Tổng quan cấu hinh về nhà máy điện nhiệt điện

Tổng quan về nhà máy điện than CFB lớn nhất Việt Nam. Công nghệ lò hơi tuần hoàn tân tiến. Dành cho các kĩ sư làm việc tại các nhà máy nhiệt điện. Rất bổ ích cho các sinh viên đại học và những người đang và sẽ làm trong nhà máy điện có cái nhìn tổng quan chi tiết về các hệ thống và nguyên lý hoạt động.

E Feb 13, ‘13 Issue for Approval J.A.SEO M.K.LEE J.Y.KIM

REV DATE DESCRIPTION DSGN CHKD APPD PROJECT :

TWO(2) x 500 MW MONG DUONG 1 THERMAL POWER PLANT

1.0 INTRODUCTION 1

1.1 GENERAL 1

1.2 PROJECT DESCRIPTION 1

1.3 DESIGN CONDITION AND CODE 2

1.4 PLANT OVERALL SYSTEM CONFIGURATION 2

1.5 MAJOR SYSTEM DESIGN CONSIDERATION 19

2.0 PLANT CONTROL PHILOSOPHY 25

2.1 GENERAL 25

2.2 BALANCING CONTROL 25

2.3 PLANT CONTROL MODE 25

2.4 CONTROL FUNCTION OF MAJOR EQUIPMENT 26

3.0 PLANT OPERATION PHILOSOPHY 27

3.1 BASIC CONCEPT OF OVERALL PLANT OPERATION 27

3.2 PLANT OPERATION MODE 27

4.0 PLANT START-UP AND SHUT-DOWN PROCEDURE 32

4.1 PLANT START-UP 32

4.2 PLANT SHUT-DOWN 42

4.3 DEGREE OF AUTOMATION FOR PLANT START-UP AND SHUTDOWN 43

5.0 ABBREVIATION 52

6.0 ATTACHMENTS 54

7.0 REFERENCES 54

1.0 INTRODUCTION

1.1 General

This description introduces and provides a general understanding of system configuration, feature and control scheme of the Mong Duong 1 Thermal Power Plant, which will have a nominal gross output of 540MW per each unit and have two Units, in Cam Pha town, Quang Ninh province, Vietnam

This document has been updated with the Contractor’s review and improvement of actual engineering and design However, the document may be improved to reflect the actual

engineering and design as required

1.2 Project Description

Mong Duong Thermal Power Plant is located adjacent to the national highway N0.I8A, which

is about 50km from Ha Long city in the northeast and about 18km from Cam Pha town This location belongs to zone No 3, Mong Duong ward, Cam Pha town, Quang Ninh province

Mong Duong Thermal Power Plant, with an area of about 107 hectares, includes Mong Duong

1 comprising 2 X 540 MW coal-fired CFB steam units and Mong Duong 2 comprising 2 X 600

MW PC steam units respectively

The plant and facilities provided will comply with the local rules and regulations and the

Technical Requirements specified in this document The power island will consist of four (4) Circulating Fluidized Bed (CFB) boilers supplying steam to two (2) steam turbine generators

Electric power will be fed to the National Grid at voltage of 500 kV to Quang Ninh 500/220 kV substation The 110 kV transmission line will supply power for the start-up and commissioning, and serve as the standby power source during normal operation

The power plan cooling water (once through cycle) will be extracted from Gac Canal

(seawater) whilst fresh water is piped to the site from the Thac Thay River located at about 12

km from the site The fresh water supply system will be undertaken by the Owner

Coal supplied to the power plant is dust coal mixtures of 5HG dust coal, 6HG dust coal, dust coal and slurry coal from coal mines in Mong Duong - Cam Pha area Coal will be supplied

to the terminal point in the receiving tower located at the south side of the plant

Heavy Fuel oil Type 2B TCVN 6239-2002 will be used as secondary fuel for boiler start-up and operation at low load Fuel oil is transported to the power plant by specialized barges to the fuel oil unloading jetty

Limestone used for the CFB boiler is taken from limestone mines in Hoanh Bo area, Quang Ninh Province, by trucks to Troi port From the port limestone is transported to the power plant

by barges to the berth adjacent to the fuel oil unloading berth

Fly ash and bottom ash will be disposed of at the ash pond located about 1 km from the power plant

1.3 Design Condition and Code

1.3.1 Site Condition

For overall power plant design, please refer to Attachment 8, “Site Ambient Condition”

For consistency of performance comparison between different operating configuration, all performance figures are estimated at reference site condition as below:

▪ Ambient Temperature 34.5 ℃

▪ Barometric Pressure 1,010 mbar

▪ Sea Water Temperature 26.5 ℃

▪ Boiler Fuel Performance Coal (Anthracite)

1.3.2 Fuel and Ash Specification

Please refer to Attachment 9, “Fuel and Ash Specification”

1.3.3 Water Qualities

Please refer to Attachment 10, “Water Qualities”

1.3.4 Codes and Standards

Please refer to Attachment 11, “Code and Standards”

1.4 Plant Overall System Configuration

Mong Duong 1 Thermal Power Plant is composed of two(2) Units And One(1) Unit includes Two(2) CFBC boilers and One(1) STG Therefore, configuration of all the main equipment can

be classified into three categories, Plant common, Unit common and Boiler basis

Unit common basis means that configuration and function of subsystem or equipment is organized for Each Unit Boiler basis means that configuration and function of subsystem or

equipment is organized for Each Boiler Plant common basis means that configuration and

function of subsystem or equipment is organized for overall plant

For detail system configuration, please refer to Attachment 12, “Redundancy List”

Design information for major equipment are as follows:

Steam Generation Type Natural Recirculation Type

Rated Condition

Rated Condition

Coal Handling

System

Conveying Capacity 1,000 ton/hr

Crushing Capacity 1,000 ton/hr

Storage Capacity 158,800 ton

Limestone Conveying Capacity 250 ton/hr

Equipment Design Parameter Value Remark

Transfer Capacity Fly Ash : 155.2 ton/hr

Bottom Ash :345.6 ton/hr

Disposal Capacity 500.8 ton/hr

Fly Ash Storage 9,600 m3

Bottom Ash Storage 7,400 m3

Steam Turbine Type triple pressure, reheat,

regeneration, three casing, tandem compound, four(4) flow and down exhaust type

Generator Generator Terminal Output,

Under RO load

Generator rated voltage, kV 21

Generator cooling method, stator / rotor Water/Hydrogen

Exciter Type and Gen full load field current

PSCR (Potential-sourcecontrolled rectifier system), 4183A

load Cooling Water Temperature 26.5 ℃

Deaerator & Type Horizontal, Spray & Tray

Equipment Design Parameter Value Remark

L.L.W.L Under VWO

Cooling Method ONAN/ONAF

1.4.1 Main Equipment or System as Unit Common Basis

1) One(1) X 100% of Steam Turbine and Generator with its auxiliaries

Steam turbine is of triple pressure, reheat, three casing, tandem compound and down

exhaust type and has 540 MW nominal gross output capacity Generator is of

hydrogen/water cooled type Auxiliary systems such as lube oil system, hydraulic oil

system, seal oil supply system, generator cooling system and so on will be provided for

STG

For detail, please refer to “System Description of Steam Turbine & Generator (Doc.No : MD1-0-V-111-03-00001)

2) Main & Reheat Steam System

This system is composed of main steam and reheat steam piping to connect between boiler and steam turbine with its auxiliaries For detail, please refer to “System

Description –Main & Reheat Steam System (Doc.No : MD1-0-M-110-03-00001)

3) Feedwater Heating System

This system is composed of Seven(7) stage feedwater heaters (13LCC11/12/20/30/40 AC001, 13LAD10/20/30AC001), one(1) X 100% of deaerator and feedwater tank (13LAA 10AC/BB001), extraction piping, cascade drain piping and vent piping with their

auxiliaries For detail, please refer to “System Description –Feedwater Heating System (Doc.No : MD1-0-M-110-03-00003)

(Doc.No : MD1-0-M-120-03-00001)

5) Feedwater System

This system is composed of three(3) X 50% of boiler feedwater booster pump (13LAC11/ 12/13AP001) and boiler feedwater pumps (13LAC21/22/13AP001) with fluid coupling device (13LAC21/22/23AP001MG01) and its piping to connected between feedwater tank and boiler economizer (11HAC10AC301) with its auxiliaries including feedwater control valves (11LAB33AA101) For detail, please refer to “System Description –

Feedwater System (Doc.No : MD1-0-M-120-03-00002)

6) Auxiliary Steam System

This system is composed of three(3) stage cascade auxiliary steam supply system The first stage system will receive source steam from auxiliary boiler (00UHB04AC004KC01) and main steam line and provide conditioned steam to next stage system and air

preheater soot blower (00HCB05/06AT001/002KT01) The second stage system will receive steam cold reheat steam line as well as the first stage and provide conditioned steam to the third stage system and many superheated steam users The third stage system will provide to heating steam users

For detail, please refer to “System Description – Auxiliary Steam System (Doc.No : MD1-0-M-110-03-00005)

7) Circulating Water System

This system is composed of two(2) X 50% circulating water pumps (13PAC11/12AP001) and its piping, which is routed from intake channel with one(1) set of stop log (13PAA11/ 12AB001), coarse bar screen (13PAA11/12AT001), fine bar screen (13PAA11/12AT002) and travelling bend screen (13PAA11/12AT003) to seal pit via debris filter (13PAH10/20/ 30/40AT001), tube cleaning system and condenser

For detail, please refer to “System Description – Circulating Water System (Doc.No : MD1-0-M-130-03-00001)

8) Closed Cooling Water System

This system is composed of one(1) set of closed cooling water tank (13PGF10CL

501), two(2) X 100% of closed cooling water pumps (13PSC11/12AP001) and closed cooling water coolers (13PGD10/20AC001), various equipment coolers and its piping

to connect them as closed loop This closed cooling water cooler will be cooled by sea water that two(2) X 100% of auxiliary cooling water pumps (13PCC10/20AP001) and auto filters (13PCH10/20AT001) provide from branch point of circulating water piping

For detail, please refer to “System Description – Closed Cooling Water System

(Doc.No : MD1-0-M-140-03-00001)

9) Electrical power and auxiliaries and unit transformer (main step-up and unit aux

transformer)

10) Power Transformers

The following transformers and accessories will be provided for power plant as

shown in Key Single Line Diagram (Dwg No MD1-0-E-500-31-00002)

850

11) Switchgears

For the power supply of the steam turbine generator units and plant common

auxiliaries, switchgears and MCC’s will be provided as required for the power plant

as shown in Key Single Line Diagram (Dwg No MD1-0-E-500-31-00002)

▪ Medium Voltage Switchgears

The 10kV MV switchgears will be of the type tested, metal clad, drawout type and rated for the maximum expected short circuit current based on short circuit calculation and continuous current capacity MV motors and LV switchgears will be fed from MV switchgears

The switchgears will be provided with automatic high speed busbar transfer scheme and will be located indoor The degree of protection will be IP 41

Circuit breakers will be drawout type, electrically stored energy operated vacuum circuit breakers

Breakers will be provided with local control in addition to the remote control in the control room The control voltage will be 220V DC Access space will be provided in back and in front of the switchgear

▪ Low Voltage Switchgears

The 400V LV switchgears will be of type tested, metal enclosed, draw out, fully compartmentalized metal enclosed type using air break technology and rated for the maximum expected short circuit currents based on short circuit calculation and continuous current capacity The construction of the LV switchgears will be such that the internal separation by barriers complies with form 4b separation in accordance with the requirements of IEC 60439-1

The design will give the degree of protection equal or better than IP 41

Circuit breakers will be electrically operated draw out air circuit breakers with solid state trips for selective protection against overload, phase and ground faults Control voltage will be 220V DC

▪ Motor Control Centers

The motor control centers will be designed metal enclosed type, dual or one face type, withdrawable and modular type, consisting of enclosed sections with main bus, insulated vertical bus, compartments and wireways

400V motors, distribution panels, etc will be fed from the motor control centers

Starter circuits for motor feeder will be full voltage starting combination type, consisting of molded case circuit breakers, magnetic contactors, thermal overload

relays, auxiliary relays, etc Starter sizes will be based on motor capacity, full load current, and type of service

12) DC & UPS System

Each 220V DC system consists of two battery charger, one lead acid batteries and one DC distribution board 220V batteries are of valve regulated lead-acid (VRLA)

and rated for a minimum period of 30 minutes in the event of a total loss of AC

supplies The battery chargers are solid state using silicon rectifiers with full wave, fully controlled bridge configuration and complete with automatic voltage regulator, current limiting circuitry, surge suppression network, smoothing filter circuits and soft-start feature

The chargers will be suitable for float charging as well as boost charging the battery Each battery charger will be capable of float charging batteries while supplying the station normal DC load Each rectifier-charger unit shall be designed for a capacity to supply 100% of the consumers (inclusive the inverter for the UPS system) connected

to the complete main DC switchgear and to charge one battery at the same time

Each 230V UPS system consist of inverters, bypass line transformers, voltage

stabilizer, static switch, manual bypass switch, distribution boards, necessary

protective devices and accessories Each inverter will be fed from upstream 220V

DC distribution board

The configuration of DC and UPS system are shown in Key Single Line Diagram

(Dwg No MD1-0-E-500-31-00002)

13) I&C System for automation and operation

I&C system will consist of DCS for process control, package control system, steam and water analyzing system(SWAS) for water and steam quality monitoring and

control, continuous emission monitoring system(CEMS), Vibration monitoring system for major equipment protection and vibration monitoring and field instrumentation

DCS will be provided for boiler & BOP control and monitoring and interface with

Package control system DCS will be consisted of redundant power supplies, control processors, memory devices, data communication facilities, operator stations,

engineering workstations, historian and printers Four(4) remote monitoring stations will be provided in administration building

Burner management system(BMS) is included in DCS and provided as separate

controller which is same type and manufacturer as DCS It will be provided for

start-up, shutdown and normal operation of the fuel firing equipment and to prevent errors

in operation and to protect against malfunctions of fuel firing equipment or associated air systems for the most common emergency situations

The On line performance monitoring system(OPM) will be integrated into the DCS and provided to calculate the performance of the power plant

Vibration monitoring system will be provided as an independent item to perform

machinery condition monitoring function and a computerized analysis system and

located in Computer Room for each unit.For interface with Load dispatch center,

redundant data links will be provided to link the RTU located in switchyard control

building And the RTU will be interface with the DCS for remote control and

Reference Drawing No

BOP system

- Main and reheat steam system

- Turbine bypass system

- Feedwater system

- Condensate system

- Auxiliary steam system

- Closed cooling water system

- Circulating water system

- Service water / Demin water

Ash Handling System PLC MD1-0-V-173-51-02001

Condenser Tube Cleaning

System

Compressed Air System Manufacturer's

own microprocessor

MD1-0-V-151-02-00017

Fire Detection and Alarm

System

Manufacturer's own

microprocessor

MD1-0-E-750-01-00101

own microprocessor

MD1-0-H-203-35-00901

Switchyards Control System SICAM PAS MD1-0-V-570-02-00004

For detail, please refer to “Design criteria for control and instrumentation (Doc.No : MD1-0-J-600-04-00001)

14) Fire fighting and alarm system

▪ Fire Water Storage System

Two(2) fire water storage tanks complete with foundations, fittings, valves, connections and instrumentation shall be provided The fire water storage tank shall

be sized to provide three(3) hours continuous fire water supply in 5,500m3/tank (1,750m3 water demand calculated) per each in accordance with TCVN 2622

▪ Fire Pumps

Fire water pumps, installed inside the fire protection pump house adjacent to the outdoor fire water storage tanks, shall take a suction from the fire water storage tanks and shall feed fire water to the fire water distribution system One(1) x 2,500 gpm (568m3/hr), 95m duty electric motor driven fire pump and one(1) One(1) x 2,500 gpm (568m3/hr), 95m standby diesel engine driven fire pump shall be provided Two(2) x 100 gpm(22.7m3/hr) 95m electric motor driven jockey pumps with associated piping and instrumentation controls, shall also be provided to maintain the fire main system pressure All fire pumps shall be UL/FM approved and designed in accordance with NFPA 20 and applicable local fire codes

▪ Fire Water Distribution System

The fire water distribution systems are looped around the whole plant area The fire water loop inside the steam turbine building, boiler structure, administration building, control building, switchgear control building and hydrogen plant shall be provided with two (2) valve connections to the outdoor fire water ring main and with appropriate sectional manual control valves on the interior loop

Outdoor hydrants shall be installed in the plant for additional protection of yard facilities buildings and structures The hydrants shall be located along the fire engine access road such that every part of the access road and / or access way is within an unobstructed distance of 50m from any hydrant The hydrants shall be located that they are at least 10 m away from potential fire areas and hydrant spacing shall be not more than 60 m spacing for the power block (turbine and boiler) area, fuel oil storage tank area and coal dry storage shed, and 90m to 150m spacing for the other areas

▪ Indoor Hydrant system & Hose reel system

Each building except in the far distance area shall be provided with indoor hydrants but small building less than 500m2 in floor area to be protected by hose reel This systems shall be designed in accordance with NFPA 14, TCVN 2622 and TCVN

4513

▪ Automatic Sprinkler System

The automatic sprinkler system is provided for turbine generator bearing, cable room in control building, diesel generator house, hydrogen plant room, fire protection pump house, I&C electrical & mechanical warehouse and administration building

This system shall be designed in accordance with NFPA 13 and TCVN 7336

▪ Automatic Water Spray System

The automatic water spray system is provided for turbine oil tank, control oil unit, sealing oil unit, turbine oil cooler, air heater, burner front end, rear end, Aux boiler, transformers, steam turbine dirty oil tank and H2/O2 cylinder in hydrogen plant building The automatic water cooling spray system is provided for fuel oil storage tanks and diesel oil storage tank

The automatic water spray system shall be designed in accordance with NFPA 15 and TCVN 5307

▪ Foam System

The fixed foam discharge system with Type II foam pourer is provided for fuel oil storage tanks and diesel oil storage tank The foam water sprinkler system is provided for fuel oil pump house and the fixed foam unit is provided for fuel oil unloading jetty and fuel oil unloading pump house

The automatic water spray system shall be designed in accordance with NFPA 11, NFPA 16 and TCVN 5307

▪ Clean Agent (FM-200) Fire Extinguishing System

The clean agent fire extinguishing system is provided for main control room and electronic equipment room in control building, control & protection room in switchyard control house, control & equipment room in coal handling control building, control room in hydrogen plant building, ESP control room in ESP control house

Clean agent fire extinguishing systems for protection by total flooding shall FM-200 system in compliance with the requirements of NFPA 2001 The system released into the protected space will allow a person to breathe in the reduced oxygen atmosphere The design concentration shall be 7% for under floor, room and ceiling space

▪ Portable and Wheeled Fire Extinguishers

The following shall be provided within the buildings of the plant and at all locations required by the relevant local rules and regulations:

4.0 ~ 8.0 kg portable dry-chemical fire extinguisher 5.0 kg portable CO2 fire extinguisher

Mobile fire extinguishers with 50 kg dry powder shall be provided and located in the turbine generator halls and the diesel generator house

Mobile fire extinguishers with 24 kg CO2 shall be provided and located in the turbine generator halls and the control/switchgear building

Portable fire extinguishers shall be provided in accordance with TCVN 3890 and 7435-1

For control of firefighting system, please refer to “Description for Fire Fighting System

& Fire Alarm System (Doc No.: MD1-0-F-750-03-00001)” and “Equipment Data

sheet – Main Fire Alarm Control Panel (Doc No.: MD1-0-V-750-09-00037)”

15) Heating, Ventilation and Air Conditioning System

For detail HVAC system description (including HVAC control), please refer to “Design Criteria for HVAC system (Doc No.: MD1-0-H-710-04-00101)”

16) Public Address System

For detail, please refer to “Communication Layout – Riser Diagram Public Address System (Doc No.: MD1-0-E-545-01-00301)”

1.4.2 Main Equipment or System as Boiler Dependent Basis

The following Equipment or system will be provided as Boiler dependent basis :

1) One complete circulating fluidized bed boiler

This equipment is composed of steam generation system, combustion system, coal feed system, bottom ash removal system, start-up burner system, sootblower system and its ancillary system

The major equipment of each system as mentioned in the above is as follows:

▪ Steam Generation System : Economizer, Steam Drum (11HAD10BB

501), HRA, superheaters (11HAH10/20/ 30AC301), reheaters (11HAJ10/20AC 301), and its interconnection pipings

▪ Combustion System : Furnace, Three(3) X 33% of cyclones,

Two(2) X 50% of Primary Air Fans (11 HAB11//12AN101) and Secondary Air Fans (11HAB21/22AN101), Loop seal blowers (11HDW01/02/03AN101), Air preheater, Steam coil air heater (11HLC10AC101)

▪ Coal Feeding System : Five(5) coal silos (11HFA01/02/03/04/05

BB101) and its coal feeders (11HFB10~ 80AF001)

▪ Bottom Ash Removal System : Four(4) X 33% of Stripper coolers (11

HDA10~40AT101), Striper Cooler Blowers (11HDA10~40AN101) and Bottom Ash Rotary Valves

(11HDA10~40AF101)

▪ Sootblower System : Full Retractable type and Half

Retractable type soot blowers

For detail, please refer to “Steam Generation System Description (Doc.No : V-161-03-00001)”

MD1-0-2) Flue Gas System

This system is composed of electrostatic precipitator (11HDE10AT001),

Two(2)X50% of induced draft fan (11HNC15AN001/002), stack (14UTJ) and its

interconnection duct Stack has two flues and each flue is connected to one boiler flue gas duct

For detail of electrostatic precipitator, please refer to “Overall Description with ESP Control (Doc No : MD1-0-V-162-03-00004)”

For detail of induced draft fan, please refer to “System Description – Induced draft fan (Doc No : MD1-0-V-163-03-00001)” (To be submitted later)

3) Bottom Ash Handling System

This system is composed of two(2) sets of mechanical conveyors and one(1) bottom ash silo (04EUH10/20BB001)

For detail, please refer to “Design Basis Report & System Description – Ash

Handling System (Doc No : MD1-0-V-173-03-00281)”

4) Fly Ash Handling System

This system is composed of two(2) buffer tanks, three(3) X 50% of pneumatic

vacuum blowers (04EUK10/20AN001~003), and three(3) X 50% of pneumatic

blowers and their interconnection piping Fly ash silo (04EUH30BB001) will be

provided for fly ash from two boilers

For detail, please refer to “Design Basis Report & System Description – Ash

Handling System (Doc No : MD1-0-V-173-03-00281)”

5) Turbine Bypass System

This system is composed of one(1) set of HP bypass valve (11/12MAN10AA101)

with desuperheating station, one(1) set of LP bypass valve (11/12MAP10AA081) with desuperheating station, one(1) dump tube and its interconnection piping with its

auxiliaries Hydraulic power supply unit will be provided to supply hydraulic oil to

control valves

For detail, please refer to “System Description – Turbine Bypass System (Doc No : MD1-0-M-110-03-00002)”

1.4.3 Common systems

1) Coal Handling System

This system is composed of two (2) lines of conveying system from coal receiving

tower to coal silos via coal storage shed with Four(4) sets of stock piles and two(2)

sets of coal stacker (04EAD10/20AF001) and reclaimer (04EAF10/20AF001),

transfer towers and coal crusher tower with two(2) sets of vibrating screen

(04ECA61/62AJ001) and coal crusher (04ECA63/64AJ001)

For detail, please refer to “System Description & Operational Description for Coal

Handling System (Doc No : MD1-0-V-171-03-02102)”

2) Limestone Handling System

This system is composed of the following subsystems

One (1) set of mechanical conveying system including one(1) bucket type ship

unloader (04EDA10AW001) and one(1) limestone tripper car from limestone

unloading jetty to limestone storage shed via Four(4) transfer towers

One (1) set of limestone mechanical conveying system for limestone preparation

from limestone storage shed to limestone surge bin including one(1) set of reclaiming hopper (04EBE10BB001), belt feeder (04EDC10AF001), bucket elevator

(04EDC20AF001) and reversible belt feeder (04EDC30AF001)

Two(2) sets of limestone grinding system Each set includes limestone one(1)

limestone surge bin (04EDE21/22BB001), one(1) tube mill (04EDH11/12AJ001),

one(1) screw conveyor (04EDC51/52AF001), one(1) bucket elevator

(04EDC61/62AF001) and one(1) limestone storage silo (04EDE31BB001)

Two(2) sets of limestone pneumatic conveying system from limestone storage silo to boiler limestone silo Each set includes two(2)X100% limestone pneumatic blowers (04EDP13/14AN001, 04EDP23/24AN001) and two(2) lines of pneumatic pipings

For detail, please refer to “System Description & Operational Description for

Limestone Handling System (Doc No : MD1-0-V-172-03-02102)”

3) Fuel Unloading and Supply System

This system is composed of the following subsystems

HFO unloading system including two(2) X100% of HFO unloading pumps (04EGC 10AP001), one(1) Fuel unloading heater (04EGG20AC001), oil/water separator

(04EGR10KT001) and its interconnection piping with its auxiliaries between Fuel Oil Unloading Jetty (04EGR10BB001) and Fuel Oil Storage Tanks (14EGB10BB001)

Two(2) sets of HFO supply system Each set is for One(1) unit and is composed of one(1) HFO storage tanks, Two(2)X100% of HFO supply pumps (14EGC10AP001), two(2) X100% of two(2) level HFO heaters (14EGT11/12/21/22AC001/002), One(1)

set of surge compression chamber (14EGF10BB001) and its interconnection piping with its auxiliaries between tank and Boiler burners

DO supply system including DO truck unloading station with header, two(2)X100% of

DO unloading pumps (04EGC20/21AP001) and its interconnection piping, one(1) DO storage tank (04EGB10BB001), two(2) sets of DO supply pumping stations, each set

of which is composed of two(2) X 100% of DO supply pumps (14EGC20/21 AP001) for One(1) unit, and its interconnection piping with its auxiliaries between DO storage tank and boiler burners (11HJA10~80AV101)

For detail, please refer to “System Description –Fuel Oil Unloading and Supply

System (Doc No : MD1-0-M-160-03-00001)”

4) Compressed air system

This system is composed of three(3)X50% of air compressor units, two(2) X 100% of desiccant type air dryer (03QFF71/72AT001) units for instrument air, two(2) air

receivers for service air (03QFA30/40BB001), two(2) air receivers for instrument

air(03QFA10/20 BB001) and its interconnection piping with its auxiliaries

For detail, please refer to “System Description – Compressed Air System (Doc

No : MD1-0-V-151-02-00017)”

5) Water treatment system

This system is composed of Preliminary treatment plant, Demineralization, Potable water treatment plant The Preliminary treatment plant shall be include two(2) x 50%

of Clarifier, two(2) x 50% of Gravity filter with related ponds, pumps, chemical dosing units and accessories

The Demineralization treatment plant is composed of two(2) x 50% of A/C filter,

two(2) x 50% of Cation exchangers, two(2) x 50% of Degasifers, two(2) x 50% of

Anion exchangers, two(2) x 50% of Mixed bed exchangers with related chemical

regeneration facilities, pumps, chemical dosing tank & pumps, chemical storage

tanks and accessories

The Potable water treatment plant is composed of one(1) of A/C filter, three(3) of

potable water pumps, two(2) of transfer pumps, potable water tank with related

The Wastewater treatment system is composed of one(1) of API oil/water separator, one(1) of CPI oil/water separator, two(2) of Mixing blowers, one(1) of Clarifiers,

two(2) of A/C filters, two(2) of pressure filters, one(1) of sludge thickener, two(2) of Backwash pumps, one(1) of wastewater storage pond with related ponds, pumps, chemical dosing tank & pumps, chemical storage tanks and accessories

For detail, please refer to “System Description – Waste water Treatment System

(Doc.No :MD1-0-W-840-03-00001)

7) Gaseous chlorination system

The Gaseous chlorination system is composed of five(5) of Chlorine evaporators, five(5) of Chlorinators, five(5) of Sea water pumps, five(5) of Chlorine evaporators, two(2) Drum weight scale, twenty four (24) Chlorine drums, two(2) of Strainers,

one(1) of Neutralization facility with related chemical tanks & pumps, blowers and

accessories

For detail, please refer to “System Description – Gaseous Chlorination System

(Doc.No : MD1-0-W-860-03-00001)

8) Emergency generator set

Emergency generator set is composed of engine part, which converts chemical

energy into mechanical rotational energy, and generator part, which generate power from the mechanical rotational motion

For detail, please refer to “Control Philosophy (Doc No : MD1-0-V-182-36-32001)”

9) Hydrogen Generating System

Hydrogen generating system is composed of two(2) sets of hydrogen generating

cells (00GKA11AG001) and one(1) set of hydrogen storage (00QKB11/12/13/14

BB001) system with its interconnection piping, valves and auxiliaries

10) Nitrogen Storage System

Nitrogen Storage System is composed of ten(10) cylinder racks each with forty(40) bottles of N2 storage and one(1) common pressure reducing manifold with its

interconnecting piping, valves and auxiliaries

11) Chemical Dosing System

The Chemical Dosing System for boiler system shall be included with Ammonia Bulk Storage & Transfer System as common for Unit 1 & 2 consisting of one (1) unit

Ammonia Storage Tank, two (2) units Ammonia Transfer Pumps, one (1) unit

Ammonia Seal Tank The chemical dosing system for Unit 1 is identical for Unit 2

and this contains Ammonia Dosing System consisting of one (1) unit Ammonia

Dosing Tank, one (1) unit Ammonia Measuring Tank, two (2) units Ammonia Dosing Pumps; Oxygen Scavenger Dosing System consisting of one (1) unit Hydrazine

Dosing Tank, one (1) unit Hydrazine Measuring Tank, Two (2) units Hydrazine

Dosing Pumps and Phosphate Dosing System consisting of one (1) unit Phosphate Dosing Tank and three (3) units Phosphate Dosing Pumps

For detail, please refer to “System Description for Boiler Chemical Dosing System (Doc.No : MD1-0-V-850-03-00001)

1.4.4 Ancillary System

1) Potable water supply

2) Firefighting system

3) Heating, ventilating and air conditioning (HVAC) system

4) Equipment for monitoring and measurement as requested for environmental control

5) Cranes, hoists and elevators as required for operation and maintenance

1.5 Major System Design Consideration

This clause describes major system design features that should be considered owing to Two(2) boiler + One(1) STG configuration

In case of Two(2) boiler and One(1) STG configuration, increase of operating case by two(2) boilers should be considered In other words, system design should be done to enable both boilers operated under different condition

To achieve such operation, any boiler should be isolated and incoming flow to both boilers should be adjusted according to load of each boiler

1.5.1 Boiler Isolation Operation

Boiler isolation operation should be required before main steam pressure and temperature condition of the second boiler reaches those of the first boiler in start-up operation and during single boiler operation

In case of one(1) boiler and one(1) STG configuration, boiler isolation is not necessary since trip of boiler and STG cause plant trip Therefore, as schematic diagram of this configuration (Fig.1), isolation valves between boiler and STG might not be installed Also, configuration of

bypass system will be determined between 1X100% and 2X50% per unit owing to economical

reason

Figure 1 Schematic Diagram of One(1) Boiler & One(1) Boiler

By the way, in case of two(2) boilers and one(1) STG configuration, boiler isolation should be

required during start-up, shut-down and abnormal operation such as run back and single boiler operation

For boiler isolation operation, each boiler should be equipped with isolation valves at its main

steam and reheat steam line and One(1) set of bypass system should be allocated to each

boiler In other words, configuration of bypass system should be of 2X50% per unit Also,

isolation valve on main steam, hot reheat and cold steam line of each boiler should be

installed and HP bypass piping will be tapped at the upstream of main steam line isolation

valve (13MBA10AA201/202) and connected at the downstream of cold reheat steam line

isolation valve (11LBC10AA201/202) LP bypass piping will be also tapped at the upstream of

hot reheat steam line isolation valve (13LBB10AA201/202) and routed to condenser (Refer to

Figure 2.)

Figure 2 Schematic Diagram for Boiler isolation operation

Not only turbine trip condition but also blending condition should be considered in bypass

system sizing since its pressure is relatively lower than trip condition though its flow rate is

lower than turbine trip condition

As it can be seen in Fig 2, each bypass system is connected to one condenser The bypass system for boiler #1 is connected to condenser “A” and that for boiler #2 to condenser “B” And then in start-up operation, heating load to condenser “B” is always higher than condenser “A” while the second boiler is being isolated Such load difference between condenser “A” and “B” causes difference of vacuum pressure between both condensers

To prevent such potential risk, Steam duct size should be determined to make pressure difference between both condensers lower than turbine trip setting value when such heating load difference is maximized

For detail, refer to “Condenser – Equalizing Duct Sizing Data Sheet (Doc No.: 09-00019)”

MD1-0-V-113-1.5.2 Flow Balancing

At two(2) boilers and one(1) STG configuration, feedwater flow from BFP discharge and cold reheat steam flow from HP turbine exhaust are divided and enter to both boiler Also, both boilers can be operated at different load Therefore, device for flow balancing of incoming flows to boiler according to boiler load is necessary

1) Feedwater line

In case that variable speed control is applied to Boiler Feedwater Pump, feedwater flow rate can be controlled by BFP speed instead of feedwater control valve to decrease auxiliary load of BFP In many cases that variable speed control is applied to BFP, main feedwater control valve, which covers from high load(approx 30% RO) to 100% load, is not installed to decrease design head of BFP and its auxiliary power consumption at maximum load

In case of one(1) boiler and one(1) STG configuration, to achieve three(3) element control (main steam flow rate/drum level/feedwater flow rate) for feedwater flow control, main steam flow meter don’t have to be installed because main steam flow rate can be calculated by the 1st bowl pressure of STG and decrease of friction loss on main steam line due to removal of main steam flow meter will be helpful to plant performance (Refer

to Fig.3)

Figure 3 Schematic Diagram for feedwater control in 1 Boiler + 1 STG

But, for two(2) boiler and one(1) STG configuration, feedwater control valve for both

boiler inlets will be installed though BFP is variable speed control type because

feedwater control device for each boiler should be individually required Also, main steam

flow meter (11LBA10CF001QB01) is required individually at the outlet of main steam

from each boiler since main steam flow measurement from each boiler is required (Refer

to Fig 4)

Figure 4 Schematic Diagram for Feedwater Control in 2 Boiler + 1 STG

2) Steam Line (Main Steam / Reheat Steam)

These main steam flow meters are also used for balancing of reheat steam flow between

two boilers Main steam flow rate according to boiler load will be controlled by feedwater

control because feedwater flow rate is basically the same as main steam flow rate except

transient operation If there is no control device of reheat steam flow, reheat steam flow

rate of both boilers are almost same regardless of difference between both boiler loads If

both boiler loads are different from each other, hot reheat temperature of boiler with

smaller load will be too higher and that of the other too lower To prevent it, reheat steam

flow control is necessary

For balancing of reheat steam flow, main steam flow meter, cold reheat flow meter

(11LBC10CF001QB01) and cold reheat flow control valve should be installed on the cold

at each boiler side Since high accuracy for cold reheat steam flow measurement is not

required, ANNOVA type flow meter with small friction loss will be applied

Figure 5 Schematic Diagram for Steam Control in 2 Boiler + 1 STG

1.5.3 Summary of design consideration for Two(2) Boilers and One(1) STG configuration

Design feature of Two(2) boilers & One(1) STG configuration comparing with One(1) boiler &

One(1) STG configuration is summarized as follows:

No Item 1 Boiler + 1STG 2 Boilers + 1

1 Isolation

Valves Not Necessary

MOVs on MS/CRH/HRH lines

For boiler isolation operation

2

Bypass System Configuration

1 X 100% or 2 X

For boiler isolation operation

3 Steam Duct

Sizing

Start-up condition is not considered

Unbalanced heating load at blending should

be considered

For boiler isolation operation

4

Feedwater Control Valve

Not Necessary (MOV is replaced)

Necessary For flow

balancing

5 Main Steam

Flow Meter

Not Necessary (STG 1st bowl pressure can be replaceable)

Necessary For flow

balancing

6

Reheat Steam Flow Meter

Not Necessary Necessary For flow

balancing

7

Reheat Steam Flow Control Valve

Not Necessary Necessary For flow

balancing

2.0 PLANT CONTROL PHILOSOPHY

2.1 General

In principle, plant power will be controlled mainly in modified variable pressure control mode

From 90% RO load to VWO load, plant will be operated under constant pressure operating

mode And variable pressure operating mode will be applied from 90% RO to minimum stable

load

Therefore, under higher load, plant can have rapid load response and under lower load,

turbine rotor life can be increased since turbine first stage temperature can remain relatively

constant for wide load range which shortens start-up times

2.2 Balancing control

Owing to Mong Duong 1 power plant configuration of Two(2) boiler and One(1) STG,

balancing between two boiler is necessary because their load should be the same as each

other basically during normal operation Therefore, load of each boiler will be adjusted in

order that the ratio between main steam flow rate measurements of two boilers should be

One(1) and it will be target value of ratio between reheat steam flow measurement of two

boilers, which will be done by adjustment of reheat steam flow control valve of each boiler

Balancing control like the above will be always applied regardless of plant control mode

except run-back operation and single boiler operation

In case of run-back operation by boiler equipment failure such as PA and SA fan malfunction,

balancing control is not applied When run-back is initiated, the load of both boilers will be set

to predefined value During this run-back operation, only reheat steam flow control valves of

both boilers will control reheat steam flow in order that these ratio between both boilers should

be the same as that of main steam flow rate between both boilers

Since feedwater flow to boiler will be controlled by three(3) element control method through

feedwater flow rate measurement, drum level measurement and main steam flow

measurement of each boiler respectively, additional balancing control function is not required

For detail of single element control and three(3) element control for feedwater control, refer to

clause 10.0 in “Control Narrative (Doc No.: MD1-0-V-161-33-06002)”

2.3 Plant Control Mode

Main steam pressure of MD1 plant will be controlled according to the following condition

▪ From minimum stable load (40% RO) to 90% RO : Variable Pressure

To achieve the above main steam pressure condition, target main steam pressure

corresponding to power demand is determined Such target condition will be controlled by the three control schemes, coordinated mode, boiler following mode and turbine following mode

2.3.1 Boiler Following Mode

In this mode, after turbine valve opening has been fixed according to power demand, boiler master will control boiler load in order for main steam pressure to reach its setting value corresponding to power demand During adjustment of boiler load in this mode, balancing control will be applied to make load of two boilers the same

2.3.2 Turbine Following Mode

In this mode, according to changed power demand, at first, total required boiler load is divided and dispatched to each boiler After changed boiler load point is set, turbine valve opening will adjust main steam pressure to setting value corresponding to changed power demand

In this mode, boiler master will not control main steam pressure If main steam flow rate from two boilers are different between each other after plant load stabilization for changed power demand, their loads should be equalized through balancing control

2.3.3 Coordinated Mode

In this mode, in order that difference between main steam pressure and setting pressure and between actual and target of plant output should be zero, boiler load and turbine valve

opening will be controlled at the same time

Since boiler load is adjusted in this mode to make main steam pressure its setting value, boiler load balancing control will be applied like boiler following mode

2.4 Control Function of major equipment

2.4.1 Boiler Control Function

For detail, please refer to “Control Narrative (Doc No.:MD1-0-V-161-33-06002)”

2.4.2 Steam Turbine Control Function

For detail, please refer to “System Description of Mark Vle Control System (Doc No : V-111-03-00701)

MD1-0-3.0 PLANT OPERATION PHILOSOPHY

3.1 Basic Concept of Overall Plant Operation

This plant is designed to meet electrical power demand This plant is of two(2) boilers and one(1) STG configuration Since the plant is operated from 90% RO load to minimum stable load under variable pressure operation, loads of two boilers should be the same under this load range except transient operation mode such as start-up, shut-down and run back

operation Therefore, adjustment between loads of two boilers should be done during this operation mode

3.2 Plant Operation Mode

3.2.1 Normal Operation (Two(2) Boiler & One(1) STG Operation)

When plant is operated from minimum stable load to RO load after plant start-up is finished, loads of two boilers should be the same as each other Therefore, the same load between boilers will be done through balancing control function as described in clause 2.2

During normal operation mode, boiler can maintain its load firing only coal Fuel oil firing will support boiler load in start-up or less than 40% BMCR load

3.2.2 Runback Operation

In case that major equipment or subsystem of plant is tripped, plant including boiler and STG should decrease its load to maintain stable operation according to run back case

1) Runback due to boiler equipment failure

In this clause, we assumed that equipment which belongs to the 1st boiler is tripped

When run-back operation is initiated by boiler equipment failure such as PA fan, SA fan

so on, the 1st boiler load should be decreased to set value predefined according to equipment and the 2nd boiler load will be maintained as the same as prior to run-back At this time, the main steam pressure of turbine will be controlled by turbine control valve opening as the same as that prior to run-back

In other words, if run-back happens by boiler equipment failure, plant control mode will

be changed from coordinated mode to turbine follow mode

Predefined heat input of the 1st boiler, expected steam output of the 2nd boiler and

expected plant power output for run-back cases due to boiler equipment failure are shown in Table 1 “Run Back Operating Cases by boiler equipment failure”

2) Runback due to steam cycle equipment failure

In case that run back happens due to steam cycle equipment such as BFP and CEP, boiler load and steam turbine load should be decreased at the same time Both boiler load will be balanced through balancing control at this run back case

Predefined heat input of the 1st boiler and the 2nd boiler and expected plant power output for run-back cases due to steam cycle equipment failure are shown in Table 2 “Run Back Operating Cases by steam cycle equipment failure”

3.2.3 One(1) Boiler & One(1) STG Operation

Basically, it is not allowed that only one(1) boiler should support plant load But, in case that one boiler cannot be operated or is tripped completely, this configuration can be allowed

In this case, boiler load should be almost full load to make plant load maintain more than minimum stable load and main steam pressure and temperature should be as high as STG can allow though its plant load is less than 90% RO

When one boiler is tripped and then plant starts this operation mode, it will proceed according

to the same way of clause 3.2.2 1) of this document

3.2.4 Load Rejection to House Loads

When load rejection is initiated, for example, grid is disconnected, one of both units will be tripped and the other unit will provide power to auxiliary equipment in MD1 power plant

The operating unit will be controlled under governor free mode to maintain normal frequency

of electricity Boilers will be decreased to their minimum stable load Extra steam, which is not used to generate power, will be bypassed

3.2.5 Plant Trip Operation

During two(2) boiler and Steam turbine operation, in case one(1) boiler trip, its operation is single boiler operation described in clause 3.2.3 In case both boilers are tripped, Turbine will be tripped

In case turbine tripped, both boiler load will be decreased to minimum load (about 40%) and bypass operation will be applied

Regarding plant trip operation, refer to the following documents

Boiler system : MD1-0-V-161-33-06202~06219

1 Runback by boiler equipment

Item Configuration Run-back Activity

Load

Remark

Boiler Plant

(Expected Power Output)

1st Boiler(Heat Input)

2nd Boiler (Expected Steam Output) *1

1 Boiler 2 X 50%/Unit 1 of 2 trip Trip 85% 42%

2 of 2 trip Trip Trip 0%

2 Coal Feeder 8 X 25%/Boiler

1 of 8 trip 100% 100% 100 % Worst coal basis

2 of 8 trip 100% 100% 100% Assume that the two rear wall feeders tripped

3 of 8 trip 80%*2 90% 85% Assume that the two rear wall feeders tripped

4 of 8 trip Trip*3 100% 42%

Assume that the two rear wall feeders tripped, Without Fuel Oil, Trip after any metal temperature alarm is activated

3 PA Fan 2 X 50%/Boiler 1 of 2 trip 45% 85% 60%

6 Stripper Cooler 4 X 33%/Boiler

1 of 4 trip 100% 100% 100% Worst coal basis

2 of 4 trip 65%*4 90% 80% After time delay based on ash generation rate to allow time

Item Configuration Run-back Activity

Load

Remark

Boiler Plant

(Expected Power Output)

1st Boiler(Heat Input)

2nd Boiler (Expected Steam Output) *1

to get equipment back in service or when PA fan motor reaches 95% of full load amps

7 Air Preheater 1 X 100%/Boiler 1 of 1 trip Trip 100% 45%

8 BFP 3X50%/Unit 1 of 3 trip 100% 100% 100% Stand-by Pump start-up

Stand-by Start Fail 50% 50% 40%

9 CEP 3X50%/Unit 1 of 3 trip 100% 100% 100% Stand-by Pump start-up

Stand-by Start Fail 50% 50% 50%

Table 1 Run Back Operating Cases by boiler equipment

Note

*1 When run back happens in the 1st boiler or steam cycle, the 2nd boiler load is assumed to be 100% Load In this column, expected steam

output is shown on the condition the 2nd boiler load is 100% heat input

*2 Load limit based on maximum feeder capacity

*3 Operator initiated trip

*4 Operator initiated action

2 Runback by steam cycle equipment

Item Configuration Run-back Activity

Load

Remark

Boiler Plant

(Expected Power Outptu)

1st Boiler(Heat Input) 2

nd Boiler (Heat Input)

1 BFP 3X50%/Unit 1 of 3 trip 100% 100% 100% Stand-by Pump start-up

Stand-by Start Fail 50% 50% 50%

2 CEP 3X50%/Unit 1 of 3 trip 100% 100% 100% Stand-by Pump start-up

Stand-by Start Fail 50% 50% 50%

Table 2 Run Back Operating Cases by steam cycle equipment

4.0 PLANT START-UP AND SHUT-DOWN PROCEDURE

In accordance with ERQ clause 4.3.3 Operating Regime, classification of start-up is defined

as follows:

Shutdown Period No of Starts per

year

Total

4.1 Plant Start-up

For detailed time sequences, refer to “Plant Start-up Curve (MD1-0-M-100-57-00010)”

4.1.1 Preparation sequence Before boiler ignition

1) Check of readiness of BOP system

The following systems should be checked their own readiness

▪ Fire Detection and Protection System

▪ Water Treatment System

▪ Waste Water Treatment System

▪ Plant Water Distribution System

▪ Coal Handling System

▪ Ash handling system

▪ Electrical & Instrumentation including SWAS, CEMS etc related the above

mentioned system

2) Circulating Water System Operation

According to the following sequences, circulating water system will be started

▪ Fill circulating water system piping with sea water by cooling water filling pump

▪ Start vacuum priming system

▪ Verify Intake level (higher than Low Water Level)

▪ Verify circulating water pump discharge MOV Close

▪ Start One(1) Circulating Water Pump

▪ Open CWP discharge MOV gradually as checking that discharge pressure of CWP

▪ Start auxiliary cooling water pump

3) Closed Cooling Water System Operation

According to the following sequences, closed cooling water system will be started

▪ Verify condensate storage tank level ( higher than Low Water Level)

▪ Start condensate make-up pump

▪ Verify closed cooling water head tank level (higher than Normal Water Level)

▪ Vent closed cooling water system piping and heat exchanger

▪ Start closed cooling water pump

4) Compressed Air System Operation

According to the following sequences, circulating water system will be started

▪ Check status of desiccant in instrument air dryer

▪ Start instrument air dryer

▪ Verify if closed cooling water is in service to equipment cooler

▪ Check status of lube oil system

▪ Start air compressor (03QEA10/20/30AN001)

5) Auxiliary Boiler Operation (Auxiliary Steam Supply Start)

For detail, refer to clause 5.0 in “Auxiliary Boiler Package Commissioning Procedure for Start-up & Stop (Doc No : MD1-0-V-181-05-00013)”

6) Condensate Extraction Pump Operation

According to the following sequences, condensate extraction pump will be started

▪ Verify condenser hotwell level (higher than Low Water Level)

▪ Fill seal water line to condensate extraction pump with demineralized water

▪ Fill condensate system piping from condenser to deaerator with condensate water

by demi water transfer pump (05GHB11/12AP001)

▪ Set condenser level control valve Auto

▪ Start condensate extraction pump

For detail, refer to clause 5.2 and 5.3 of “System Description for CEP 00001)”

(MD1-0-V-122-03-7) STG auxiliary system Operation for Start-up

According to the following sequences, STG auxiliary system for start-up will be done

▪ Check TCS operating status

▪ Start main lube oil system

▪ Start generator seal oil system

▪ Start generator gas control system

For detail, refer to item no 1 to 3 in clause 8.1 of “Turbine Startup and Shutdown

Procedure (Doc No.: MD1-0-V-111-05-00003)”

8) Turning Gear Operation

Turning gear operation should be maintained for minimum Four(4) hours before turbine rolling Before turning gear start, it should be checked whether AC lubricating oil pump should be in service

According to the following sequences, turbine gear operation will be done

▪ Engage turning gear

▪ Verify if rotor eccentricity is within allowable range

▪ Verify if turbine journal bearing metal temperature is within allowable range

▪ Verify if thrust bearing metal temperature is within allowable range

For detail, refer to item no 5 in clause 8.1 of “Turbine Startup and Shutdown Procedure (Doc No.: MD1-0-V-111-05-00003)”

9) Gland Seal Steam Supply Start

According to the following sequences, gland seal steam will be provided

▪ Verify pressure and temperature of auxiliary steam header 1 (auxiliary steam source : auxiliary boiler)

▪ Set gland seam steam pressure control valve Auto

▪ Open gland seal steam shut-off valve

▪ Adjust steam seal header pressure

▪ Check steam seal header temperature

For detail, refer to item no 6 in clause 8.1 of “Turbine Startup and Shutdown Procedure (Doc No.: MD1-0-V-111-05-00003)”

10) Condenser Vacuum Up

According to the following sequences, condenser vacuum up will be done

▪ Close vacuum breaker and check sealing water in service

▪ Verify seal water cooler in service

▪ Check separator level

▪ Start sealing water recirculation pump

▪ Start all the condenser vacuum pumps together (Hogging mode)

▪ Stop one(1) condenser vacuum pump when condenser vacuum reaches 0.3 bara (Start holding mode)

For detail, refer to clause 2-5 of “Condenser Vacuum Pump Instruction Manuals for Erection, Installation, Operation and Maintenance (MD1-0-V-123-05-00016)”

11) Hydraulic Fluid System Operation

For detail, refer to item no 8 in clause 8.1 of “Turbine Startup and Shutdown Procedure (Doc No.: MD1-0-V-111-05-00003)”

12) Generator System Operation

According to the following sequences, generator cooling system will be started

▪ Verify Hydrogen Storage Tank Pressure (Higher than Normal Operating Pressure)

If it is lower, hydrogen plant should be started and fill the tank upto normal operating pressure

▪ Start generator Hydrogen gas system

▪ Start stator cooling water system

13) Feedwater Warming Up & Boiler Filling

According to the following sequences, feedwater warming-up will be done

▪ Open suction valve (13LAB11/12/13AA001) of boiler feedwater booster pump

▪ Close discharge MOV (13LAB21/22/23AA201) of boiler feedwater pump

▪ Verify feedwater tank level (higher than Normal Water Level)

▪ Close isolation valves (13LAB46AA011/012) of feedwater filling line

▪ Verify if sealing water supply to boiler initial filling & warm-up recirculation pump (13LAC40AP001) in service

▪ Start boiler filling & warm-up recirculating pump

▪ Supply auxiliary steam to deaerator

▪ Start boiler filling after feedwater temperature reaches 100 ℃

14) Turbine Rotor Warming Up

According to the following sequences, turbine rotor warming up will be done

▪ Check seal steam supply and condenser vacuum

▪ Verify if turbine is rotated by turning gear

▪ Close all turbines, reheat piping extraction piping drains and vents between the CVs and the IVs

▪ Open the HSPV slowly by stepwise increasing the setpoint until HP turbine is pressurized

For detail, refer to item no 1 in clause 8.2 and attachment #3 of “Turbine Startup and Shutdown Procedure (Doc No.: MD1-0-V-111-05-00003)”

4.1.2 From Boiler Ignition to Turbine Rolling

1) Verify Preparation for Boiler Start-up (The 1st Boiler)

For detail, refer to clause 3.3.1 of “MD1 Boiler Operation and Maintenance Manual (Doc No.: MD1-0-V-161-05-00004)”

2) Boiler Air and Gas System Operation (The 1st Boiler)

According to the following sequences, boiler air and gas system will be started

▪ Start the regenerative and steam coil air heaters

▪ Verify an open gas path from the inlets of the PA, SA and Loop Seal Air Fans to stack via the unit

▪ Verify upper ring SA nozzle air flow to fuel feed air bustles and limestone drops open

▪ Start induced draft fan

▪ Start loop seal air fan

▪ Start the secondary air fans

▪ Start the primary air fans

For detail, refer to clause 3.3.2 of “MD1 Boiler Operation and Maintenance Manual (Doc No.: MD1-0-V-161-05-00004)”

3) Installation of Bed Material (The 1st Boiler)

For detail, refer to clause 3.3.3 of “MD1 Boiler Operation and Maintenance Manual (Doc No.: MD1-0-V-161-05-00004)”

4) Boiler Purge and Boiler Ignition (The 1st Boiler)

According to the following sequences, boiler purge and ignition will be done

▪ Check precondition for boiler purge

▪ Start burner light-off one by one

▪ Increase heat input to the burners to heat up the bed and increase the boiler

pressure

For detail, refer to clause 3.3.4 and 3.3.5 of “MD1 Boiler Operation and Maintenance Manual (Doc No.: MD1-0-V-161-05-00004)”

5) Boiler Warm-up (The 1st Boiler)

For detail, refer to clause 3.3.6 of “MD1 Boiler Operation and Maintenance Manual (Doc No.: MD1-0-V-161-05-00004)”

6) CV Chest Warming

According to the following sequences, CV chest warming will be done

This operation should be done if the difference between main steam temperature and control valve chest outer surface temperature is greater than the allowable difference across the valve wall

▪ Verify that the CVs are fully closed

▪ Open MSVBV and pressurize CV chest slowly

▪ Soaking heat after the chest pressure has reached 85% of main steam pressure until their temperature difference is less than the heat soak targets

For detail, refer to item no 2 in clause 8.2 and attachment #3 of “Turbine Startup and Shutdown Procedure (Doc No.: MD1-0-V-111-05-00003)”

7) Turbine Bypass System Operation (The 1st Boiler)

According to the following sequences, HP turbine bypass system will be started

▪ Open partially HP bypass valve as soon as boiler ignition

▪ Maintain HP bypass valve openness until main steam pressure reaches 10 barg

▪ Open HP bypass valve upto the 2nd preset value

▪ Maintain HP bypass valve openness until main steam pressure reaches 80 barg

▪ Set HP bypass valve Auto

According to the following sequences, LP turbine bypass system will be started

▪ Open partially LP bypass valve when reheat steam pressure reaches 2 barg

▪ Open gradually LP bypass valve until reheat steam pressure reaches 12 barg

▪ Set LP bypass valve Auto

8) Auxiliary Steam Source Change (From Auxiliary Boiler to Main Steam)

According to the following sequence, auxiliary steam source will be changed

▪ Open shut-off MOV on supply steam line from main steam line when main steam pressure reaches 30 barg

▪ Set pressure control valve and temperature control valve on this line Auto

▪ Close shut-off MOV on supply line from auxiliary boiler gradually

4.1.3 From Turbine Rolling to Synchronization

1) Turbine Rolling

According to the following sequences, turbine rolling will be done

▪ Check the permissive conditions for turbine rolling

▪ Verify if rotor prewarming and chest warming is enough