water level.

Normal drain water from HP heaters cascade to deaerator. Emergency drain

pipes are set for each heater and respectively led to emergency drain flash tank

or deaerator in order to ensure smooth drain and keep normal level in case that

high water level in HP heaters appears or HP heater is out of service.

Normal drain water from LP heaters cascade to condenser; Pipes for emergency

drain water of each LP heater can ensure smooth drain to condenser when water

level in LP heater is high or at low load or its downstream LP heater(s) is (are)

out of service.

Control valve is designed in each drain pipe of HP&LP heaters to control water

level.

Multi-stage water sealing device is set in the drain piping of gland steam

condenser to ensure smooth drain to main condenser in all operating conditions.

4.2.6 Auxiliary steam system

Auxiliary steam system provide steam to deaerator when start-up, low-load and

trip, provide steam to boiler bottom heating, provide steam to turbine gland

steam system when start-up and standby, provide steam to soot-blower when air

preheater start-up, and provide steam to mill inerting steam and fuel oil system.







38

Auxiliary steam is taken from cold reheat pipe at normal operation. During unit

startup, shutdown and when cold reheat pipe pressure is inadequate, the steam

is taken from main steam pipe. When the unit start up, start-up steam will be

provided from the existing 2*130MW thermal power plant. JSW/TCE indicated

that the parameters of the steam from the existing unit will be about 9.0 bar (g)

and 280 Deg C at the terminal point. The terminal point location shall be 1m from

the turbine building Column -1 between B-C row. There is a interconnection of

auxiliary steam headers between the two units, so the auxiliary steam can be

provided when one unit is startup and another is in service. Steam header has

continuous drain pipes, it can drain condensed water of header to condenser.

One auxiliary steam header is provided for each unit. The pressure of auxiliary

steam header is about 1.20MPa and temperature is about 320 0C in normal

operation. Two safety valves are set on the header with different pressure

setting.

The source of auxiliary steam come from cold reheat steam pipe at normal

condition and main steam pipe when unit startup, shutdown or cold reheat pipe

pressure is inadequate. However if steam is required for pre commissioning/

commissioning of first unit, auxiliary steam source shall be arranged by JSW.

4.2.7 Condensate make-up water system

Condensate make-up water system will fill condenser and boiler and deaerator

with water before the starting of unit, and complement water to hot well when

operating. Beside these, the system will supply sealing water for condensed

pump, make-up water for HVAC system, make-up water for vacuum pump and

etc.

1







39

4.2.8 Vacuum system

The function of this system is extracting the non-condensable gas from

condenser and maintain rated vacuum in condenser during normal operating

condition. The vacuum will be break to protect turbine during emergency. Two

vacuum pumps are set in this system. Before unit startup, two pumps will operate

in parallel to establish vacuum as fast as possible (17 minutes reach to 35KPa).

Under normal operation, one pump is in operation and another is standby.

Mixture of steam and air is extracted from condenser. Uncondensed gas

exhaust to atmosphere.

There is one vacuum breaker pipe at neck of condenser. During the unit load

rejection, air admission valve will be opening to break vacuum in condenser and

decrease rotating speed of turbine, then shorten time of turning by inertia to

protect turbine. This will be used only in emergency case.

4.2.9 Condenser tube cleaning system

JSW not adopt.

4.2.10 Closed cycle DM water system

Closed cooling water shall be used to turbine auxiliary equipments and boiler

auxiliary equipments such as generator hydrogen cooler, turbine lube oil cooler,

generator stator water cooler, BFP motor cooler, the bearing of equipments, etc

The closed cooling water for auxiliary equipments is demineralized water.

1

1







40

Chemical department will guarantee the water quality. The demineralized water

is pumped by the closed cooling water pumps and is sent to the heat exchanger

in which the demineralized water is cooled by the Aux. cooling water. 3x50%

CCW pumps and 2x50% PHEs shall be provided for CCW system.

Demineralized water will be sent to the equipments and return to the inlet of the

cooling water pumps. An expansion water tank with volume 10m3 is set to meet

the needs of volume change of cooling water caused by water temperature. The

water tank will be arranged at a high place to gives the closed cooling water

pump sufficient NPSH. Make-up water of the system is from outlet of condensate

water pump in normal condition and from condensate make-up water system in

emergency condition. The make-up water is led to expansion water tank with

control valve for water tank level set in the pipe.

4.2.10 Boiler blowdown and drain system

1) Continuous blowdown system

Drum will continuously blowdown some unqualified boiler water to continuous

blowdown tank to separate steam and water, steam flow into deaerator and

water is discharged to intermittent blowdown flash tank. When continuous

blowdown flash tank is failure during operation, blowdown water will flow through

bypass to intermittent blowdown flash tank directly. If quality of boiler water is

getting worse, this bypass can also be used to increase continuous blowdown

water flow.

2) Boiler intermittent blowdown system

According to quality of boiler water, the water accumulated in bottom headers of







41

boiler with some deposits will be discharged intermittently. This water will be

discharged to intermittent blowdown flash tank directly. After steam water

separate in tank, steam is exhausted to atmosphere. The water in intermittent

blowdown flash tank then discharge to a concrete pit underground and mixed

with cooling water there, then discharged out.

3) Drainage and discharge system

Drainage and discharge pipes of each header would collect together to drainage

manifold in boiler house during startup and shutdown, and then water is

discharged to boiler intermittent blowdown flash tank.

4.2.11 Steam turbine lube oil and Lube oil handling system

Steam turbine lube oil system will supply lube oil to the bearing of steam turbine

and generator, with main oil tank, oil pumps, oil coolers etc.

4.2.12 Lubrication Oil System

The function of the lubrication system is to :

Provide oil to lubricate the turbine and generator journal bearings .

Provide oil to lubricate the thrust bearing

Provide oil to lubricate the turning gear .

Provide oil pressure for the generator hydrogen seal oil system .

Provide oil pressure for the governor system

The lubrication oil system is a closed system using oil stored in a reservoir which







42

is pumped to various points of use. the lubrication system uses both shaft-driven

and motor-driven pumps .A shaft-driven pump in the turbine governor

pedestal ,together with oil ejector in the reservoir ,pumps the oil when the turbine

is operating at or near rated speed .Motor-driven pumps are used when the main

oil pump and oil ejector cannot supply sufficient oil pressure. The system uses

two oil coolers to regulate the temperature of the lubricating oil system for the

turbine generator unit consists of the following major components:

Lubrication oil reservoir :

Turbine shaft driven main oil pump oil ejector

Auxiliary motor driven oil pumps

Vapor extractors

oil coolers

Oil piping

Protective devices

Bearing lift oil system

The lubrication oil reservoir is a steel tank in which the lubrication oil is stored.

Mounted on the reservoir are the auxiliary motor driven pumps, vapour extraction

system, level sensors, pressure transducers, and pressure gages .the oil ejector

uses high-pressure oil from the main oil pump discharge to pick up oil from the

reservoir when the unit is operating at or near rated speed .Strainers on the oil







43

ejector intake ,auxiliary oil pump suctions ,and oil return drain help to prevent

particle contaminants from circulating through the system. The Reservoir is

provided with man way access openings on the top of the shell and a drain

connection on the bottom.

The main oil pump is a volute-type centrifugal pump mounted horizontally on the

turbine extension shaft in the governor pedestal area. At or near rated turbine

speed, the main oil pump supplies all of the oil requirements of the lubrication

system. Provide oil pressure for the governor system and provides two source of

backup for the generator hydrogen seal oil system.

The oil ejector is mounted inside the oil reservoir. The inlet is supplied with high-

pressure oil from the discharge of the main oil pump when the turbine generator

is at or near rated speed. One outlet, the oil is directed through the oil coolers to

the turbine generator bearings. The other outlet supplies the inlet side of the

mail oil pump with oil.

The bearing oil pump (BOP) is an AC motor-driven centrifugal pump, vertically

mounted on the top of plate of the oil reservoir which is used at startup and

shutdown. During startup, the BOP is placed in service before the unit is put on

turning gear operation. It stays in service until the main oil pump can satisfy the

system oil requirements.

The emergency oil pump (EOP) is a DC motor-driven centrifugal pump which is

identical to the BOP except for the motor. The EOP serves as a backup to the

BOP in case of AC power failure.

The seal oil backup pump (SOB) is an AC motor-driven gear pump, horizontally







44

mounted on the top of the oil reservoir which is used during startup and

shutdown of the turbine generator when main oil pump discharge pressure is too

low to meet the oil pressure for the governor system and the generator seal

system high-pressure oil backup requirements.

Two vapor extractors are supplied for the reservoir, one vapor extractor is

normally operating and the other vapor extractor is on standby. The main

function is to remove oil vapors and maintain a slight vacuum at the turbine

pedestal, bearing housings, oil reservoir, and oil guard piping system.

The lubrication oil system includes two full-size oil coolers to maintain an

acceptable temperature range of oil to the bearings while the system is in

operation. The coolers are identical in construction. One cooler is used during

normal operation and the other cooler is kept on standby. Valves between the

two coolers direct oil flow from reservoir to the selected cooler.

Design basis of oil system

The Main oil tank capacity shall provide a minimum of 8 minutes retention time.

There shall be a minimum of 0.023 m2 of free oil surface for each lpm of normal

oil flow.

Turbine unit oil purification system shall be of centrifuge type. The hourly

conditioning capacity shall be equivalent to 20 percent of the combined capacity

of the main oil tank at operating level plus the oil in the lubricator system that

flows back into the main oil tank during a shutdown of the turbine each hour. The

equipment shall be designed to meet all lube oil purity requirements established

by the turbine generator manufacturer and ASME Standard 118. The oil







45

conditioning equipment shall be designed to provide for removal of particulate

matter greater than 10 microns absolute and all free water in accordance with

ASME.

In addition to unit oil purification ( centrifuge type) , a common turbine oil

purification system for both unit comprising of Dirty oil tank, Clean oil tank,

Purification system, two convey pump, one cleaning oil pump and one dirty oil

pump set will be provided.

Lube oil handling system will handle the unqualified lube oil before unit startup

or under normal operation. The lube oil volume of steam turbine is 32m3, so a

48m3 dirty oil tank and a 48m3 clean oil tank is set in this system, with water

coalescer type oil purifier and lube oil transfer pump.

4.3 Major Auxiliary Equipment Selection

4.3.1 Feed-water pump

Each unit will be furnished with three 50% capacity motor-driven variable speed

feed-water pump with hydraulic coupling. Two pumps are working at normal

operation and one pump is standby. Three booster pumps are set for each feed-

water pump.

The capacity of the pumps is regulated by throttling pump discharge across a

feedwater regulator. The pumps are capable of operating satisfactorily at

deliveries ranging from minimum recirculation flow to the maximum specified.

The pumps furnished for each installation is operate satisfactorily both in two







46

pump parallel operation and single pump operation and when bringing in or

taking a pump out of service with one or two other pumps in service.

During startup and low load operation, when the variable speed drive cannot

provide the required feedwater flow control, a low load regulating valve is used.

The low load regulating valve is bypassed.

Boiler feed pumps design is based on 110% feed water flow at BMCR. Pump is

designed for complete frequency range of 47.5 to 51.5 Hz during normal

operation. Pump and motor are provided with online vibration monitoring system

and bearing metal temperature measurement.

BFP SIZING DATA SHEET

No Name Symbo

l Unit

Calculation &

Remark BMCR

TMCR

(3%MU)

Technical

evaluatio

n sheet

A BFP inlet suction flow

1 Maximun steam flow G1

t/h

HBD from

Shanghai

steam turbine

works

1015 920.593

2

BFP gland seal

discharge and injection

flow difference

G2 t/h 2 2

3 Interstage flow for RH

spray G3 t/h

Data from

Shanghai boiler

works Co.ltd

42 42

4 Total suction flow of

BFPs G4 t/h

G4=G1*110%+

G2+G3 1160.5 964.593







47

No Name Symbo

l Unit

Calculation &

Remark BMCR

TMCR

(3%MU)

Technical

evaluatio

n sheet

5 Feedwater specific

volume m3/kg

According to

HBD 0.001119 0.001119

6 Feedwater density kg/m3 =1/ 893.66 893.66

7 Capacity of each BFP G t/h G=G4/2 580.25 482.3

Q m3/h Q=G**1000 649.3 539.7

BFP suction flow m3/h 650 550

8 Interstage flow of BFP Q1 m3/h

Q1=G3**1000

/2 23.5 23.5

m3/h 30 30

9 BFP booster pump

suction flow Q2 m3/h

650 550

B BFP head

1 Pipe and equipments pressure drop

a

Pipe pressure drop from

deaerator tank outlet to

economizer inlet

PPIPE Mpa P LP

P IP+ P HP 0.876 0.734

Mpa Considering 20

margin 1.051 0.881

b Equipment pressure drop

HP heaters P EQUI

P Mpa

0.1*3 (3 HP

heaters) 0.3 0.3

Mpa Considering 20

margin 0.36

Total pressure drop from

deaerator tank outlet to

ecoonmizer inlet

P1 Mpa P PIPE+ P EQUI

P 1.411 1.181







48

No Name Symbo

l Unit

Calculation &

Remark BMCR

TMCR

(3%MU)

Technical

evaluatio

n sheet

2

Water differential

pressure between

economizer inlet and

deaerator tank normal

water level

P2 Mpa (29.5-

24.8)*9.81/ 0.041 0.041

3 Drum safety valve

relieving P3 Mpa

According to

data sheet from

boiler works

20.4

Total pressure drop from

economizer inlet to

drum

0.45

Economizer inlet

feedwater pressure at

MCR condition

18.78

4 Rated working pressure

of deaerator(neagative) P4 Mpa

From HBD -0.814 -0.778

Total head of BFP P Mpa

P= P1+ P

2+ P3+ P4 21.487 19.224

C BFP sizing result Head P mH2o 2454 2200

Suction flow Q m3/h 650 550

Note: all these data is primary data for the selection of BFP.

NPSH calculation for BFP

No. Name Symbol Unit Calculation Data 1 BFP flow W kg/s SG BMCR condition 294.200

1

1

1







49

2 Water weight from deaerator to BFP booster pump

a) Pipe length of BFP booster pump A LP feedwater pipe L1 m 35.64

Water weight of one meter in pipe Q1 kg/m 325X8 67.02 Total weight of water G1 kg L3XQ3 2388.59

b) Pipe length of BFP booster pump B LP feedwater pipe L3 m 37.1

Water weight of one meter in pipe Q3 kg/m 325X8 67.02 Total weight of water G3 kg L3XQ3 2486.44

c) Pipe length of BFP booster pump C LP feedwater pipe L2 m 55.62

Water weight of one meter in pipe Q3 kg/m 325*8 67.02 Total weight of water G2 kg Q3L2 3727.65

d) Water weight from deaerator to BFP booster pump MS kg Normal operation is two BFP, Ms= G3+G2 6214.09

3

Water weight in condensate pipe from No. 4 LP heater to deaerator

a) Pipe length L m 71.3 Water weight of one meter in pipe Q1 kg/m 325*8 69.55 Total weight of water Gs1 kg LQ1 4958.92 Total weight of metal Gi kg 325*8 weight: 62.542kg/mL 4459.24

b) Operation weight of No. 4 LP heater Gb kg Data of manufactory 16380

Total metal weight of No. 4 LP heater Gc kg Data of manufactory 12820

Total water weight of No. 4 LP heater Gs2 kg 3560

Convert coefficient of metal Gs3 Convert coefficient: C'=0.1185 0.1185 Weight of valve Gcf kg Valve handbook 1600

c) Water weight in condensate pipe from No. 4 LP heater to deaerator ML kg Gs1+Gs2+0.1185(Gi+Gc+Gcf) 10756.11

4

Water weight in condensate pipe from No. 2 LP heater outlet to No. 4 LP heater inlet

a) Pipe length from No. 2 LP heater outlet to No. 3 LP heater inlet L2-3 m 89

b) Pipe length from No. 3 LP heater outlet to No. 4 LP heater inlet L3-4 m 56.9

Water weight of one meter in pipe Q1 kg/m 325*8 72.06c) Water weight of L2-3 and L3-4 Gs1 kg (L2-3+L3-4)Q1 10513.55







50

d) Metal weight of L2-3 and L3-4 Gi kg 3258 weight: 62.542kg/m*(L2-3+L3-4) 9124.88

e) Operation weight of No. 3 LP heater Gb3 kg Data of manufactory 14920

Total metal weight of No. 3 LP heater Gc3 kg Data of manufactory 11850

Total water weight of No. 3 LP heater Gs2 kg 3070

6) Operation weight of No. 1&2 LP heater Gb2 kg Data of manufactory 48345

Total metal weight of No. 1&2 LP heater Gc2 kg Data of manufactory 36320

Total water weight of No. 1&2 LP heater Gs3 kg 12025

Convert coefficient of metal C' C'=0.1185 0.1185 Weight of valve Gcf kg Valve handbook 3200

Water weight in condensate pipe from No. 2 LP heater outlet to No. 4 LP heater inlet Mc kg

Gs1+Gs2+Gs3+0.1185*(Gi+Gc6+Gc7+Gcf) 32777.20

5 Water weight of deaerator a) Cubage of deaerator water tank Q m3 Data of manufactory 180

b) Metal weight of deaerator water tank Gj kg Data of manufactory 73300

c) Radius of deaerator water tank R m 1.8

d) Center elevation of deaerator water tank V m 23.55

e) The lowest water level elevation of deaerator water tank V1 m 22.85

f) Water weight of the lowest water

level in deaerator water tank Gs kg 63.233m3 56511

Water calculation weight of the lowest water level in deaerator M kg Gs+C'*Gj 65197.05

6

Saturation water enthalpy of deaerator when transient load rejection HO kJ/kg VWO 736.3

7

Condensate water enthalpy of No.4 LP heater outlet when load rejection HL kJ/kg VWO 589.6

8 Condensater water enthalpy of condensor HC kJ/kg VWO 192.2

9 Calculation time after load rejection TS S standard 300

10 Kind of downcomer N 111 NPSH25% margin Nr m 3.6*1.25 4.5

12

Level difference from calculation water elevation of deaerator to BFP booster pump C Hj m 21.955







51

13 Resistance of strainer PL kPa 20

14 Specific volume of BFP booster pump inlet VV m3/kg VWO: 173.9C 0.001119

15 Inner diameter of downcomer DN m [325-28)]/1000 0.30916 Calculatiom length of downcomer L m The max 55.62

17 Part resistance coefficient of downcomer

Outside diameter of pipe DW mm 325 Thickness of pipe S mm 8 Inner diameter of pipe Di mm DW-2*S 309 Equivalence roughness of pipe E.2.1-1 0.2 Friction coefficient of pipe 1/(1.14+2*logDi/)2 0.01769 Length of pipeline L m 55.62 Friction coefficient of pipeline A *L/Di/1000) 3.18482

Part resistance coefficient of pipeline

Elbow90 total 11.5 1 E.2.2-1 2.875 Motorized gate valves 2 E.2.2-16 PN2.5;DN300 2.8

Inlet resistance cofficient of downcomer 3 P180 E.2.2-14 2.5

Total resitance coefficient of pipe 11.36

18 Flow of each downcomer G kg/s 147.1

result Available NPSH of load ejection condition ZH m 0.237

Originality data for calculation program

294.2,6214.09,10756.11,32777.2,65197 736.3,589.6,192.2,300,1 4.5,21.955,20,0.001119 0.309,55.62 11.36,147.1

4.3.2 Heaters

The extraction system of each unit will be set with three HP heaters, four LP

heaters, one deaerator, and one gland steam condenser.







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All of the heaters are horizontal type and are designed in accordance with HEI

standard. Shell wall thickness shall be determined in accordance with the ASME

code utilizing the allowable stress value for the shell material at the design

pressure and temperature. They are arranged indoors. Two LP heaters are

arranged at the neck of condenser.

The deaerator has enough volume to ensure the boiler working at the maximum

operation condition for about 10 minutes. The deaerator storage tank is also

sized in conjunction with the deaerator outlet piping and height to provide a

storage volume which allow adequate transient NPSH for the boiler feed due to

a sudden full load rejection and prevent flashing at the pump suction.

Deaerator shall remove dissolved oxygen from the condensate in excess of

0.005 cc per liter at any load from 5 percent to and including rated capacity.

HP heaters:

Closed feedwater heaters are used in a regenerative steam cycle to improve the

thermodynamic gain. This is accomplished by extracting system at various points

from the turbine and condensing kit using boiler feedwater. The resultant heating

of the feed water aids in avoiding thermal shock to the boiler and reduces the

fuel consumption required to convert the feedwater to steam. Since the work lost

by extracting the steam is derived from sensible heat, i.e. no change of phase,

the much greater latent heat recovered in the feedwater heater by changing

phase from steam to water result in a net energy gain. Without a feedwater

heater, the latent heat is wasted or thrown out in the main condenser or cooling

tower. Therefore, feedwater heaters also help to reduce thermal pollution.

The high pressure heater is essentially an all-welded assembly. A special insert







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is assembled in the inlet end of every heater-transfer U tube. Each high pressure

heater has indicating, regulating and alarming devices of level. When accident

has taken place, automatic regulating of drain level can fast bypass high

pressure heater. Heater shell is provided with relief valves to protect the shell in

case of tube failure. On tube side, relief valve is provided to prevent excessive

pressure. Each high pressure heater contains three zones, (i.e. desuperheating

zone, condensing zone and subcooling zone).

The welded seams are radiographed to insure the quality of the joint.

Stainless steel impingement plates have been installed in these heaters of

steam and other drains inlets to avoid direct impingement of steam and drains

upon the tubes to prevent tube erosion.

HP HEATER Nos. 8 DATA SHEET

Parameter SL.

No DESCRIPTION

Tube side Shell side Unit

1 Sort Class 3rd pressure

vessel

Class 2nd pressure

vessel

2 Type JG-1370

3 Heating area 1370 m2

4 Design pressure 27.5 7.58 MPa(a)

5 Design temperature 295 420/295 oC

6 Max. operating

pressure

27.5 7.58 MPa(a)

7 Operating pressure 21.5 6.2145 MPa(a)

8 Operating

temperature

279.5 393.4/277.9 oC

9 Max. pressure drop






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Parameter SL.

No DESCRIPTION


10 Flow 1015 80.785 T/h

11 Medium Water Steam & Water

12 Weld coefficient 1 1

13 Test pressure 41.25 11.37 MPa(a)

14 Corrosion allowable 1

15 Estimated weight

Net weight 64956 Kg

Operating weight 70861 Kg

Flooded weight 82717 Kg

Manhole weight 120 Kg

16 Estimated Volume

Volume of water in sub-cooler zone at

normal water level

1.40 m3

Volume of water in shell at normal water

level outside sub-cooler zone

0.86 m3

Volume of steam in shell operating 12.1 m3

Volume of tube side 3.78 m3

HP HEATER Nos. 7 DATA SHEET

Parameter SL.

No DESCRIPTION



vessel

Class 2nd pressure

vessel

2 Type JG-1575


4 Design pressure 27.5 4.81 MPa(a)








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Parameter SL.

No DESCRIPTION


6 Max. operating

pressure

27. 5 4.81 MPa(a)


8 Operating

temperature

245 324/245 oC







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Parameter SL.N

o DESCRIPTION



vessel

Class 2nd pressure

vessel

2 Type JG-1230


4 Design pressure 27. 5 2.07 MPa(a)


6 Max. operating

pressure

27. 5 2.07 MPa(a)


8 Operating

temperature

207.6 455/207.6 oC







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Parameter SL.N

o DESCRIPTION


Volume of steam in shell operating 13.6 m3

Volume of tube side 3.50 m3

Note: class III: 10 to 100MPa, class II: 1.6 to 10MPa.

The high-pressure feedwater heaters shall be manufactured of following

DBR 300 mw.pdf

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